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, 2002
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
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(Address of Principal Executive Offices) (Zip Code)
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Registrant's Telephone Number, Including Area Code (918) 493-7700
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange
------------------- on which registered
Common Stock, par value -------------------
$.20 per share New York Stock Exchange
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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 information statements incorporated by reference in PART III of this Form 10-K or any amendment to this Form 10-K. ___
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).
Yes _X_ No ___
Aggregate Market Value of the Voting Stock Held By Non-affiliates on June 30, 2002 - $420,961,714
Number of Shares of Common Stock Outstanding on March 7, 2003 - 43,514,317
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting of Stockholders to be held May 7, 2003 are incorporated by reference in
Part III.
Exhibit Index - See Page 100
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 2
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 2
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 21
Item 4. Submission of Matters to a Vote of Security Holders . . 21
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . 22
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . 24
Item 7a. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . 40
Item 8. Financial Statements and Supplementary Data . . . . . . 41
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . 87
PART III
Item 10. Directors and Executive Officers of the Registrant. . . 87
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 89
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . 89
Item 13. Certain Relationships and Related Transactions. . . . . 89
Item 14. Controls and Procedures . . . . . . . . . . . . . . . . 89
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 90
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
Certifications. . . . . . . . . . . . . . . . . . . . . . . . . . 96
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UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2002
PART I
OUR BUSINESS
Through our wholly owned subsidiaries, we
. contract to drill onshore oil and natural gas wells for others and
. explore, develop, acquire and produce oil and natural gas properties
for our self.
We were founded in 1963 as a contract drilling company.
Our executive offices are at 1000 Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; our telephone number is (918) 493-7700. We also have regional offices in Oklahoma City, Oklahoma, Woodward, Oklahoma, Booker, Texas, Houston, Texas and Casper, Wyoming.
Our primary Internet address is www.unitcorp.com. We make our periodic SEC Reports (Forms 10-Q and Forms 10-K) and current reports (Form 8-K) available free of charge through our Web site as soon as reasonably practicable after they are filed electronically with the SEC. We may from time to time provide important disclosures to investors by posting them in the investor relations section of our Web site, as allowed by SEC rules.
Materials we file with the SEC may be read and copied at the SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet Web site at www.sec.gov that contains reports, proxy and information statements, and other information regarding our company that we file electronically with the SEC.
When used in this report, the terms Corporation, Unit, our, we and its refer to Unit Corporation and, as appropriate, Unit Corporation and/or one or more of its subsidiaries.
OUR LAND CONTRACT DRILLING BUSINESS
General. Using our 75 drilling rigs, our wholly owned subsidiary, Unit Drilling Company, drills onshore natural gas and oil wells for a wide range of customers. Our drilling operations are mainly in the Oklahoma and Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf Cost and in the East Texas and Rocky Mountain regions.
The following table sets forth, for each of the periods indicated, certain information concerning our contract drilling operations:
Year Ended December 31,
----------------------------------------------
1998 1999 2000 2001 2002
------ ------ ------ ------ ------
Number of Rigs
Owned at End
of Period 34.0 47.0 50.0 55.0 75.0 (1)
Average Number
of Rigs Owned
During Period 34.0 37.3 47.0 51.8 61.6
Average Number
of Rigs
Utilized 22.9 23.1 39.8 46.3 39.1
Utilization
Rate (2) 67% 62% 85% 90% 63%
Average Revenue
Per Day (3) $6,394 $6,582 $7,432 $9,879 $8,285
Total Footage
Drilled
(Feet in
1000's) 2,203 2,211 3,650 4,008 3,829
Number of Wells
Drilled 198 197 316 361 318
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(1) Includes 20 rigs acquired in August 2002.
(2) We determine our utilization rate on a 365 day year by dividing the number of rigs used by our total number of rigs.
(3) Represents total revenues from contract drilling operations divided by the total number of days rigs were used during the period.
Acquisitions. On August 15, 2002 we acquired twenty drilling rigs, spare drilling equipment and vehicles when we acquired CREC Rig Equipment Company and CDC Drilling Company. We issued 6,819,748 shares of common stock and paid $3,813,053 for all the outstanding shares of CREC Rig Acquisition Company and issued 400,252 shares of common stock and paid $686,947 for all the outstanding shares of CDC Drilling Company. The twenty rigs range in horsepower from 650 to 2,000 with 15 having a horsepower rating of 1,000 or more. Twelve of the rigs are SCR electric. Depth capacities range from 12,000 to 25,000 feet.
Description of our Drilling Rigs. A land drilling rig consists, in part, of engines, drawworks or hoists, derrick or mast, substructure, pumps to circulate the drilling fluid, blowout preventers and drill pipe. Over the life of a typical rig, due to the normal wear and tear of operating 24 hours a day, several of the major components, such as engines, mud pumps and drill pipe, must be replaced or rebuilt on a periodic basis, while other components, such as the substructure, mast and drawworks, can be used for extended periods of time with proper maintenance. We also own additional equipment used in the operation of our rigs, including large air compressors, trucks and other support equipment.
Our rigs have maximum depth capacities ranging from 9,500 to 40,000 feet.
The following table shows the current distribution of our rigs as of March 7, 2003:
Average
Rated
Active Idle Total Drilling
Region Rigs(1) Rigs(1) Rigs Depths(ft)
------------------ -------- -------- ------- ----------
Anadarko Basin 35 6 41 16,000
West Texas - 2 2 20,000
Arkoma Basin 6 1 7 17,000
East Texas and
Gulf Coast 11 6 17 19,000
Rocky Mountains 3 5 8 22,000
-------------------
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(1) A rig is active when under contract. An idle rig is one that is not under contract but is available and marketed.
At present, we do not have a shortage of drilling rig related equipment. However, at any given time, our ability to use all of our rigs is dependent on a number of conditions, including the availability of qualified labor, drilling supplies and equipment as well as demand.
Types of Drilling Contracts We Work Under. Our drilling contracts are predominantly obtained through competitive bidding and are for a single well. Terms and payment rates vary depending on the nature and duration of the work, the equipment and services supplied and other matters. We 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. Our contracts also contain provisions regarding indemnification against certain types of claims involving injury to persons, property and for acts of pollution. The specific terms of these indemnifications are subject to negotiation on a contract by contract basis.
The type of contract used determines our compensation. The contracts are generally one of three types: daywork; footage; or turnkey. Additional compensation may be acquired for special risks and unusual conditions. Under daywork contracts we provide the drilling rig with the required personnel to the operator who then supervises the drilling of the well. Our compensation depends on a negotiated rate for each day of the rig's use. Footage contracts usually require us to bear some of the drilling costs in addition to providing the rig. We are paid on a negotiated per foot drilled rate on completion of the well. Under turnkey contracts we contract to drill the well for a lump sum amount to a specified depth and provide most of the equipment and services required. We bear the risk of drilling the well to the contract depth and are paid when the contract provisions are completed.
Under turnkey contracts we may incur losses if we underestimate the costs to drill the well or if unforeseen events occur. To date, we have not experienced significant losses in performing turnkey contracts. In 2002, we drilled 15 turnkey wells and turnkey revenue represented 4 percent of our contract drilling revenues as compared to one percent for 2001. We had one turnkey contract in progress at December 31, 2002. Because market conditions as well as the desires of our customers determine the use of turnkey contracts, we can't predict whether the portion of drilling conducted on a turnkey basis will increase or decrease in the future.
Customers. During 2002, 10 customers accounted for approximately 43 percent of our total contract drilling revenues. Approximately 4 percent of our contract drilling revenues came from drilling operations we conducted on oil and natural gas properties of which we were the operator (including properties owned by limited partnerships for which we acted as general partner).
Additional Information. Further information relating to contract drilling operations can be found in Notes 1, 2 and 10 of Notes to Consolidated Financial Statements set forth in Item 8 hereof.
OUR OIL AND NATURAL GAS BUSINESS
General. In 1979 we began to develop our exploration and production operations to diversify our contract drilling revenues. Today, our wholly owned subsidiary, Unit Petroleum Company, conducts our exploration and production activities. Our producing oil and natural gas properties, undeveloped leaseholds and related assets are mainly in Oklahoma, Texas, Louisiana and New Mexico and, to a lesser extent, in Arkansas, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi, Illinois, Michigan, Nebraska and Canada.
When we are the operator of a property, we generally employ our own drilling rigs.
Well and Leasehold Data. The tables below set forth certain information regarding our oil and natural gas exploratory and development drilling operations:
Year Ended December 31,
-------------------------------------------------------
2000 2001 2002
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Wells Drilled:
--------------
Exploratory:
Oil - - 1 .01 - -
Natural gas 2 1.63 8 3.60 2 .50
Dry - - 5 4.46 5 2.00
-------- -------- -------- -------- -------- --------
2 1.63 14 8.07 7 2.50
-------- -------- -------- -------- -------- --------
Development:
Oil 7 1.45 6 1.06 4 1.91
Natural gas 75 28.51 87 33.51 68 33.25
Dry 17 8.56 18 10.80 17 14.21
-------- -------- -------- -------- -------- --------
99 38.52 111 45.37 89 49.37
-------- -------- -------- -------- -------- --------
Total 101 40.15 125 53.44 96 51.87
======== ======== ======== ======== ======== ========
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Year Ended December 31,
----------------------------------------------------------
2000 2001 2002
------------------ ------------------ ------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Oil and Natural
Gas Wells
Producing or
Capable of
Producing:
---------------
Oil - USA 799 278.06 786 279.06 790 273.34
Oil -
Canada - - - - - -
Gas - USA 2,088 431.11 2,188 457.38 2,449 524.45
Gas -
Canada 64 1.60 64 1.60 65 1.63
-------- -------- -------- -------- -------- --------
Total 2,951 710.77 3,038 738.04 3,304 799.42
======== ======== ======== ======== ======== ========
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In December 2002, we acquired 73 producing oil and natural gas wells for $12.5 million. The properties are in Hemphill County, Texas.
On March 7, 2003, we were participating in the drilling of 7 gross (2.1304 net) wells in the United States.
The following table summarizes our oil and natural gas leasehold acreage for each of the years indicated:
Developed Acreage Undeveloped Acreage
--------------------- ---------------------
Gross Net Gross Net
--------- --------- --------- ---------
2000:
-----
USA 564,780 153,507 61,487 39,480
Canada 39,040 976 26,243 13,121
--------- --------- --------- ---------
Total 603,820 154,483 87,730 52,601
========= ========= ========= =========
2001:
-----
USA 567,731 155,890 110,489 69,229
Canada 39,040 976 7,273 3,636
--------- --------- --------- ---------
Total 606,771 156,866 117,762 72,865
========= ========= ========= =========
2002:
-----
USA 585,313 166,397 142,764 79,911
Canada 39,040 976 5,441 3,360
--------- --------- --------- ---------
Total 624,353 167,373 148,205 83,271
========= ========= ========= =========
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Price and Production Data. The following table sets forth our 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 for the years indicated:
Year Ended December 31,
----------------------------------
2000 2001 2002
---------- ---------- ----------
Average Sales Price per Barrel of Oil
Produced:
USA $ 26.95 $ 23.62 $ 21.54
Canada - - -
Average Sales Price per Mcf of Natural
Gas Produced:
USA $ 3.91 $ 4.00 $ 2.87
Canada $ 2.39 $ 4.21 $ 2.11
Oil Production (Mbbls):
USA 488 492 473
Canada - - -
---------- ---------- ----------
Total 488 492 473
========== ========== ==========
Natural Gas Production (MMcf):
USA 19,239 18,819 18,927
Canada 46 45 41
---------- ---------- ----------
Total 19,285 18,864 18,968
========== ========== ==========
Average Production Expense per
Equivalent Mcf:
USA $ 0.74 $ 0.86 $ 0.79
Canada $ 0.42 $ 0.51 $ 0.60
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Oil and Natural Gas Reserves. The following table sets forth our estimated proved developed and undeveloped oil and natural gas reserves for each of the years indicated:
Year Ended December 31,
----------------------------------
2000 2001 2002
---------- ---------- ----------
Oil (Mbbls):
USA 4,183 4,343 4,096
Canada - - -
---------- ---------- ----------
Total 4,183 4,343 4,096
========== ========== ==========
Natural gas (MMcf):
USA 215,196 227,865 244,494
Canada 441 389 317
---------- ---------- ----------
Total 215,637 228,254 244,811
========== ========== ==========
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Our oil production is sold at or near our wells under purchase contracts at prevailing prices in accordance with arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines as well as to independent marketing firms under contracts with terms ranging from one month to a year. The longer term contracts contain provisions for price adjustments. Most of these contracts contain provisions for readjustment of price, termination and other terms customary in the industry.
Additional Information. Further information relating to oil and natural gas operations can be found in Notes 1 and 10 of Notes to Consolidated Financial Statements set forth in Item 8 hereof.
VOLATILE NATURE OF OUR BUSINESS
The prevailing prices for natural gas and oil significantly affect our revenues, operating results, cash flow and future rate of growth. Because natural gas makes up the biggest part of our oil and natural gas reserves as well as the focus of most of our drilling work we do for others, changes in natural gas prices have a disproportionate impact on our financial results than do oil price changes. Historically, oil and natural gas prices have been volatile, and we expect that they will continue to be volatile. Oil and natural gas prices increased substantially in the last half of 1999 and throughout 2000 into the first quarter of 2001. Prices then started to decline sharply and by February 2002, our average price for natural gas was $1.87 per Mcf and our average oil price was $15.58. Commodity prices have once again increased and the average natural gas price we received in December 2002 was $3.95 and the average oil price we received was $25.59. Our average natural gas and oil price for 2002 was $2.87 and $21.54, respectively.
Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
. political conditions in oil producing regions, including the Middle East;
. the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
. the price of foreign imports;
. actions of governmental authorities;
. the domestic and foreign supply of oil and natural gas;
. the level of consumer demand;
. United States storage levels of natural gas;
. weather conditions;
. domestic and foreign government regulations;
. the price, availability and acceptance of alternative fuels; and
. overall economic conditions.
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of oil and natural gas.
Our contract drilling operations are dependent on the level of demand in our operating markets. Both short-term and long-term trends in oil and natural gas prices affect demand. Because oil and natural gas prices are volatile, the level of demand for our services can also be volatile. Decreased oil and natural gas prices during 1998 and early 1999 adversely affected our contract drilling activity by lowering the demand for our rigs and reducing the rates we were able to charge. With the increase in oil and natural gas prices starting in the last half of 1999 and continuing through January 2001, our dayrates and rig utilization increased substantially. Due to the fall in natural gas prices which started in February, 2001, we began to experience less demand for our drilling rigs starting in October, 2001 and the rates received for our rigs also began to fall until they stabilized in the middle of the second quarter of 2002. Natural gas and oil prices once again began to rise during the last half of 2002. As a result, the future extent of the demand for our drilling services is uncertain.
COMPETITION
All of our business' are highly competitive. Competition in onshore contract drilling traditionally involves such factors as price, efficiency, condition of equipment, availability of labor and equipment, reputation and customer relations. Some of our competitors in the onshore contract drilling business are substantially larger than we are and have appreciably greater financial and other resources. The competitive environment within which we operate is uncertain and extremely price oriented.
Our 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 have more experience in the exploration for and production of oil and natural gas than we have.
OIL AND NATURAL GAS PROGRAMS AND CONFLICTS OF INTEREST
Unit Petroleum Company serves as the general partner of five oil and gas limited partnerships and five employee oil and gas limited partnerships. We formed public partnerships in 1979, 1984, 1985 and two 1986. The employee partnerships not rolled up and formed in each year subsequent to 1999 have had an interest not exceeding 5 percent of our interest, in most of the oil and natural gas wells we drill or acquire for our own account during that particular year. The total interest the employees have in our oil and natural gas wells from participating in these partnerships does not exceed one percent. The limited partners in the employee partnerships are either employees or directors of Unit or its subsidiaries. On December 31, 2002, nine of the oldest employee oil and gas limited partnerships were rolled into one of our five remaining oil and gas limited partnerships.
Under the terms of our partnership agreements, the general partner 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 entirely eliminate such conflicts. Additionally, conflicts of interest may arise when we are the operator of an oil and natural gas well and also provide contract drilling services. In such cases, these drilling operations are under contracts containing terms and conditions comparable to those contained in our drilling contracts with non-affiliated operators. We believe we fulfill our responsibility to each contracting party and comply fully with the terms of the agreements which regulate such conflicts.
EMPLOYEES
As of March 7, 2003, we had approximately 1,177 employees in our land contract drilling operations, 62 employees in our oil and natural gas operations and 52 in our general corporate area. None of our employees are members of a union or labor organization nor have our operations ever been interrupted by a strike or work stoppage. We consider relations with our employees to be satisfactory.
OPERATING AND OTHER RISKS
Our drilling operations are subject to the many hazards inherent in the drilling industry, including injury or death to personnel, blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather. Our exploration and production operations are also subject to many of these similar risks. Any of these events could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, our drilling contracts provide for the division of responsibilities between us and our customer, and we seek to obtain indemnification from our drilling customers for some of these risks. To the extent that we are unable to transfer these risks to our drilling customers, we seek protection through insurance. However, our insurance or our indemnification agreements, if any, may not adequately protect us against liability from all of the consequences of the hazards described above. In addition, even if we have insurance coverage, we may still have a degree of exposure based on the amount of our deductible. The occurrence of an event not fully insured or indemnified against, or the failure of a customer to meet its indemnification obligations, could result in substantial losses to us. In addition, we may not be able to obtain insurance to cover any or all of these risks. Even if available, the insurance might not be adequate to cover all of our losses, or we might decide against obtaining that insurance because of high premiums or other costs.
Exploration and development operations involve numerous risks that may result in dry holes, the failure to produce oil and natural gas in commercial quantities and the inability to fully produce discovered reserves. The cost of drilling, completing and operating wells is substantial and uncertain. Our operations may be curtailed, delayed or cancelled as a result of many things beyond our control, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
. adverse weather conditions;
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs or delivery
crews and the delivery of equipment.
A majority of the wells in which we own an interest are operated by other parties. As a result, we have little control over the operations of
such wells which can act to increase our risk. Operators of these wells may act in ways that are not in our best interests.
Our future performance depends upon our ability to find or acquire additional oil and natural gas reserves that are economically recoverable. In general, production from oil and natural gas properties declines as reserves deplete, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in our oil and natural gas production, revenues and cash flow from operations. Historically, we have succeeded in increasing reserves after taking production into account. However, it is possible that we may not be able to continue to replace reserves. Low prices of oil and natural gas may also limit the kinds of reserves that we can economically develop. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
GOVERNMENTAL REGULATIONS
Various state and federal regulations highly affect the production and sale of oil and natural gas. All states in which we conduct activities impose restrictions on the drilling, production, transportation and sale of oil and natural gas.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas. Because "first sales" include typical wellhead sales by producers, all natural gas produced from our natural gas properties is sold at market prices, subject to the terms of any private contracts which may be in effect. The FERC's jurisdiction over natural gas transportation is not affected by the Decontrol Act.
Our sales of natural gas will be affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes are intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of gas transporters. All natural gas marketing by the pipelines is required to divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and the individual pipeline restructuring proceedings of the early to mid-1990s, the interstate pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders
affecting intrastate pipelines that provide similar interstate services, the FERC expanded the impact of open access regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. We do not know what effect the FERC's other activities will have on the access to markets, the fostering of competition and the cost of doing business.
As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counter parties. We believe these changes generally have improved the access to markets for natural gas while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt or what effect subsequent regulations may have on production and marketing of natural gas from our properties.
In the past, Congress has been very active in the area of natural gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation and the promotion of competition in the natural gas industry. Thus, in addition to "first sales" deregulation, Congress also repealed incremental pricing requirements and natural gas use restraints previously applicable. There are other legislative proposals pending in the Federal and State legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, these proposals might have on the production and marketing of natural gas by us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue or what the ultimate effect will be on the production and marketing of natural gas by us cannot be predicted.
Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products will be affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally
grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC will examine the relationship between the annual change in the applicable index and the actual cost changes experienced by the oil pipeline industry. We are not able to predict with certainty what effect, if any, these relatively new federal regulations or the periodic review of the index by the FERC will have on us.
Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production and related operations. Oklahoma, Texas and other states require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and natural gas is produced from our properties. The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects its profitability. Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with those laws.
SAFE HARBOR STATEMENT
This report, including the information we incorporate by reference, information included in, or incorporated by reference from, future filings by us with the SEC, as well as information contained in written material, press releases and oral statements issued by or on behalf of us, contain, or may contain, certain statements that may seem to be "forward-looking statements" within the meaning of federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events or developments which we expect or anticipate will or may occur in the future are forward-looking statements. The words "believes," "intends," "expects," "anticipates," "projects," "estimates," "predicts" and similar expressions to identify forward-looking statements.
These forward-looking statements include, among others, such things as:
. the amount and nature of our future capital expenditures;
. wells to be drilled or reworked;
. prices for oil and gas;
. demand for oil and gas;
. exploitation and exploration prospects;
. estimates of proved oil and gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and gas industry;
. business strategy;
. production of oil and gas reserves;
. expansion and growth of our business and operations; and
. drilling rig utilization and drilling rig rates.
These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:
. the risk factors discussed in this prospectus and in the documents we
incorporate by reference;
. general economic, market or business conditions;
. the nature or lack of business opportunities that we pursue;
. demand for our land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
You should not place undue reliance on any these forward-looking statements. We disclaim any current intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this report to reflect the occurrence of unanticipated events.
In order to provide a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made by us, the following discussion outlines certain factors that in the future could cause our consolidated results for 2003 and beyond to differ materially from those that may be presented in any such forward-looking statement made by or on behalf of us.
Commodity Prices. The prices we receive for our oil and natural gas production have a direct impact on our revenues, profitability and our cash flow as well as our ability to meet our projected financial and operational goals. The prices for natural gas and crude oil are heavily dependent on a number of factors beyond our control, including 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 we receive for such natural 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 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 resulting, at times, in large differences in such prices even on a month-to-month basis. All of these factors, especially when coupled with the fact that much of our product prices are determined on a daily basis, can, and at times do, lead to wide fluctuations in the prices we receive.
Based on our 2002 production, a $.10 per Mcf change in what we receive for our natural gas production would result in a corresponding $147,100 per month ($1,765,000 annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price would have a $36,700 per month ($440,000 annualized) change in our pre-tax operating cash flow. During 2002, substantially all of our natural gas and crude oil volumes were sold at market responsive prices.
In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we sometimes enter into hedging or swap arrangements. Our hedging or swap arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and natural gas prices. These hedging or swap arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices.
Drilling Customer Demand. Demand for our 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 our drilling rigs. These include the availability of funds to such third parties to carry out their drilling operations during any given time period which, in turn, are often subject to downward revision based on decreases in the then current prices of oil and natural gas. Many of our customers are small to mid-size oil and natural gas companies whose drilling budgets tend to be susceptible to the influences of current price fluctuations. Other factors that affect our ability to work our drilling rigs are: the weather which, under adverse circumstances, can delay or even cause the abandonment of a project by an operator; the competition faced by us in securing the award of a drilling contract in a given area; our experience and recognition in a new market area; and the availability of labor to run our drilling rigs.
Uncertainty of Oil and Natural Gas Reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond our control. The reserve data included in this document represent only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend on a number of variable factors, including historical production from the area compared with production from other producing areas, and assumptions concerning:
. the effects of regulations by governmental agencies;
. future oil and natural gas prices;
. future operating costs;
. severance and excise taxes;
. development costs; and
. workover and remedial costs.
Some or all of these assumptions may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery, and estimates of the future net cash flows from reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and those variances may be material.
The information regarding discounted future net cash flows included in this document is not necessarily the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves rely based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also are affected by the following factors:
. the amount and timing of actual production;
. supply and demand for oil and natural gas;
. increases or decreases in consumption; and
. changes in governmental regulations or taxation.
In addition, the 10% discount factor, required by the SEC for use in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our operations or the oil and natural gas industry in general.
We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if we exceed the ceiling, even if prices are depressed for only a short period of time. We may be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. If a write-down is required, it would result in a charge to earnings but would not impact cash flow
from operating activities. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.
We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including acquisitions that would be significantly larger than those consummated to date by us. We cannot assure you that we will successfully consummate any acquisition, that we will be able to acquire producing oil and natural gas properties that contain economically recoverable reserves or that any acquisition will be profitably integrated into our operations.
Debt and Bank Borrowing. We have experienced and expect to continue to experience substantial working capital needs due to the growth in our drilling operations and our active exploration and development programs. Historically, we have funded our working capital needs through a combination of internally generated cash flow, equity financing and borrowings under our bank loan agreement. We currently have, and will continue to have, a certain amount of indebtedness. At December 31, 2002, our long-term debt outstanding, all carried under our bank loan agreement, was $30.5 million. As of December 31, 2002, we had a total loan commitment of $100 million, but we elected to limit the amount available for borrowing under our bank loan agreement to $40 million in order to reduce our financing costs.
Our level of debt, the cash flow needed to satisfy our indebtedness and the covenants governing our indebtedness could:
. limit funds otherwise available for financing our capital expenditures,
our drilling program or other activities or cause us to curtail these
activities;
. limit our flexibility in planning for or reacting to changes in our
business;
. place us at a competitive disadvantage to some of our competitors that
are less leveraged than us;
. make us more vulnerable during periods of low oil and natural gas
prices or in the event of a downturn in our business; and
. prevent us from obtaining additional financing on acceptable terms or
limit amounts available under our existing or any future credit
facilities.
Our ability to meet our debt service obligations will depend on our future performance. If the requirements of our indebtedness are not satisfied, a default would be deemed to occur and our lenders would be entitled to accelerate the payment of the outstanding indebtedness. If this occurs, we would not have sufficient funds available nor would we be able to obtain the financing required to meet our obligations.
The amount of our existing debt as well as its future debt is, to a large extent, a function of the costs associated with the projects we undertake at any given time and the cash flow we receive. Generally, our normal operating costs are those associated with the drilling of oil and natural gas wells, the acquisition of producing properties, and the costs
associated with the maintenance or expansion of our drilling rig fleet. To some extent, these costs, particularly the first two items, are discretionary and we maintain 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 us to incur increased debt above that which we had expected or forecasted. Likewise, for many of the reasons mentioned above, our cash flow may not be sufficient to cover our current cash requirements which would then require us to increase our debt either through bank borrowings or otherwise.
We are a party to various legal proceedings arising in the ordinary course of our business, none of which, in our opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash flows.
No matters were submitted to our security holders during the fourth quarter of 2002.
PART II
Our common stock trades on the New York Stock Exchange under the symbol "UNT." The following table identifies the high and low sales prices per share of our common stock for the periods indicated:
2001 2002
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
First $ 21.3750 $ 16.3000 $ 18.6000 $ 10.2400
Second $ 23.0000 $ 14.5000 $ 20.2500 $ 16.0100
Third $ 15.8000 $ 7.4100 $ 19.2500 $ 13.6500
Fourth $ 14.2400 $ 8.2900 $ 20.4400 $ 16.7100
|
On March 7, 2003 there were 1,857 record holders of our common stock.
We have never paid cash dividends on our common stock and currently intend to continue our policy of retaining earnings from our operations. Our loan agreement prohibits us from declaring and paying dividends (other than stock dividends) in any fiscal year in an amount greater than 25 percent of our preceding year's consolidated net income and then only if our working capital provided from operations for the previous year was equal to or greater than 175 percent of the current maturities of our long-term debt at the end of the previous year.
Item 6. Selected Financial Data
------- -----------------------
Year Ended December 31,
----------------------------------------------------------
1998 (1) 1999 (1) 2000 2001 2002
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 97,274 $ 102,352 $ 201,264 $ 259,179 $ 187,636
========== ========== ========== ========== ==========
Net Income $ 1,428 $ 3,048 $ 34,344 $ 62,766 $ 18,244
========== ========== ========== ========== ==========
Earnings Per
Common Share:
Basic $ 0.05 $ 0.10 $ 0.96 $ 1.75 $ 0.47
========== ========== ========== ========== ==========
Diluted $ 0.05 $ 0.10 $ 0.95 $ 1.73 $ 0.47
========== ========== ========== ========== ==========
Total Assets $ 233,096 $ 295,567 $ 346,288 $ 417,253 $ 578,163
========== ========== ========== ========== ==========
Long-Term Debt $ 75,048 $ 67,239 $ 54,000 $ 31,000 $ 30,500
========== ========== ========== ========== ==========
Other Long-Term
Liabilities $ 2,368 $ 2,325 $ 3,597 $ 4,110 $ 5,439
========== ========== ========== ========== ==========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
========== ========== ========== ========== ==========
----------------------
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(1) Restated for the merger with Questa Oil and Gas Co.
See Management's Discussion of Financial Condition and Results of Operations for a review of 2000, 2001 and 2002 activity.
Summary. Our financial condition and liquidity depends on the cash flow from our two principal subsidiaries and borrowings under our bank loan agreement. Our cash flow is influenced mainly by the prices we receive for our natural gas production, the demand for and the dayrates we receive for our drilling rigs and, to a lesser extent, the prices we receive for our oil production. At December 31, 2002, we had cash totaling $497,000 and we had borrowed $30.5 million of the $40.0 million we have elected to have available under our loan agreement.
The following is a summary of certain financial information on December 31, 2002 and for the year ended December 31, 2002:
Working Capital . . . . . . . $ 16,867,000 Net Income. . . . . . . . . . $ 18,244,000 Net Cash Provided by Operating Activities. . . . $ 70,547,000 Long-Term Debt. . . . . . . . $ 30,500,000 Shareholders' Equity. . . . . $ 421,372,000 Ratio of Long-Term Debt to Total Capitalization. . . . 7% |
The following table summarizes certain operating information for the years ended December 31, 2001 and 2002:
Percent
2001 2002 Change
------------ ------------ --------
Oil Production (Bbls) . . . 492,000 473,000 (4%)
Natural Gas Production (Mcf) 18,864,000 18,968,000 1%
Average Oil Price Received. $ 23.62 $ 21.54 (9%)
Average Natural Gas Price
Received. . . . . . . . . $ 4.00 $ 2.87 (28%)
Average Number of Our
Drilling Rigs in Use
During the Period . . . . 46.3 39.1 (16%)
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Our Bank Loan Agreement. On July 24, 2001, we signed a $100 million bank loan agreement. At our election, the amount currently available for us to borrow is $40 million. Although the current value of our assets would have allowed us to have access to the full $100 million, we elected to set the loan commitment at $40 million to reduce our financing costs since we are charged a facility fee of .375 of 1 percent on the amount available but not borrowed. At December 31, 2002, we had borrowed $30.5 million through the bank loan.
Each year, on April 1 and October 1, our banks re-determine the loan value of our assets. This value is mainly based on an amount equal to a percentage of the discounted future value of our oil and natural gas reserves, as determined by the banks. In addition, an amount representing a part of the value of our drilling rig fleet, limited to $20 million, is added to the loan value. Our loan agreement provides for a revolving credit facility which ends on May 1, 2005 followed by a three-year term loan. Borrowing under our loan agreement totaled $32.4 million on February 19, 2003.
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 1.00 to 1.50 percent depending on the level of debt as a percentage of the total loan value. After May 1, 2005, borrowings under the loan agreement bear interest at the Prime Rate or the Libor Rate plus 1.25 to 1.75 percent depending on the level of debt as a percentage of the total loan value. In addition, the loan agreement allows us to select between the date of the agreement and 3 days before the start of the term loan, a fixed rate for the amount outstanding under the credit facility. Our ability to select the fixed rate option is subject to several conditions, all of which are set out in the loan agreement.
The interest rate on our bank debt was 2.47 percent at December 31, 2002 and February 19, 2003. At our election, any portion of our outstanding bank debt may be fixed at the Libor Rate, as adjusted depending on the level of our debt as a percentage of the amount available for us to borrow. The Libor Rate may be fixed for periods of up to 30, 60, 90 or 180 days with the balance of our bank debt being subject to the Prime Rate. During any Libor Rate funding period, we may not pay any part of the outstanding principal balance which is subject to the Libor Rate. Borrowings subject to the Libor Rate were $30.5 million at December 31, 2002 and $31.0 million at February 19, 2003.
The loan agreement also requires us to maintain:
. consolidated net worth of at least $125 million;
. a current ratio of not less than 1 to 1;
. a ratio of long-term debt, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.2 to 1;
. a ratio of total liabilities, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.65 to 1; and
. working capital provided by operations, as defined in the loan
agreement, cannot be less than $40 million in any year.
We are restricted from paying dividends (other than stock dividends) during any fiscal year in excess of 25 percent of our consolidated net income from the preceding fiscal year. Additionally, we can pay dividends if our working capital provided from our operations during the preceding year is equal to or greater than 175 percent of current maturities of long-term debt at the end of the preceding year. We also cannot incur additional debt except in certain limited exceptions. The creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any of our property is prohibited unless it is in favor of our banks.
Hedging. Periodically we hedge the prices we will receive for a portion of our future natural gas and oil production. We do so in an attempt to reduce the impact and uncertainty that price variations have on our cash flow. We entered into a collar contract covering approximately 25 percent of our daily oil production from November 1, 2000 through February 28, 2001. The collar had a floor of $26.00 per barrel and a ceiling of $33.00 per barrel and we received $0.86 per barrel for entering into the transaction. During the first quarter of 2001, our oil hedging transaction yielded an increase in our oil revenues of $17,200.
During the second quarter of 2001, we entered into a natural gas collar contract for approximately 36 percent of our June and July 2001 production, at a floor price of $4.50 and a ceiling price of $5.95. During the third quarter of 2001, we entered into two natural gas collar contracts for approximately 38 percent of our September thru November 2001 natural gas production. Both contracts had a floor price of $2.50. One contract had a ceiling of $3.68 and the other contract had a ceiling of $4.25. During the year of 2001, the collar contracts increased natural gas revenues by $2,030,000.
On April 30, 2002, we entered into a collar contract covering approximately 19 percent of our natural gas production for the periods of April 1, 2002 thru October 31, 2002. The collar had a floor of $3.00 and a ceiling of $3.98. During the year of 2002, our natural gas hedging transactions increased natural gas revenues by $40,300. We did not have any hedging transactions outstanding at December 31, 2002.
During the first quarter of 2003, we entered into two collar contracts covering approximately 40 percent of our natural gas production for the periods of April 1, 2003 thru September 30, 2003. One collar has a floor of $4.00 and a ceiling of $5.75 and the other collar has a floor of $4.50 and a ceiling of $6.02. We also entered into two collar contracts covering approximately 25 percent of our oil production for the periods of May 1, 2003 thru December 31, 2003. One collar has a floor of $25.00 and a ceiling of $32.20 and the other collar has a floor of $26.00 and a ceiling of $31.40.
Self-Insurance. We are self-insured for certain losses relating to workers' compensation, general liability, property damage and employee medical benefits. With the recent tightening in the insurance markets our self-insurance levels have significantly increased. During the August 1, 2002 renewal of most of our insurance policies, our exposure (i.e. our deductible or retention) per occurrence we elected to incur ranged from $200,000 for general liability to $1 million for rig physical damage. We have purchased stop-loss coverage in order to limit, to the extent feasible, our per occurrence and aggregate exposure to certain claims. There is no assurance that such coverage will adequately protect us against liability from all potential consequences.
Impact of Prices for Our Oil and Natural Gas. Natural gas comprises 91 percent of our total oil and natural gas reserves. Any significant change in natural gas prices has a material affect on our revenues, cash flow and the value of our oil and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances and by world wide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. All of these factors are beyond our control and we can not predict nor measure their future influence on the prices we will receive.
Based on our production in 2002, a $.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $147,100 per month ($1,765,000 annualized) change in our pre-tax operating cash flow. Our 2002 average natural gas price was $2.87 compared to an average natural gas price of $4.00 received 2001. A $1.00 per barrel change in our oil price would have a $36,700 per month ($440,000 annualized) change in our pre-tax operating cash flow. Our 2002 average oil price was $21.54 compared with an average oil price of $23.62 received in 2001.
Because natural gas prices have such a significant affect on the value of our oil and natural gas reserves, declines in these prices can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the semi-annual determination of the amount available for us to borrow under our bank loan agreement since that determination is based mainly on the value of our oil and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects.
We sell most of our natural gas production to third parties under month-to-month contracts. Several of these buyers have experienced financial complications resulting from the recent investigations into the energy trading industry. The long-term implications to the energy trading business, as well as to oil and natural gas producers, because of these investigations remains, to be determined. Presently we believe that our buyers will be able to perform their commitments to us. However, we continue to evaluate the information available to us about these buyers in an effort to reduce any possible future adverse impact to us.
Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital expenditures are discretionary and directed toward future growth. Our decision to increase our oil and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential and opportunities to obtain financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when to incur such costs. We drilled 96 wells (51.87 net wells) in 2002 compared to 125 wells (53.44 net wells) in 2001. In December 2002, we acquired 73 producing oil and natural gas wells for $12.5 million. Our total capital expenditures for oil and natural gas exploration and acquisitions in 2002 totaled $58.8 million. Based on current prices, we plan to drill an estimated 140 to 150 wells in 2002 and total capital expenditures for oil and natural gas exploration and acquisitions is planned to be around $65 million.
Contract Drilling. Our drilling work is subject to many factors that influence the number of rigs we have working as well as the costs and revenues associated with such work. These factors include competition from other drilling contractors, the prevailing prices for natural gas and oil, availability and cost of labor to run our rigs and our ability to supply the equipment needed. We have not encountered major difficulty in hiring and keeping rig crews, but such shortages have occurred periodically in the past. If demand for drilling rigs increases rapidly in the future, shortages of experienced personnel may limit our ability to increase the number of rigs we could operate.
Most of our contract drilling fleet is targeted to the drilling of natural gas wells, so changes in natural gas prices influence the demand for our drilling rigs and the prices we can charge for our contract drilling services. Low oil and natural gas prices, during most of the 1980's and 1990's, reduced demand for domestic land contract drilling rigs. In the last half of 1999 and throughout 2000, as oil and natural gas prices increased, we experienced a big increase in demand for our rigs. Demand continued to increase until the end of the third quarter of 2001 and reached a high when 52 of our rigs were working in July 2001. Because of declining natural gas prices throughout 2001, demand for our rigs dropped significantly in the fourth quarter of 2001 and stabilized with between 30 and 35 rigs operating in the first half on 2002. Natural gas and oil prices once again began to rise during the last half of 2002. With the August acquisition of 20 rigs described below, the average use of our rigs in 2002 was 39.1 rigs (63 percent) compared with 46.3 rigs (90 percent) for 2001.
As demand for our rigs increased during 2001 so did the dayrates we received. Our average dayrate reached $11,142 by September of 2001. However, as demand began to decrease, so did our rates. Our average dayrate in 2002 was $7,716 compared to $10,044 for 2001. Based on the average utilization of our rigs in 2002, a $100 per day change in dayrates has a $3,900 per day ($1,424,000 annualized) change in our pre-tax operating cash flow. Utilization and dayrates for our drilling rigs will depend mainly on the price of natural gas.
Our contract drilling subsidiary provides drilling services for our exploration and production subsidiary. The contracts for these services are issued under the same conditions and rates as the contracts we have entered into with unrelated third parties. Per regulations provided by the Securities and Exchange Commission, the profit received by our contract drilling segment of $2,259,000 and $841,000 during 2001 and 2002, respectively, was used to reduce the carrying value of our oil and natural gas properties rather than being included in our profits in current operations.
Drilling Acquisitions and Capital Expenditures. On August 15, 2002, we completed the acquisition of CREC Rig Equipment Company and CDC Drilling Company, which included twenty drilling rigs, spare drilling equipment and vehicles, for 7.22 million shares of our common stock and $4.5 million in cash. Total consideration for the acquisition was valued at $127 million of which $7.7 million went to goodwill and $2.2 million went to deferred tax assets. All of the rigs are operational and range in horsepower from 650 to 2,000 with 15 having a horsepower rating of 1,000 or more. Depth
capacities range from 12,000 to 25,000 feet and twelve of the rigs are SCR electric. These agreements also give us the exclusive first option to purchase any additional rigs constructed by one of the sellers within the next three years. The addition of these twenty rigs brought our fleet to 75. For our contract drilling operations during 2002, we incurred $139.3 million in capital expenditures, which included $7.7 million for goodwill and $2.2 million for deferred tax assets. For the year 2003, we anticipate capital expenditures of approximately $25 million for our contract drilling operations.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. As of December 31, 2002, we rolled up nine of our employee partnerships into a consolidated partnership. After the rollup, we are the general partner for ten oil and natural gas partnerships which were formed privately and publicly. The partnership's revenues and costs are shared under formulas prescribed in each limited partnership agreement. The partnerships repay us for contract drilling, well supervision and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party's share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party's behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party's level of activity and are considered by management to be reasonable. During 2000, 2001 and 2002, the total paid to us for all of these fees was $966,000, $1,107,000 and $929,000, respectively. We expect the fees to be about the same in 2003. Our proportionate share of assets, liabilities and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements.
We own a 40 percent equity interest in a natural gas gathering and processing company. Our investment, including our share of the equity in the earnings of this company, totaled $1.8 million at December 31, 2002 and is reported in other assets in our accompanying balance sheet. From time to time we may guarantee the debt of this company. However, as of December 31, 2002 and February 19, 2003, we were not guaranteeing any of the debt of this company.
Outlook. Both of our operating segments are extremely dependent on natural gas prices. These prices affect not only our production revenues, but also the future demand and rates for our contract drilling services. On February 19, 2003, the Nymex Henry Hub average contract settle price for the next twelve months was $5.59. We anticipate that if natural gas prices continue at that level, there will be an increase in demand for our rigs and an upward movement on the rates we receive for our contract drilling services. There is a certain degree of uncertainty as to whether these prices can be sustained. This uncertainty has, in turn, made it difficult to measure the future use of our drilling rigs. We would anticipate that if current natural gas prices are, in fact, maintained we will experience an upward movement in demand for our rigs.
Contractual Commitments. We have the following contractual obligations at December 31, 2002:
Payments Due by Period
-------------------------------------------------
Less
Contractual Than 1 2-3 4-5 After 5
Obligations Total Year Years Years Years
------------- --------- ------- -------- --------- --------
(In thousands)
Bank Debt(1) $ 30,500 $ - $ 5,931 $ 20,333 $ 4,236
Hickman
Note(2) 1,000 1,000 - - -
Retirement
Agreement(3) 1,412 170 600 600 42
Operating
Leases(4) 1,666 663 839 164 -
--------- ------- -------- --------- --------
Total
Contractual
Obligations $ 34,578 $1,833 $ 7,370 $ 21,097 $ 4,278
========= ======= ======== ========= ========
-------------------
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(1) See Previous Discussion in Management Discussion and Analysis
regarding bank debt.
(2) On November 20, 1997, we acquired Hickman Drilling Company
pursuant to an agreement and plan of merger entered into by
and between us, Hickman Drilling Company and all of the
holders of the outstanding capital stock of Hickman Drilling
Company. As part of this acquisition, the former shareholders
of Hickman held, as of December 31, 2002, promissory notes in
the aggregate outstanding principal amount of $1.0 million
(See Note 4 of our Consolidated Financial Statements). These
notes were paid in full in January 2003. The notes bore
interest at the Chase Prime Rate, which at December 31, 2002
was 4.25 percent.
(3) In the second quarter of 2001, we recorded $1.3 million in
additional employee benefit expenses for the present value of
a separation agreement made in connection with the retirement
of King Kirchner from his position as Chief Executive Officer.
The liability associated with this expense, including accrued
interest, will be paid in monthly payments of $25,000 starting
in July 2003 and continuing through June 2009 (See Note 4 of
our Consolidated Financial Statements).
(4) We lease office space in Tulsa, Houston and Woodward under the
terms of operating leases expiring through January 31, 2007
(See Note 9 of our Consolidated Financial Statements).
At December 31, 2002, we also have the following commitments and contingencies that could create, increase or accelerate our liabilities:
Amount of Commitment Expiration
Per Period
-------------------------------------
Total
Amount
Committed Less
Other Or Than 1 2-3 4-5 After 5
Commitments Accrued Year Years Years Years
--------------- --------- -------- -------- -------- --------
(In thousands)
Deferred
Compensation
Agreement(1) $ 1,391 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,081 $ 295 Unknown Unknown Unknown
Gas Balancing
Liability(3) $ 1,020 Unknown Unknown Unknown Unknown
Repurchase
Obliga-
tions(4) Unknown Unknown Unknown Unknown Unknown
|
(1) We provide a salary deferral plan which allows participants to
defer the recognition of salary for income tax purposes until
actual distribution of benefits, which occurs at either
termination of employment, death or certain defined
unforeseeable emergency hardships. We recognize payroll
expense and record a liability, included in other long-term
liabilities in our Consolidated Balance Sheet, at the time of
deferral (See Note 6 of our Consolidated Financial
Statements).
(2) Effective January 1, 1997, we adopted a separation benefit
plan ("Separation Plan"). The Separation Plan allows eligible
employees whose employment with us is involuntarily terminated
or, in the case of an employee who has completed 20 years of
service, voluntarily or involuntarily terminated, to receive
benefits equivalent to 4 weeks salary for every whole year of
service completed with Unit up to a maximum of 104 weeks. To
receive payments the recipient must waive any claims against
us in exchange for receiving the separation benefits. On
October 28, 1997, we adopted a Separation Benefit Plan for
Senior Management ("Senior Plan"). The Senior Plan provides
certain officers and key executives of Unit with benefits
generally equivalent to the Separation Plan. The Compensation
Committee of the Board of Directors has absolute discretion in
the selection of the individuals covered in this plan (See
Note 6 of our Consolidated Financial Statements).
(3) In December 2002, we recorded a liability on certain
properties where we believe there is insufficient reserves
available to allow the under-produced owners to recover their
under-production from future production volumes.
(4) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 2003, with a subsidiary of ours serving as General Partner. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of each year. These partnership agreements require, upon the election of a limited partner, that we repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20 percent of the units outstanding. We made repurchases of $14,000 and $1,000 in 2000 and 2002, respectively, for such limited partners' interests. No repurchases were made in 2001 (See Note 9 of our Consolidated Financial Statements).
Critical Accounting Policies. We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized. At the end of each quarter, the net capitalized costs of our oil and natural gas properties is limited to the lower of unamortized cost or a ceiling. The ceiling is defined as the sum of the present value (10 percent discount rate) of estimated future net revenues from proved reserves, based on period-end oil and natural gas prices, plus the lower of cost or estimated fair value of unproved properties not included in the costs being amortized, less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are subject to a write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts stockholders' equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down cannot be reversed even if prices subsequently recover.
The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed or if we have large downward revisions in our estimated proved reserves. Application of these rules during periods of relatively low oil or natural gas prices, even if temporary, increases the chance of a ceiling test write-down. Based on oil and natural gas prices on December 31, 2002 ($4.42 per Mcf for natural gas and $29.70 per barrel for oil), the unamortized cost of our domestic oil and natural gas properties did not exceed the ceiling of our proved oil and natural gas reserves. Natural gas prices remain erratic and any significant declines below quarter-end prices used in the reserve evaluation could result in a ceiling test write-down in following quarterly reporting periods.
The value of our oil and natural gas reserves is used to determine the loan value under our bank loan agreement. This value is affected by both price changes and the measurement of reserve volumes. Oil and natural gas reserves cannot be measured exactly. Our estimate of oil and natural gas reserves require extensive judgments of our reservoir engineering data and are less precise than other estimates made in connection with financial disclosures. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves.
We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the natural gas balancing position on wells in which we have an imbalance are not material.
Drilling equipment, transportation equipment and other property and equipment are carried at cost. Renewals and betterments are capitalized while repairs and maintenance are expensed. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances suggest the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of property and equipment.
We recognize revenues generated for "daywork" drilling contracts as the services are performed, which is similar to the percentage of completion method. Under "footage" and "turnkey" contracts, we bear the risk of completion of the well, so revenues and expenses are recognized using the completed contract method. The entire amount of a loss, if any, is recorded when the loss can be reasonably determined, however, any profit is recorded only at the time the well is finished. The costs of uncompleted drilling contracts include expenses incurred to date on "footage" or "turnkey" contracts, which are still in process at the end of the period, and are included in other current assets.
In the 18 years prior to the last half of 1999, the effects of inflation on our operations was minimal due to low inflation rates and moderate demand for contract drilling services. However, starting in the last half of 1999 and throughout 2000 and the first three quarters of 2001, as drilling rig dayrates and utilization increased, the impact of inflation increased as the availability of used equipment and third party services decreased. Due to industry-wide demand for qualified labor, contract
drilling labor costs increased substantially in the summer of 2000 and once again in the summer of 2001 and when rig dayrates declined in 2002 the labor rates did not come back down to the levels incurred prior to the increases. How inflation will affect us in the future will depend on additional increases, if any, realized in our drilling rig rates and the prices we receive for our oil and natural gas. If industry activity recovers and returns to levels achieved in early 2001, shortages in support equipment such as drill pipe, third party services and qualified labor could occur resulting in additional corresponding increases in our material and labor costs. These conditions may limit our ability to realize improvements in operating profits.
In July 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("FAS 143"). FAS 143 is effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for us) and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells) in the period in which the liability is incurred (at the time the wells are drilled). In the first quarter of 2003, the effect of the implementation of FAS 143 (unaudited) is expected to increase liabilities including deferred taxes by $11.7 million, increase the net book value of our oil and natural gas properties by $13.0 million and we anticipate adjustment to increase net income for the accumulated effect of a change in accounting principle of $1.3 million.
In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13, and Technical Corrections" ("FAS 145"). FAS 145 is effective for fiscal years beginning after May 15, 2002. This statement eliminates an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. We do not expect the adoption of FAS 145 to have a material effect on our financial position, results of operations or cashflows.
In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, "Accounting for Cost Associated with Exit or Disposal Activities" ("FAS 146"). FAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. FAS 146 nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)." We do not expect the adoption of FAS 146 to have a material effect on our financial position, results of operations or cashflow.
On December 31, 2002, the FASB issued Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FAS 123" ("FAS 148"). FAS 148 provides additional transition guidance for companies that elect to voluntarily adopt the accounting provisions of FAS 123, "Accounting For Stock-Based Compensation." FAS 148 does not change the provisions of FAS 123 that permit entities to continue to apply the intrinsic value method of APB 25, "Accounting for Stock Issued to Employees" ("APB 25"). Since we apply APB 25, our accounting for stock-based compensation will not change as a result of FAS 148. FAS 148 does require certain new disclosures in both annual and interim financial statements. The required annual disclosures were effective immediately for us and have been included in Note 1 of our financial statements. The new interim disclosure provisions will be effective for us in the first quarter of 2003.
On November 25, 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, an interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34" ("FIN 45"). FIN 45 clarifies the requirements of FASB Statement No. 5, Accounting for Contingencies (FAS 5), relating to the guarantor's accounting for, and disclosure of, the issuance of certain types of guarantees. For guarantees that fall within the scope of FIN 45, the Interpretation requires that guarantors recognize a liability equal to the fair value of the guarantee upon its issuance. The Interpretation's provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The guarantor's previous accounting for guarantees that were issued before the date of FIN 45's initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the Interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. We have guaranteed liabilities in the past which would fall under the terms of FIN 45, but we do not have any such guarantees at December 31, 2002.
On January 17, 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights ("variable interest entities" or "VIEs") and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. We do not expect the adoption of this standard to have a material impact on our financial position or results of operations.
Percent
2001 2002 Change
--------------- --------------- ---------
Total Revenue $ 259,179,000 $ 187,636,000 (28%)
Net Income $ 62,766,000 $ 18,244,000 (71%)
Oil and Natural Gas:
Revenue $ 90,237,000 $ 67,959,000 (25%)
Average natural gas price (Mcf) $ 4.00 $ 2.87 (28%)
Average oil price (Bbl) $ 23.62 $ 21.54 (9%)
Natural gas production (Mcf) 18,864,000 18,968,000 1%
Oil production (Bbl) 492,000 473,000 (4%)
Operating profit
(revenue less operating
costs) $ 68,041,000 $ 47,164,000 (31%)
Operating margin 75% 69%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.91 $ 1.04 14%
Depreciation, depletion and
amortization (includes
$2,083,000 and $346,000
write off of interest
in Shenandoah in 2001
and 2002) $ 22,116,000 $ 23,338,000 6%
Drilling:
Revenue $ 167,042,000 $ 118,173,000 (29%)
Percentage of revenue from
daywork contracts 99% 91%
Average number of rigs in use 46.3 39.1 (16%)
Average dayrate on daywork
contracts $ 10,044 $ 7,716 (23%)
Operating profit
(revenue less operating
costs) $ 76,036,000 $ 26,835,000 (65%)
Operating margin 46% 23%
Depreciation $ 13,888,000 $ 14,684,000 6%
General and Administrative Expense $ 8,476,000 $ 8,712,000 3%
Interest Expense $ 2,818,000 $ 973,000 (65%)
Average Interest Rate 5.7% 3.0% (47%)
Average Long-Term Debt Outstanding $ 44,995,000 $ 24,771,000 (45%)
|
Oil and natural gas revenues, operating profits and operating profit margins were all negatively affected by lower prices received for both oil and natural gas during 2002 compared to 2001. Production in equivalent Mcf was almost the same in 2002 as in 2001. Total operating cost decreased due to lower gross production taxes resulting from lower revenues. Total depreciation, depletion and amortization ("DD&A") on our oil and natural gas properties increased due to the increase in the DD&A rate in 2002, which resulted from higher development drilling cost per equivalent Mcf. The increase would have been larger, but included in 2001 DD&A was the write down of our investment in Shenandoah Resources LTD. of $2.1 million. The remaining balance of our investment in Shenandoah Resources LTD. of $346,000 was written off in the third quarter of 2002.
Reduced natural gas prices, especially in the fourth quarter of 2001 and the first quarter of 2002, caused decreases in operator demand for contract drilling rigs within our working area and resulted in lower rig use and dayrates for our rigs. As a result, operating margins declined between 2002 and 2001. Approximately 9 percent of our total drilling revenues in 2002 came from footage and turnkey contracts, which had profit margins lower than our daywork contracts. One percent of our total drilling revenues came from footage and turnkey contracts in 2001. Contract drilling depreciation increased due to the acquisition of 20 rigs in August of 2002. The increase was partially offset by lower rig use.
General and administrative expense was higher in 2002 due to increases in labor cost, insurance expense and outside contract services. In the second quarter of 2001, we recorded $1.3 million in additional employee benefit expenses for the present value of a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. The liability associated with this expense plus accrued interest will be paid in $25,000 monthly payments starting in July 2003 and continuing through June 2009. Our total interest expense is lower due to lower interest rates along with a substantial reduction in our long-term debt.
Provided below is a comparison of selected operating and financial data for the year of 2001 versus the year of 2000:
Percent
2000 2001 Change
--------------- --------------- ---------
Total Revenue $ 201,264,000 $ 259,179,000 29%
Net Income $ 34,344,000 $ 62,766,000 83%
Oil and Natural Gas:
Revenue $ 92,016,000 $ 90,237,000 (2%)
Average natural gas price (Mcf) $ 3.91 $ 4.00 2%
Average oil price (Bbl) $ 26.95 $ 23.62 (12%)
Natural gas production (Mcf) 19,285,000 18,864,000 (2%)
Oil production (Bbl) 488,000 492,000 1%
Operating profit
(revenue less operating
costs) $ 72,262,000 $ 68,041,000 (6%)
Operating margin 79% 75%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.82 $ 0.91 11%
Depreciation, depletion and
amortization (includes
$2,083,000 write off
of interest in
Shenandoah in 2001) $ 18,492,000 $ 22,116,000 20%
Drilling:
Revenue $ 108,075,000 $ 167,042,000 55%
Percentage of revenue from
daywork contracts 85% 99%
Average number of rigs in use 39.8 46.3 16%
Average dayrate on daywork
contracts $ 6,957 $ 10,044 44%
Operating profit
(revenue less operating
costs) $ 24,024,000 $ 76,036,000 217%
Operating margin 22% 46%
Depreciation $ 11,999,000 $ 13,888,000 16%
General and Administrative Expense $ 6,560,000 $ 8,476,000 29%
Interest Expense $ 5,136,000 $ 2,818,000 (45%)
Average Interest Rate 7.9% 5.7% (28%)
Average Long-Term Debt Outstanding $ 62,302,000 $ 44,995,000 (28%)
|
Total revenues and net income were higher in 2001 versus 2000 due to increases in the use of our drilling rigs, as well as, the dayrates we received for the use of the drilling rigs.
Oil and natural gas revenues, operating profits and operating profit margins were all negatively affected by lower natural gas production and drops in the oil price we received between 2001 and 2000. Total operating cost increased due to the addition of new wells through development drilling and increases in ad valorem taxes, workover expenses and compression fees. Operating margins also decreased due to declines in production on older wells without corresponding declines in operating expenses. Depreciation, depletion and amortization ("DD&A") increased in 2001 due to a write down of our investment in Shenandoah Resources LTD. by $2.1 million and an increase in our DD&A rate per equivalent Mcf resulting from higher development drilling cost per equivalent Mcf.
Higher natural gas prices in the last quarter of 2000 and the first quarter of 2001 increased the demand for our drilling rigs which in turn pushed contract drilling dayrates higher. As a result, drilling revenues and operating margins increased between 2001 and 2000. Our contract drilling operating cost per rig per day decreased $400 in 2001 when compared with 2000 as increased usage reduced the impact of our fixed indirect drilling expenses. Total contract drilling operating costs were up primarily due to increased utilization and increases in field labor cost.
General and administrative expense was higher in 2001 because we recorded $1.3 million in additional employee benefit expenses for the present value of a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. Our total interest expense is lower due to lower interest rates along with a reduction in our long-term debt.
Our operations are exposed to market risks primarily as a result of changes in commodity prices and interest rates.
Commodity Price Risk. Our major market risk exposure is in the price we receive for our oil and natural gas production. The price we receive is primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our natural gas production. Historically, prices we received for our oil and natural gas production fluctuated and such fluctuation is expected to continue. The price of natural gas also effects the demand for our rigs and the amount we can charge for the use of the rigs. Based on our 2002 production, a $.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $147,100 per month ($1,765,000 annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our oil price would have a $36,700 per month ($440,000 annualized) change in our pre-tax operating cash flow.
In an effort to try and reduce the impact of price fluctuations, over the past several years we periodically have used hedging strategies to hedge the price we will receive for a portion of our future oil and natural gas production. A detailed explanation of those transactions has been included under hedging in the financial condition portion of management's discussion and analysis of financial condition and results of operations included above.
Interest Rate Risk. Our interest rate exposure relates to our long-term debt, all of which bears interest at variable rates based on the prime rate or the London Interbank Offered Rate ("Libor Rate"). At our election, borrowings under our revolving credit and term loan may be fixed at the Libor Rate for periods up to 180 days. Historically, we have not utilized any financial instruments, such as interest rate swaps, to manage our exposure to increases in interest rates. However, we may use such financial instruments in the future should our assessment of future interest rates warrant such use. Based on our average outstanding long-term debt in 2002, a one percent change in the floating rate would change our annual pre-tax cash flow by approximately $248,000.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
-----------------------
2001 2002
---------- ----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 391 $ 497
Accounts receivable (less allowance for
doubtful accounts of $604 and $1,203) 33,886 33,912
Materials and supplies 5,358 8,794
Income tax receivable 3,198 3,602
Prepaid expenses and other 3,761 4,594
---------- ----------
Total current assets 46,594 51,399
---------- ----------
Property and Equipment:
Drilling equipment 244,698 369,777
Oil and natural gas properties, on
the full cost method 406,491 465,250
Transportation equipment 6,441 6,856
Other 9,231 9,906
---------- ----------
666,861 851,789
Less accumulated depreciation, depletion,
amortization and impairment 304,643 341,031
---------- ----------
Net property and equipment 362,218 510,758
---------- ----------
Other Assets 8,441 16,006
---------- ----------
Total Assets $ 417,253 $ 578,163
========== ==========
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
-----------------------
2001 2002
---------- ----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
-----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities $ 1,893 $ 1,465
Accounts payable 16,292 21,119
Accrued liabilities 10,616 11,921
Contract advances 240 27
---------- ----------
Total current liabilities 29,041 34,532
---------- ----------
Long-Term Debt 31,000 30,500
---------- ----------
Other Long-Term Liabilities (Note 4) 4,110 5,439
---------- ----------
Deferred Income Taxes 73,940 86,320
---------- ----------
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,
75,000,000 shares authorized,
36,006,267 and 43,339,400
shares issued, respectively 7,201 8,668
Capital in excess of par value 141,977 264,180
Retained earnings 130,280 148,524
Treasury stock at cost (30,000 shares) (296) -
---------- ----------
Total shareholders' equity 279,162 421,372
---------- ----------
Total Liabilities and Shareholders' Equity $ 417,253 $ 578,163
========== ==========
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
--------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 108,075 $ 167,042 $ 118,173
Oil and natural gas 92,016 90,237 67,959
Other 1,173 1,900 1,504
---------- ---------- ----------
Total revenues 201,264 259,179 187,636
---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 84,051 91,006 91,338
Depreciation 11,999 13,888 14,684
Oil and natural gas:
Operating costs 19,754 22,196 20,795
Depreciation, depletion,
amortization and
impairment 18,492 22,116 23,338
General and administrative 6,560 8,476 8,712
Interest 5,136 2,818 973
---------- ---------- ----------
Total expenses 145,992 160,500 159,840
---------- ---------- ----------
Income Before Income Taxes 55,272 98,679 27,796
---------- ---------- ----------
Income Tax Expense:
Current 621 5,609 (3,469)
Deferred 20,307 30,304 13,021
---------- ---------- ----------
Total income taxes 20,928 35,913 9,552
---------- ---------- ----------
Net Income $ 34,344 $ 62,766 $ 18,244
========== ========== ==========
Net Income Per Common Share:
Basic $ 0.96 $ 1.75 $ 0.47
========== ========== ==========
Diluted $ 0.95 $ 1.73 $ 0.47
========== ========== ==========
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 2000, 2001 and 2002
Accumulated
Capital Other
In Excess Comprehen-
Common Of Par Retained Sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- ----------- -------- ----------
(In thousands)
Balances,
January 1, 2000 $ 7,128 $ 139,207 $ 33,170 $ - $ - $ 179,505
Net income - - 34,344 - - 34,344
Activity in
employee
compensation
plans
(135,419
shares) 26 665 - - - 691
-------- ---------- --------- ----------- -------- ----------
Balances,
December 31,
2000 7,154 139,872 67,514 - - 214,540
Net Income - - 62,766 - - 62,766
Activity in
employee
compensation
plans
(237,923
shares) 47 2,105 - - - 2,152
Purchase of
treasury
shares
(30,000
shares) - - - - (296) (296)
Other
comprehensive
income (net of
tax):
Change in
value of
cash flow
derivative
instru-
ments
used as
cash flow
hedges - - - 1,258 - 1,258
Adjustment
reclas-
ification -
derivative
settle-
ments - - - (1,258) - (1,258)
-------- ---------- --------- ----------- -------- ----------
Balances,
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED
Year Ended December 31, 2000, 2001 and 2002
Accumulated
Capital Other
In Excess Comprehen-
Common Of Par Retained Sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- ----------- -------- ----------
(In thousands)
Balances,
December 31,
2001 $ 7,201 $ 141,977 $130,280 $ - $ (296) $ 279,162
Net Income - - 18,244 - - 18,244
Activity in
employee
compensation
plans
(113,133
shares) 23 1,156 - - 296 1,475
Issuance of
stock for
acquisistion
(7,220,000
shares) 1,444 121,047 - - - 122,491
Other
comprehensive
income (net of
tax):
Change in
value of
cash flow
derivative
instru-
ments
used as
cash flow
hedges - - - 25 - 25
Adjustment
reclas-
ification -
derivative
settle-
ments - - - (25) - (25)
-------- ---------- --------- ----------- -------- ----------
Balances,
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands)
Cash Flows From Operating
Activities:
Net Income $ 34,344 $ 62,766 $ 18,244
Adjustments to reconcile
net income to net cash
provided (used) by
operating activities:
Depreciation, depletion,
amortization and
impairment 30,946 36,642 38,657
Equity in net earnings of
unconsolidated investments - (1,148) (745)
Loss (gain) on disposition
of assets (969) (56) (69)
Employee compensation
plans 443 2,873 1,165
Bad debt expense 350 - 603
Deferred tax expense 20,307 30,304 13,021
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (18,500) 6,334 (43)
Materials and supplies (543) (1,556) (3,436)
Prepaid expenses and other (96) (3,533) 2,365
Accounts payable (1,370) (155) 1,784
Accrued liabilities 3,067 929 (350)
Contract advances (179) 61 (213)
Other liabilities (440) (440) (436)
---------- ---------- ----------
Net cash provided by
operating activities 67,360 133,021 70,547
---------- ---------- ----------
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands)
Cash Flows From Investing
Activities:
Capital expenditures (including
producing property
acquisitions) $ (60,447) $(108,339) $ (75,225)
Proceeds from disposition of
property and equipment 4,259 2,631 1,949
(Acquisition) disposition
of other assets (2,656) 17 540
---------- ---------- ----------
Net cash used in
investing activities (58,844) (105,691) (72,736)
---------- ---------- ----------
Cash Flows From Financing
Activities:
Borrowings under line of credit 31,200 57,200 36,700
Payments under line of credit (44,439) (79,200) (36,200)
Net payments on notes payable
and other long-term debt (556) (1,000) (1,161)
Proceeds from exercise of
stock options 250 609 413
Book overdrafts (Note 1) 3,108 (4,978) 2,543
Acquisition of treasury stock - (296) -
---------- ---------- ----------
Net cash provided by
(used in) financing
activities (10,437) (27,665) 2,295
---------- ---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (1,921) (335) 106
Cash and Cash Equivalents,
Beginning of Year 2,647 726 391
---------- ---------- ----------
Cash and Cash Equivalents,
End of Year $ 726 $ 391 $ 497
========== ========== ==========
Supplemental Disclosure of Cash
Flow Information:
Cash paid (received) during
the year for:
Interest $ 5,135 $ 2,807 $ 1,053
Income taxes $ 519 $ 7,779 $ (4,585)
|
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its directly and indirectly wholly owned subsidiaries ("Unit"). The investment in limited partnerships is accounted for on the proportionate consolidation method, whereby Unit's share of the partnerships' assets, liabilities, revenues and expenses is included in the appropriate classification in the accompanying consolidated financial statements.
Nature of Business. Unit is engaged in the land contract drilling of natural gas and oil wells and the exploration, development, acquisition and production of oil and natural gas properties. Unit's current contract drilling operations are focused primarily in the natural gas producing provinces of the Oklahoma and Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf Coast and the Rocky Mountain regions. Unit's primary exploration and production operations are also conducted in the Anadarko and Arkoma Basins and in the Texas Gulf Coast area with additional properties in the Permian Basin. The majority of its contract drilling and exploration and production activities are oriented toward drilling for and producing natural gas. At December 31, 2002, Unit had an interest in a total of 3,304 wells and served as operator of 707 of those wells. Unit provides land contract drilling services for a wide range of customers using the drilling rigs, which it owns and operates. In 2002, 68 of Unit's 75 rigs performed contract drilling services.
Drilling Contracts. Unit recognizes revenues generated from "daywork" drilling contracts as the services are performed, which is similar to the percentage of completion method. Under "footage" and "turnkey" contracts, Unit bears the risk of completion of the well therefore, revenues and expenses are recognized using the completed contract method. The duration of all three types of contracts range typically from 20 to 90 days, but some of our daywork contracts in the Rocky Mountains can range up to one year. The entire amount of a 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" contracts, which are still in process at the end of the period, and are included in other current assets.
Cash Equivalents and Book Overdrafts. Unit 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. Book overdrafts are checks that have been issued prior to the end of the period, but not presented to Unit's bank for payment prior to the end of the period. At December 31, 2001 and 2002, book overdrafts of $1.1 million and $3.6 million have been included in accounts payable.
Property and Equipment. Drilling equipment, transportation equipment and other property and equipment are carried at cost. Renewals and betterments are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives, including a minimum provision of 20 percent of the active rate when the equipment is idle. Unit 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 property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause Unit to reduce the carrying value of property and equipment.
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 drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.
Goodwill. Goodwill represents the excess of the cost of the acquisition of Hickman Drilling Company, CREC Rig Equipment Company and CDC Drilling Company over the fair value of the net assets acquired. Prior to January 1, 2002 goodwill was amortized on the straight-line method using a 25 year life. Unit expensed $243,000 annually for the amortization of goodwill. On July 20, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("FAS 142"). For goodwill and intangible assets recorded in the financial statements, FAS 142 ends the amortization of goodwill and certain intangible assets and subsequently requires, at least annually, that an impairment test be performed on such assets to determine whether the fair value has changed. FAS 142 became effective for the fiscal years starting after December 15, 2001 (January 1, 2002 for Unit). Net goodwill reported in other assets at December 31, 2001 and 2002 was $5,088,000 and $12,794,000, respectively, and is all related to the drilling segment. Goodwill of $7,009,000 is expected to be deductible for tax purposes.
Oil and Natural Gas Operations. Unit 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. Unit capitalizes internal costs that can be directly identified with its acquisition, exploration and development activities. Independent petroleum engineers annually review Unit's determination of its oil and natural gas reserves. The average composite rates used for depreciation, depletion and amortization ("DD&A") were $0.82, $0.91 and $1.04 per Mcfe in 2000, 2001 and 2002, respectively. The 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. Unit's unproved properties totaling $16.0 million are excluded from the DD&A calculation. 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 Unit's oil and natural gas properties. As discussed in Note 12, such estimates are imprecise.
No gains or losses are recognized upon the sale, conveyance or other disposition of oil and natural gas properties unless a significant reserve amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in current operations for services performed on oil and natural gas properties in which Unit has an interest or on properties in which a partnership, of which Unit is a general partner, has an interest. Accordingly, in 2000, 2001 and 2002, Unit recorded $179,000, $2,259,000 and $841,000 of contract drilling profits, respectively, as a reduction of the carrying value of its oil and natural gas properties rather than including these profits in current operations.
Limited Partnerships. Unit's wholly owned subsidiary, Unit Petroleum Company, is a general partner in ten oil and natural gas limited partnerships sold privately and publicly. Some of Unit's officers, directors and employees own the interests in most of these partnerships. Unit shares partnership revenues and costs in accordance with formulas prescribed in each limited partnership agreement. The partnerships also reimburse Unit for certain administrative costs incurred on behalf of the partnerships.
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. Unit uses the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Unit estimates its December 31, 2002 balancing position to be approximately 1.9 Bcf on under-produced properties and approximately 2.3 Bcf on over-produced properties. Unit has recorded a receivable of $485,000 on certain wells where we estimated that insufficient reserves are available for Unit to recover the under-production from future production volumes. Unit has also recorded a liability of $1,020,000 on certain properties where we believe there is insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Unit's policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which Unit has imbalances are not material.
Equity Investments. Unit owns a 40 percent equity interest in a natural gas gathering and processing company. The investment, including Unit's share of the equity in the earnings of this company, totaled $1.8 million at December 31, 2002 and is reported in other assets.
Employee and Director Stock Based Compensation. Unit applies APB Opinion 25 in accounting for its stock option plans for its employees and directors, which are explained more fully in Note 6. Under this standard, no compensation expense is recognized for grants of options, which include an exercise price equal to or greater than the market price of the stock on the date of grant. Accordingly, based on Unit's grants in 2000, 2001 and 2002 no compensation expense has been recognized. Compensation expense included in reported net income is Unit's matching 401(k) contribution (See Note 6). Had compensation been determined on the basis of fair value pursuant to FASB Statement No. 123, net income and earnings per share would have been reduced as follows:
2000 2001 2002
--------- --------- ---------
Net Income, as Reported
(In Thousands) $ 34,344 $ 62,766 $ 18,244
Add Stock Based Employee Compensation
Expense Included in Reported Net
Income - Net of Tax 369 671 669
Less Total Stock Based Employee
Compensation Expense Determined
Under Fair Value Based Method
For All Awards (727) (1,615) (1,488)
--------- --------- ---------
Pro Forma Net Income $ 33,986 $ 61,822 $ 17,425
========= ========= =========
Basic Earnings per Share:
As reported $ 0.96 $ 1.75 $ 0.47
========= ========= =========
Pro forma $ 0.95 $ 1.72 $ 0.45
========= ========= =========
Diluted Earnings per Share:
As reported $ 0.95 $ 1.73 $ 0.47
========= ========= =========
Pro forma $ 0.94 $ 1.71 $ 0.45
========= ========= =========
|
The fair value of each option granted is estimated using the Black-Scholes model. Unit's estimate of stock volatility in 2000 and 2001 was 0.55 and in 2002 was 0.53, based on previous stock performance. Dividend yield was estimated to remain at zero with a risk free interest rate of 5.26, 5.41 and 4.24 percent in 2000, 2001 and 2002, respectively. Expected life ranged from 1 to 10 years based on prior experience depending on the vesting periods involved and the make up of participating employees. The aggregate fair value of options granted during 2000 and 2002 under the Stock Option Plan were $1,470,000 and $1,669,000, respectively. No options were issued under the Stock Option Plan in 2001. Under the Non-Employee
Directors' Stock Option Plan the aggregate fair value of options granted during 2000, 2001 and 2002 were $99,000, $201,000 and $262,000, respectively.
Self Insurance. Unit utilizes self insurance programs for employee group health and worker's compensation. Self insurance costs are accrued based upon the aggregate of estimated liabilities for reported claims and claims incurred but not yet reported. Accrued liabilities include $4,583,000 and $3,632,000 for employer group health insurance and worker's compensation at December 31, 2001 and 2002, respectively. Due to high premium cost, Unit decided to increase its deductible for general liability claims to $200,000 and to $1.0 million for rig physical damage claims.
Treasury Stock. On August 30, 2001, Unit's Board of Directors authorized the purchase of up to one million shares of Unit's common stock. The timing of stock purchases are made at the discretion of management. During 2001, 30,000 shares were repurchased for $296,000. These shares were used for a portion of the company match to the 401(k) Employee Thrift Plan. No treasury stock was owned by Unit at December 31, 2002.
Financial Instruments and Concentrations of Credit Risk. Financial instruments, which potentially subject Unit to concentrations of credit risk, consist primarily of trade receivables with a variety of national and international oil and natural gas companies. Unit does not generally require collateral related to receivables. Such credit risk is considered by management to be limited due to the large number of customers comprising Unit's customer base. During 2002, one purchaser of Unit's oil and natural gas production accounted for approximately 11 percent of consolidated revenues. At December 31, 2002 accounts receivable from one oil and natural gas purchaser was approximately $713,000. In addition, at December 31, 2001 and 2002, Unit had a concentration of cash of $2.0 million and $3.0 million, respectively, with one bank.
Hedging Activities. On January 1, 2001, Unit adopted Statement of Financial Accounting Standard No. 133 (subsequently amended by Financial Accounting Standard No.'s 137 and 138), "Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"). This statement requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, Unit is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain (loss) on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under FAS 133 must be recorded at fair value with gains (losses) recognized in earnings in the period of change.
Unit periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil and natural gas production. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-
counter swaps and basic hedges with major energy derivative product specialists. Initial adoption of this standard was not material. In the first quarter of 2000, Unit entered into swap transactions in an effort to lock in a portion of its daily production at the higher oil prices which currently existed. These transactions applied to approximately 50 percent of Unit's daily oil production covering the period from April 1, 2000 to July 31, 2000 and 25 percent of our oil production for August and September of 2000, at prices ranging from $24.42 to $27.01.
Unit entered into a collar contract for approximately 25 percent of its daily production for the period covering November 1, 2000 to February 28, 2001. The collar had a floor of $26.00 and a ceiling of $33.00 and Unit received $0.86 per barrel for entering into the collar transaction. During 2000, the net effect of these hedging transactions yielded a reduction in Unit's oil revenues of $465,000. During the first quarter of 2001, the net effect of this hedging transaction yielded an increase in oil revenues of $17,200. During the second quarter of 2001, Unit entered into a natural gas collar contract for approximately 36 percent of its June and July 2001 natural gas production, at a floor price of $4.50 and a ceiling price of $5.95. During the third quarter of 2001, Unit entered into two natural gas collar contracts for approximately 38 percent of its September thru November 2001 natural gas production. Both contracts had a floor price of $2.50. One contract had a ceiling price of $3.68 and the other contract had a ceiling price of $4.25. During 2001 natural gas collar contracts added $2,030,000 to Unit's natural gas revenues.
On April 30, 2002, Unit entered into a collar contract covering approximately 19 percent of its natural gas production for the periods of April 1, 2002 thru October 31, 2002. The collar had a floor of $3.00 and a ceiling of $3.98. During the year of 2002, the natural gas hedging transactions increased natural gas revenues by $40,300. At December 31, 2002, Unit was not holding any natural gas or oil derivative contracts.
During the first quarter of 2003, Unit entered into two collar contracts covering approximately 40 percent of its natural gas production for the periods of April 1, 2003 thru September 30, 2003. One collar has a floor of $4.00 and a ceiling of $5.75 and the other collar has a floor of $4.50 and a ceiling of $6.02. Unit also entered into two collar contracts covering approximately 25 percent of its oil production for the periods of May 1, 2003 thru December 31, 2003. One collar has a floor of $25.00 and a ceiling of $32.20 and the other collar has a floor of $26.00 and a ceiling of $31.40.
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 July 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("FAS 143"). FAS 143, is effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for Unit), and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for Unit's depleted wells) in the period in which the liabilities are incurred (at the time the wells are drilled). In the first quarter of 2003, the effect of the implementation of FAS 143 (unaudited) is expected to increase liabilities including deferred taxes by $11.7 million, increase the net book value of Unit's oil and natural gas properties by $13.0 million and the anticipated adjustment to increase net income for the accumulated effect of a change in accounting principle is expected to be $1.3 million.
In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13, and Technical Corrections" ("FAS 145"). FAS 145 is effective for fiscal years beginning after May 15, 2002. This statement eliminates an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. Unit does not expect the adoption of FAS 145 to have a material effect on our financial position, results of operations or cashflows.
In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, "Accounting for Cost Associated with Exit or Disposal Activities" ("FAS 146"). FAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. FAS 146 nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Unit does not expect the adoption of FAS 146 to have a material effect on our financial position, results of operations or cashflows.
On December 31, 2002, the FASB issued Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FAS 123" ("FAS 148"). FAS 148 provides additional transition guidance for companies that elect to voluntarily adopt the accounting provisions of FAS 123, "Accounting For Stock-Based Compensation." FAS 148 does not change the provisions of FAS 123 that permit entities to continue to apply the intrinsic value method of APB 25, "Accounting for Stock Issued to Employees" ("APB 25"). Since Unit applies APB 25, its accounting for stock-based compensation will not change as a
result of FAS 148. FAS 148 does require certain new disclosures in both annual and interim financial statements. The required annual disclosures were effective immediately for Unit and have been included above in Note 1 of the Company's financial statements. The new interim disclosure provisions will be effective for Unit in the first quarter of 2003.
On November 25, 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, an interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34" ("FIN 45"). FIN 45 clarifies the requirements of FASB Statement No. 5, Accounting for Contingencies ("FAS 5"), relating to the guarantor's accounting for, and disclosure of, the issuance of certain types of guarantees. For guarantees that fall within the scope of FIN 45, the Interpretation requires that guarantors recognize a liability equal to the fair value of the guarantee upon its issuance. The Interpretation's provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The guarantor's previous accounting for guarantees that were issued before the date of FIN 45's initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the Interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. Unit has guaranteed liabilities in the past which would fall under the terms of FIN 45, but it does not have any such guarantees at December 31, 2002.
On January 17, 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights ("variable interest entities" or "VIEs") and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. Unit does not expect the adoption of this standard to have a material impact on its financial position or results of operations.
On August 15, 2002, Unit completed the acquisition of CREC Rig Equipment Company and CDC Drilling Company. Both of these acquisitions were stock purchase transactions. Unit issued 6,819,748 shares of common stock and paid $3,813,053 for all the outstanding shares of CREC Rig Equipment Company and issued 400,252 shares of common stock and paid $686,947 for all the outstanding shares of CDC Drilling Company. The assets of the acquired companies included twenty drilling rigs, spare drilling equipment and vehicles. What we paid in both transactions was determined through arms-length negotiations between the parties and only the cash portion of the transaction appears in the investing and financing activities of Unit's Consolidated Condensed Statement of Cash Flows.
Total consideration given in the acquisition was determined based on the depth capacity of the rigs, the working condition of the rigs and the ability of the rigs to enhance Unit's ability to provide services and equipment required by our customers on a timely basis within the Anadarko and Gulf Coast areas were the rigs are located. The calculation and allocation of the total consideration paid for the acquisition are as follows (in thousands):
Calculation of Consideration Paid:
Unit Corporation common stock
(7,220,000 shares at $16.96556 per share) $ 122,491
Cash 4,500
----------
Total consideration $ 126,991
==========
Allocation of Total Consideration Paid:
Drilling rigs $ 112,994
Spare drilling equipment 3,500
Vehicles 636
Deferred tax asset 2,155
Goodwill 7,706
----------
Total consideration $ 126,991
==========
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Unaudited summary pro forma results of operations for the Company, reflecting the above acquisitions as if they had occurred at the beginning of the year ended December 31, 2001 are as follow:
Year Ended Year Ended
December 31, December 31,
2001 2002
-------------- --------------
Revenues $ 311,104,000 $ 215,805,000
============== ==============
Net Income $ 70,457,000 $ 15,320,000
============== ==============
Net Income per
Common Share
(Diluted) $ 1.62 $ 0.34
============== ==============
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The pro forma results of operations are not necessarily indicative of the actual results of operations that would have occurred had the purchase actually been made at the beginning of the respective periods nor of the results which may occur in the future.
The following data shows the amounts used in computing earnings per share.
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Year Ended
December 31, 2000:
Basic earnings per
common share $ 34,344,000 35,723,000 $ 0.96
==========
Effect of dilutive
stock options 409,000
------------- -------------
Diluted earnings per
common share $ 34,344,000 36,132,000 $ 0.95
============= ============= ==========
For the Year Ended
December 31, 2001:
Basic earnings per
common share $ 62,766,000 35,967,000 $ 1.75
==========
Effect of dilutive
stock options 291,000
------------- -------------
Diluted earnings per
common share $ 62,766,000 36,258,000 $ 1.73
============= ============= ==========
For the Year Ended
December 31, 2002:
Basic earnings per
common share $ 18,244,000 38,844,000 $ 0.47
==========
Effect of dilutive
stock options 268,000
------------- -------------
Diluted earnings per
common share $ 18,244,000 39,112,000 $ 0.47
============= ============= ==========
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The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of common shares for the years ended December 31,:
2000 2001 2002
---------- ---------- ----------
Options 144,000 153,000 198,500
========== ========== ==========
Average Exercise Price $ 16.59 $ 16.79 $ 19.01
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Long-term debt consisted of the following as of December 31, 2001 and 2002:
2001 2002
---------- ----------
(In thousands)
Revolving Credit and Term Loan,
with Interest at December 31,
2001 and 2002 of 3.3 Percent
and 2.5 Percent, Respectively $ 30,000 $ 30,500
Notes Payable for Hickman
Drilling Company Acquisition
with Interest at December 31,
2001 and 2002 of 4.75 Percent
and 4.25 Percent, Respectively 2,000 1,000
---------- ----------
32,000 31,500
Less Current Portion 1,000 1,000
---------- ----------
Total Long-Term Debt $ 31,000 $ 30,500
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At December 31, 2002, Unit has a $100 million bank loan agreement consisting of a revolving credit facility through May 1, 2005 and a term loan thereafter, maturing on May 1, 2008. Borrowings under the loan agreement are limited to a commitment amount. Although, the current value of Unit's assets under the latest loan value computation supported a full $100 million, Unit elected to set the loan commitment at $40 million in order to reduce costs. The loan value under the revolving credit facility is subject to a semi-annual re-determination calculated primarily as the sum of a percentage of the discounted future value of Unit's oil and natural gas reserves, as determined by the banks. In addition, an amount representing a part of the value of Unit's drilling rig fleet, limited to
$20 million, is added to the loan value. Any declines in commodity prices would adversely impact the determination of the loan value.
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 1.00 to 1.50 percent depending on the level of debt as a percentage of the total loan value. Subsequent to May 1, 2005, borrowings under the loan agreement bear interest at the Prime Rate or the Libor Rate plus 1.25 to 1.75 percent depending on the level of debt as a percentage of the total loan value.
At Unit'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 outstanding principal balance of the note to which such Libor Rate option applies may not be paid. Borrowings under the Prime Rate option may be paid anytime in part or in whole without premium or penalty.
Unit pays an origination fee equal to one percent of the elected loan commitment annually and a facility fee of 3/8 of one percent is charged for any unused portion of the commitment amount. Some of Unit's drilling rigs are collateral for such indebtedness and the balance of Unit'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 Unit 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 debt at the end of such year, (ii) the incurrence by Unit 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 Unit or any of its subsidiaries, except in favor of its banks. The loan agreement also requires that Unit maintain consolidated net worth of at least $125 million, a current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.2 to 1 and a ratio of total liabilities, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.65 to 1. In addition, working capital provided by operations, as defined in the loan agreement, cannot be less than $40 million in any year.
In November 1997, Unit completed the acquisition of Hickman Drilling Company. In association with this acquisition, we issued an aggregate of $5.0 million in promissory notes payable in five equal annual installments commencing January 2, 1999, with interest at the Prime Rate. At December 31, 2002, $1 million remained outstanding on these promissory notes and they were paid in full in January 2003.
Other long-term liabilities consisted of the following as of December 31, 2001 and 2002:
2001 2002
---------- ----------
(In thousands)
Separation Benefit Plan $ 1,959 $ 2,081
Deferred Compensation Plan 1,277 1,391
Retirement Agreement 1,330 1,412
Gas Balancing Liability - 1,020
Natural Gas Purchaser Prepayment 437 -
---------- ----------
5,003 5,904
Less Current Portion 893 465
---------- ----------
Total Other Long-Term Liabilities $ 4,110 $ 5,439
========== ==========
|
Estimated annual principal payments under the terms of long-term debt and other long-term liabilities from 2003 through 2007 are $1,465,000, $300,000, $6,231,000, $10,467,000 and $10,467,000. Based on the borrowing rates currently available to Unit for debt with similar terms and maturities, long-term debt at December 31, 2002 approximates its fair value.
A reconciliation of the income tax expense, computed by applying the federal statutory rate to pre-tax income to Unit's effective income tax expense is as follows:
2000 2001 2002
---------- ---------- ----------
(In thousands)
Income Tax Expense Computed by
Applying the Statutory Rate $ 19,345 $ 34,538 $ 9,739
State Income Tax, Net of
Federal Benefit 1,575 2,859 834
Statutory Depletion and Other 8 (1,484) (1,021)
---------- ---------- ----------
Income tax expense $ 20,928 $ 35,913 $ 9,552
========== ========== ==========
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Deferred tax assets and liabilities are comprised of the following at December 31, 2001 and 2002:
2001 2002
----------- -----------
(In thousands)
Deferred Tax Assets:
Allowance for losses
and nondeductible accruals $ 3,867 $ 3,942
Net operating loss carryforward - 17,752
Statutory depletion carryforward 2,874 4,231
Alternative minimum tax credit
carryforward 5,196 395
----------- -----------
Gross deferred tax assets 11,937 26,320
Deferred Tax Liability:
Depreciation, depletion and
amortization (83,720) (110,598)
----------- -----------
Net deferred tax liability (71,783) (84,278)
Current Deferred Tax Asset 2,157 2,042
----------- -----------
Non-Current - Deferred Tax Liability $ (73,940) $ (86,320)
=========== ===========
|
Realization of the deferred tax asset is dependent on generating sufficient future taxable income. 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 are reduced.
At December 31, 2002, Unit has an excess statutory depletion carryforward of approximately $11,135,000, which may be carried forward indefinitely and is available to reduce future taxable income, subject to statutory limitations. At December 31, 2002, Unit has net operating loss carryforwards of approximately $46,700,000 which expire from 2019 to 2022.
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, Unit's shareholders approved and 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. No shares were issued under the Plan in 2000, 2001 and 2002.
Unit also has a Stock Option Plan (the "Option Plan"), which provides for the granting of options for up to 2,700,000 shares of common stock to officers and employees. The Option Plan permits the issuance of qualified or nonqualified stock options. Options granted typically become exercisable at the rate of 20 percent per year one year after being granted and expire after ten years from the original grant date. The exercise price for options granted under this plan is the fair market value of the common stock on the date of the grant.
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 2000 657,600 $ 4.41
Granted 146,000 16.59
Exercised (79,700) 4.19
Cancelled (4,200) 4.94
----------- ----------
Outstanding at December 31, 2000 719,700 6.87
Exercised (177,200) 3.13
Cancelled (10,400) 10.26
----------- ----------
Outstanding at December 31, 2001 532,100 8.09
Granted 160,000 19.03
Exercised (59,400) 5.67
----------- ----------
Outstanding at December 31, 2002 632,700 $ 11.08
=========== ==========
OUTSTANDING OPTIONS
AT DECEMBER 31, 2002
---------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 2.75 - $ 4.00 236,500 4.3 years $ 3.42
$ 7.25 - $10.00 94,200 4.1 years $ 8.58
$11.31 - $14.06 6,500 7.3 years $ 13.61
$16.69 - $19.04 295,500 9.0 years $ 17.95
|
EXERCISABLE OPTIONS
AT DECEMBER 31, 2002
-------------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
------------------------------------ ----------- -----------
$ 2.75 - $ 4.00 196,000 $ 3.36
$ 7.25 - $10.00 91,700 $ 8.61
$11.31 - $14.06 3,200 $ 13.18
$16.69 - $19.04 64,200 $ 17.05
|
Options for 407,900, 329,300 and 355,100 shares were exercisable with weighted average exercise prices of $4.24, $6.25 and $7.28 at December 31, 2000, 2001 and 2002, respectively.
In February and May 1992, the Board of Directors and shareholders, respectively, approved the Unit Corporation Non-Employee Directors' Stock Option Plan (the "Old Plan") and in February and May 2000, the Board of Directors and shareholders, respectively, approved the Unit Corporation 2000 Non-Employee Directors' Stock Option Plan (the "Directors' Plan"). Under the Directors' Plan, which replaced the Old Plan, an aggregate of 300,000 shares of Unit's common stock may be issued upon exercise of the stock options. Under the Old Plan, on the first business day following each annual meeting of stockholders of Unit, each person who was then a member of the Board of Directors of Unit and who was not then an employee of Unit or any of its subsidiaries was granted an option to purchase 2,500 shares of common stock. Under the Directors' Plan, commencing with the year 2000 annual meeting, the amount granted has been increased to 3,500 shares of common stock. The option price for each stock option is the fair market value of the common stock on the date the stock options are granted. No stock options may be exercised during the first six months of its term except in case of death and no stock options are exercisable after ten years from the date of grant.
Activity pertaining to the Directors' Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 2000 77,500 $ 5.86
Granted 17,500 12.19
----------- ----------
Outstanding at December 31, 2000 95,000 7.03
Granted 17,500 17.54
Exercised (37,000) 6.80
----------- ----------
Outstanding at December 31, 2001 75,500 9.58
Granted 21,000 20.10
Exercised (2,500) 1.75
----------- ----------
Outstanding at December 31, 2002 94,000 $ 12.14
=========== ==========
OUTSTANDING AND
EXERCISABLE OPTIONS
AT DECEMBER 31, 2002
---------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 2.88 - $ 3.75 15,000 1.0 years $ 3.40
$ 6.87 - $ 9.00 30,000 5.0 years $ 7.76
$12.19 - $17.54 28,000 8.0 years $ 15.53
$20.10 - $20.10 21,000 9.3 years $ 20.10
|
Under Unit'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. Unit may match each employee's contribution, up to a specified maximum, in full or on a partial basis. The Company made discretionary contributions under the plan of 58,353, 35,016 and 87,452 shares of common stock and recognized expense of $595,000, $1,082,000 and $1,079,000 in 2000, 2001 and 2002, respectively.
Unit provides a salary deferral plan ("Deferral Plan") which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. Funds set aside in a trust to satisfy Unit's obligation under the Deferral Plan at December 31, 2000, 2001 and 2002 totaled $1,536,000, $1,277,000 and $1,391,000, respectively. Unit recognizes payroll expense and records a liability at the time of deferral.
Effective January 1, 1997, Unit adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with Unit is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to 4 weeks salary for every whole year of service completed with Unit up to a maximum of 104 weeks. To receive payments the recipient must waive any claims against Unit in exchange for receiving the separation benefits. On October 28, 1997, Unit adopted a Separation Benefit Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Unit recognized expense of $558,000, $589,000 and $619,000 in 2000, 2001 and 2002, respectively, for benefits associated with anticipated payments from both separation plans.
Unit has entered into key employee change of control contracts with five of our executive officers. These severance contracts have an initial three-year term that is automatically extended for one year upon each anniversary, unless a notice not to extend is given by Unit. If a change of control of the company, as defined in the contracts, occurs during the term of the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally provide that the executive's terms and conditions for employment (including position, work location, compensation and benefits) will not be adversely changed during the three-year period after a change of control. If the executive's employment is terminated by the company (other than for cause, death or disability), the executive terminates for good reason during such three-year period, or the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of control, and upon certain terminations prior to a change of control or in connection with or in anticipation of a change of control, the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9 times the executive's base salary plus
annual bonus (based on historic annual bonus); and the company matching contributions that would have been made had the executive continued to participate in the company's 401(k) plan for up to an additional three years.
The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and render services commensurate with his position.
Unit formed private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 2002, with a subsidiary of Unit serving as General Partner. Questa Oil and Gas Co. formed five private limited partnerships for 1981 to 1993. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with Unit in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with Unit and Questa, respectively, in most drilling operations and most producing property acquisitions commenced by Unit or Questa for their own account during the period from the formation of the Partnerships through December 31 of each year. Unit repurchased the limited partner's interest in three of five Questa partnerships in the fourth quarter of 2000 and one of the Questa partnerships in the first quarter of 2001 and the four partnerships were dissolved. On December 31, 2002, Unit rolled up nine of the private limited partnerships and consolidated them into one partnership.
Amounts received in the years ended December 31 from both public and private Partnerships for which Unit and Questa are a general partner are as follows:
2000 2001 2002
--------- --------- ---------
(In thousands)
Contract Drilling $ 296 $ 416 $ 209
Well Supervision and Other Fees $ 478 $ 498 $ 510
General and Administrative
Expense Reimbursement $ 192 $ 193 $ 210
|
Related party transactions for contract drilling and well supervision fees are the related party's share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party's behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party's level of activity and are considered by management to be reasonable.
A subsidiary of Unit paid the Partnerships, for which Unit or a subsidiary is the general partner, $6,000, $3,000 and $1,000 during the years ended December 31, 2000, 2001 and 2002, respectively, for purchases of natural gas production.
Unit maintains a Shareholder Rights Plan (the "Plan") designed to deter coercive or unfair takeover tactics, to prevent a person or group from gaining control of Unit without offering fair value to all shareholders and to deter other abusive takeover tactics, which are not in the best interest of shareholders.
Under the terms of the Plan, each share of common stock is accompanied by one right, which given certain acquisition and business combination criteria, entitles the shareholder to purchase from Unit one one-hundredth of a newly issued share of Series A Participating Cumulative Preferred Stock at a price subject to adjustment by Unit or to purchase from an acquiring company certain shares of its common stock or the surviving company's common stock at 50 percent of its value.
The rights become exercisable 10 days after Unit learns that an acquiring person (as defined in the Plan) has acquired 15 percent or more of the outstanding common stock of Unit or 10 business days after the commencement of a tender offer, which would result in a person owning 15 percent or more of such shares. Unit can redeem the rights for $0.01 per right at any date prior to the earlier of (i) the close of business on the tenth day following the time Unit learns that a person has become an acquiring person or (ii) May 19, 2005 (the "Expiration Date"). The rights will expire on the Expiration Date, unless redeemed earlier by Unit.
Unit leases office space under the terms of operating leases expiring through January 31, 2007. Future minimum rental payments under the terms of the leases are approximately $663,000, $647,000, $192,000, $151,000 and $13,000 in 2003, 2004, 2005, 2006 and 2007, respectively. Total rent expense incurred by the Company was $535,000, $582,000 and $678,000 in 2000, 2001 and 2002, respectively.
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 Unit 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. Unit made repurchases of $14,000 and $1,000 in 2000 and 2002, respectively, for such limited partners' interests. No repurchases were made in 2001. Subsequent to the merger, in 2000, Unit also paid $17,000 for additional interest in two of the Questa limited partnerships and $1,980,000 for all the remaining interest in three other Questa partnerships. In 2001, Unit paid $15,000 for interests in two of the Questa limited partnerships and subsequently dissolved one of the Questa partnerships.
Unit is a party to various legal proceedings arising in the ordinary course of its business none of which, in management's opinion, will result in judgments which would have a material adverse effect on Unit's financial position, operating results or cash flows.
Unit has two business segments: Contract Drilling and Oil and Natural Gas, representing its two strategic business units offering different products and services. The Contract Drilling segment provides land contract drilling of oil and natural gas wells and the Oil and Natural Gas segment is engaged in the development, acquisition and production of oil and natural gas properties.
The accounting policies of the segments are the same as those described in the Summary of Significant Accounting Policies (Note 1). Management evaluates the performance of Unit's operating segments based on operating income, which is defined as operating revenues less operating expenses and depreciation, depletion and amortization. Unit has natural gas production in Canada, which is not significant.
2000 2001 2002
---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 108,075 $ 167,042 $ 118,173
Oil and natural gas 92,016 90,237 67,959
Other 1,173 1,900 1,504
---------- ---------- ----------
Total revenues $ 201,264 $ 259,179 $ 187,636
========== ========== ==========
Operating Income (1):
Contract drilling $ 12,025 $ 62,148 $ 12,151
Oil and natural gas 53,770 45,925 23,826
---------- ---------- ----------
Total operating income 65,795 108,073 35,977
General and administrative
expense (6,560) (8,476) (8,712)
Interest expense (5,136) (2,818) (973)
Other income (expense)- net 1,173 1,900 1,504
---------- ---------- ----------
Income before income taxes $ 55,272 $ 98,679 $ 27,796
========== ========== ==========
Identifiable Assets (2):
Contract drilling $ 141,324 $ 183,471 $ 299,655
Oil and natural gas 198,251 220,476 261,440
---------- ---------- ----------
Total identifiable assets 339,575 403,947 561,095
Corporate assets 6,713 13,306 17,068
---------- ---------- ----------
Total assets $ 346,288 $ 417,253 $ 578,163
========== ========== ==========
|
2000 2001 2002
---------- ---------- ----------
(In thousands)
Capital Expenditures:
Contract drilling $ 22,045 $ 51,280 $ 139,298 (3)
Oil and natural gas 39,884 56,933 58,778
Other 3,324 539 516
---------- ---------- ----------
Total capital expenditures $ 65,253 $ 108,752 $ 198,592
========== ========== ==========
Depreciation, Depletion,
Amortization and Impairment:
Contract drilling $ 11,999 $ 13,888 $ 14,684
Oil and natural gas 18,492 22,116 23,338
Other 455 638 635
---------- ---------- ----------
Total depreciation,
depletion, amortization
and impairment $ 30,946 $ 36,642 $ 38,657
========== ========== ==========
----------------------
|
(1) Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization and impairment and does not include non-operating revenues, general corporate expenses, interest expense or income taxes.
(2) Identifiable assets are those used in Unit's operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment.
(3) Includes $7.7 million for goodwill and $2.2 million for deferred tax assets.
Summarized quarterly financial information for 2001 and 2002 is as follows:
THREE MONTHS ENDED
------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ----------- ------------ -----------
(In thousands except per share amounts)
Year Ended
December 31, 2001:
Revenues $ 70,443 $ 71,087 $ 68,399 $ 49,250
=========== =========== =========== ===========
Gross profit(1) $ 33,414 $ 32,091 $ 27,277 $ 15,291
=========== =========== =========== ===========
Income before
income taxes $ 30,862 $ 29,070 $ 25,170 $ 13,577
=========== =========== =========== ===========
Net income(2) $ 19,172 $ 18,048 $ 15,631 $ 9,915
=========== =========== =========== ===========
Earnings per
common share:
Basic (3) $ 0.53 $ 0.50 $ 0.43 $ 0.28
=========== =========== =========== ===========
Diluted $ 0.53 $ 0.50 $ 0.43 $ 0.27
=========== =========== =========== ===========
Year Ended
December 31, 2002:
Revenues $ 38,730 $ 44,753 $ 48,272 $ 55,881
=========== =========== =========== ===========
Gross profit(1) $ 6,515 $ 10,295 $ 8,107 $ 11,060
=========== =========== =========== ===========
Income before
income taxes $ 4,254 $ 8,297 $ 6,022 $ 9,223
=========== =========== =========== ===========
Net income(2) $ 2,642 $ 5,108 $ 3,708 $ 6,786
=========== =========== =========== ===========
Earnings per
common share:
Basic (3) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== =========== ===========
Diluted (4) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== =========== ===========
------------------
|
(1) Gross profit excludes other revenues, general and administrative
expense and interest expense.
(2) The net income for the three months ended December 31, 2001 and 2002
includes a tax benefit of $1.5 million and $1.1 million, respectively,
relating to an increase in the estimated amount of statutory depletion
carryforward.
(3) Due to the effect of rounding basic earnings per share for the year's
four quarters does not equal the annual earnings per share.
(4) Due to the effect of price changes of Unit's stock, diluted earnings
per share for the year's four quarters, which includes the effect of
potential dilutive common shares calculated during each quarter, does
not equal the annual diluted earnings per share, which includes the
effect of such potential dilutive common shares calculated for the
entire year.
The capitalized costs at year end and costs incurred during the year were as follows:
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Capitalized costs:
Proved properties $ 338,159 $ 553 $ 338,712
Unproved properties 10,795 200 10,995
----------- --------- -----------
348,954 753 349,707
Accumulated depreciation,
depletion, amortization
and impairment (176,515) (435) (176,950)
----------- --------- -----------
Net capitalized costs $ 172,439 $ 318 $ 172,757
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 5,522 $ 16 $ 5,538
Producing properties acquired 3,752 45 3,797
Exploration 2,409 - 2,409
Development 28,140 - 28,140
----------- --------- -----------
Total costs incurred $ 39,823 $ 61 $ 39,884
=========== ========= ===========
2001:
Capitalized costs:
Proved properties $ 391,216 $ 888 $ 392,104
Unproved properties 14,207 180 14,387
----------- --------- -----------
405,423 1,068 406,491
Accumulated depreciation,
depletion, amortization
and impairment (196,270) (475) (196,745)
----------- --------- -----------
Net capitalized costs $ 209,153 $ 593 209,746
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 7,503 $ 21 $ 7,524
Producing properties acquired 1,419 - 1,419
Exploration 9,336 - 9,336
Development 38,359 295 38,654
----------- --------- -----------
Total costs incurred $ 56,617 $ 316 $ 56,933
=========== ========= ===========
|
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2002:
Capitalized costs:
Proved properties $ 448,331 $ 895 $ 449,226
Unproved properties 15,692 332 16,024
----------- --------- -----------
464,023 1,227 465,250
Accumulated depreciation,
depletion, amortization
and impairment (218,956) (520) (219,476)
----------- --------- -----------
Net capitalized costs $ 245,067 $ 707 $ 245,774
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 5,330 $ 152 $ 5,482
Producing properties acquired 13,379 - 13,379
Exploration 6,591 - 6,591
Development 33,319 7 33,326
----------- --------- -----------
Total costs incurred $ 58,619 $ 159 $ 58,778
=========== ========= ===========
|
The results of operations for producing activities are provided below.
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Revenues $ 88,461 $ 110 $ 88,571
Production costs (16,457) (19) (16,476)
Depreciation, depletion,
amortization and impairment (18,258) (15) (18,273)
----------- --------- -----------
53,746 76 53,822
Income tax expense (20,350) (30) (20,380)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 33,396 $ 46 $ 33,442
=========== ========= ===========
2001:
Revenues $ 86,810 $ 190 $ 87,000
Production costs (18,636) (23) (18,659)
Depreciation, depletion
and amortization (19,756) (40) (19,796)
----------- --------- -----------
48,418 127 48,545
Income tax expense (17,621) (40) (17,661)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 30,797 $ 87 $ 30,884
=========== ========= ===========
2002:
Revenues $ 64,534 $ 87 $ 64,621
Production costs (17,300) (25) (17,325)
Depreciation, depletion
and amortization (22,685) (45) (22,730)
----------- --------- -----------
24,549 17 24,566
Income tax expense (8,436) (5) (8,441)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 16,113 $ 12 $ 16,125
=========== ========= ===========
|
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 (unaudited):
USA CANADA TOTAL
---------------- ---------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- -------- ------- --------
(In thousands)
2000:
Proved developed and
undeveloped reserves:
Beginning of year 4,527 186,770 - 569 4,527 187,339
Revision of previous
estimates (45) 6,385 - (82) (45) 6,303
Extensions, discoveries
and other additions 286 37,896 - - 286 37,896
Purchases of minerals
in place 229 4,893 - - 229 4,893
Sales of minerals in
place (326) (1,509) - - (326) (1,509)
Production (488) (19,239) - (46) (488) (19,285)
------- -------- ------- -------- ------- --------
End of Year 4,183 215,196 - 441 4,183 215,637
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 3,583 144,992 - 467 3,583 145,459
End of year 3,222 162,718 - 389 3,222 163,107
2001:
Proved developed and
undeveloped reserves:
Beginning of year 4,183 215,196 - 441 4,183 215,637
Revision of previous
estimates (214) (24,253) - (7) (214) (24,260)
Extensions, discoveries
and other additions 861 54,521 - - 861 54,521
Purchases of minerals
in place 8 1,246 - - 8 1,246
Sales of minerals in
place (3) (26) - - (3) (26)
Production (492) (18,819) - (45) (492) (18,864)
------- -------- ------- -------- ------- --------
End of Year 4,343 227,865 - 389 4,343 228,254
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 3,222 162,718 - 389 3,222 163,107
End of year 2,753 150,419 - 338 2,753 150,757
|
USA CANADA TOTAL
---------------- ---------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- -------- ------- --------
(In thousands)
2002:
Proved developed and
undeveloped reserves:
Beginning of year 4,343 227,865 - 389 4,343 228,254
Revision of previous
estimates (166) (10,543) - (31) (166) (10,574)
Extensions, discoveries
and other additions 230 29,541 - - 230 29,541
Purchases of minerals
in place 192 16,558 - - 192 16,558
Sales of minerals in
place (30) - - - (30) -
Production (473) (18,927) - (41) (473) (18,968)
------- -------- ------- -------- ------- --------
End of Year 4,096 244,494 - 317 4,096 244,811
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 2,753 150,419 - 338 2,753 150,757
End of year 2,951 168,049 - 317 2,951 168,366
|
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. Unit utilizes Ryder Scott Company, independent petroleum consultants, to review its reserves as prepared by its 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 previously explained. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth herein is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static and no price or cost 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.
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 (unaudited):
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Future cash flows $2,260,796 $ 4,155 $2,264,951
Future production and
development costs (484,900) (433) (485,333)
Future income tax expenses (574,099) (1,099) (575,198)
----------- --------- -----------
Future net cash flows 1,201,797 2,623 1,204,420
10% annual discount for
estimated timing of cash flows (527,210) (1,184) (528,394)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 674,587 $ 1,439 $ 676,026
=========== ========= ===========
2001:
Future cash flows $ 676,051 $ 975 $ 677,026
Future production and
development costs (279,499) (341) (279,840)
Future income tax expenses (94,037) (134) (94,171)
----------- --------- -----------
Future net cash flows 302,515 500 303,015
10% annual discount for
estimated timing of cash flows (125,238) (194) (125,432)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 177,277 $ 306 $ 177,583
=========== ========= ===========
2002:
Future cash flows $1,256,434 $ 1,400 $1,257,834
Future production and
development costs (386,206) (309) (386,515)
Future income tax expenses (250,413) (233) (250,646)
----------- --------- -----------
Future net cash flows 619,815 858 620,673
10% annual discount for
estimated timing of cash flows (275,015) (344) (275,359)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 344,800 $ 514 $ 345,314
=========== ========= ===========
|
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows (unaudited):
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (72,005) $ (91) $ (72,096)
Net changes in prices and
production costs 647,313 1,854 649,167
Revisions in quantity
estimates and changes in
production timing 44,991 (324) 44,667
Extensions, discoveries and
improved recovery, less
related costs 184,624 - 184,624
Purchases of minerals in place 23,144 - 23,144
Sales of minerals in place (3,469) - (3,469)
Accretion of discount 19,881 51 19,932
Net change in income taxes (293,357) (581) (293,938)
Other - net (43,760) 53 (43,707)
----------- --------- -----------
Net change 507,362 962 508,324
Beginning of year 167,225 477 167,702
----------- --------- -----------
End of year $ 674,587 $ 1,439 $ 676,026
=========== ========= ===========
2001:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (68,174) $ (167) $ (68,341)
Net changes in prices and
production costs (768,295) (1,600) (769,895)
Revisions in quantity
estimates and changes in
production timing (32,705) 13 (32,692)
Extensions, discoveries and
improved recovery, less
related costs 54,127 - 54,127
Purchases of minerals in place 1,217 - 1,217
Sales of minerals in place (220) - (220)
Accretion of discount 99,953 205 100,158
Net change in income taxes 271,421 524 271,945
Other - net (54,634) (108) (54,742)
----------- --------- -----------
Net change (497,310) (1,133) (498,443)
Beginning of year 674,587 1,439 676,026
----------- --------- -----------
End of year $ 177,277 $ 306 $ 177,583
=========== ========= ===========
|
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2002:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (47,230) $ (62) $ (47,292)
Net changes in prices and
production costs 230,934 363 231,297
Revisions in quantity
estimates and changes in
production timing (49,000) (110) (49,110)
Extensions, discoveries and
improved recovery, less
related costs 60,957 - 60,957
Purchases of minerals in place 23,334 - 23,334
Sales of minerals in place (150) - (150)
Accretion of discount 23,080 39 23,119
Net change in income taxes (84,843) (59) (84,902)
Other - net 10,441 37 10,478
----------- --------- -----------
Net change 167,523 208 167,731
Beginning of year 177,277 306 177,583
----------- --------- -----------
End of year $ 344,800 $ 514 $ 345,314
=========== ========= ===========
|
Unit'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 spot prices of oil ($29.70) and natural gas ($4.42) relating to proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil and natural gas reserves less the tax basis of Unit's properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to Unit'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.
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in shareholders' equity and cash flows present fairly in all material respects, the financial position of Unit Corporation and its subsidiaries at December 31, 2001 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the accompanying financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. 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 of these financial statements in accordance with auditing standards generally accepted in the United States of America which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 19, 2003
None.
PART III
The table below and accompanying footnotes set forth certain information concerning each of our executive officers. Unless otherwise indicated, each has served in the positions set forth for more than five years. Executive officers are elected for a term of one year. There are no family relationships between any of the persons named.
NAME AGE POSITION
---------------- --- ----------------------------------------
John G. Nikkel 68 President, Chief Executive Officer,
Chief Operating Officer and Director
Earle Lamborn 68 Senior Vice President, Drilling and
Director
Philip M. Keeley 61 Senior Vice President, Exploration and
Production
Larry D. Pinkston 48 Executive Vice President, Treasurer and
Chief Financial Officer
Mark E. Schell 45 Senior Vice President, General Counsel
and Secretary
|
Mr. Nikkel joined Unit in 1983 as its President and a director. On July 1, 2001 Mr. Nikkel was elected to the additional office of Chief Executive Officer. 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 Cotton 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. From August 16, 2000 until August 23,2002 Mr. Nikkel also served as a director of Shenandoah Resources LTD., a Canadian company. Shenandoah Resources LTD. filed for creditors protection (Initial Application Order Under The Companies' Creditor Arrangement Act) in April, 2002 with the Court of Queen's Bench of Alberta, Judicial District of Calgary. Mr. Nikkel received a Bachelor of Science degree in Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 50 years, joining Unit's predecessor in 1952 prior to its becoming a publicly-held corporation. He was elected Vice President, Drilling in 1973 and to his current position as Senior Vice President, Drilling 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, until November 2001, served 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 had 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. In December 2002, he was elected to the additional position of Executive Vice President. 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 1987, as its Secretary and General Counsel. In December 2002, he was elected to the additional position as Senior Vice President. 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. He is a member of the Oklahoma and American Bar Association as well as being a member of the American Corporate Counsel Association and the American Society of Corporate Secretaries.
The balance of the information required in this Item 10 is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 2002 annual meeting of stockholders.
Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2003 annual meeting of stockholders.
Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2003 annual meeting of stockholders.
Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2003 annual meeting of stockholders.
a) Evaluation of disclosure controls and procedures. Within the 90 day period prior to the filing date of this Annual Report on Form 10-K, our management, under the supervision and with the participation of the our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer believe that:
i) the company's disclosure controls and procedures are designed to ensure that information required to be disclosed by the company in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and
ii) the company's disclosure controls and procedures operate such that important information flows to appropriate collection and disclosure points in a timely manner and is effective to ensure that such information is accumulated and communicated to the company's management, and made known to our Chief Executive Officer and Chief Financial Officer, particularly during the period when this Annual Report on Form 10-K was prepared, as appropriate to allow timely decision regarding the required disclosure.
b) Changes in internal controls. There have been no significant changes in the company's internal controls or in other factors that could significantly affect the company's internal controls subsequent to their evaluation, nor have there been any corrective actions with regard to significant deficiencies or material weaknesses.
PART IV
(a) Financial Statements, Schedules and Exhibits:
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:
--------
2.6.1 Amended and Restated Stock Purchase Agreement dated as
of June 24, 2002 by and among Unit Corporation, George
B. Kaiser and Kaiser Francis Oil Company (incorporated
herein by reference to Exhibit 99.1 to Form 8-K dated
August 27,2002).
2.6.2 Amended and Restated Share Purchase Agreement dated as
of June 24, 200, by and among Unit Corporation, Kaiser
Francis Charitable Income Trust B and Kaiser Francis
Oil Company (incorporated herein by reference to
Exhibit 99.2 to Form 8-K dated August 27,2002).
|
3.1 Restated Certificate of Incorporation of Unit Corporation
(file as Exhibit 3.1 to Form S-3 (file No. 333-83551), which
is incorporated herein by reference).
3.2 By-Laws of Unit Corporation (filed as Exhibit 3.2 to Unit's
Form 8-K to Form S-3 (file No. 333-83551), which is
incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.1 on
Form S-3 as S.E.C. File No. 333-83551, which is incorporated
herein by reference).
4.2.6 Rights Agreement between Unit Corporation and Chemical Bank,
as Rights Agent (filed as Exhibit 1 to Unit's Form 8-A filed
with the S.E.C. on May 23, 1995, File No. 1-92601 and
incorporated herein by reference).
4.2.7 First Amendment of Rights Agreement dated May 19, 1995,
between the Company and Mellon Shareholder Services
LLC, as Rights Agent (filed as Exhibit 4 to Unit's Form
8-K dated August 23, 2001, which is incorporated herein
by reference).
4.2.8 Second Amendment of the Rights Agreement, dated August 14,
2002, between the Company and Mellon Shareholder Services LLC,
as Rights Agent (filed herein).
10.1.25 Loan Agreement dated July 24, 2001 (filed as an Exhibit
to Unit's Quarterly Report under cover of Form 10-Q for
the quarter ended June 30, 2001, 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).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed
as Exhibit 10.16 to Unit's Registration Statement on
Form S-4 as S.E.C. File No. 33-7848, which is incorporated
herein by reference).
10.2.22* The Company's Amended and Restated Stock Option Plan
(filed as an Exhibit to Unit's Registration Statement on
Form S-8 as S.E.C. File No's. 33-19652, 33-44103 and
33-64323 which is incorporated herein by reference).
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan
(filed as an Exhibit to Form S-8 as S.E.C. File
No. 33-49724, which is incorporated herein by reference).
91
|
10.2.24* Unit Corporation Employees' Thrift Plan (filed as an Exhibit
to 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 Unit'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 Unit's Annual Report under cover of Form
10-K for the year ended December 31, 1993, which is
incorporated herein by reference).
10.2.30* Separation Benefit Plan of Unit Corporation and
Participating Subsidiaries (filed as an Exhibit to
Unit's Annual Report under the cover of Form 10-K for
the year ended December 31, 1996, which is incorporated
herein by reference).
10.2.32 Unit Corporation Separation Benefit Plan for Senior
Management (filed as an Exhibit to Unit's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1997, which is incorporated herein by
reference).
10.2.35 Unit 2000 Employee Oil and Gas Limited Partnership
Agreement of Limited Partnership (filed as an Exhibit
to Unit's Annual Report under the cover of Form 10-K
for the year ended December 31, 1999).
10.2.36* Unit Corporation 2000 Non-Employee Directors' Stock
Option Plan (filed as an Exhibit to Form S-8 as S.E.C.
File No. 333-38166, which is incorporated herein by
reference).
10.2.37* Unit Corporation's Amended and Restated Stock Option
Plan (filed as an Exhibit to Unit's Registration
Statement on Form S-8 as S.E.C. File No. 333-39584 which
is incorporated herein by reference).
10.2.38 Unit 2001 Employee Oil and Gas Limited Partnership
Agreement of Limited Partnership (filed as an Exhibit
to Unit's Annual Report under the cover of Form 10-K
for the year ended December 31, 2000).
10.2.39* Form of Unit Corporation Key Employee Change of Control
Contract (filed as an Exhibit to Unit's Annual Report
under the cover of Form 10-K for the year ended
December 31, 2000).
10.2.40 Form of Indemnification Agreement entered into between
the Company and its executive officers and directors
(filed as Exhibit 10 to Unit's Form 8-K dated August
23, 2001, which is incorporated herein by reference).
92
|
10.2.41 Unit 2002 Employee Oil and Gas Limited Partnership
Agreement of Limited Partnership (filed as an Exhibit
to Unit's Annual Report under cover of Form 10-K for
the year ended December 21, 2001).
10.2.42 Unit 2003 Employee Oil and Gas Limited Partnership
Agreement of Limited Partnership (filed herein).
21 Subsidiaries of the Registrant (filed herewith).
23 Consent of Independent Accountants (filed herewith).
99.2 Separation Agreement, dated May 11, 2001, between the
Registrant and Mr. Kirchner (filed as Exhibit 99.A4 to
Unit's Form 8-K dated May 18, 2001, which is incorporated
herein by reference).
|
* Indicates a management contract or compensatory plan identified pursuant to the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
On November 5, 2002 we filed a report on Form 8-K under item 9. This report disclosed that the Principal Executive Officer, John G. Nikkel, and Principal Financial Officer, Larry D. Pinkston, of Unit Corporation, had filed with the SEC certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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, 2000 $ 583 $ 350 $ 14 $ 919
========== ========== ========== ==========
Year ended
December 31, 2001 $ 919 $ - $ 315 $ 604
========== ========== ========== ==========
Year ended
December 31, 2002 $ 604 $ 603 $ 4 $ 1,203
========== ========== ========== ==========
|
Deferred Tax Asset Valuation Allowance:
Balance
Balance at At
Beginning End of
Description of Period Additions Deductions Period
----------- ---------- ---------- ---------- ----------
(In thousands)
Year ended
December 31, 2000 $ 335 $ - $ 335 $ -
========== ========== ========== ==========
Year ended
December 31, 2001 $ - $ - $ - $ -
========== ========== ========== ==========
Year ended
December 31, 2002 $ - $ - $ - $ -
========== ========== ========== ==========
|
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 12, 2003 By: /s/ John G. Nikkel
----------------- ---------------------------
JOHN G. NIKKEL
President and Chief Executive 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 12th day of March, 2003.
Name Title
------------------------------- -----------------------------------
/s/ King P. Kirchner
------------------------------- Chairman of the Board and Director
KING P. KIRCHNER
/s/ John G. Nikkel
------------------------------- President and Chief Executive Officer
JOHN G. NIKKEL Chief Operating Officer, Director
/s/ Earle Lamborn
------------------------------- Senior Vice President, Drilling,
EARLE LAMBORN Director
/s/ Larry D. Pinkston
------------------------------- Executive Vice President, Chief Financial
LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz
------------------------------- Controller
STANLEY W. BELITZ
/s/ J. Michael Adcock
------------------------------- Director
J. MICHAEL ADCOCK
/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
|
1. I have reviewed this annual report on Form 10-K of Unit Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 12, 2003 By: /s/ John G. Nikkel
------------------ ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
|
CERTIFICATIONS
I, Larry D. Pinkston, certify that:
1. I have reviewed this annual report on Form 10-K of Unit Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 12, 2003 By: /s/ Larry D. Pinkston
------------------ ------------------------------
LARRY D. PINKSTON
Executive Vice President,
Chief Financial Officer and
Treasurer
|
Exhibit
No. Description Page
------- ---------------------------------------------- -----
4.2.8 Second Amendment of the Rights Agreement, dated
August 14, 2002, between the Company and Mellon
Shareholder Services LLC, as Rights Agent.
10.2.42 Unit 2003 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
|
SECOND AMENDMENT
OF
RIGHTS AGREEMENT
This Second Amendment (this "Amendment") of the Rights Agreement (as defined below) is made and entered into as of the 14 day of August 2002, by and between Unit Corporation, a Delaware corporation (the "Company"), and Mellon Investor Services L.L.C., as "Rights Agent" under the Rights Agreement.
RECITALS:
WHEREAS, on May 19, 1995, the Board of Directors of the Company declared a dividend of one stock purchase right (a "Right") for each outstanding share of common stock, $.20 par value of the Company to the stockholders of record at the close of business on May 31, 1995, with each Right entitling the registered holder to purchase from the Company one one-hundredth of a share of the Series A Participating Cumulative Preferred Stock of the Company, or a combination of securities and assets of equivalent value, upon the terms and subject to the conditions set forth in a Rights Agreement, dated as of May 19, 1995, between the Company and Chemical Bank as Rights Agent, as subsequently amended by the First Amendment of Rights Agreement, dated as of June 7, 2001, between the Company and Mellon Investor Services L.L.C., successor to Chemical Bank as Rights Agent (as so amended, the "Rights Agreement"); and
WHEREAS, the Board of Directors deems it advisable and in the best interests of the Company and its stockholders to amend certain provisions of the Rights Agreement; and
WHEREAS, no Person (as such term is defined in the Rights Agreement) has become an Acquiring Person; and
WHEREAS, the Company desires to amend the Rights Agreement as set forth below;
NOW, THEREFORE, the undersigned, in consideration of the premises, covenants and agreements contained herein and in the Rights Agreement, and other good, sufficient and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, do hereby agree as follows:
Each of the following sections or provisions of the Rights Agreement is hereby amended as follows:
(A). The definition of an "Acquiring Person", as defined in Section 1, is amended to read as follows:
"Acquiring Person" shall mean any Person who or which, alone or together with all Affiliates and Associates of such Person, shall be the Beneficial Owner of more than 15% of the Common Shares then outstanding, but shall not include the Company, any Subsidiary of the Company, any employee benefit plan of the Company or of any of its Subsidiaries, any Person holding Common Shares for or pursuant to the terms of any such employee
benefit plan or a Permitted Investor; provided, however, that (i) if the Board of Directors of the Company determines in good faith that a Person who would otherwise be an "Acquiring Person" became the Beneficial Owner of a number of Common Shares such that the Person would otherwise qualify as an "Acquiring Person" inadvertently (including, without limitation, because (A) such Person was unaware that it beneficially owned a percentage of Common Shares that would otherwise cause such Person to be an "Acquiring Person" or (B) such Person was aware of the extent of its Beneficial Ownership of Common Shares but had no actual knowledge of the consequences of such Beneficial Ownership under this Agreement) and without any intention of changing or influencing control of the Company, then such Person shall not be deemed to be or to have become an "Acquiring Person" for any purposes of this Agreement unless and until such Person shall have failed to divest itself, as soon as practicable (as determined, in good faith, by the Board of Directors of the Company), of Beneficial Ownership of a sufficient number of Common Shares so that such Person would no longer otherwise qualify as an "Acquiring Person"; and (ii) no Person shall become an "Acquiring Person" as the result of an acquisition of Common Shares by the Company which, by reducing the number of shares outstanding, increases the proportionate number of Common Shares beneficially owned by such Person to more than 15% of the Common Shares then outstanding (or in the case of a Permitted Investor, more than 23% of the Common Shares then outstanding), provided, however, that if a Person shall become the Beneficial Owner of more than 15% of the Common Shares then outstanding (or in the case of a Permitted Investor, more than 23% of the Common Shares then outstanding) by reason of such share acquisitions by the Company and shall thereafter become the Beneficial Owner of any additional Common Shares (other than pursuant to a dividend or distribution paid or made by the Company on the outstanding Common Shares or pursuant to a split or subdivision of the outstanding Common Shares), then such Person shall be deemed to be an "Acquiring Person" unless upon becoming the Beneficial Owner of such additional Common Shares such Person does not beneficially own more then 15% of the Common Shares then outstanding (or in the case of a Permitted Investor, more than 23% of the Common Shares then outstanding).
(B). Section 1 is amended by adding a new subsection thereto, which shall read as follows:
"Permitted Investors" shall mean the Kaiser Francis Charitable Income Trust B and George B. Kaiser for so long as such Persons, together with their respective Affiliates and Associates, collectively shall be the Beneficial Owners of greater than 15%, but not more than 23%, of the Common Shares then outstanding, provided that all such Persons shall cease to be Permitted Investors at such time, after the initial issuance of Common Shares to any such Person pursuant to the transactions contemplated by the (i) Amended and Restated Stock Purchase Agreement dated as of June 24, 2002 between Unit Corporation and Kaiser Francis Charitable Income Trust B, and (ii) Amended and Restated Share Purchase Agreement dated as of June 24, 2002 between Unit Corporation and George B. Kaiser, when such Persons shall collectively become the Beneficial Owners of less than 15% of the Common Shares then outstanding.
This Amendment shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns.
This Amendment may be executed in counterparts, each of which shall be
deemed an original, but all of which shall constitute one and the same
instrument.
Except as hereby amended, the Rights Agreement shall remain in full
force and effect.
This Amendment shall be governed by, and interpreted in accordance with, the laws of the State of Delaware, without regard to principles of conflict of laws.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the day and year first above written.
Unit Corporation Mellon Investor Services L.L.C. ------------------------------ ---------------------------- By: John G. Nikkel By: |
Its: Chief Executive Officer Its:
CONFIDENTIAL
For Private Placement Purposes Only Copy No. _________________
UNIT 2003 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 SECURITIES 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 CONSIDERATIONS." 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 December 30, 2002
600 Preformation
Units of Limited Partnership Interest
in the
UNIT 2003 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 600 (minimum of 50) units of limited partnership interest ("Units") in the UNIT 2003 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP, a proposed Oklahoma limited partnership (the "Partnership"), 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, and 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.
. 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 adjustment to their reported tax liabilities; and
. a Limited Partner will not benefit from his or her share of Partnership deductions in excess of his or her share of Partnership income unless he or she has 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.
THE SECURITIES OFFERED BY THIS MEMORANDUM 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, has 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
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 Amended and Restated 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 2002, the annual report to shareholders and all quarterly reports to shareholders submitted by UNIT to its shareholders during calendar year 2002.
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. The agreement of limited partnership for the Unit 1986 Energy Income Limited Partnership.
SUMMARY OF CONTENTS
Page
----
SUMMARY OF PROGRAM.........................................................1
Terms of the Offering...................................................1
Risk Factors............................................................2
Additional Financing....................................................4
Proposed Activities.....................................................4
Application of Proceeds.................................................4
Participation in Costs and Revenues.....................................5
Compensation............................................................6
Federal Income Tax Considerations; Opinion of Counsel...................6
RISK FACTORS...............................................................7
INVESTMENT RISKS......................................................7
TAX STATUS AND TAX RISKS.............................................13
OPERATIONAL RISKS....................................................14
TERMS OF THE OFFERING.....................................................16
General................................................................16
Limited Partnership Interests..........................................17
Subscription Rights....................................................17
Payment for Units; Delinquent Installment..............................18
Right of Presentment...................................................19
Rollup or Consolidation of Partnership.................................20
ADDITIONAL FINANCING......................................................21
Additional Assessments.................................................21
Prior Programs.........................................................22
Partnership Borrowings.................................................22
PLAN OF DISTRIBUTION......................................................23
Suitability of Investors...............................................23
RELATIONSHIP OF THE PARTNERSHIP, THE GENERAL PARTNER AND AFFILIATES.......24
PROPOSED ACTIVITIES.......................................................24
General................................................................24
Partnership Objectives.................................................27
Areas of Interest......................................................27
Transfer of Properties.................................................27
Record Title to Partnership Properties.................................28
Marketing of Reserves..................................................28
Conduct of Operations..................................................28
APPLICATION OF PROCEEDS...................................................29
PARTICIPATION IN COSTS AND REVENUES.......................................29
COMPENSATION..............................................................31
Supervision of Operations..............................................31
Purchase of Equipment and Provision of Services........................32
Prior Programs.........................................................32
MANAGEMENT................................................................34
The General Partner....................................................34
Officers, Directors and Key Employees..................................34
Prior Employee Programs................................................37
Ownership of Common Stock..............................................39
Interest of Management in Certain Transactions.........................40
CONFLICTS OF INTEREST.....................................................40
Acquisition of Properties and Drilling Operations......................41
Participation in UNIT's Drilling or Income Programs....................42
Transfer of Properties.................................................42
Partnership Assets.....................................................43
Transactions with the General Partner or Affiliates....................43
Right of Presentment Price Determination...............................44
Receipt of Compensation Regardless of Profitability....................44
Legal Counsel..........................................................44
vi
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FIDUCIARY RESPONSIBILITY..................................................44 General................................................................44 Liability and Indemnification..........................................45 PRIOR ACTIVITIES..........................................................46 Prior Employee Programs................................................48 Results of the Prior Oil and Gas Programs..............................49 FEDERAL INCOME TAX CONSIDERATIONS.........................................58 Summary of Conclusions.................................................58 General Tax Effects of Partnership Structure...........................61 Ownership of Partnership Properties....................................61 Intangible Drilling and Development Costs Deductions...................62 Depletion Deductions...................................................63 Depreciation Deductions................................................64 Interest Deductions....................................................64 Transaction Fees.......................................................65 Basis and At Risk Limitations..........................................65 Passive Loss Limitations...............................................66 Alternative Minimum Tax................................................66 Gain or Loss on Sale of Property or Units..............................67 Partnership Distributions..............................................67 Partnership Allocations................................................68 Profit Motive..........................................................68 Administrative Matters.................................................68 Accounting Methods and Periods.........................................69 State and Local Taxes..................................................70 Individual Tax Advice Should Be Sought.................................70 COMPETITION, MARKETS AND REGULATION.......................................70 Marketing of Production................................................70 Regulation of Partnership Operations...................................71 Natural Gas Price Regulation...........................................71 Oil Price Regulation...................................................75 State Regulation of Oil and Gas Production.............................75 Legislative and Regulatory Production and Pricing Proposals............75 Production and Environmental Regulation................................76 SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT..............................77 Partnership Distributions..............................................77 Deposit and Use of Funds...............................................77 Power and Authority....................................................78 Rollup or Consolidation of the Partnership.............................78 Limited Liability......................................................79 Records, Reports and Returns...........................................79 Transferability of Interests...........................................80 Amendments.............................................................81 Voting Rights..........................................................82 Exculpation and Indemnification of the General Partner.................82 Termination............................................................83 Insurance..............................................................83 COUNSEL...................................................................83 GLOSSARY..................................................................84 FINANCIAL STATEMENTS......................................................87 |
EXHIBIT A - AGREEMENT OF LIMITED PARTNERSHIP
EXHIBIT B - LEGAL OPINION
SUMMARY OF PROGRAM
This summary is not 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 2003 Employee Oil and Gas Limited Partnership, a proposed Oklahoma limited partnership (the "Partnership"), offers 600 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 27, 2003 (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, 2003 and the remaining three of such Installments being due on June 15, September 15, and December 15, 2003, respectively, or (ii) through equal deductions from 2003 salary commencing immediately after formation of the Partnership.
The purchase price of each Unit is $1,000, and the minimum permissible 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 2003. Each member of the Board of Directors of UNIT may subscribe for up to 200 Units ($200,000). The Partnership must sell at least 50 Units ($50,000) before the Partnership 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 required for formation of the Partnership. The Partnership will terminate on December 31, 2033, 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 2003 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 whose annual base salaries for 2003 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 2003. Directors' subscriptions may not be for more than 200 Units ($200,000). 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, 2004, 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 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, 2004 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.
. 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.
. Certain allocations of income, gain, loss and deduction of the Partnership among the Partners may be challenged by the Internal Revenue Service (the "Service"). A successful challenge would likely result in a Limited Partner having to report additional taxable income or being denied a deduction.
. Investment as a Limited Partner may be less advisable for a person who does not have substantial current taxable income from trade or business activities in which the Limited Partner does not materially participate.
. Federal income tax payable by a Limited Partner by reason of his or her allocated share of Partnership income for any year may exceed the Partnership distributions to a Limited Partner for the year.
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 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, 2003, if the Partnership is formed prior to such date or from the date of the formation of the Partnership if subsequent to January 1, 2003, until December 31, 2003, 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 2003. 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 2003. 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 2003.
Application of Proceeds
The offering proceeds will be used to pay the Leasehold Acquisition 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:
$600,000 $50,000
Program Program
Leasehold Acquisition Costs
of Properties to Be Drilled........... $30,000 $2,500
Drilling Costs of Exploratory
Wells(1).............................. 30,000 2,500
Drilling Costs of Development
Wells(1).............................. 420,000 35,000
Leasehold Acquisition Costs of
Productive Properties................. 120,000 10,000
Reimbursement of General
Partner's Overhead Costs(2)........... -- --
-------- -------
Total.................................... $600,000 $50,000
---------------
(1) See "GLOSSARY."
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(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 Limited
Partner's Minimum Capital Partner's Partners'
Contribution...................... Percentage(1) Percentage(1)
General Limited
Partner's Partners'
REVENUES................................ Percentage(1) Percentage(1)
---------------
1) See "GLOSSARY."
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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 Considerations; Opinion of Counsel
The General Partner has received an opinion from its tax counsel, Conner & Winters, P.C. ("Conner & Winters"), concerning all material federal income tax issues applicable to an investment in the Partnership. To be fully understood, the complete discussion of these matters set forth in the full tax opinion in Exhibit B should be read by each prospective investor. Based upon current laws, regulations, interpretations, and court decisions, Conner & Winters has rendered its opinion that (i) the material federal income tax benefits in the aggregate from an investment in the Partnership will be realized; (ii) the Partnership will be treated as a partnership for federal income tax purposes and not as a corporation and not as an association taxable as a corporation; (iii) to the extent the Partnership's wells are timely drilled and its drilling costs are timely paid, then subject to the limitations on deductions discussed in such opinion, the Partners will be entitled to claim as deductions their pro rata shares of the Partnership's intangible drilling and development costs ("IDC") paid in 2003; (iv) for most Limited Partners, the Partnership's operations will be considered a passive activity within the meaning of Section 469 of the Internal Revenue Code of 1986, as amended (the "Code"), and losses generated therefrom will be limited by the passive activity provisions of the Code; (v) to the extent provided herein, the Partners' distributive shares of Partnership tax items will be determined and allocated substantially in accordance
with the terms of the Partnership Agreement; and (vi) the Partnership will not be required to register with the Service as a tax shelter.
Due to the lack of authority regarding, or the essentially factual nature of certain issues, Conner & Winters expresses no opinion on the following: (i) the impact of an investment in the Partnership on an investor's alternative minimum tax liability; (ii) whether, under Code Section 183, the losses of the Partnership will be treated as derived from "activities not engaged in for profit," and therefore nondeductible from other gross income (due to the inherently factual nature of a Partner's interest and motive in investing in the Partnership); (iii) whether any of the Partnership's properties will be considered "proven" for purposes of depletion deductions; (iv) whether any interest incurred by a Partner with respect to any borrowings incurred to purchase Units will be deductible or subject to limitations on deductibility; and (v) whether the Partnership will be treated as the tax owner of Partnership Properties acquired by the General Partner as nominee for the Partnership.
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, 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 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, 2003, if the Partnership is formed prior to such date, or from the date of the formation of the Partnership, if subsequent to January 1, 2003, through December 31, 2003 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 2003. 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 2003. 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 2003 and will have no rights in production from wells commenced in years other than 2003. Likewise, if additional interests are acquired in wells participated in by the Partnership after 2003, 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 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, 2004, 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 (allocated) 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 2004. In addition, to the extent that the Partnership uses its revenues to repay borrowings or to finance its activities (see "ADDITIONAL FINANCING"), the funds available for cash distributions by the Partnership will be reduced or may be unavailable. It is possible that the amount of tax payable by a Limited Partner on his or her distributive share of the income of the Partnership will exceed his or her cash distributions from the Partnership. See "FEDERAL INCOME TAX CONSIDERATIONS."
If and 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
(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 would 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 funds to pay certain costs of the Partnership. While the use of financing to preserve the Partnership's equity in oil and gas properties will be intended to increase the 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 Conner & Winters 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 Partnership's business and, thus, should result in greater certainty and more easily obtainable opinions of Conner & Winters 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 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 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 2003. 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 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 Retirement (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 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.
Title To Properties
The Partnership Agreement empowers the General Partner, UNIT or any of their affiliates, to hold title to the Partnership Properties for the benefit of the Partnership. As such it is possible that the Partnership Properties could be subject to the claims of creditors of the General Partner. The General Partner is of the opinion that the likelihood of the occurrence of such claims is remote. However, the Partnership Property could be subject to claims and litigation in the event that the General Partner failed to pay its debts or became subject to the claims of creditors.
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 STATUS AND TAX RISKS
It is possible that the tax treatment currently available with respect to oil and gas exploration and production will be modified or eliminated on a retroactive or prospective basis by legislative, judicial, or administrative actions. The limited tax benefits associated with oil and gas exploration do not eliminate the inherent economic risks. See "Federal Income Tax Considerations."
Partnership Classification
Conner & Winters has rendered its opinion that the Partnership will be classified for federal income tax purposes as a partnership and not as a corporation, an association taxable as a corporation or a "publicly traded partnership." Such opinion is not binding on the Service or the courts. If the Partnership were classified as a corporation, association taxable as a corporation or publicly traded partnership, any income, gain, loss, deduction, or credit of the Partnership would remain at the entity level, and not flow through to the Partners, the income of the Partnership would be subject to corporate tax rates at the entity level and distributions to the Partners could be considered dividend distributions. See "Federal Income Tax Considerations--General Tax Effects of Partnership Structure."
Limited Partner Interests
An investment as a Limited Partner may not be advisable for a person who does not anticipate having substantial current taxable income from passive trade or business activities (not counting dividend or interest income). Such a person cannot utilize any passive losses generated by the Partnership until and unless he or she has realized "passive income". Partnership income, losses, gains, and deductions allocable to most Limited Partners will be subject to the "passive activity loss" rules.
Tax Liabilities in Excess of Cash Distributions
For any taxable year, federal income tax payable by a Partner by reason of his or her distributive share of Partnership taxable income may exceed the cash distributed to such Partner by the Partnership. A Partner must include in his or her own income tax return for a taxable year his or her share of the items of the Partnership's income, gain, profit, loss, and deductions for the year, to the extent required under the Code as then in effect, whether or not cash proceeds are actually distributed to the Partner. For example, income from the Partnership's sale of gas production will be taxable to Partners as ordinary income subject to depletion and other deductions whether or not the proceeds from such sale are actually distributed (for example, where Partnership income is used to repay Partnership indebtedness).
Items Not Covered by the Tax Opinion
Due to the lack of authority regarding, or the essentially factual nature of certain issues, Conner & Winters has expressed no opinion as to the following: (i) the impact of an investment in the Partnership on an investor's alternative minimum tax liability; (ii) whether, under Code Section 183, the losses of the Partnership will be treated as derived from "activities not engaged in for profit," and therefore nondeductible from other gross income (due to the inherently factual nature of a Partner's interest and motive in investing in the Partnership); (iii) whether any of the Partnership's properties will be considered "proven" for purposes of depletion deductions; (iv) whether interest paid by a Partner with respect to any borrowings incurred to purchase Units will be deductible or subject to limitations on deductibility; and (v) whether the Partnership will be treated as the tax owner of Partnership Properties acquired by the General Partner as nominee for the Partnership.
The determination of various of the above-referenced issues is dependent on facts not currently available. Therefore, Conner & Winters is unable to render an opinion at this time with respect to such issues. Also, the unknown facts with respect to the various issues referred to above will vary from Partner to Partner and will result in different tax consequences and burdens for individual Partners.
Prospective investors should recognize that an opinion of Conner & Winters merely represents Conner & Winters' best legal judgment under existing statutes, judicial decisions, and administrative regulations and interpretations. There can be no assurance that some of the deductions claimed by the Partnership in reliance upon an opinion of Conner & Winters will not be challenged successfully by the Service.
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, 2003 or the time the Partnership is formed through December 31, 2003 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 2003.
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
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 production, gathering and transportation, (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.
Markets for Oil and Natural Gas Production
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. Until recently, however, members of OPEC were unable to agree to and maintain price and production controls, which resulted in significant downward pressure on oil prices. Commencing in early 2001, OPEC members were able to reach agreement on oil production levels which has contributed to a rise in 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 oil that the Partnership produces can be marketed on favorable price and other contractual terms. See "COMPETITION, MARKETS AND REGULATION -- Marketing of Production."
The natural gas market is also unsettled due to a number of factors. In the past, production from natural gas wells in some geographic areas of the United States was curtailed for considerable periods of time due to a lack of market demand. Over the past several years demand for natural gas has increased greatly limiting the number of wells being shut in for lack of demand. It is possible, however, that Partnership Wells may in the future be shut-in or that natural gas will be sold on terms less favorable than might otherwise be obtained should demand for gas lessen in the future. 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 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
. 600 Maximum Units; 50 Minimum Units
. $1,000 Units; Minimum subscription: $2,000
. Minimum Partnership: $50,000 in subscriptions
. Maximum Partnership: $600,000 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 600 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.
The offering of Units will be closed on January 27, 2003 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 whose annual base salaries for 2003 (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 2003. Each director of UNIT may subscribe for a maximum of 200 Units (maximum investment of $200,000). At December 4, 2002 there were approximately 262 people eligible to purchase Units.
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, 2003 and the remaining three of such Installments being due on June
15, September 15, and December 15, 2003, respectively, or (ii) by employees so
electing in the space provided on the Subscription Agreement, through equal
deductions from 2003 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 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, 2004, 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
(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 determinations of the prices to be used as well as the escalations, if any, of such prices and cost 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 or her 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 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 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. 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 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 2002, Additional Assessments could be called for as provided herein. At September 30, 2002, 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.
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. The Units will be offered and sold by the officers and directors of UPC or UNIT.
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.
UNIT CORPORATION
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| General Partner |
| --------------- |
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| Unit Petroleum Company | | Unit Drilling Company |
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| Unit 2003 Employee Oil |
| & Gas Limited |
| Partnership |
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| Limited Partners
| ----------------
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| Eligible Employees |
| and |
| Directors |
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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 2003. The Partnership will acquire 2 1/2% 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 2003 and (ii) serving as a co-general partner in any drilling or income programs, or both, formed by the General Partner or UNIT during 2003.
Acquisition of Properties and Drilling Operations. The Partnership will participate, to the extent of 2 1/2% 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, 2003, or the time of the formation of the Partnership if subsequent to January 1, 2003, until December 31, 2003, 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;
(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 standpoint. 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 2003. The Partnership will be charged with 2 1/2% of the total costs and expenses charged to the general partners and allocated 2 1/2% of the revenues allocable to the general partners in any such program and UPC or UNIT will be charged with the remaining 97 1/2% of the general partners' share of costs and expenses and allocated the remaining 97 1/2% 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 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 2002. Although it does not currently contemplate doing so, UNIT may form such drilling or income programs during 2003. 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 2003 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 2003 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, 97 1/2% for the account of UNIT and/or UPC and 2 1/2% 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.
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 2003 nor can it predict what producing properties, if any, will be acquired by it during 2003. 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 125 to 150 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 7% on Exploratory Wells and 93% 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 2003. In either instance, the Partnership will have an interest only in those wells begun in 2003 and will have no rights in production from wells commenced in years other than 2003 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 2003, 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."
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 2003. 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 2003.
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 of the original spacing unit unless such additional wells are commenced during 2003. If additional interests in Partnership Wells are
acquired in years subsequent to 2003 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 2003. 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 General Partner. However, the General Partner will hold the Partnership Properties as a nominee for the Partnership under a form of nominee agreement to be entered into between the General Partner and the Partnership. Under the form of nominee agreement, the General Partner 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 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 600 Units offered hereby are sold, the proceeds to the Partnership would be $600,000. 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:
$600,000 Program $50,000 Program
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Percent Amount Percent Amount
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Leasehold Acquisition Costs
of Properties to Be Drilled... 5% $ 30,000 5% $ 2,500
Drilling Costs of Exploratory
Wells......................... 5% 30,000 5% 2,500
Drilling Costs of Develop-
ment Wells.................... 70% 420,000 70% 35,000
Leasehold Acquisition Costs
of Productive Properties...... 20% 120,000 20% 10,000
Total....................... 100% $600,000 100% $50,000
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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.
Until Capital Contributions are invested in the Partnership's operations, they will be temporarily deposited, with or without interest, 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 offering and syndication of any drilling or income program formed by UPC or UNIT and its affiliates during 2003 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 determined as of December 31, 2003 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, 2003 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 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:
General Limited
Partner Partners
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COSTS AND EXPENSES
. 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%
30
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. After expenditure of
Limited Partner Capital
Contributions and until
expenditure of General
Partner's Minimum Capital
Contribution........................... 100% 0%
After expenditure of
General Partner's General Limited
Minimum Capital Partner's Partners'
Contribution........................... Percentage Percentage
General Limited
Partner's Partners'
REVENUES Percentage Percentage
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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 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, geological, engineering, travel, office rent, telephone, secretarial, salaries, 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 reimbursed 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 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 40% interest in Superior Pipeline Company, L.L.C., an Oklahoma limited liability company, which may build or own an interest in certain gathering systems through which a portion of the Partnership's gas production is transported.
These persons are in the business of supplying such equipment and services to non-affiliated parties in the industry and any such equipment and such services will be acquired or provided at prices or rates no higher than those normally charged in the same or comparable geographic 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 therefore 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 predecessor, 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, 2002, is set forth below.
Compensation
for
Supervision Reimbursement
and of General
Operation of Administra- Fees
Productive tive Received as
and and Overhead a Drilling
Management Drilling Expense(2) Contractor
Program Fee(1) Wells(2)(3) (3)(4) (2)
------- ------------- ----------- ----------- ----------
1979................ 150,000 2,723,146 2,495,263 1,835,762
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................ - 287,414 914,271 829,503
1984 Employee(*).... - 3,924 5,000 13,452
1985 Employee(*).... - 10,316 - 54,892
1986 Energy
Income Fund(**)..... - 314,750 1,119,372 64,945
1986 Employee(*).... - 23,505 - 59,446
1987 Employee(*).... - 50,688 - 97,079
1988 Employee(*).... - 93,854 - 112,861
1989 Employee(*).... - 54,536 - 165,436
1990 Employee(*).... - 28,884 - 144,722
1991 Employee....... - 557,299 - 144,993
1992 Employee....... - 155,039 - 14,934
1993 Employee....... - 83,269 - 68,504
Consolidated
Program(*).......... - 169,465 - -
1994 Employee....... - 117,902 - 41,807
1995 Employee....... - 70,000 - 35,903
1996 Employee....... - 81,435 - 112,911
1997 Employee....... - 71,359 - 170,174
1998 Employee....... - 53,953 - 161,259
1999 Employee....... - 88,323 - 186,408
2000 Employee....... - 41,223 - 600,775
2001 Employee....... - 8,164 - 363,567
2002 Employee....... - 959 - 138,887
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(*) 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 - 2002 Employee Programs and no management fee is payable by the Partnership to UNIT or any of its affiliates.
(2) Paid only to UDEC.
(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 partnership revenues being allocated to them.
(4) Although the partnership agreement for each of the 1985 - 2002 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 predecessor, 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 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 75 Chairman of the Board
and Director
John G. Nikkel 67 President, Chief
Executive Officer,
Chief Operating
Officer and Director
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Name Age Position
---- --- --------
O. Earle Lamborn 67 Senior Vice President,
Drilling and Director
Philip M. Keeley 61 Senior Vice President,
Exploration and
Production
Larry D. Pinkston 48 Vice President,
Treasurer and Chief
Financial Officer
Mark E. Schell 45 Secretary and General
Counsel
William B. Morgan 58 Director
Don Cook 77 Director
John S. Zink 74 Director
John H. Williams 84 Director
J. Michael Adcock 53 Director
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The names, ages and respective positions of the directors and executive officers of UPC are as follows:
Name Age Position
---- --- --------
John G. Nikkel 67 Chairman of the Board,
President and Director
Philip M. Keeley 61 Vice President and
Director
Mark E. Schell 45 Secretary and General
Counsel
Larry Pinkston 48 Treasurer
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Mr. Kirchner, a co-founder of UNIT, has been the Chairman of the Board and a director since 1963. He served as the Company's President until November 1983 and as its Chief Executive Officer until June 30, 2001. 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, with honors, from the University of Oklahoma. Following graduation, he was employed by Lufkin Manufacturing as a development engineer for hydraulic pumping units. Prior to co-founding Unit he served in the US Army during the Korean War and after that as vice-president engineering and operations for Woolaroc Oil Company.
Mr. Nikkel joined UNIT in 1983 as its President and a director. On July 1, 2001 Mr. Nikkel was elected to the additional office of Chief Executive Officer. 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 Cotton from 1979 until his departure. Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production Company for 18 years, last serving as Division Geologist for Amoco's Denver Division. Mr. Nikkel presently serves as President and a director of Nike Exploration Company. Mr. Nikkel received a Bachelor of Science degree in Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 50 years, joining UNIT's predecessor in 1952 prior to its becoming a publicly-held corporation. He was elected Vice President, Drilling in 1973 and to his current position as Senior Vice President, Drilling 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, until November 2001, served 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 had 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. In December 2002, he was elected to the additional position of Executive Vice President. 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 1987, as its Secretary and General Counsel. In December 2002, he was elected to the additional position of Senior Vice President. 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. He is a member of the Oklahoma and American Bar Association as well as being a member of the American Corporate Counsel Association and the American Society of Corporate Secretaries.
Mr. Morgan was elected a director of UNIT in February 1988. Mr. Morgan has been Executive Vice President and General Counsel of St. John Health System, Inc., Tulsa, Oklahoma, since March 1, 1995 and, since October 1, 1996, the President of its principal for profit subsidiary Utica Services, Inc. Before that, he was a Partner in the law firm of Doerner, Saunders, Daniel & Anderson, Tulsa, Oklahoma, for over 20 years.
Mr. Cook has served as a director of UNIT since UNIT's inception. He is a Certified Public Accountant and was a partner in the accounting firm of Finley & Cook, Shawnee, Oklahoma, from 1950 until 1987, when he retired.
Mr. Zink was elected a director of UNIT in May 1982. For over 5 years, he has been a principal in several privately held companies engaged in the businesses of designing and manufacturing equipment used in the petroleum industry, construction and heating and air conditioning services and
installation. He holds a Bachelor of Science degree in Mechanical Engineering from Oklahoma State University. He is also a director of Matrix Service Company, Tulsa, Oklahoma.
Mr. Williams was elected a director of UNIT in December 1988. Prior to retiring on December 31, 1978, he was Chairman of the Board and Chief Executive Officer of The Williams Companies, Inc. where he continues to serve as an honorary director. Mr. Williams also serves as a director of Apco Argentina, Inc., and Willbros Group, Inc. In addition, Mr. Williams also serves as a director of the Gilcrease Museum and is a member of the Tulsa Performing Arts Center Trust.
Mr. Adcock was elected a director of UNIT in December 1997. He is an attorney and currently manages a private trust that deals in real estate, oil and gas properties and other equity investments. He is Chairman of the Board of Arvest Bank, Shawnee and Community Health Partners, Inc. , formerly Mid America Heathcare, Inc. Between 1997 through September, 1998 he was the Chairman of the Board of Ameribank and President and Chief Executive Officer of American National Bank and Trust Company of Shawnee, Oklahoma, and Chairman of AmeriTrust Corporation, Tulsa, Oklahoma. Prior to holding these positions, he was engaged in the private practice of law and served as General Counsel for Ameribank Corporation.
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'
Capital
Name Formed 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
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
37
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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 Unit 1996 Employee Oil and Gas Limited Partnership February 5, 1996 $437,000 Unit 1997 Employee Oil and Gas Limited Partnership February 4, 1997 $413,000 Unit 1998 Employee Oil and Gas Limited Partnership February 19, 1998 $471,000 Unit 1999 Employee Oil and Gas Limited Partnership February 22, 1999 $188,000 Unit 2000 Employee Oil and Gas Limited Partnership February 22, 2000 $199,000 Unit 2001 Employee Oil and Gas Limited Partnership February 9, 2001 $370,000 Unit 2002 Employee Oil and Gas Limited Partnership January 30, 2002 $457,000 |
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 1999 Employee Programs. The capital subscriptions of the following limited partners to the 2000, 2001 and 2002 Employee Programs were as shown below:
Amount of Capital
Subcription
Position with -----------
Subscriber UNIT 2000 2001 2002
---------- ---- ---- ---- ----
King P. Chairman of the Board and
Kirchner Director $ 0 $ 25,000(1) $100,000(1)
Chief Executive Officer,
John G. President, Chief Operating
Nikkel Officer and Director $114,264(2) $151,400(2) $100,000(2)
Philip M. Senior Vice President,
Keeley Exploration and Production $ 33,736(2) $ 43,600(2) $ 40,000(2)
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(1) Mr. Kirchner invested $25,000 indirectly in the 2001 Employee Program and $100,000 in the 2002 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 2000, 2001 and 2002 Employee Programs both directly and through Nike Exploration Company which until October of 2001 was owned 71.4% by Mr. Nikkel and members of his family and 28.6% by Mr. Keeley. Subsequent to October of
2001, Mr. Nikkel and members of his family were the sole owners of Nike Exploration Company. The amounts invested directly and indirectly through Nike Exploration Company in the 2000, 2001 and 2002 Employee Programs by Messrs. Nikkel and Keeley are set forth below:
Nike
Employee Mr. Nikkel Mr. Keeley Exploration
Program Directly Directly Company
-------- ---------- ---------- -----------
2000 $ 60,000 $12,000 $ 76,000
2001 $ 80,000 $15,000 $100,000
2002 $100,000 $40,000 $100,000
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Ownership of Common Stock
UNIT's Common Stock is listed on the New York Stock Exchange as reported on the Composite Tape. On December 3, 2002 there were 43,337,300 shares outstanding.
As of December 3, 2002, the directors and officers of UNIT owned of record or beneficially owned shares of UNIT Common Stock as follows:
Amount of
Beneficial % of
Name Ownership (1) Outstanding (1)
---- --------- -----------
King P. Kirchner............. 677,128 (2) 1.56
John Williams................ 11,000 (3) *
Don Cook..................... 31,118 (3) *
Philip M. Keeley............. 135,725 (2)(4) *
Earle Lamborn................ 271,507 (2)(4) *
John G. Nikkel............... 436,409 (2)(4) *
Larry D. Pinkston............ 63,243 (2)(4) *
Mark E. Schell............... 67,608 (2)(4) *
John S. Zink................. 71,500 (3) *
William B. Morgan............ 20,400 (3) *
J. Michael Adcock............ 602,291 (3)(5) 1.38
All Officers and Directors
as a Group................ 2,387,929 5.47
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*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 December 3, 2002, pursuant to the exercise of currently exercisable 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 December 3, 2002 pursuant to the exercise of currently exercisable stock options.
(2) Includes shares of common stock held under UNIT's 401(k) thrift plan as of December 4, 2002 for the account of: Earle Lamborn, 13,979; John G. Nikkel, 31,682; Philip M. Keeley, 11,991; Larry D. Pinkston, 2,268; and Mark E. Schell, 30,197.
(3) 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: J. Michael Adcock, 15,500; Don Cook, 25,500; William B. Morgan, 14,500; John H. Williams, 7,000; John S. Zink, 28,000; and King P. Kirchner 3,500 shares and all non-Employee Directors as a group, 94,000.
(4) Includes unexercised stock options granted under UNIT's Amended and Restated Stock Option Plan to each of the following, all of which are exercisable within 60 days from December 3, 2002 at the discretion of the holder: John G. Nikkel 95,000; Philip M. Keeley, 37,500; Earle Lamborn, 43,500; Larry D. Pinkston, 20,100; and Mark E. Schell, 20,100.
(5) Of the shares shown, Mr. J. Michael Adcock is deemed to be the beneficial owner of 585,791 shares by virtue of his position as one of three trustees of the Don Bodard 1995 Revocable Trust.
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, 2003, or from the formation of the Partnership if subsequent to January 1, 2003, through December 31, 2003 except for wells:
(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;
(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 2003. 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 economic 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 profitable. Thus, there can be no assurance that the General Partner will always make the most profitable decision from the Partnership's standpoint 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 same prospect area unless the drilling of those wells commences during the period from January 1, 2003, or from the formation of the Partnership if subsequent to January 1, 2003, through December 31, 2003. 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, 2003, or from the formation of the Partnership if subsequent to January 1, 2003, through December 31, 2003. Likewise the Partnership would have no interest in any increased density wells
drilled on the original spacing unit unless such wells were drilled during 2003. In addition, if additional interests are acquired in wells participated in by the Partnership after 2003, 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 2003, 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.
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 Partnership 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 2003.
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 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 Partnership will be fairly and equitably apportioned according to the respective 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 40% interest in Superior Pipeline Company, L.L.C. which is engaged in the business of buying and building gas gathering systems. It is anticipated that the Partnership will obtain services, equipment and supplies from one or both 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.
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 "PARTICIPATION IN COSTS AND REVENUES" and "COMPENSATION." Such fees, compensation 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, P.C. 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 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 or her 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 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 therefore.
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 following table depicts the drilling results achieved as of September 30, 2002 by UNIT during each year since 1975. Because of the unpredictability of oil and gas exploration in general, such results 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
----- ------ ----- ------ ------- ------- ------- -------
Gross Wells (2) Net Wells(3)
Year Ended --------------- ------------
December 31(1) Total Oil Gas Dry Total Oil Gas Dry
-------------- ----- ------ ----- ------ ------- ------- ------- -------
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
----- ------ ----- ------ ------- ------- ------- -------
|
Gross Wells (2) Net Wells(3)
Year Ended --------------- ------------
December 31(1) Total Oil Gas Dry Total Oil Gas Dry
-------------- ----- ------ ----- ------ ------- ------- ------- -------
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
----- ------ ----- ------ ------- ------- ------- -------
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
----- ------ ----- ------ ------- ------- ------- -------
1995 Exploratory...... 0 0 0 0 0 0 0 0
Development...... 45 15 24 6 14.94 4.67 8.04 2.23
----- ------ ----- ------ ------- ------- ------- -------
Total........ 45 15 24 6 14.94 4.67 8.04 2.23
----- ------ ----- ------ ------- ------- ------- -------
1996 Exploratory...... 0 0 0 0 0 0 0 0
Development...... 70 10 51 9 32.09 7.61 20.09 4.39
----- ------ ----- ------ ------- ------- ------- -------
Total........ 70 10 51 9 32.09 7.61 20.09 4.39
----- ------ ----- ------ ------- ------- ------- -------
1997 Exploratory...... 2 0 0 2 2.00 0 0 2.00
Development...... 80 8 58 14 35.94 4.35 23.29 8.30
----- ------ ----- ------ ------- ------- ------- -------
Total........ 82 8 58 16 37.94 4.35 23.29 10.30
----- ------ ----- ------ ------- ------- ------- -------
|
Gross Wells (2) Net Wells(3)
Year Ended --------------- ------------
December 31(1) Total Oil Gas Dry Total Oil Gas Dry
-------------- ----- ------ ----- ------ ------- ------- ------- -------
1998 Exploratory...... 2 0 1 1 .63 0 .375 .26
Development...... 76 3 52 21 30.17 .31 18.750 11.11
----- ------ ----- ------ ------- ------- ------- -------
Total........ 78 3 53 22 30.80 .31 19.125 11.37
----- ------ ----- ------ ------- ------- ------- -------
1999 Exploratory...... 0 0 0 0 0 0 0 0
Development...... 51 1 42 8 21.8 .4 17.4 4.0
----- ------ ----- ------ ------- ------- ------- -------
Total........ 51 1 42 8 21.8 .4 17.4 4.0
----- ------ ----- ------ ------- ------- ------- -------
2000 Exploratory...... 2 0 2 0 1.72 0 1.72 0
Development...... 98 7 73 18 38.37 1.45 28.55 8.37
----- ------ ----- ------ ------- ------- ------- -------
Total........ 100 7 75 18 40.09 1.45 30.27 8.37
----- ------ ----- ------ ------- ------- ------- -------
2001 Exploratory...... 3 0 0 3 2.03 0 0 2.03
Development...... 123 7 94 22 49.94 1.08 34.12 14.74
----- ------ ----- ------ ------- ------- ------- -------
Total........ 126 7 94 25 51.97 1.08 34.12 16.77
----- ------ ----- ------ ------- ------- ------- -------
Period of January 1,
2002 to
September 30, 2002
Exploratory...... 4 0 1 3 .38 0 .01 .37
Development...... 57 3 42 12 32.58 1.62 21.57 9.39
----- ------ ----- ------ ------- ------- ------- -------
Total........ 61 3 43 15 32.96 1.62 21.58 9.76
----- ------ ----- ------ ------- ------- ------- -------
---------------
|
(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 interest 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 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 contributions thereto plus UNIT's interest costs with respect to the unrecovered 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 generally, 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 2002, 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 - 2001 Employee Programs, in which case the percentage was 5% and the 2001 and 2002 Employee Programs in which case the percentage was 2 1/2%) 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.
As noted above, the Funds and the Employee Programs have participated in a specified percentage (ranging from 2 1/2% to 15%, depending on the program) 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.
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, 2002, and the economic results at September 30, 2002 of prior oil and gas programs and the 1984 - 2002 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 all of the Employee Programs formed since 1991. 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.
DRILLING RESULTS
As of September 30, 2002
Gross Wells Net Wells
----------- ---------
Programs 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, 2002
Gross Wells Net Wells
----------- ---------
Programs Total Oil Gas Dry Total Oil Gas Dry
-------- ----- ------ ----- ------ ------- ------- ------- -------
1984(1)
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 25 4 12 9 .14 .02 .06 .06
----- ------ ----- ------ ------- ------- ------- -------
Total................. 25 4 12 9 .14 .02 .06 .06
----- ------ ----- ------ ------- ------- ------- -------
1985(1)
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 30 8 10 12 .38 .12 .08 .18
----- ------ ----- ------ ------- ------- ------- -------
Total................. 30 8 10 12 .38 .12 .08 .18
----- ------ ----- ------ ------- ------- ------- -------
1986(1)
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 18 6 8 4 .48 .12 .30 .06
----- ------ ----- ------ ------- ------- ------- -------
Total................. 18 6 8 4 .48 .12 .30 .06
----- ------ ----- ------ ------- ------- ------- -------
1987(1)
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 21 12 5 4 1.17 .74 .25 .18
----- ------ ----- ------ ------- ------- ------- -------
Total................. 21 12 5 4 1.17 .74 .25 .18
----- ------ ----- ------ ------- ------- ------- -------
1988(1)
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
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)
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 32 7 14 11 1.48 .59 .36 .53
----- ------ ----- ------ ------- ------- ------- -------
Total................. 32 7 14 11 1.48 .59 .36 .53
----- ------ ----- ------ ------- ------- ------- -------
1990(1)
Empl.
Exploratory Wells..... 5 0 2 3 .122 0.00 .01 .11
Development Wells..... 34 11 14 9 1.65 .83 .35 .46
----- ------ ----- ------ ------- ------- ------- -------
Total................. 39 11 16 12 1.78 .83 .36 .57
----- ------ ----- ------ ------- ------- ------- -------
1991
Empl.
Exploratory Wells..... 4 0 0 4 .08 0.00 0.00 .08
Development Wells..... 28 10 9 9 1.59 .86 .39 .34
----- ------ ----- ------ ------- ------- ------- -------
Total................. 32 10 9 13 1.67 .86 .39 .42
----- ------ ----- ------ ------- ------- ------- -------
1992
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 18 1 11 6 .29 .05 .17 .07
----- ------ ----- ------ ------- ------- ------- -------
Total................. 18 1 11 6 .29 .05 .17 .07
----- ------ ----- ------ ------- ------- ------- -------
1993
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 16 9 6 1 .63 .45 .17 .01
----- ------ ----- ------ ------- ------- ------- -------
Total................. 16 9 6 1 .63 .45 .17 .01
----- ------ ----- ------ ------- ------- ------- -------
1994
Empl.
Exploratory Wells..... 3 0 1 2 .09 0.00 .05 .04
Development Wells..... 57 5 40 12 1.29 .24 .70 .35
----- ------ ----- ------ ------- ------- ------- -------
Total................. 60 5 41 14 1.38 .24 .75 .39
----- ------ ----- ------ ------- ------- ------- -------
1995
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 45 15 24 6 .74 .23 .40 .11
----- ------ ----- ------ ------- ------- ------- -------
Total................. 45 15 24 6 .74 .23 .40 .11
----- ------ ----- ------ ------- ------- ------- -------
1996
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 53 7 38 8 1.24 .27 .76 .21
----- ------ ----- ------ ------- ------- ------- -------
Total................. 53 7 38 8 1.24 .27 .76 .21
----- ------ ----- ------ ------- ------- ------- -------
|
Gross Wells Net Wells
----------- ---------
Programs Total Oil Gas Dry Total Oil Gas Dry
-------- ----- ------ ----- ------ ------- ------- ------- -------
1997
Empl.
Exploratory Wells..... 2 0 0 2 .10 0.00 0.00 .10
Development Wells..... 80 8 58 14 1.80 .22 1.16 .42
----- ------ ----- ------ ------- ------- ------- -------
Total................. 82 8 58 16 1.90 .22 1.16 .52
----- ------ ----- ------ ------- ------- ------- -------
1998
Empl.
Exploratory Wells..... 2 0 1 1 .03 0.00 .02 .01
Development Wells..... 76 3 52 21 1.51 .02 .94 .56
----- ------ ----- ------ ------- ------- ------- -------
Total................. 78 3 53 22 1.54 .02 .96 .57
----- ------ ----- ------ ------- ------- ------- -------
1999
Empl.
Exploratory Wells..... 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells..... 51 1 42 8 1.09 .02 .87 .20
----- ------ ----- ------ ------- ------- ------- -------
Total................. 51 1 42 8 1.09 .02 .87 .20
----- ------ ----- ------ ------- ------- ------- -------
2000
Empl.
Exploratory Wells..... 2 0 2 0 .09 0.00 .09 0.00
Development Wells..... 98 7 73 18 1.92 .07 1.43 .42
----- ------ ----- ------ ------- ------- ------- -------
Total................. 100 7 75 18 2.01 .07 1.52 .42
----- ------ ----- ------ ------- ------- ------- -------
2001
Empl.
Exploratory Wells..... 3 0 0 3 .05 0.00 0.00 .05
Development Wells..... 123 7 94 22 1.25 .03 .85 .37
----- ------ ----- ------ ------- ------- ------- -------
Total................. 126 7 94 25 1.30 .03 .85 .42
----- ------ ----- ------ ------- ------- ------- -------
2002
Empl.
Exploratory Wells..... 4 0 1 3 .01 0.00 0.00 .01
Development Wells..... 57 3 42 12 .82 .04 .78 0.00
----- ------ ----- ------ ------- ------- ------- -------
Total................. 61 3 43 15 .83 .04 .78 .01
----- ------ ----- ------ ------- ------- ------- -------
---------------
|
(1) Effective December 31, 1993 this Program was merged with and into the Consolidated Program.
GENERAL PARTNERS' PAYOUT TABLE(1)
As of September 30, 2002
Total
Revenues
Before
Deducting
Total Operating
Total Revenues Costs
Expenditures Before for 3 Months
Including Deducting Ended
Operating Operating September 30,
Program Costs(2) Costs 2002
------- -------- ----- ----
1979............... $8,680,055 $10,723,123 $16,976
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............... 2,463,539 2,135,735 22,459
1984 Employee(*)... 1,542 1,745 -
1985 Employee(*)... 2,820 1,808 -
1986 Energy
Income Fund(**).... 1,675,234 1,749,312 16,054
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...... 2,316,972 2,982,144 47,494
1992 Employee...... 237,800 392,505 6,509
1993 Employee...... 484,248 709,061 7,427
Consolidated
Program............ 16,514 15,021 294
1994 Employee...... 1,417,597 1,797,038 31,186
1995 Employee...... 484,461 587,263 9,519
1996 Employee...... 897,447 852,709 12,412
1997 Employee...... 1,251,738 1,132,057 28,779
1998 Employee...... 1,164,961 1,030,506 39,295
1999 Employee...... 932,790 1,255,997 46,747
2000 Employee...... 1,852,868 1,681,199 76,522
2001 Employee...... 879,481 235,808 47,293
2002 Employee...... 299,615 55,108 32,988
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(*) 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.
LIMITED PARTNERS' PAYOUT TABLE(1)
As of September 30, 2002
Total
Revenues
Before
Deducting
Total Operating
Total Revenues Costs
Expenditures Before for 3 Months
Including Deducting Ended
Operating Operating September 30,
Program Costs(2) Costs 2002
------- -------- ----- ----
1979............... $14,605,719 $18,687,656 $20,748
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............... 3,118,590 2,230,338 22,459
1984 Employee(*)... 120,942 171,540 -
1985 Employee(*)... 277,901 178,984 -
1986 Energy
Income Fund(**).... 2,725,195 3,744,463 24,193
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...... 610,721 794,939 12,625
1992 Employee...... 612,995 1,013,387 16,737
1993 Employee...... 440,661 656,598 6,747
Consolidated
Program............ (379,965) 1,487,654 28,618
1994 Employee...... 575,005 736,120 12,728
1995 Employee...... 774,015 923,897 14,881
1996 Employee...... 549,392 524,462 7,601
1997 Employee...... 583,763 509,596 12,927
1998 Employee...... 605,594 524,038 20,302
1999 Employee...... 283,370 375,167 13,963
2000 Employee...... 254,558 229,383 10,434
2001 Employee...... 402,838 105,943 21,247
2002 Employee...... 245,139 45,088 26,990
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(*) 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.
GENERAL PARTNERS' NET CASH TABLE(1)
As of September 30, 2002
Total Total
Revenues Revenues
Less Distrib-
Operating uted
Total Total Costs for for
Expenditures Revenues 3 Months 3 Months
Less Less Ended Total Ended
Operating Operating Sept. 30, Revenues Sept. 30,
Program Costs(2) Costs 2002 Distributed 2002
------- -------- ----- ---- ----------- ----
1979.............. $2,805,917 $4,848,985 $(17,048) $3,952,564 $ -
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.............. 933,334 605,530 4,532 949,234 9,850
1984 Employee(*).. 874 1,077 - 1,000 -
1985 Employee(*).. 2,300 1,288 - 1,035 -
1986 Energy
Income Fund(**)... 177,078 251,156 (5,650) 466,265 -
1986 Employee(*).. 2,698 5,108 - 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..... 1,058,426 1,732,599 26,428 1,601,520 32,000
1992 Employee..... 99,349 254,055 3,913 227,639 4,000
1993 Employee..... 311,944 536,758 4,849 467,780 4,600
Consolidated
Program........... 10,448 8,955 148 10,147 450
1994 Employee..... 854,905 1,234,347 17,745 1,060,708 15,000
1995 Employee..... 330,555 433,358 7,534 345,504 7,000
1996 Employee..... 681,566 636,828 5,233 442,583 7,250
1997 Employee..... 1,054,610 934,929 21,218 677,477 19,500
1998 Employee..... 920,634 786,180 25,947 612,718 24,500
1999 Employee..... 706,130 1,029,337 33,382 768,578 38,000
2000 Employee..... 1,535,890 1,364,221 31,171 731,669 75,500
2001 Employee..... 840,917 197,244 38,940 40,000 33,000
2002 Employee..... 295,446 50,939 30,389 - -
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(*) 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.
LIMITED PARTNERS' NET CASH TABLE(1)
As of September 30, 2002
Total Total
Revenues Revenues
Less Distrib-
Total Operating uted
Expendit- Total Cost for for 3
ures Revenues 3 Months Total Months
Less Less Ended Revenues Ended
Capital Operating Operating Sept. 30, Distrib- Sept. 30,
Program Contributed Costs(2) Costs 2002 uted 2002
------- ----------- -------- ----- ---- ---- ----
1979..... $3,000,000 $6,085,402 $10,167,338 $(20,154) $6,198,801 $ -(5)
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..... 1,875,000 2,038,016 1,149,764 14,222 892,751 11,025(6)
1984
Employee(*) 174,000 86,664 137,262 - 125,280 -
1985
Employee(*) 283,500 227,670 128,753 - 182,644 -
1986 Energy
Income
Fund(**). 1,000,000 988,116 2,077,383 (5,104) 1,896,500 4,400(7)
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. 263,000 275,981 460,198 7,025 428,427 7,890 (8)
1992
Employee. 240,000 256,285 656,677 10,061 616,808 8,880 (9)
1993
Employee. 245,000 281,472 497,410 4,373 454,965 3,920(10)
Consol-
idated... - (957,279) 910,340 14,907 923,860 14,219(11)
1994
Employee. 284,000 344,637 505,752 7,240 426,568 5,680(12)
1995
Employee. 454,000 493,241 643,123 12,029 563,444 11,350(13)
1996
Employee. 437,000 419,561 394,631 (1,273) 378,005 3,059(14)
1997
Employee. 413,000 494,711 420,544 9,530 339,486 7,434(15)
1998
Employee. 471,000 486,199 404,643 13,424 386,691 12,717(16)
1999
Employee. 141,000 214,330 306,127 9,972 279,556 10,904(17)
2000
Employee. 199,000 209,793 184,618 3,770 166,165 9,751(18)
2001
Employee. 370,000 385,513 88,618 17,496 41,440 11,840(19)
2002
Employee. 370,000 241,729 41,678 24,863 - -
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|
(*) 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.
(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 2002 the 1979 Program made a distribution of $-0- to that program's limited partners. (In November 2002, no distribution was made to the 1979 Program's limited partners.)
(6) In November 2002 the 1984 Program made a distribution of $13,545 to that program's limited partners.
(7) In November 2002 the 1986 Program made a distribution of $3,500 to that program's limited partners.
(8) In November 2002 the 1991 Employee Program made a distribution of $5,786 to that program's limited partners.
(9) In November 2002 the 1992 Employee Program made a distribution of $10,080 to that program's limited partners.
(10) In November 2002 the 1993 Employee Program made a distribution of $4,410 to that program's limited partners.
(11) In November 2002 the Consolidated Program made a distribution of $16,605 to that program's limited partners.
(12) In November 2002 the 1994 Employee Program made a distribution of $7,100 to that program's limited partners.
(13) In November 2002 the 1995 Employee Program made a distribution of $9,080 to that program's limited partners.
(14) In November 2002 the 1996 Employee Program made a distribution of $4,807 to that program's limited partners.
(15) In November 2002 the 1997 Employee Program made a distribution of $8,673 to that program's limited partners.
(16) In November 2002 the 1998 Employee Program made a distribution of $12,246 to that program's limited partners.
(17) In November 2002 the 1999 Employee Program made a distribution of $8,648 to that program's limited partners.
(18) In November 2002 the 2000 Employee Program made a distribution of $7,562 to that program's limited partners.
(19) In November 2002 the 2001 Employee Program made a distribution of $12,950 to that program's limited partners.
FEDERAL INCOME TAX CONSIDERATIONS
The full tax opinion of Conner & Winters is attached to this Memorandum as Exhibit B. All prospective investors should review Exhibit B in its entirety before investing in the Partnership. All references in this "Federal Income Tax Considerations" section to the opinion of Conner & Winters are to the tax opinion set forth in Exhibit B.
The following is a summary of the opinions of Conner & Winters on all material federal income tax consequences to the Partnership and to the Limited Partners. There may be aspects of a particular investor's tax situation which are not addressed in the following discussion or in Exhibit B. Additionally, the resolution of certain tax issues depends upon future facts and circumstances not known to Conner & Winters as of the date of this Memorandum; thus, no assurance as to the final resolution of such issues should be drawn from the following discussion.
The following statements are based upon the provisions of the Code, existing and proposed regulations promulgated under the Code ("Regulations"), current administrative rulings, and court decisions. It is possible that legislative or administrative changes or future court decisions may significantly modify the statements and opinions expressed herein. Such changes could be retroactive with respect to transactions occurring prior to the date of such changes.
Moreover, uncertainty exists concerning some of the federal income tax aspects of the transactions being undertaken by the Partnership. Some of the tax positions being taken by the Partnership may be challenged by the Service and any such challenge could be successful. Thus, there can be no assurance that all of the anticipated tax benefits of an investment in the Partnership will be realized.
Conner & Winters' opinion is based upon the transactions described in this Memorandum (the "Transaction") and upon facts as they have been represented to Conner & Winters or determined by it as of the date of the opinion. Any alteration of the facts may adversely affect the opinions rendered. It is possible, however, that a variation of such facts could result in some of the tax benefits being eliminated or deferred to future years.
Because of the factual nature of the inquiry, and in certain cases the lack of clear authority in the law, it is not possible to reach a judgment as to the outcome on the merits (either favorable or unfavorable) of certain material federal income tax issues as described more fully herein.
Summary of Conclusions
Opinions expressed: The following is a summary of the specific opinions expressed by Conner & Winters with respect to Federal Income Tax Considerations discussed herein.
TO BE FULLY UNDERSTOOD, THE COMPLETE DISCUSSION OF THESE MATTERS SET FORTH IN THE FULL TAX OPINION IN EXHIBIT B SHOULD BE READ BY EACH PROSPECTIVE LIMITED PARTNER.
1. The material federal income tax benefits in the aggregate from an investment in the Partnership will be realized.
2. The Partnership will be treated as a partnership for federal income tax purposes and not as a corporation, an association taxable as a corporation or a "publicly traded partnership". See "Partnership Status"; "Federal Taxation of Partnerships."
3. To the extent the Partnership's wells are timely drilled and its drilling costs are timely paid, the Partners will be entitled to their pro rata shares of the Partnership's intangible drilling and development costs ("IDC") paid in 2003. See "Intangible Drilling and Development Costs Deductions."
4. Most Limited Partners' Units will be considered as ownership interests in a passive activity within the meaning of Code Section 469 and losses generated therefrom will be limited by the passive activity provisions of the Code. See "Passive Loss and Credit Limitations."
5. To the extent provided herein, the Partners' distributive shares of Partnership tax items will be determined and allocated substantially in accordance with the terms of the Partnership Agreement. See "Partnership Allocations."
6. The Partnership will not be required to register with the Service as a tax shelter. See "Registration as a Tax Shelter."
No opinion expressed: Due to the lack of authority regarding, or the essentially factual nature of, the issue, Conner & Winters expresses no opinion as to:
1. The impact of an investment in the Partnership on an investor's alternative minimum tax liability, due to the factual nature of the issue (See "Alternative Minimum Tax");
2. Whether, under Code Section 183, the losses of the Partnership will be treated as derived from "activities not engaged in for profit", and therefore nondeductible from other gross income, due to the inherently factual nature of a Partner's interest and motive in engaging in the Transaction (See "Profit Motive");
3. Whether each Partner will be entitled to percentage depletion since such a determination is dependent upon the status of the Partner as an independent producer and on the Partner's other oil and gas production; due to the inherently factual nature of such a determination, Conner & Winters is unable to render an opinion as to the availability of percentage depletion (See "Depletion Deductions");
4. Whether any interest incurred by a Partner with respect to any borrowings to acquire a Unit will be deductible or subject to limitations on deductibility, due to the factual nature of the issue; and
5. Whether the Partnership will be treated as the tax owner of Partnership Properties acquired by the General Partner as nominee for the Partnership.
General Information: Certain matters contained herein are not considered to address a material tax consequence and are for general information, including the matters contained in sections dealing with gain or loss on the sale of Units or of Property, Partnership distributions, tax audits, penalties, and state, local, and self-employment tax. See "General Tax Effects of Partnership Structure," "Gain or Loss on Sale of Properties or Units," "Partnership Distributions," "Administrative Matters," "Accounting Methods and Periods," and "State and Local Tax."
Facts and Representations: The opinions of Conner & Winters are also based upon the facts described in this Memorandum and upon certain representations made to it by the General Partner, including the following:
1. The Partnership Agreement to be entered into by and among the General Partner and Limited Partners and any amendments thereto will be duly executed and will be made available to any Limited Partner upon written request. The Partnership Agreement will be duly recorded in all places required under the Oklahoma Revised Uniform Limited Partnership Act (the "Act") for the due
formation of the Partnership and for the continuation thereof in accordance with the terms of the Partnership Agreement. The Partnership will at all times be operated in accordance with the terms of the Partnership Agreement, the Memorandum, and the Act.
2. No election will be made by the Partnership, Limited Partners, or General Partner to be excluded from the application of the provisions of Subchapter K of the Code.
3. The Partnership will own operating mineral interests, as defined in the Code and in the Regulations, and none of the Partnership's revenues will be from non-working interests.
4. The General Partner will cause the Partnership to properly elect to deduct currently all IDC.
5. The Partnership will have a December 31 taxable year and will report its income on the accrual basis.
6. All Partnership wells will be spudded by not later than December 31, 2003. The entire amount to be paid under any drilling and operating agreements entered into by the Partnership will be attributable to IDC.
7. Such drilling and operating agreements will be duly executed and will govern the operation of the Partnership's wells.
8. Based upon the General Partner's review of its experience with its previous oil and gas partnerships for the past several years and upon the intended operations of the Partnership, the General Partner believes that the sum of (i) the aggregate deductions, including depletion deductions, and (ii) 350 percent of the aggregate tax credits from the Partnership will not, as of the close of any of the first five years ending after the date on which Units are offered for sale, exceed two times the aggregate cash invested by the Partners in the Partnership as of such dates. In that regard, the General Partner has reviewed the economics of its similar oil and gas partnerships for the past several years, and has represented that it has determined that none of those partnerships has resulted in a "tax shelter ratio", as such term is defined in the Code and Regulations, greater than two to one. Further, the General Partner has represented that the deductions that are or will be represented as potentially allowable to an investor will not result in the Partnership having a tax shelter ratio, as such term is defined in the Code and Regulations, greater than two to one and believes that no person could reasonably infer from representations made, or to be made, in connection with the offering of Units that such sums as of such dates will exceed two times the Partners' cash investments as of such dates.
9. The General Partner believes that at least 90% of the gross income of the Partnership will constitute income derived from the exploration, development, production, and/or marketing of oil and gas. The General Partner does not believe that any market will ever exist for the sale of Units and the General Partner will not make a market for the Units. Further, the Units will not be traded on an established securities market.
10. The Partnership and each Partner will have the objective of carrying on the business of the Partnership for profit and dividing the gain therefrom.
11. The General Partner will, as nominee for the Partnership, acquire and hold title to Partnership Properties on behalf of the Partnership; the General Partner will enter into an agency agreement before the General Partner acquires any such oil and gas properties on behalf of the Partnership; the agency agreement will reflect that the General Partner's acquisition of Partnership
properties is on behalf of the Partnership; and the General Partner will execute assignments of all oil and gas interests acquired by it on behalf of the Partnership to the Partnership.
The opinions of Conner & Winters are also subject to all the assumptions, qualifications, and limitations set forth in the following discussion and in the opinion, including the assumptions that each of the Partners has full power, authority, and legal right to enter into and perform the terms of the Partnership Agreement and to take any and all actions thereunder in connection with the transactions contemplated thereby.
Each prospective investor should be aware that, unlike a ruling from the Service, an opinion of Conner & Winters represents only Conner & Winters' best judgment. THERE CAN BE NO ASSURANCE THAT THE SERVICE WILL NOT SUCCESSFULLY ASSERT POSITIONS WHICH ARE INCONSISTENT WITH THE OPINIONS OF CONNER & WINTERS SET FORTH IN THIS DISCUSSION AND EXHIBIT B OR IN THE TAX REPORTING POSITIONS TAKEN BY THE PARTNERS OR THE PARTNERSHIP. EACH PROSPECTIVE INVESTOR SHOULD CONSULT HIS OR HER OWN TAX ADVISOR TO DETERMINE THE EFFECT OF THE TAX ISSUES DISCUSSED HEREIN AND IN EXHIBIT B ON HIS OR HER INDIVIDUAL TAX SITUATION.
General Tax Effects of Partnership Structure
The Partnership will be formed as a limited partnership pursuant to the Partnership Agreement and the laws of the State of Oklahoma. No tax ruling will be sought from the Service as to the status of the Partnership as a partnership for federal income tax purposes. The applicability of the federal income tax consequences described herein depends on the treatment of the Partnership as a partnership for federal income tax purposes and not as a corporation and not as an association taxable as a corporation. Any tax benefits anticipated from an investment in the Partnership would be adversely affected or eliminated if the Partnership were treated as a corporation for federal income tax purposes.
Conner & Winters is of the opinion that, at the time of its formation, the Partnership will be treated as a partnership for federal income tax purposes. The opinion is based on the provisions of the Partnership Agreement, applicable state and federal law and representations made by the General Partner. The opinion of Conner & Winters is not binding on the Service. In addition, no assurance can be given that the Partnership will not lose partnership status as a result of changes in either the manner in which it is operated or the facts upon which the opinion of Conner & Winters is based.
Under the Code, a partnership is not a taxable entity and, accordingly, incurs no federal income tax liability. Rather, a partnership is a "pass-through" entity which is required to file an information income tax return with the Service. In general, the character of a partner's share of each item of income, gain, loss, deduction, and credit is determined at the partnership level. Each partner is allocated a distributive share of such items in accordance with the partnership agreement and is required to take such items into account in determining the partner's income. Each partner includes such amounts in determining his or her income for any taxable year of the partnership ending within or with the taxable year of the partner, without regard to whether the partner has received or will receive any cash distributions from the partnership.
Ownership of Partnership Properties
The General Partner has indicated that it, as nominee for the Partnership (the "Nominee"), will acquire and hold title to Partnership Properties on behalf of the Partnership. The Nominee and the Partnership will enter into an agency agreement before the Nominee acquires any oil and gas properties
on behalf of the Partnership. That agency agreement will reflect that the Nominee's acquisition of Partnership Properties is on behalf of the Partnership. The Nominee will execute assignments to all oil and gas interest acquired by the Nominee on behalf of the Partnership to the Partnership. For various cost and procedural reasons, the assignments will not be recorded in the real estate records in the counties in which the Partnership Properties are located. That is, while the Partnership will be the owner of the Partnership Properties, there will be no public record of that ownership. It is possible that the Service could assert that the Nominee should be treated for federal income tax purposes as the owner of the Partnership Properties, notwithstanding the assignment of those Partnership Properties to the Partnership. If the Service were to argue successfully that the Nominee should be treated as the tax owner of the Partnership 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 Partnership Properties. The Service is concerned that taxpayers not be able to shift the tax consequences of transactions between parties based on the parties' declaration that one party is the agent of another; the Service generally requires that taxpayers respect the form of their transactions and ownership of property. Based on this concern, the Service may challenge the Partnership's treatment of Partnership Properties, and tax attributes thereof, which are held of record by the Nominee.
In Commissioner of Internal Revenue v. Bollinger, 485 U.S. 340 (1988), the United States Supreme Court reviewed a principal-agent relationship and held for the taxpayer in concluding that the principal should be treated as the tax owner of property held in the name of the agent. In that case the Supreme Court noted that "It seems to us that the genuineness of the agency relationship is adequately assured, and tax-avoiding manipulation adequately avoided, when the fact that the corporation is acting as agent for its shareholders with respect to a particular asset is set forth in a written agreement at the time the asset is acquired, the corporation functions as agent and not principal with respect to the asset for all purposes, and the corporation is held out as the agent and not principal in all dealings with third parties relating to the asset." While the Partnership and the Nominee will have in place an agreement defining their relationship before any Partnership Properties are acquired by the Nominee and the Nominee will function as agent with respect to those Partnership Properties on behalf of the Partnership, the Nominee will not hold itself out to all third parties as the agent of the Partnership in dealings relating to the Partnership Properties. Unlike the relationship between the principal and the agent in Bollinger, the Nominee will, however, assign title to Partnership Properties to the Partnership, but will not record those assignments. Accordingly, the facts related to the relationship between the Nominee and the Partnership are not the same as the facts in Bollinger and it is not clear that the failure of the Nominee to hold itself out to third parties as the agent of the Partnership in dealings relating to Partnership Properties should result in the treatment of the Nominee as the tax owner of the Partnership Properties. For the foregoing reasons, Conner & Winters have not expressed an opinion on this issue, but Conner & Winters believe that substantial arguments may be made that the Partnership should be treated as the tax owner of Partnership Properties acquired by the Nominee on the Partnership's behalf. If the Partnership were not treated as the tax owner of Partnership Properties, then the following discussions which relate to the Partners' deduction of tax items which are derived from Partnership Properties, such as IDC, depletion and depreciation, would not be applicable.
Intangible Drilling and Development Costs Deductions
Congress granted to the Secretary of the Treasury the authority to prescribe regulations that would allow taxpayers the option of deducting, rather than capitalizing, IDC. The Secretary's rules state that, in general, the option to deduct IDC applies only to expenditures for drilling and development items that do not have a salvage value.
The Memorandum provides that 75% of the Partners' capital contributions will be utilized for IDC, which will flow through to the Partners as a deductible item in the year of investment. The deduction of IDC by most Limited Partners generally will be available only to offset passive income. Based on a deduction of 75% of a Partner's capital contribution, a one Unit ($1,000) investor in a 35% marginal Federal tax bracket could possibly reduce taxes payable by $262. The investor might also realize additional tax savings on income taxes in the state in which such investor resides.
Classification of Costs. In general, IDC consists of those costs which in and of themselves have no salvage value. In previous partnerships for which the General Partner has served as general partner, intangible drilling and development costs have ranged from 72% to 27% of the investors' contributions. While the planned activities of the Partnership are similar in nature to those of prior partnerships, the amount of expenditures classified as IDC could be greater or less than for prior partnerships. In addition, a partnership's classification of a cost as IDC is not binding on the Service, which might reclassify an item labeled as IDC as a cost which must be capitalized. To the extent not deductible, such amounts will be included in the Partnership's basis in a mineral property and in the Partners' tax basis in their interests in the Partnership.
Timing of Deductions. Although the Partnership will elect to deduct IDC, each investor has an option of deducting IDC, or capitalizing all or a part of the IDC and amortizing it on a straight-line basis over a sixty-month period, beginning with the taxable month in which the expenditure is made. In addition to the effect of this change on regular taxable income, the two methods have different treatment under the Alternative Minimum Tax ("AMT") (see "Alternative Minimum Tax").
Although the General Partner will attempt to satisfy each requirement of the Service and judicial authority for deductibility of IDC in 2003 for the Partnership, no assurance can be given that the Service will not successfully contend that the IDC of a Partnership well which is not completed until 2004 is not deductible in whole or in part until 2004. Furthermore, no assurance can be given that the Service will not challenge the current deduction of IDC because of the prepayment being made to a related party. If the Service were successful with such a challenge, the Partners' deductions for IDC would be deferred to later years.
Recapture of IDC. IDC previously deducted that is allocable to a property (directly or through the ownership of an interest in a partnership) and which, if capitalized, would have been included in the adjusted basis of the property is recaptured as ordinary income to the extent of any gain realized upon the disposition of the property. Treasury regulations provide that recapture is determined at the partner level (subject to certain anti-abuse provisions). Where only a portion of recapture property is disposed of, any IDC related to the entire property is recaptured to the extent of the gain realized on the portion of the property sold. In the case of the disposition of an undivided interest in a property (as opposed to the disposition of a portion of the property), a proportionate part of the IDC with respect to the property is treated as allocable to the transferred undivided interest to the extent of any realized gain.
Depletion Deductions
The owner of an economic interest in an oil and gas property is entitled to claim the greater of percentage depletion or cost depletion with respect to oil and gas properties which qualify for such depletion methods. In the case of partnerships, the depletion allowance must be computed separately by each partner and not by the partnership. For properties placed in service after 1986, depletion deductions, to the extent they reduce basis in an oil and gas property, are subject to recapture under Code section 1254.
Cost depletion for any year is determined by multiplying the number of units (e.g., barrels of oil or Mcf of gas) sold during the year by a fraction, the numerator of which is the cost or other basis of the mineral interest and the denominator of which is total reserves available at the beginning of the period. In no event can the cost depletion exceed the adjusted basis of the property to which it relates.
Percentage depletion is a statutory allowance pursuant to which a deduction currently equal to 15% of the taxpayer's gross income from each property is allowed in any taxable year, not to exceed 100% of the taxpayer's taxable income from the property (computed without the allowance for depletion) with the aggregate deduction limited to 65% of the taxpayer's taxable income for the year (computed without regard to percentage depletion and net operating loss and capital loss carrybacks). The percentage depletion deduction rate will vary with the price of oil, but the rate will not be less than 15%. A percentage depletion deduction that is disallowed in a year due to the 65% of taxable income limitation may be carried forward and allowed as a deduction for a subsequent year, subject to the 65% limitation in that subsequent year. Percentage depletion deductions reduce the taxpayer's adjusted basis in the property. However, unlike cost depletion, percentage depletion deductions are not limited to the adjusted basis of the property; the percentage depletion amount continues to be allowable as a deduction after the adjusted basis has been reduced to zero.
The availability of depletion, whether cost or percentage, will be determined separately by each Partner. Each Partner must separately keep records of his share of the adjusted basis in an oil or gas property, adjust such share of the adjusted basis for any depletion taken on such property, and use such adjusted basis each year in the computation of his cost depletion or in the computation of his gain or loss on the disposition of such property. These requirements may place an administrative burden on a Partner.
Depreciation Deductions
The Partnership will claim depreciation, cost recovery, and amortization deductions with respect to its basis in Partnership Property as permitted by the Code. For most of the Partnership's tangible personal property, the "modified accelerated cost recovery system" ("MACRS") must be used in calculating the cost recovery deductions. Thus, the cost of lease equipment and well equipment, such as casing, tubing, tanks, and pumping units, and the cost of oil or gas pipelines cannot be deducted currently, but must be capitalized and recovered under MACRS. The cost recovery deduction for most equipment used in domestic oil and gas exploration and production and for most of the tangible personal property used in natural gas gathering systems is calculated using the 200% declining balance method switching to the straight-line method, a seven-year recovery period, and a half-year convention. If an accelerated depreciation method is used, a portion of the depreciation will be a preference item for AMT purposes.
Interest Deductions
In the Transaction, the Limited Partners will acquire their interests by remitting cash in the amount of $1,000 per Unit to the Partnership. Some Limited Partners may choose to borrow the funds necessary to acquire a Unit and may incur interest expense in connection with those loans. Conner & Winters is unable to express an opinion with respect to the deductibility of any interest paid or incurred on such a loan because the deductibility of such interest is dependent upon facts unique to each Limited Partner.
Transaction Fees
The Partnership may classify a portion of the fees or expense reimbursements to be paid to third parties and to the General Partner as expenses which are deductible as organizational expenses or otherwise. There is no assurance that the Service will allow the deductibility of such expenses and Conner & Winters expresses no opinion with respect to the allocation of such fees or reimbursements to deductible and nondeductible items.
Generally, expenditures made in connection with the creation of, and with sales of interests in, a partnership will fit within one of several categories.
A partnership may elect to amortize and deduct its organizational expenses ratably over a period of not less than 60 months commencing with the month the partnership begins business. Examples of organizational expenses are legal fees for services incident to the organization of the partnership, such as negotiation and preparation of a partnership agreement, accounting fees for services incident to the organization of the partnership, and filing fees.
No deduction is allowable for "syndication expenses," examples of which include brokerage fees, registration fees, legal fees of the underwriter or placement agent and the issuer (general partners or the partnership) for securities advice and for advice pertaining to the adequacy of tax disclosures in the offering or private placement memorandum for securities law purposes, printing costs, and other selling or promotional material. These costs must be capitalized. Payments for services performed in connection with the acquisition of capital assets must be amortized over the useful life of such assets.
No deduction is allowable with respect to "start-up expenditures," although such expenditures may be capitalized and amortized over a period of not less than 60 months.
The Partnership intends to make overhead reimbursement payments to the General Partner, as described in greater detail in the Memorandum. To be deductible, payments to a partner must be for services rendered by the partner other than in his or its capacity as a partner or for compensation determined without regard to partnership income. Payments which are not deductible because they fail to meet this test may be treated as special allocations of income to the recipient partner and thereby decrease the net loss, or increase the net income among all partners. If the Service were to successfully challenge the General Partner's allocations, a Partner's taxable income could be increased, thereby resulting in increased taxes and in potential liability for interest and penalties.
Basis and At Risk Limitations
A Partner's share of Partnership losses will be allowed as a deduction by the Partner only to the extent of the aggregate amount with respect to which the taxpayer-Partner is "at risk" for the Partnership's activity at the close of the taxable year. Any such loss disallowed by the "at risk" limitation shall be treated as a deduction allocable to the activity in the first succeeding taxable year.
The Code provides that a taxpayer must recognize taxable income to the extent that his or her "at risk" amount is reduced below zero. This "recaptured" income is limited to the sum of the loss deductions previously allowed to the taxpayer, less any amounts previously recaptured. A taxpayer may be allowed a deduction for the recaptured amounts included in his taxable income if and when he increases his amount "at risk" in a subsequent taxable year.
The Limited Partners will purchase Units by tendering cash to the Partnership. To the extent the cash contributed constitutes the "personal funds" of the Partners, the Partners should be considered at risk with respect to those amounts. If the cash contributed constitutes "personal funds," in the opinion of
Conner & Winters, neither the at risk rules nor the adjusted basis rules will limit the deductibility of losses generated from the Partnership and allocated to a Limited Partner, to the extent of such Limited Partner's cash contributions. In no event, however, may a Partner deduct his distributive share of partnership loss where such share exceeds the Partner's tax basis in the Partnership.
Passive Loss Limitations
Introduction. The deductibility of losses generated from passive activities will be limited for certain taxpayers. The passive activity loss limitations apply to individuals, estates, trusts, and personal service corporations as well as, to a lesser extent, closely held C corporations.
The definition of a "passive activity" generally encompasses all rental activities as well as all activities with respect to which the taxpayer does not "materially participate." A taxpayer will be considered as materially participating in a venture only if the taxpayer is involved in the operations of the activity on a "regular, continuous, and substantial" basis. In addition, no limited partnership interest will be treated as an interest with respect to which a taxpayer materially participates.
Passive activity losses ("PALs") of a taxpayer are the amounts of such taxpayer's losses from passive activities for a taxable year. Individuals and personal service corporations are entitled to deduct PALs only to the extent of their passive income whereas closely held C corporations (other than personal service corporations) can offset PALs against both passive and net active income, but not against portfolio (dividends, interest, etc.) income. In calculating passive income and loss, however, all passive activities of the taxpayer are aggregated. PALs disallowed as a result of the above rules will be suspended and can be carried forward indefinitely to offset future passive (or passive and active, in the case of a closely held C corporation) income.
Upon a taxpayer's disposition of his entire interest in a passive activity in a fully taxable transaction not involving a related party, any passive loss of such taxpayer that was suspended by the provisions of the passive activity loss rules is deductible against either passive or non-passive income.
Limited Partner Interests. Most Limited Partners' distributive shares of the Partnership's losses will be treated as PALs, the availability of which will be limited in each case to the individual Partner's passive income in all passive activities in which the Limited Partner has an interest. If a Limited Partner does not have sufficient passive income to utilize the PALs, the disallowed PALs will be suspended and may be carried forward to be deducted against passive income arising in future years. Further, upon the disposition by a Limited Partner of his entire interest in the Partnership to an unrelated party in a fully taxable transaction, such suspended losses will be available, as described above.
Alternative Minimum Tax
Tax benefits associated with oil and gas exploration activities similar to that of the Partnership had for several years been subject to the AMT. Specifically, prior to January 1, 1993, IDC was an AMT preference item to the extent that "excess IDC" exceeded 65% of a taxpayer's net income from oil and gas properties for the year. Excess IDC was the amount by which the taxpayer's IDC deduction exceeded the deduction that would have been allowed if the IDC had been capitalized and amortized on a straight-line basis over ten years. Percentage depletion, to the extent it exceeded a property's basis, was also an AMT preference item.
For independent producers in taxable years beginning after 1992, the Energy Policy Act of 1992 repealed the treatment of percentage depletion as a preference item for AMT purposes and reduced the AMT on expensing of IDC by 30%.
Gain or Loss on Sale of Property or Units
In the event some or all of the property of the Partnership is sold, or upon sale of a Unit, a Limited Partner will realize gain to the extent the amount realized exceeds his or her basis in the Partnership. In such case, there may be recapture, as ordinary income, of IDCs and depletion previously allocated to such Limited Partner. If the gain realized exceeds the amount of the recapture income, the Limited Partner will recognize capital gains for the balance.
It is possible that a Limited Partner will be required to recognize ordinary income pursuant to the recapture rules in excess of the taxable income on the disposition transaction or in a situation where the disposition transaction resulted in a taxable loss. To balance the excess income, the Limited Partner would recognize a capital loss for the difference between the gain and the income. Depending on a Limited Partner's particular tax situation, some or all of this loss might be deferred to future years, resulting in a greater tax liability in the year in which the sale was made and a reduced future tax liability.
Any partner who sells or exchanges interests in a partnership must generally notify the partnership in writing within 30 days of such transaction in accordance with Regulations and must attach a statement to his tax return reflecting certain facts regarding the sale or exchange. The notice must include names, addresses, and taxpayer identification numbers (if known) of the transferor and transferee and the date of the exchange. The partnership also is required to provide copies to the transferor and the transferee of information it is required to provide to the Service in connection with such a transfer.
A Limited Partner who is required to notify the Partnership of a transfer of his or her Partnership interest and who fails to do so may be fined $50 for each failure, limited to $100,000 provided there is no intentional disregard of the filing requirement. Similarly, the Partnership may be fined for failure to report the transfer. The partnership's penalty is $50 for each failure, limited to $250,000 provided there is no intentional disregard of the filing requirement.
Partnership Distributions
Under the Code, any increase in a partner's share of partnership liabilities, or any increase in such partner's individual liabilities by reason of an assumption by him or her of partnership liabilities is considered to be a contribution of money by the partner to the partnership. Similarly, any decrease in a partner's share of partnership liabilities or any decrease in such partner's individual liabilities by reason of the partnership's assumption of such individual liabilities will be considered as a distribution, a constructive distribution, of money to the partner by the partnership.
A Partner's adjusted basis in his or her Units will initially consist of the cash he or she contributes to the Partnership. His or her basis will be increased by his or her share of Partnership income and decreased by his or her share of Partnership losses and distributions. To the extent that actual or constructive distributions are in excess of a Partner's adjusted basis in his or her Partnership interest (after adjustment for contributions and his or her share of income and losses of the Partnership), that excess will generally be treated as gain from the sale of a capital asset. In addition, gain could be recognized to a distributee partner upon the disproportionate distribution to a partner of unrealized receivables or substantially appreciated inventory. The Partnership Agreement prohibits distributions to a Limited Partner to the extent such distribution would create or increase a deficit in a Limited Partner's Capital Account.
Partnership Allocations
The Partners' distributive shares of partnership income, gain, loss, and deduction should be determined and allocated substantially in accordance with the terms of the Partnership Agreement.
The Service could contend that the allocations contained in the Partnership Agreement do not have substantial economic effect or are not in accordance with the Partners' interests in the Partnership and may seek to reallocate these items in a manner that will increase the income or gain or decrease the deductions allocable to a Partner.
Profit Motive
The existence of economic, non-tax motives for entering into the Transaction is essential if the Partners are to obtain the tax benefits associated with an investment in the Partnership. That is, Partners must seek to make a profit from their activities with respect to the Partnership and its activities beyond any tax benefits derived from those activities or risk losing those tax benefits.
Where an activity entered into by an individual is not engaged in for profit, the individual's deductions with respect to that activity are limited to those not dependent upon the nature of the activity (e.g., interest and taxes); any remaining deductions are limited to gross income from the activity for the year. Should it be determined that a Partner's motives with respect to the Transaction are "not for profit," the Service could disallow all or a portion of the deductions generated by the Partnership's activities and allocated to such Partner.
The Code generally provides for a presumption that an activity is entered into for profit where gross income from the activity exceeds the deductions attributable to such activity for three or more of the five consecutive taxable years ending with the taxable year in question. At the taxpayer's election, such presumption can relate to three or more of the taxable years in the 5-year period beginning with the taxable year in which the taxpayer first engages in the activity.
Due to the inherently factual nature of a Partner's intent and motive in engaging in the Transaction, Conner & Winters does not express an opinion as to the ultimate resolution of this issue in the event of a challenge by the Service.
Administrative Matters
Returns and Audits. While no federal income tax is required to be paid by an organization classified as a partnership for federal income tax purposes, a partnership must file federal income tax information returns which are subject to audit by the Service. Any such audit may lead to adjustments, in which event the Limited Partners may be required to file amended personal federal income tax returns. Any such audit may also lead to an audit of a Limited Partner's individual tax return and adjustments to items unrelated to an investment in Units.
For purposes of reporting, audit, and assessment of additional federal income tax, the tax treatment of "partnership items" is determined at the partnership level. Partnership items will include those items that the Regulations provide are more appropriately determined at the partnership level than the partner level. The Service generally cannot initiate deficiency proceedings against an individual partner with respect to partnership items without first conducting an administrative proceeding at the partnership level as to the correctness of the partnership's treatment of the item. An individual partner may not file suit for a credit or a refund arising out of a partnership item without first filing a request for an administrative proceeding by the Service at the partnership level. Individual partners are entitled to notice of such administrative proceedings and decisions therein, except in the case of partners with less
than 1% profits interest in a partnership having more than 100 partners. If a group of partners having an aggregate profits interest of 5% or more in such a partnership so requests, however, the Service also must mail notice to a partner appointed by that group to receive notice. All partners, whether or not entitled to notice, are entitled to participate in the administrative proceedings at the partnership level, although the Partnership Agreement provides for waiver of certain of these rights by the Limited Partners. All Partners, including those not entitled to notice, may be bound by a settlement reached by the Partnership's representative, the "tax matters partner," which will be Unit Petroleum Company. If a proposed tax deficiency is contested in any court by any Partner or by the General Partner, all Partners may be deemed parties to such litigation and bound by the result reached therein.
Consistency Requirements. A partner must generally treat partnership items on his or her federal income tax returns consistently with the treatment of such items on the partnership information return unless he or she files a statement with the Service identifying the inconsistency or otherwise satisfies the requirements for waiver of the consistency requirement. Failure to satisfy this requirement will result in an adjustment to conform the partner's treatment of the item with the treatment of the item on the partnership return. Intentional or negligent disregard of the consistency requirement may subject a partner to substantial penalties.
Compliance Provisions. Taxpayers are subject to several penalties and other provisions that encourage compliance with the federal income tax laws, including an accuracy-related penalty in an amount equal to 20% of the portion of an underpayment of tax caused by negligence, intentional disregard of rules or regulations or any "substantial understatement" of income tax. A "substantial understatement" of tax is an understatement of income tax that exceeds the greater of (a) 10% of the tax required to be shown on the return (the correct tax), or (b) $5,000 ($10,000 in the case of a corporation other than an S corporation or personal holding corporation).
Except in the case of understatements attributable to "tax shelter" items, an item of understatement may not give rise to the penalty if (a) there is or was "substantial authority" for the taxpayer's treatment of the item or (b) all facts relevant to the tax treatment of the item are disclosed on the return or on a statement attached to the return, and there is a reasonable basis for the tax treatment of such item by the taxpayer. In the case of partnerships, the disclosure is to be made on the return of the partnership. Under the applicable Regulations, however, an individual partner may make adequate disclosure with respect to partnership items if certain conditions are met.
In the case of understatements attributable to "tax shelter" items, the substantial understatement penalty may be avoided only if the taxpayer establishes that, in addition to having substantial authority for his or her position, he or she reasonably believed the treatment claimed was more likely than not the proper treatment of the item. A "tax shelter" item is one that arises from a partnership (or other form of investment) the principal purpose of which is the avoidance or evasion of federal income tax.
Based on the definition of a "tax shelter" in the Regulations, performance of previous partnerships, and the planned activities of the Partnership, the General Partner does not believe that the Partnership will qualify as a "tax shelter" under the Code, and will not register it as such.
Accounting Methods and Periods
The Partnership will use the accrual method of accounting and will select the calendar year as its taxable year.
State and Local Taxes
The opinions expressed herein are limited to issues of federal income tax law and do not address issues of state or local law. Prospective investors are urged to consult their tax advisors regarding the impact of state and local laws on an investment in the Partnership.
Individual Tax Advice Should Be Sought
The foregoing is only a summary of the material tax considerations that may affect an investor's decision regarding the purchase of Units. The tax considerations attendant to an investment in a Partnership are complex and vary with individual circumstances. Each prospective investor should review such tax consequences with his tax advisor.
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 programs 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 markets for gas have improved significantly recently, there can be no assurance that such improvement will continue. As a result, it is possible that there may be significant delays in selling any gas from Partnership Properties.
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, historically the prices for domestic oil production have
generally 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 interest 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 addition, if a property which might otherwise be acquired by the Partnership 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 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 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. 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. 13,267 (Apr. 16, 1992), III FERC Stats. & Regs. Preambles Paragraph 30,939, at 30,406; 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; 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).
Among other things, Order 636 required 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.
In response to a Court remand, on February 27, 1997 FERC issued its final rule further revising Order 636. Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 and Regulation of National Pipelines After Partial Wellhead Decontrol, 62 Fed. Reg. 10204 (Mar. 6, 1997). It modified its regulation by (i) changing the selection of a twenty-year matching term for the right of first refusal and instead adopting a five-year matching term and (ii) reversing the requirement that pipelines allocate 10% of GSR costs to interruptible customers and requiring that pipelines propose the percentage that interruptible customers will bear based on the individual circumstances present on each pipeline. Most of the individual pipeline restructurings arising from Order 636 have been completed.
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 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 were 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 has also 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 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 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). 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, many interstate pipeline companies have divested
their gathering 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 FERC
required that the pipeline must offer a two-year "default contract" to existing
users of the gathering facilities. However, on appeal, while the United States
Court of Appeals for the District of Columbia upheld the FERC's allowing the
spinning down of gathering facilities to a non-regulated affiliate, in Conoco
Inc. v. FERC, 90 F.3d 536, 552-53 (D.C. Cir. 1996) the D.C. Circuit remanded the
FERC's default contract mechanism. On February 18, 1997 the United States
Supreme Court denied a petition to review the D. C. Circuit's decision. As a
result of FERC's action, some states have enacted or are considering statutory
and/or regulatory provisions to regulate gathering systems. Consequently, the
General Partner cannot reliably predict at this time how regulation will
ultimately impact Partnership Revenue.
Oil Price Regulation
With respect to oil pipeline rates subject to the FERC's jurisdiction under the Interstate Commerce Act, in October 1993 the FERC issued Order 561 to implement the requirements of Title XVIII of the Energy Policy Act of 1992. Order 561 established an indexing system, effective January 1, 1995, under which many oil pipelines are able to readily change their rates to track changes in the Producer Price Index for Finished Goods (PPI-FG), minus one percent. This index established ceiling levels for rates. Order 561 also permits cost-of-service proceedings to establish just and reasonable rates. The Order does not alter the right of a pipeline to seek FERC authorization to charge market rates. However, until the FERC makes the finding that the pipeline does not exercise significant market power, the pipeline's rates cannot exceed the applicable index ceiling level or a level justified by the pipeline's cost of service.
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 1992 Oklahoma and Texas imposed additional limitations on gas production to more closely track market demand. The General Partner cannot predict whether any 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, an oil import fee, restructuring how oil pipeline rates are determined and implemented reducing
production allowables, providing purchasers with "market-out" options in existing and future gas purchase contracts, eliminating or limiting the operation of take-or-pay clauses, 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), and state regulation of gathering systems. 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.
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 productive 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 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 uncertainties 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 Agreement. 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 Partnership borrowings. It is expected that no cash distributions will be made earlier than the first quarter of 2004. Distributions of cash determined by the General Partner to be available therefore will be made 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, 2033 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 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 to be 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 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 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 authorizing 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 Conner & Winters 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 authorizing 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 pursuant to such 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.
Rollup or Consolidation of the Partnership
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 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 or she 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 Partnership. 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 Partner's contribution to the extent necessary to discharge Partnership 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 compliance with certain legal requirements of those jurisdictions. In such jurisdictions, the General Partner shall cause the Partnership to operate in such a manner as it, on the advice of responsible Conner & Winters, deems appropriate to avoid unlimited liability for the Limited Partners (see Sections 1.5, 12.1 and 12.2 of the Agreement). After the termination 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 2003 (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, accounts 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 reserves 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 practicable, 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;
. 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.
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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. Moreover, 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 anticipated 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 automatically 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 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 representation 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.
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 jurisdiction 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 corporation for federal income tax purposes (see Section 12.1 of the Agreement). Any transferee of the General Partner's interest may become a 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;
. 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 willful 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, 2033. 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 terminate the Partnership as of an earlier date. Such right to accelerate 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 "Transferability 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 terminate 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 following 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 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.
Upon termination, all of the Partnership's debts, liabilities and obligations, including expenses incurred in connection with the termination 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 properties 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, P.C., 3700 First Place Tower, Tulsa, Oklahoma, has acted as special counsel to the General Partner in connection with certain aspects of this offering. Conner & Winters has assisted
in the preparation of the Agreement and this Memorandum. In connection with the preparation of this Memorandum, Conner & Winters has relied entirely upon information submitted to it by the General Partner. Certain of this information has been verified by Conner & Winters 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, Conner & Winters has made no independent investigation of the financial information concerning the General Partner. Further, while passing on certain legal matters, Conner & Winters 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 therefore 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 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 commercial production of oil or gas therefrom.
(j) "Effective Date" refers to the date on which the certificate 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.
(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, 2003, 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, 2003, if any, minus (iii) the amount, if any, of the unexpended Aggregate Subscription at December 31, 2003.
(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, June 15, September 15, 2003 and December 15, 2003, respectively, or
(ii) if an employee so elects, through equal deductions from 2003 salary
commencing immediately after formation of the Partnership.
(p) "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 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 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 Contribution 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 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 sometimes 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 Partnership 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 jurisdiction, or in the absence of such a regulatory body or action 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 connection 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, 2002 is unaudited and includes all adjustments which UNIT considers necessary for a fair presentation of the financial position of Unit Petroleum Company at October 31, 2002.
Unit Petroleum Company and Subsidiary
Consolidated Balance Sheet
(In Thousands)
October 31, 2002
(Unaudited)
Assets
------
Current Assets:
Cash and cash equivalents $ 442
Trade accounts receivable 9,081
Materials and supplies, at lower of cost or market 3,120
Other 516
-----------------
Total current assets 13,159
-----------------
Property and Equipment:
Oil and natural gas properties, on the full
cost method 440,942
Other 525
-----------------
441,467
Less accumulated depreciation, depletion,
amortization and impairment 215,850
-----------------
Net property and equipment 225,617
-----------------
Other Assets 62
-----------------
Total Assets $ 238,838
=================
Liabilities and Shareholders' Equity
------------------------------------
Current Liabilities:
Accounts payable $ 8,125
Accounts payable to parent 8,384
Contract advances 50
Accrued liabilities 1,372
-----------------
Total current liabilities 17,931
-----------------
Deferred Income Taxes 55,599
Shareholders' Equity:
Common stock, $1.00 par value, 500 shares
authorized and outstanding 1
Capital in excess of par value 31,543
Retained earnings 133,764
-----------------
Total shareholders' Equity 165,308
-----------------
Total Liabilities and Shareholders' Equity $ 238,838
=================
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EXHIBIT A
UNIT 2003 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
AGREEMENT OF LIMITED PARTNERSHIP
INDEX
ARTICLE I Formation of Limited Partnership...................................3
ARTICLE II Definitions.......................................................4
ARTICLE III Purposes and Powers of the Partnership...........................8
ARTICLE IV Partner Capital Contributions....................................10
ARTICLE V Deposit and Use of Capital Contributions and
Other Partnership Funds.........................................11
ARTICLE VI Sharing of Costs, Capital Accounts and Allocation
of Charges and Income..........................................13
ARTICLE VII Fiscal Year, Accountings and Reports............................17
ARTICLE VIII Tax Returns and Elections......................................17
ARTICLE IX Distributions....................................................18
ARTICLE X Rights, Duties and Obligations of the General Partner.............18
ARTICLE XI Compensation and Reimbursements..................................23
ARTICLE XII Rights and Obligations of Limited Partners......................24
ARTICLE XIII Transferability of Limited Partner's Interest..................25
ARTICLE XIV Assignments by the General Partner..............................27
ARTICLE XV Limited Partners' Right of Presentment...........................28
ARTICLE XVI Termination and Dissolution of Partnership......................29
ARTICLE XVII Notices........................................................31
ARTICLE XVIII Amendments....................................................32
ARTICLE XIX General Provisions..............................................32
ATTACHMENT I Limited Partner Subscription Agreement
and Suitability Statement.......................I-1
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UNIT 2003 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 2003 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 will not be commenced prior to such date. The Partnership will continue in existence until December 31, 2033, 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 partnership (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 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 transferred pursuant to Section 4.2 of this 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 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 certificate
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, 2003, 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, 2003, minus (iii) the amount, if any, of the unexpended Aggregate Subscription at December 31, 2003.
(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 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.
(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."
(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.
(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 connection 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;
(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 professional 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 contributions 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 consideration 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;
(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;
(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, 2003, June 15, 2003, September 15, 2003, and December 15, 2003, respectively, or (ii) by employees so electing, through equal deductions from 2003 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 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 Partnership that are charged to the General Partner's account as such costs are incurred.
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 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 Partnership 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.
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 2003 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 connection 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 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 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 (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 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, deduction, 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 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.
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 evaluation 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.
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 conducting 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 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 2003 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, 2003 or the Effective Date through December 31, 2003 (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 comprising the spacing unit on which a Partnership Well is located or is to 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 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 2003 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 2003 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 2003 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 Properties 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 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 appropriate 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 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.
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 proceedings 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 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 administrative 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 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. 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
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. Distributions 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 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) 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 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 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 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, 2004, 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 price to be used in calculating future gross revenues as well as 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 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 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, 2033, 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.
16.4 As soon as possible after December 31, 2033, 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, encumbrances, 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 satisfactory 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 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, 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 January, 2003 but effective as of the Effective Date.
"General Partner"
UNIT PETROLEUM COMPANY
Attest:
By___________________________________ By___________________________________ Mark E. Schell, Secretary John G. Nikkel, President
LIMITED PARTNER SUBSCRIPTION AGREEMENT AND
SUITABILITY STATEMENT
(ALL INFORMATION WILL BE TREATED CONFIDENTIALLY)
Unit 2003 Employee Oil and Gas Limited Partnership
c/o Unit Petroleum Company
1000 Kensington Center
7130 South Lewis Avenue
Tulsa, Oklahoma 74136
RE: Unit 2003 Employee Oil and Gas Limited Partnership
Gentlemen:
In connection with the subscription of the undersigned for units of limited partnership interest ("Units") in the Unit 2003 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 December 30, 2002 of the Unit 2003 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 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 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 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
(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 2003 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.
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 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.
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 2003 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 2003 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, 2003, June 15, 2003, September 15, 2003 and December 15, 2003, respectively; or
_______ (b) through equal deductions from 2003 salary of the undersigned commencing immediately after the Effective Date (as defined in Article II of the Agreement).
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
________________________ Mailing Address Social Security or Tax
Please Print Name if different: Identification Number)
TAX I.D. OR SOCIAL
_________________________ SECURITY NO.
------------
Date: ____________________ _________________________ __________________
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ACCEPTED THIS _____ DAY OF __________________, 2003.
UNIT 2003 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 2003 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.
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
State or Province Percentage
Subsidiary of Incorporation Owned
------------------------------------- ----------------- ----------
Unit Drilling Company Oklahoma 100%
Unit Petroleum Company Oklahoma 100%
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EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby 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, 33-53542, 333-38166 and 333-39584) and Form S-3 (File No.'s 333-83551 and 333-99979) of our report dated February 19, 2003, on our audits of the consolidated financial statements and financial statement schedule of Unit Corporation as of December 31, 2001 and 2002, and for the years ended December 31, 2000, 2001 and 2002, which report is included in this Annual Report on Form 10-K.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 12, 2003