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F O R M 1 0 - K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
++++++++++++++++++++++++++++++++
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
Common Stock, par value New York Stock Exchange
$.20 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Warrants to Purchase Shares of Common Stock
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or in formation statements incorporated by reference in PART III of this
Form 10-K or any amendment to this Form 10-K.
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 13, 1996 - $69,030,808
Number of Shares of Common Stock
Outstanding on March 13, 1996 - 21,009,635
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting
of Stockholders to be held May 1, 1996 are incorporated by reference in Part
III.
Exhibit Index - See Page 72
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FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business............................................. 1
Item 2. Properties........................................... 1
Item 3. Legal Proceedings.................................... 17
Item 4. Submission of Matters to a Vote of Security Holders.. 17
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters................................ 18
Item 6. Selected Financial Data.............................. 19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................ 20
Item 8. Financial Statements and Supplementary Data.......... 28
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................ 61
PART III
Item 10. Directors and Executive Officers of the Registrant... 61
Item 11. Executive Compensation............................... 62
Item 12. Security Ownership of Certain Beneficial Owners
and Management..................................... 63
Item 13. Certain Relationships and Related Transactions....... 63
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K........................................ 64
Signatures ..................................................... 71
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UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1995
PART I
Item 1. Business and Item 2. Properties
- -----------------------------------------
GENERAL
The Company, through its wholly owned subsidiaries, is engaged in the
land contract drilling of oil and natural gas wells and the development,
acquisition and production of oil and natural gas properties. The Company
operates primarily in the Anadarko and Arkoma Basins, which cover portions of
Oklahoma, Texas, Kansas and Arkansas and has additional producing properties
located in Canada and other states, including but not limited to, New Mexico,
Louisiana, North Dakota, Colorado, Wyoming, Montana, Alabama and Mississippi.
The Company was originally incorporated in Oklahoma in 1963 as Unit
Drilling Company. In 1979 it became a publicly held Delaware corporation and
changed its name to Unit Drilling and Exploration Company ("UDE") to more
accurately reflect the importance of its oil and natural gas business. In
September 1986, pursuant to a merger and exchange offer, the Company acquired
all of the assets and assumed all of the liabilities of UDE and six oil and gas
limited partnerships for which UDE was the general partner, in exchange for
shares of the Company's common stock (the "Exchange Offer").
The Company's principal executive offices are maintained at 1000
Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number
(918) 493-7700. The Company also has a regional office in Houston, Texas. As
used herein, the term " Company" refers to Unit Corporation and at times Unit
Corporation and/or one or more of its subsidiaries with respect to periods from
and after the Exchange Offer and to UDE with respect to periods prior thereto.
OIL AND NATURAL GAS OPERATIONS
In 1979, the Company began to acquire oil and natural gas properties to
diversify its source of revenues which had previously been derived from contract
drilling. The development, production and sale of oil and natural gas together
with the acquisition of producing properties now constitutes the largest part of
the Company's operations as conducted through its wholly owned subsidiary, Unit
Petroleum Company.
As of December 31, 1995, the Company had 5,428 Mbbls and 108,728 MMcf of
estimated proved oil and natural gas reserves, respectively. The Company's
producing oil and natural gas interests, undeveloped leaseholds and related
assets are locate d primarily in Oklahoma, Texas, Louisiana and New Mexico and
to a lesser extent in Arkansas, North Dakota, Colorado, Wyoming, Montana,
Alabama, Mississippi and Canada. As of December 31, 1995, the Company had an
1
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interest in a total of 2,570 wells in the United States and served as the
operator of 482 wells. The Company also had an interest in 65 wells located in
Canada. The majority of the Company's development and exploration prospects are
generated by its technical staff. When the Company is the operator of a
property, it generally employs its own drilling rigs and the Company's own
engineering staff supervises the drilling operation.
The Company intends to continue the growth in its oil and natural gas
operations utilizing funds generated from operations and its bank revolving line
of credit.
Well and Leasehold Data. The Company's oil and natural gas exploration
and development drilling activities and the number of wells in which the Company
had an interest, which were producing or capable of producing, were as follows
for the periods indicated:
Year Ended December 31,
Wells drilled: 1995 1994 1993
-------------- Gross Net Gross Net Gross Net
Exploratory: ------ ------ ------ ------ ------ ------
Oil.............. - - - - - -
Natural gas...... - - 1 .98 1 1.00
Dry.............. - - 2 .80 1 0.10
------ ------ ------ ------ ------ ------
Total - - 3 1.78 2 1.10
====== ====== ====== ====== ====== ======
Development:
Oil.............. 15 4.70 5 5.00 12 11.98
Natural gas...... 26 7.02 40 13.46 25 11.12
Dry.............. 6 2.27 12 7.26 8 4.29
------ ------ ------ ------ ------ ------
Total 47 13.99 57 25.72 45 27.39
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
------------------------------------------------------------
Oil - USA........ 750 207.80 675 177.68 337 162.09
Oil - Canada..... - - - - - -
Gas -USA........ 1,820 232.03 1,089 179.99 709 141.76
Gas - Canada..... 65 1.63 61 1.53 61 1.53
------ ------ ------ ------ ------ ------
Total 2,635 441.46 1,825 359.20 1,107 305.38
====== ====== ====== ====== ====== ======
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The following table summarizes the Company's acreage as of the end of each of
the years indicated:
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
------- ------- ------- -------
1995
----
USA 548,674 117,403 24,810 12,866
Canada 31,360 784 - -
------- ------- ------- -------
Total 580,034 118,187 24,810 12,866
======= ======= ======= =======
1994
----
USA 340,241 100,732 21,514 11,540
Canada 31,360 784 - -
------- ------- ------- -------
Total 371,601 101,516 21,514 11,540
======= ======= ======= =======
1993
----
USA 246,115 86,013 28,738 18,021
Canada 31,360 784 - -
------- ------- ------- -------
Total 277,475 86,797 28,738 18,021
======= ======= ======= =======
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Price and Production Data. The average sales price, oil and natural gas
production volumes and average production cost per equivalent Mcf (1 barrel
(Bbl) of oil = 6 thousand cubic feet (Mcf) of natural gas) of production,
experienced by the Company, for the periods indicated were as follows:
Year Ended December 31,
1995 1994 1993
Average sales price per barrel -------- -------- --------
of oil produced:
USA $ 16.65 $ 15.13 $ 16.73
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 1.61 $ 1.86 $ 2.07
Canada $ 0.98 $ 1.27 $ 0.96
Oil production (Mbbls):
USA 577 406 397
Canada - - -
-------- -------- --------
Total 577 406 397
======== ======== ========
Natural gas production (MMcf):
USA 12,005 9,606 7,435
Canada 54 53 70
-------- -------- --------
Total 12,059 9,659 7,505
======== ======== ========
Average production expense per
equivalent Mcf:
USA $ 0.64 $ 0.58 $ 0.66
Canada $ 0.30 $ 0.37 $ 0.21
Reserves. The following table sets forth the estimated proved developed
and undeveloped oil and natural gas reserves of the Company at the end of each
of the years indicated:
Year Ended December 31,
1995 1994 1993
------- ------- -------
Oil (Mbbls):
USA 5,428 4,308 3,304
Canada - - -
------- ------- -------
Total 5,428 4,308 3,304
======= ======= =======
Natural gas (MMcf):
USA 107,950 92,566 71,379
Canada 778 794 861
------- ------- -------
Total 108,728 93,360 72,240
======= ======= =======
Further information relating to oil and natural gas operations is
presented in Notes 1, 4, 10 and 12 of Notes to Consolidated Financial Statements
set forth in Item 8 hereof.
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LAND CONTRACT DRILLING OPERATIONS
Unit Drilling Company, a wholly owned subsidiary of the Company, engages
in the land drilling of oil and natural gas wells for a wide range of customers.
A land drilling rig consists, in part, of engines, drawworks or hoists, derrick
or mast , pumps to circulate the drilling fluid, blowout preventers and drill
pipe. An active maintenance and replacement program during the life of a
drilling rig permits upgrading of components on an individual basis. Over the
life of a typical rig, due to the normal wear and tear of operating up to 24
hours a day, several of the major components, such as engines, mud pumps and
drill pipe, are replaced or rebuilt on a periodic basis as required, while other
components, such as the substructure, mast and drawworks, can be utilized for
extended periods of time with proper maintenance. The Company also owns
additional equipment used in the operation of its rigs, including large air
compressors, trucks and other support equipment.
As of December 31, 1995, the Company owns 22 operational drilling rigs
with rated depth capacities ranging from 8,000 to 25,000 feet. A majority of the
Company's rigs are located in the Anadarko and Arkoma Basins of Oklahoma and
Texas. In July 1994, the Company began moving rigs to the South Texas basin
region thereby expanding the Company's market area for its contract drilling
services and in December 1995, the contract drilling operations opened a
regional office in Houston, Texas. In the Anadarko and Arkoma Basins the
Company's primary focus is on the utilization of its medium depth rigs which
have a depth range of 8,000 to 14,000 feet. These medium depth rigs are suited
to the contract drilling currently undertaken by operators in these two basins.
At present, the Company does not have a shortage of rig equipment.
However, certain grades of drill pipe are reaching the end of their useful life
and the Company is increasing its drill pipe acquisitions to maintain current
utilization levels. At December 31, 1995, the Company had orders for 75,000
feet of drill pipe of various grades scheduled for delivery through the first
half of 1996. There is no assurance that sufficient supplies of such equipment
will be readily available in the future and, given the general decline
experienced in the land contract drilling industry over the past decade, the
Company's ability to utilize its full complement of drilling rigs, should
economic conditions improve rapidly, will be restricted due to a lack of
equipment, drill pipe and qualified labor not only within the Company but in the
industry as a whole.
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The following table sets forth, for each of the periods indicated,
certain data concerning the Company's contract drilling operations:
Year Ended December 31,
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Number of operational rigs owned
at end of period 22 25 25 26 26
Average number of rigs utilized(1) 10.9 9.5 8.0 5.5 9.1
Number of wells drilled 111 95 84 56 92
Total footage drilled (feet in 1000's) 1,196 1,027 788 527 736
- -------------------
(1) Utilization rates are based on a 365-day year. A rig is considered
utilized when it is operating or being moved, assembled or
dismantled under contract.
As of March 13, 1996, 14 of the Company's 22 drilling rigs were
operating under contract.
The following table sets forth, as of March 13, 1996, the type and
approximate depth capability of each of the Company's drilling rigs:
Depth
Capability
Type (feet)
---- ----------
U-15 Unit Rig.................................. 11,000
U-15 Unit Rig.................................. 11,000
U-15 Unit Rig.................................. 11,000
U-15 Unit Rig.................................. 11,000
Gardner Denver 800............................. 15,000
Gardner Denver 700............................. 15,000
BDW 800-M1..................................... 15,000
Gardner Denver 700............................. 15,000
Mid-Continent 914-C............................ 20,000
U-15 Unit Rig.................................. 11,000
Brewster N-75.................................. 15,000
Gardner Denver 500............................. 12,000
Gardner Denver 700............................. 15,000
Gardner Denver 700............................. 15,000
Gardner Denver 700............................. 15,000
Brewster N-75.................................. 15,000
BDW 1350-M..................................... 20,000
SU-15 North Texas Machine...................... 12,000
SU-15 North Texas Machine...................... 12,000
National 110-E................................. 20,000
Continental Emsco C-1-E........................ 20,000
Gardner Denver 1500-E.......................... 25,000
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For the past several years, the Company's contract drilling services
have encountered significant competition due to depressed levels of activity in
contract drilling. While the Company's drilling operations showed improvement
in 1995, this competition will, for the foreseeable future, continue to
adversely affect the Company.
Drilling Contracts. Most of the Company's drilling contracts are
obtained through competitive bidding. Generally, the contracts are for a single
well with the terms and rates varying depending upon the nature and duration of
the work, the equipment and services supplied and other matters. The contracts
obligate the Company to pay certain operating expenses, including wages of
drilling personnel, maintenance expenses and incidental rig supplies and
equipment. Usually, the contracts are subject to termination by the customer on
short notice upon payment of a fee. The Company generally indemnifies its
customers against certain types of claims by the Company's employees and claims
arising from surface pollution caused by spills of fuel, lubricants and other
solvents within the control of the Company. Such customers generally indemnify
the Company against claims arising from other surface and subsurface pollution
other than claims resulting from the Company's gross negligence.
The contracts may provide for compensation to the Company on a day rate,
footage or turnkey basis with additional compensation for special risks and
unusual conditions. Under daywork contracts, the Company provides the drilling
rig with the required personnel to the operator who supervises the drilling of
the contracted well. Compensation to the Company is based on a negotiated rate
per day as the rig is utilized. Footage contracts usually require the Company
to bear some of the drilling costs in addition to providing the rig. The
Company is compensated on a rate per foot drilled basis upon completion of the
well. Under turnkey contracts, the Company contracts to drill a well to a
specified depth and provides most of the equipment and services required. The
Company bears the risk of drilling the well to the contract depth and is
compensated when the contract provisions have been satisfied.
Turnkey drilling operations, in particular, might result in losses if
the Company underestimates the costs of drilling a well or if unforeseen events
occur. Because the proportion of turnkey drilling is currently dictated by
market condition s and the desires of customers using the Company's services,
the Company is unable to predict whether the portion of drilling conducted on a
turnkey basis will increase or decrease in the future. For 1995 turnkey revenue
represented approximately 17 percent of the Company's contract drilling
revenues. To date, the Company has not experienced significant losses in
performing turnkey contracts.
Customers. During the fiscal year ended December 31, 1995, 10 contract
drilling customers accounted for approximately 19 percent of the Company's total
revenues and approximately 1 percent of the Company's total revenues were
generated by drilling on oil and natural gas properties of which the Company was
the operator (including properties owned by limited partnerships for which the
Company acted as general partner). Such drilling was pursuant to contracts
containing terms and conditions comparable to those contained in the Company's
customary drilling contracts with non-affiliated operators.
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Further information relating to contract drilling operations is
presented in Notes 1 and 10 of Notes to Consolidated Financial Statements set
forth in Item 8 hereof.
NATURAL GAS MARKETING
Prior to April 1995, the Company marketed natural gas from wells located
primarily in Oklahoma and Texas and to a lesser extent in Arkansas, Kansas,
Louisiana, Mississippi and New Mexico. Effective April 1, 1995 the Company
completed a business combination between the Company's natural gas marketing
operations and a third party also involved in natural gas marketing activities
forming a new company called GED Gas Services, L.L.C. ("GED"). The Company owns
a 34 percent interest in GED. Effective November 1, 1995, GED sold its natural
gas marketing operations to a third party. This sale removed the Company from
the third party natural gas marketing business. The creation of GED and the
subsequent sale of the marketing operations did not adversely affect the
Company's drilling and oil and natural gas exploration operations or the
profitability of the Company as a whole. The disposition of the Company's
natural gas marketing segment has been accounted for as a discontinued
operation and accordingly, the 1995 and prior year financial information has
been restated to reflect this treatment.
MARKETING OF OIL AND NATURAL GAS PRODUCTION
The Company's revenue and profitability are substantially dependent upon
prevailing prices for natural gas and crude oil. These prices vary based on
factors beyond the control of the Company, including the extent of domestic
production and importation of crude oil and natural gas, the proximity and
capacity of oil and natural gas pipelines, the marketing of competitive fuels,
general fluctuations in the supply and demand for oil and natural gas, the
effect of federal and state regulation of production, refining, transportation
and sales, the use and allocation of oil and natural gas and their substitute
fuels and general national and worldwide economic conditions. In addition,
natural gas spot prices received by the Company are influenced by weather
conditions impacting the continental United States.
The Company's oil and condensate production is sold at or near the
Company's wells under purchase contracts at prevailing prices in accordance with
arrangements which are customary in the oil industry. The Company's natural gas
production is sold at the wellhead to intrastate and interstate pipelines as
well as to independent marketing firms under contracts with original terms
ranging from one month to 20 years. Most of these contracts contain provisions
for readjustment of price, termination and other terms which are customary in
the industry.
The worldwide supply of oil has been largely dependent upon rates of
production of foreign reserves. Although the demand for oil has increased
slightly in the United States, imports of foreign oil continue to increase.
Future domestic oil prices will depend largely upon the actions of foreign
producers with respect to rates of production and it is virtually impossible to
predict what actions those producers will take in the future. Prices may also
be affected by political, social and other factors relating to the Middle East.
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In view of the many uncertainties affecting the supply and demand for oil and
natural gas, the Company is unable to predict future oil and natural gas prices
or the overall effect, if any, that a decline in demand or oversupply of such
products would have on the Company.
COMPETITION
All lines of business in which the Company engages are highly
competitive. Competition in land contract drilling traditionally involves such
factors as price, efficiency, condition of equipment, availability of labor and
equipment, reputation and customer relations. Some of the Company's competitors
in the land contract drilling business are substantially larger than the Company
and have appreciably greater financial and other resources. As a result of the
decrease in demand for land contract drilling services over the past decade, a
surplus of certain types of drilling rigs currently exists while inventories of
certain components such as drill pipe have been depleted from continued use.
Accordingly, the competitive environment within which the Company's drilling
operations presently operates is uncertain and extremely price oriented.
The Company's oil and natural gas operations likewise encounter strong
competition from major oil companies, independent operators, and others. Many
of these competitors have appreciably greater financial, technical and other
resources and a re more experienced in the exploration for and production of oil
and natural gas than the Company.
OIL AND NATURAL GAS PROGRAMS
The Company currently serves as a general partner to 4 oil and gas
limited partnerships and 7 employee oil and gas limited partnerships. The
employee partnerships acquire an interest fixed annually ranging from 5% to 15%
of the Company's interest in most oil and natural gas drilling activities and
purchases of producing oil and natural gas properties participated in by the
Company. The limited partners in the employee partnerships are either employees
or directors of the Company or its subsidiaries.
Under the terms of the partnership agreements of each limited
partnership, the general partner, which in each case is Unit Petroleum Company,
has broad discretionary authority to manage the business and operations of the
partnership, including the authority to make decisions on such matters as the
partnership's participation in a drilling location or a property acquisition,
the partnership's expenditure of funds and the distribution of funds to
partners. Because the business activities of the limited partners on the one
hand, and the general partner on the other hand, are not the same, conflicts of
interest will exist and it is not possible to eliminate entirely such conflicts.
Additionally, conflicts of interest may arise where t he Company is the operator
of an oil and natural gas well and also provides contract drilling services.
Although the Company has no formal procedures for resolving such conflicts, the
Company believes it fulfills its responsibility to each contracting party and
complies fully with the terms of the agreements which regulate such conflicts.
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Depending upon a number of factors, including the performance of the
drilling programs and general economic and capital market conditions, the
Company may form additional drilling and/or producing property acquisition
programs in the future.
EMPLOYEES
As of March 13, 1996, the Company had approximately 225 employees in its
land contract drilling operations, 64 employees in its oil and natural gas
operations and 23 in its general corporate area. None of the Company's
employees are represented by a union or labor organization nor have the
Company's operations ever been interrupted by a strike or work stoppage. The
Company considers relations with its employees to be satisfactory.
OPERATING AND OTHER RISKS
The Company's land contract drilling and oil and natural gas operations
are subject to a variety of oil field hazards such as fire, explosion, blowouts,
cratering and oil spills or certain other types of possible surface and
subsurface pollution, any of which can cause personal injury and loss of life
and severely damage or destroy equipment, suspend drilling operations and cause
substantial damage to surrounding areas or property of others. As protection
against some, but not all, of these operating hazards, the Company maintains
broad insurance coverage, including all-risk physical damage, employer's
liability and comprehensive general liability. In all states in which the
Company operates except Oklahoma, the Company maintains worker's compensation
insurance for losses exceeding $50,000. In Oklahoma, starting in August 1991,
the Company elected to become self insured. In consideration therewith, the
Company purchased an excess liability reinsurance policy. The Company believes
that to the extent reasonably practicable such insurance coverages are adequate.
The Company's insurance policies do not, however, provide protection against
revenue losses incurred by reason of business interruptions caused by the
destruction or damage of major items of equipment nor certain types of hazards
such as specific types of environmental pollution claims. In view of the
difficulties which may be encountered in renewing such insurance at reasonable
rates, no assurance can be given that the Company will be able to maintain the
amount of insurance coverage which it considers adequate at reasonable rates.
Moreover, loss of or serious damage to any of the Company's equipment, although
adequately covered by insurance, could have an adverse effect upon the Company's
earning capacity.
The Company's oil and natural gas operations are also subject to all of
the risks and hazards typically associated with the search for and production of
oil and natural gas. These include the necessity of expending large sums of
money for the location and acquisition of properties and for drilling
exploratory wells. In such exploratory work, many failures and losses may occur
before any accumulation of oil or natural gas is found. If oil or natural gas
is encountered, there is no assurance that it will be capable of being produced
or will be in quantities sufficient to warrant development or that it can be
satisfactorily marketed. The Company's future natural gas and crude oil
revenues and production, and therefore cash flow and income, are highly
10
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dependent upon the Company's level of success in acquiring or finding additional
reserves. Without continuing reserve additions through exploration or
acquisitions, the Company's reserves and production will decline over the long
- -term.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which the Company conducts
activities impose restrictions on the drilling, production and sale of oil and
natural gas, which often include requirements relating to well spacing, waste
prevention, production limitations, pollution prevention and clean-up, obtaining
drilling permits and similar matters. The following discussion summarizes, in
part, the regulations of the United States oil and natural gas industry and is
not intended to constitute a complete discussion of the many statutes, rules,
regulations and governmental orders to which the Company's operations may be
subject.
The Company's activities are subject to existing federal and state laws
and regulations governing environmental quality and pollution control. Various
states and governmental agencies are considering, and some have adopted, laws
and regulations regarding environmental control which could adversely affect the
business of the Company. Such laws and regulations may substantially increase
the costs of doing business and may prevent or delay the commencement or
continuation of given operations. Compliance with such legislation and
regulations, together with any penalties resulting from noncompliance therewith,
will increase the cost of oil and natural gas drilling, development, production
and processing. In the opinion of the Company 's management, its operations to
date comply in all material respects with applicable environmental legislation
and regulations; however, in view of the many uncertainties with respect to the
current controls, including their duration, interpretation and possible
modification, the Company can not predict the overall effect of such controls on
its operations.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Wellhead Decontrol Act") became effective. Under the Wellhead Decontrol Act,
all remaining price and non-price controls of first sales under the NGA and NGPA
were removed effective January 1, 1993. Prices for deregulated categories of
natural gas fluctuate in response to market pressures which currently favor
purchasers and disfavor producers. As a result of the deregulation of a greater
proportion of the domestic United States natural gas market and an increase in
the availability of natural gas transportation, a competitive trading market for
natural gas has developed.
During the past several years, the Federal Energy Regulatory Commission
("FERC") has adopted several regulations designed to accomplish a more
competitive, less regulated market for natural gas. These regulations have
materially affected the market for natural gas. The major elements of several
of these initiatives remain subject to appellate review.
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One of the initiatives FERC adopted was order 636. In brief, the
primary requirements of Order 636 are as follows: pipelines must separate their
sales and transportation services; pipelines must provide open access
transportation services t hat are equal in quality for all natural gas suppliers
and must provide access to storage on an open access contract basis; pipelines
that provide firm sales service on May 18, 1992 must offer a "no-notice" firm
transportation service under which fir m shippers may receive delivery of
natural gas on demand up to their firm entitlement without incurring daily
balancing and scheduling penalties; pipelines must provide all shippers with
equal and timely access to information relevant to the availability of their
open access transportation services; open access pipelines must allow firm
transportation customers to downstream pipelines to acquire capacity on upstream
pipelines held by downstream pipelines; pipelines must implement a capacity
releasing program so that firm shippers can release unwanted capacity to those
desiring capacity (which program replaces previous "capacity brokering" and
"buy-sell" programs); existing bundled firm sales entitlement are converted to
unbundled firm sales entitlement and to unbundled firm transportation rights on
the effective date of a particular pipeline's blanket sales certificate; and
pipeline transportation rights must be developed under the Straight Fixed
Variable (SFV) method of cost classification, allocation and rate design unless
the FERC permits the pipeline to use some other method. The FERC will not
permit a pipeline to change the new resulting rates until the FERC accepts the
pipeline's formal restructuring plans.
In essence, the goal of Order 636 is to make a pipeline's position as
natural gas merchant indistinguishable from that of a non-pipeline supplier.
It, therefore, pushes the point or sale of natural gas by pipelines upstream,
perhaps all the way to the wellhead. Order 636 also requires pipelines to give
firm transportation customers flexibility with respect to receipt and delivery
points (except that a firm shipper's choice of delivery point cannot be
downstream of the existing primary delivery point) and to allow "no-notice"
service (which means that natural gas is available not only simultaneously but
also without prior nomination, with the only limitation being the customer's
daily contract demand) if the pipeline offered no-not ice city-gate sales
service on May 18, 1992. Thus, this separation of pipelines' sales and
transportation allows non-pipeline sellers to acquire firm downstream
transportation rights and thus to offer buyers what is effectively a bundled
city-gate s ales service and it permits each customer to assemble a package of
services that serves its individual requirements. But it also makes more
difficult the coordination of natural gas supply and transportation. A
corollary to these changes is that all pipelines will be permitted to sell
natural gas at market-based rates.
The results of these changes may be the increased availability of firm
transportation and the reduction of interruptible transportation, with a
corresponding reduction in the rates for off-peak and interruptible
transportation. However, due to the still evolutionary nature of Order 636 and
its implementation, it is not possible to project the overall potential impact
on transportation rates for natural gas or market prices of natural gas.
12
<PAGE>
The future interpretation and application by FERC of these rules and its
broad authority, or of the state and local regulations by the relevant agencies,
could affect the terms and availability of transportation services for
transportation of natural gas to customers and the prices at which natural gas
can be sold by the Company.
Additional proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry historically
has been very heavily regulated; therefore, there is no assurance that the less
stringent regulatory approach recently pursued by the FERC and Congress will
continue. Sales of petroleum liquids by the Company are not currently regulated
and are made at market prices; however, the FERC is considering a proposal that
could increase transportation rates for petroleum liquids. A number of
legislative proposals have also been introduced in Congress and the state
legislatures of various states, that, if enacted, would significantly affect the
petroleum industry. Such proposals involve, among other things, the imposition
of land and use controls and certain measures designed to prevent petroleum
companies from acquiring assets in other energy areas. In addition, there is
always the possibility that if market conditions change dramatic ally in favor
of oil and natural gas producers that some new form of "windfall profits" or
severance tax may be proposed and imposed upon oil or natural gas. At the
present time it is impossible to predict which proposals, if any, will actually
be enacted by Congress or the various state legislatures. The Company believes
that it is complying with all orders and regulations applicable to its
operations. However, in view of the many uncertainties with respect to the
current controls, including their duration and possible modification together
with any new proposals that may be enacted, the Company cannot predict the
overall effect, if any, of such controls on Company operations.
Certain states in which the Company operates control production from
wells through regulations establishing the spacing of wells, limiting the number
of days in a given month during which a well can produce and otherwise limiting
the rate of allowable production.
As noted above, the Company's operations are subject to numerous federal
and state laws and regulations regarding the control of contamination of the
environment. These laws and regulations may require the acquisition of a permit
before or after drilling commences, prohibit drilling activities on certain
lands lying within wilderness areas or where pollution arises and impose
substantial liabilities for pollution resulting from drilling operations,
particularly operations in offshore waters or on submerged lands.
A past, present, or future release or threatened release of a hazardous
substance into the air, water, or ground by the Company or as a result of
disposal practices may subject the Company to liability under the Comprehensive
Environmental Response, Compensation and Liability Act, as amended ("CERCLA"),
the Resource Conservation Recovery Act ("RCRA"), the Clean Water Act, and/or
similar state laws, and any regulations promulgated pursuant thereto. Under
CERCLA and similar laws, the Comp any may be fully liable for the cleanup costs
of a release of hazardous substances even though it contributed to only part of
the release. While liability under CERCLA and similar laws may be limited under
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<PAGE>
certain circumstances, the limits are so high that the maximum liability would
likely have a significant adverse effect on the Company. In certain
circumstances, the Company may have liability for releases of hazardous
substances by previous owners of Company properties. CERCLA currently excludes
petroleum from its definition of "hazardous substances." However, Congress may
delete this exclusion for petroleum, in which case the Company would be required
to manage its petroleum production and wastes from its exploration and
production activities as CERCLA hazardous substances. In addition, RCRA
classifies certain oil field wastes as "non-hazardous." Congress may delete
this exemption for oilfield waste, in which case the Company would have to
manage much of its oilfield waste as hazardous. Additionally, the discharge or
substantial threat of a discharge of oil by the Company into United States
waters or onto an adjoining shoreline may subject the Company to liability under
the Oil Pollution Act of 1990 and similar state laws. While liability under the
Oil Pollution Act of 1990 is limited under certain circumstances, the maximum
liability under those limits would still likely have a significant adverse
effect on the Company.
Violation of environmental legislation and regulations may result in the
imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the abatement of the conditions, or
suspension of the activities, giving rise to the violation. The Company
believes that the Company has complied with all orders and regulations
applicable to its operations. However, in view of many uncertainties with
respect to the current controls, including their duration and possible
modification, the Company cannot predict the overall effect of such controls on
such operations. Similarly, the Company cannot predict what future
environmental laws may be enacted or regulations may be promulgated and what, if
any, impact they would have on operations.
FACTORS INFLUENCING PROJECTIONS OF FUTURE ACTIVITY
In the normal course of its business, the Company, in an effort to help
keep its shareholders and the public informed about the Company's operations,
may, from time to time, issue certain statements, either in writing or orally,
that contain or may contain forward looking information. Generally, these
statements relate to projections involving the anticipated revenues to be
received from the Company's oil and natural gas production, the utilization rate
of its drilling rigs, growth of its oil and natural gas reserves and well
performance, and the Company's anticipated bank debt.
As with any forward- looking statement, these statements are subject to
a number of factors that may tend to influence the accuracy of the statements
and the projections upon which the statements are based. As noted elsewhere in
this report, all phases of the Company's operations are subject to a number of
influences outside the control of the Company, any one of which, or a
combination of which, could materially affect the results of the Company's
operations.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any projections made by the Company, the
14
<PAGE>
following discussion outlines certain factors that in the future could affect
the Company's consolidated results for 1996 and beyond to differ materially from
those that may be set forth in any such forward-looking statement made by or on
behalf of the Company.
COMMODITY PRICES
The prices received by the Company for its oil and natural gas
production have a direct impact on the Company's revenues, profitability and
cash flow as well as its ability to meet its projected financial and operational
goals. The prices for natural gas and crude oil are heavily dependent on a
number of factors beyond the control of the Company, including, but not limited
to, the demand for oil and/or natural gas; current weather conditions in the
continental United States which can greatly influence the demand for natural gas
at any given time as well as the price to be received for such gas; and the
ability of current distribution systems in the United States to effectively meet
the demand for oil and or natural gas at any given time, particularly in times
of peak demand which may result due to adverse weather conditions. Oil prices
are extremely sensitive to foreign influences that may be based on political,
social or economic underpinnings, any one of which could have an immediate and
significant effect on the price and supply of oil. In addition, prices of both
natural gas and oil are becoming more and more influenced by trading on the
commodities markets which, at times, has tended to increase the volatility
associated with these prices. All these factors, especially when coupled with
the fact that much of the Company's product prices are determined on a month to
month basis, can, and at times do, lead to wide fluctuations in the prices
received by the Company.
Based upon the results of operations for the year ended December
31, 1995, the Company estimates that a change of $0.10/Mcf in the average price
of natural gas and a change of $1.00/Bbl in the price of crude oil throughout
such period would have resulted in approximate changes in net income of
$1,100,000 and $535,000, respectively. During 1995, 95% of the natural gas
volume of the Company and substantially all the crude oil volume of the Company
were sold at market responsive prices.
CUSTOMER DEMAND
Demand for the Company's drilling services is dependent almost entirely
on the needs of third parties. Based on past history, such parties'
requirements are subject to a number of factors, independent of any subjective
factors, that directly impact the demand for the Company's drilling rigs. These
include the funds available by such companies to carry out their drilling
operations during any given time period which, in turn, are often subject to
downward revision based on decreases in t he then current prices of oil and
natural gas. Many of the Company's customers are small to mid-size oil and
natural gas companies whose drilling budgets tend to be more susceptible to the
influences of current price fluctuations. Other factors that can affect the
Company's ability to work its drilling rigs are the weather, which can, under
adverse circumstances, delay or even cause a project to be abandoned by an
operator, the competition faced by the Company in securing the award of a
15
<PAGE>
drilling contract in a given area, the experience and recognition of the Company
in a new market area, and the availability of labor to run the Company's
drilling rigs.
UNCERTAINTY OF OIL AND NATURAL GAS RESERVES AND WELL PERFORMANCE
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Estimating quantities of proved reserves is imprecise. Such estimates are based
upon certain assumptions pertaining to future production levels, future natural
gas and crude oil prices, timing and amount of development expenditures and
future operating costs made using currently available geologic, engineering and
economic data, some or all of which may prove to be incorrect over time. As a
result of changes in these assumptions that will occur in the future, and based
upon further production history, results of future exploration and development
activities, future natural gas and crude oil prices and other factors, the
reported quantity of reserves may be subject to upward or downward revision.
In addition to the foregoing, projections regarding the potential
production and reserve capabilities of newly drilled and/ or completed wells are
subject to additional uncertainties that may significantly influence such
projections. Such wells have a very limited production history, if any, on which
to base future forecasts of their capabilities. Since an established rate of
production is a primary factor used by reservoir engineers to forecast oil and
natural gas reserves as well as a well's production rate, the lack of this
information decreases the Company's ability to accurately project such
information. In addition, there are inherent risks in both the drilling and
completion phases of a new well which could cause a well bore to be prematurely
abandoned due either to the loss of the well bore in the physical sense or due
to the costs associated with operational problems which could render further
operations uneconomical.
BANK BORROWING
The amount of the Company's bank debt as well as its projected borrowing
is, to a large extent, a function of the costs associated with the projects
undertaken by the Company at any given time and the cash flow received by the
Company for its oil and natural gas production. Generally, the costs incurred by
the Company in its normal operations are those associated with the drilling of
oil and natural gas wells, the acquisition of producing properties, and the
costs associated with the maintenance of its drilling rig fleet. To some extent,
these costs, particularly the first two items, are discretionary and the
Company maintains a degree of control regarding the timing and/ or the need to
incur the same. However, in some cases, unforeseen circumstances may arise, such
as in the case of an unanticipated opportunity to acquire a large producing
property package or the need to replace a costly rig component due to an
unexpected loss, which could force the Company to incur increased bank debt
above that which it had expected or forecast. Likewise, for many of the reasons
mentioned above, the Company's cash flow may not be sufficient to cover its
current cash requirements which would then require the Company to increase its
bank borrowing.
16
<PAGE>
Item 3. Legal Proceeding
- -------------------------
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion, should
result in judgments which would have a material adverse effect on the Company.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted to the security holders during the fourth
quarter of the Company's calendar year ended December 31, 1995.
17
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 21, 1996, the Company had 3,225 holders of record of its
common stock. The Company has not paid any cash dividends on shares of its
common stock since its organization and currently intends to continue its policy
of retaining earnings, if any, from the Company's operations. The Company is
prohibited, by certain loan agreement provisions, from declaring and paying
dividends (other than stock dividends) during any fiscal year in excess of 25
percent of its consolidated net income of the preceding fiscal year. The table
below reflects the high and low sales prices per share of the Company's common
stock as reported by the New York Stock Exchange, Inc. for the period indicated:
1995 1994
QUARTER High Low High Low
------- ------ ------ ------ ------
First $3 1/4 $2 1/2 $3 1/2 $2 5/8
Second $3 7/8 $2 7/8 $3 1/4 $2 3/4
Third $4 1/4 $3 1/4 $3 1/2 $2 5/8
Fourth $4 3/4 $3 1/2 $3 7/8 $2 5/8
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<PAGE>
Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
1995 1994 1993 1992 1991
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $53,074 $43,895 $38,682 $33,744 $40,232
======= ======= ======= ======= =======
Income From Continuing
Operations $ 3,751 $ 4,628 $ 3,937 $ 1,631 $ 4,164
======= ======= ======= ======= =======
Net Income $ 3,999 (1) $ 4,794 (2) $ 3,871 $ 1,087 (3) $ 4,341
======= ======= ======= ======= =======
Net Income Per Common
Share:
Continued $.18 $.22 $.19 $.08 $.20
==== ==== ==== ==== ====
Net Income $.19 (1) $.23 (2) $.19 $.05 (3) $.21
==== ==== ==== ==== ====
Total Assets $110,922 $103,933 $ 88,816 $ 83,960 $ 84,972
======== ======== ======== ======== ========
Long-Term Debt $ 41,100 $ 37,824 $ 25,919 $ 22,298 $ 23,153
======== ======== ======== ======== ========
Long-Term Portion
of Natural Gas
Purchaser Prepayments $ 2,109 $ 2,149 $ 4,417 $ 5,924 $ 7,626
======== ======== ======== ======== ========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
======== ======== ======== ======== ========
___________
(1) Includes a $635,000 gain on compressor sale, a $850,000 gain from
settlement of litigation and a net $530,000 deferred tax benefit.
(2) Includes a $742,000 gain on sale of a natural gas gathering system.
(3) Includes a $1.5 million provision for litigation.
19
<PAGE>
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1995, 1994 and 1993 activity.
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------------------------------------------------------------------------
Results of Operations
- ---------------------
Financial Condition and Liquidity
- ---------------------------------
The Company currently has a loan agreement ("Loan Agreement"), which
provides for a total commitment of $75 million, consisting of a revolving credit
facility through August 31, 1997 and a term loan thereafter, maturing on August
31, 2001. Borrowings under the revolving credit facility are limited to a
borrowing base which is subject to a semi-annual redetermination. The latest
borrowing base determination indicated $50 million of the commitment is
available to the Company. The Loan Agreement contains certain covenants which
require the Company to maintain consolidated net worth of at least $48 million,
a modified current ratio of not less than 1 to 1, a ratio of long-term debt, as
defined in the Loan Agreement, to consolidated tangible net worth not greater
than 1 to 1 and a ratio of total liabilities, as defined in the Loan Agreement,
to consolidated tangible net worth not greater than 1.25 to 1. In addition,
working capital provided by operations, as defined in the Loan Agreement, cannot
be less than $12 million in any year. At December 31, 1995, borrowings under
the Loan Agreement totaled $41.1 million. At February 21, 1996, borrowings under
the Loan Agreement totaled $40.9 million with $7.9 million available for future
borrowings. The average interest rate on the bank debt was 8.2 and 7.6 percent
at December 31, 1995 and February 21, 1996, respectively. At the Company's
election, any portion of the debt outstanding may be fixed at the London
Interbank Offered Rate ("Libor Rate") for 30, 60, 90 or 180 days with the
remainder of the outstanding debt subject to the Chase Manhattan Bank, N. A.
prime rate ("Prime Rate"). During any Libor Rate funding period the Company may
not pay in part or in whole the outstanding principal balance of the note to
which such Libor Rate option applies. At both December 31, 1995 and February
21, 1996, $38.0 million of borrowings were subject to the Libor Rate. A
commitment fee of 1/2 of 1 percent is charged for any unused portion of the
borrowing base.
Shareholders' equity at December 31, 1995 was $56.6 million, making
the Company's ratio of long-term debt-to-equity .73 to 1. The Company's primary
source of liquidity and capital resources in the near- and long-term will
consist of cash flow from operating activities and available
borrowings under the Company's Loan Agreement. Net cash provided by continuing
operating activities in 1995 was $11.2 million as compared to $12.6 million in
1994.
The Company's capital expenditures during 1995 were $22.0 million. The
majority of the capital expenditures, $19.3 million, were made in the
Company's oil and natural gas operations with $8.8 million and $9.2
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<PAGE>
million used for exploration and development drilling and producing
property acquisitions, respectively. Capital expenditures made by the
Company's contract drilling operations were approximately $1.6 million in
1995 and principally consisted of drill pipe and drill collar expenditures
along with improvements to large rig components which benefit
current and future years. The Company's rigs are composed of large components
some of which, on a rotational basis, are required to be overhauled to assure
proper performance. Such capital expenditures will continue in future years.
Additional expenditures of approximately $2 million will be required in 1996 for
drill pipe as certain grades of the Company's drill pipe are reaching the end of
their useful life.
During 1996, the Company's oil and natural gas segment plans to focus on its
developmental drilling program as early 1996 natural gas prices have improved
lessening the availability of economical producing property acquisitions. The
Company's capital expenditures are discretionary and directed toward increasing
reserves and future growth. Current operations should not be adversely affected
by any inability to obtain funds outside of the Company's Loan Agreement. The
decision to acquire or drill on oil and natural gas properties at any given time
depends on market conditions, potential return on investment, future drilling
potential and the availability of opportunities to obtain financing given the
circumstances involved, thus providing the Company with a large degree of
flexibility in incurring such costs. Depending, in part, on commodity pricing,
the Company plans to spend approximately $20 million on its capital expenditure
program in 1996.
The Company has 2.873 million warrants outstanding. The warrants
entitle the holders to purchase one share of common stock at a price of
$4.375 per share. The warrants, subject to certain restrictions, are
callable by the Company, in whole or in part, at $.50 per warrant. A
Second Amendment to the Warrant Agreement between the Company and the
Warrant Agent, dated May 9, 1994, extended the term of the warrants to
August 30, 1996.
The Company continued to receive monthly payments on behalf of itself
and other parties (collectively the "Committed Interest") from a natural
gas purchaser pursuant to a settlement agreement (the "Settlement
Agreement"). As a result of the Settlement Agreement, the December 31,
1995 prepayment balance of $2.1 million paid by the purchaser for natural
gas not taken (the "Prepayment Balance") is subject to recoupment in
volumes of natural gas through a period ending on the earlier of recoupment
or December 31, 1997 (the "Recoupment Period"). Additionally, the purchaser
is obligated to make monthly payments on behalf of the Committed Interest
based on their share of the natural gas deliverability of the wells subject
to the Settlement Agreement, up to a maximum of $180,000 or a minimum of
$90,000 per month for the year 1996. Both the maximum and minimum monthly
payments decline annually through the Recoupment Period. If natural gas is
taken during a month, the value of such natural gas is credited toward the
monthly amount the purchaser is required to pay. In the event the
purchaser takes volumes of natural gas valued in excess of its monthly
payment obligations, the value taken in excess is applied to reduce any
21
<PAGE>
then outstanding Prepayment Balance. The Company currently believes that
sufficient natural gas deliverability is available to enable the Committed
Interest to receive substantially all of the maximum monthly payments
during 1996. At the end of the Recoupment Period, the Settlement Agreement
and the natural gas purchase contracts which are subject to the Settlement
Agreement will terminate. If the Prepayment Balance is not fully recouped
in natural gas by December 31, 1997, then the unrecouped portion is subject
to cash repayment, limited to a maximum of $3 million, payable in equal
annual payments over a five year period with the first payment due June 1, 1998.
The Company anticipates the maximum balance of $3 million will be unrecouped at
December 31, 1997. Under the Settlement Agreement, the purchaser is entitled to
make a monthly determination of the volumes to be purchased from the wells
subject to the Settlement Agreement. During 1994 and the first nine months of
1995 natural gas delivered was approximately 75 percent of the deliverability of
the wells subject to the Settlement Agreement. Pursuant to the terms of the
Settlement Agreement, the purchaser notified the Company that effective October
1, 1995, the purchaser plans to make seasonal takes of natural gas by requesting
the maximum deliverability subject to the Settlement Agreement in certain months
and no deliverability in other months. For the majority of the fourth quarter
of 1995 and continuing into the first quarter of 1996 the purchaser has
requested the maximum deliverability subject to the Settlement Agreement.
Because these month-to-month determinations, up to certain maximum levels, are
made by the purchaser, the Company is unable to predict with certainty future
natural gas sales from these wells. In addition, future revenues to be received
by the Company would be impacted by the failure of the purchaser to meet its
obligations, financially or otherwise, under the terms of the Settlement
Agreement or by the ability of the wells to maintain certain projected
deliverability requirements. In the event the wells are unable to maintain such
deliverability, the monthly payments to be received by the Company under the
Settlement Agreement would be decreased. The price per Mcf under the Settlement
Agreement is substantially higher than current spot market prices. The impact
of the higher price received under the Settlement Agreement increased pre-tax
income approximately $1.6, $1.8 and $1.9 million in 1995, 1994 and 1993,
respectively.
Oil prices received by the Company in 1995 ranged from an average of
$15.33 in July to $18.14 in December. The Company's average price for oil
received in 1995 was $16.65. Natural gas prices received by the Company in 1995
ranged from an average of $1.35 in March to $2.01 in December. Average natural
gas prices received by the Company remained volatile throughout 1995 and
averaged $1.61 f or the year as a whole. Oil prices within the industry
remain largely dependent upon world market developments for crude oil. Prices
for natural gas are influenced by weather conditions and supply imbalances,
particularly in the domestic market, an d by world wide oil price levels. Any
large drop in spot market natural gas prices will have a significant adverse
effect on the value of the Company's reserves and could cause the Company to
reduce the carrying value of its oil and natural gas properties. Likewise,
declines in natural gas or oil prices could adversely effect the semi-annual
borrowing base determination under the Company's Loan Agreement since this
determination is calculated on the value of the Company's oil and natural gas
reserves.
22
<PAGE>
The Company's ability to utilize its full complement of drilling rigs,
should economic conditions improve in the future, will be limited due to
the lack of qualified labor and certain supporting equipment not only
within the Company but in the industry as a whole. The Company's ability
to utilize its drilling rigs at any given time is dependent on a number of
factors, including but not limited to, the price of both oil and natural
gas, the availability of labor and the Company's ability to supply the type
of equipment required. The Company's management expects that these factors
will continue to influence the Company's rig utilization during 1996.
In the third quarter of 1994, the Company's Board of Directors
authorized the Company to purchase up to 1,000,000 shares of the Company's
outstanding common stock on the open market. Since that time, 115,100 shares
have been repurchased at prices ranging from $2 1/2 to $3 3/8 per share. During
the first quarter of 1995, 46,659 of the purchased shares were reissued as the
Company's matching contribution to its 401(k) Employee Thrift Plan. At December
31, 1995, 68,441 treasury shares were held by the Company.
The Company's wholly owned natural gas marketing subsidiary, Mountain
Front Pipeline Company, achieved substantial growth in revenues during
previous years, but did not achieve the size necessary to reach desired levels
of profitability. Consequently, on April 1, 1995 the Company completed a
business combination between the Company's natural gas marketing operations and
a third party also involved in natural gas marketing activities forming a new
company called GED Gas Services, L.L.C. ("GED"). The Company owns a 34 percent
interest in GED. Effective November 1, 1995 GED sold its natural gas marketing
operations to a third party. T his sale removed the Company from the third party
natural gas marketing business. The creation of GED and its subsequent sale of
its marketing operations did not adversely affect the Company's drilling and oil
and natural gas exploration operations or the profitability of the Company as a
whole. The discontinuation of the Company's natural gas marketing segment has
been accounted for as a discontinued operation and accordingly, the 1995 and
prior year financial information has been restated to reflect this treatment.
Effects of Inflation
- ---------------------
The effects of inflation on the Company's current operations have been
minimal due to low inflation rates. However, the impact of inflation on
the Company in the future will depend on the relative increase, if any, the
Company may realize in its rig rates and the selling price of its oil and
natural gas. If industry activity increases substantially, shortages in
support equipment such as drill pipe, third party services and qualified
labor would occur resulting in corresponding increases in material and
labor costs. These market conditions may limit the Company's ability to
realize improvements in operating profits.
23
<PAGE>
Results of Operations
1995 versus 1994
- ----------------
Net income for 1995 was $3,999,000, compared with $4,794,000 in 1994.
While the Company continued to increase natural gas production through producing
property acquisitions and developmental drilling, lower 1995 natural gas prices
limited corresponding increases in net income. Net income in the fourth quarter
of 1995 w as also further reduced by a $254,000 write down of certain rig
components as the Company elected to take 3 of its drilling rigs out of service
since current economic conditions do not warrant the capital investment
necessary to keep them in service. The impact of lower natural gas prices on
net income was partially offset by a $635,000 gain from the sale of 44 natural
gas compressors and certain related support equipment which were sold for $2.7
million in the first quarter and by the receipt of $850,000 in the third quarter
from a settlement reached by two of the Company's subsidiaries in certain
litigation brought against the Federal Deposit Insurance Corporation and other
parties. In the fourth quarter, the Company also recognized a $360,000 net gain
from the Company's interest in the sale of GED's gas marketing operations and a
$530,000 net income tax benefit. The disposition of the Company's involvement
in third party natural gas marketing does not adversely affect the operation of
the Company's drilling and oil and natural gas exploration operations or the
profitability of the Company as a whole. Total revenues from continuing
operations increased to $53,074,000 in 1995 as compared to $43,895,000 in 1994.
The Company's 1994 net income included a net gain of $742,000 recognized in
conjunction with the sale of one of the Company's natural gas gathering systems.
Oil and natural gas revenues increased 20 percent due to a 25 percent
increase in natural gas production and a 42 percent increase in oil
production between 1995 and 1994. Average oil prices received by the Company
increased 10 percent while average natural gas prices received by the Company
decreased 13 percent. The average natural gas price declined due to a 11
percent reduction in average spot market prices received by the Company coupled
with a 18 percent reduction in volumes produced from certain wells included
under the Settlement Agreement which contains provisions for prices which are
higher than current spot market prices. The impact of higher prices received
under the Settlement Agreement increased pre-tax income by approximately $1.6
and $1.8 million in 1995 and 1994, respectively.
In 1995, revenues from contract drilling operations increased by 19
percent as average rig utilization increased from 9.5 rigs operating in 1994 to
10.9 rigs operating in 1995. Daywork revenues represented 57 percent of total
drilling revenues in 1995 and 58 percent in 1994. Turnkey and footage contracts
typically provide for higher revenues since a greater portion of the expense of
drilling the well is born by the drilling contractor.
In 1994, the Company moved two of its rigs under multi-well contracts to the
South Texas Basin creating a new operating region for the Company's drilling
24
<PAGE>
services and helping to further improve its rig utilization. In the fourth
quarter of 1995, the contract drilling operations opened an office in Houston,
Texas with plans to further develop this new market area. At December 31, 19
95, four of the Company's 22 rigs were located in the South Texas Basin.
Operating margins (revenues less operating costs) for the Company's oil and
natural gas operations were 62 percent in 1995 compared to 66 percent in 1994.
The reduction was primarily due to the decrease in prices received for the
Company's natural gas production which offset increases in production between
the two years. Margins were also reduced by the shutting in of production on
certain natural gas properties in the months of February and March due to low
spot market natural gas prices. Total operating costs increased 36 percent due
to the additional costs associated with oil and natural gas production from new
wells acquired and drilled in 1995 and 1994.
Operating margins for contract drilling decreased from 12 percent in
1994 to 11 percent in 1995. Margins in 1995 were limited by initial start up
costs incurred in the first quarter of 1995 to establish rigs in the South Texas
Basin and by unusually wet weather conditions during the second quarter of 1995
which delay ed rig moves and depressed rig utilization. Total operating costs
for contract drilling were up 21 percent in 1995 versus 1994 due to increased
rig utilization and start up costs.
Contract drilling depreciation increased 28 percent in response to
increased rig utilization. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 23 percent as the
Company increased its equivalent barrels of production by 28 percent. The
Company's average DD&A rate per equivalent barrel declined from $4.08 in
1994 to $3.93 in 1995.
General and administrative expense increased 9 percent as certain
employee costs, contract services and rental costs increased between the
comparative years due to the continued growth of the Company's operations. This
increase is expected to continue in 1996 as the Company expands its operations.
Interest expense increased 96 percent as the average interest rate on the
Company's outstanding bank debt increased from 7.15 percent in 1994 to 8.52
percent in 1995. Average bank debt outstanding in 1995 was $20.3 million higher
than average bank debt outstanding in 1994 primarily due to the financing of
producing property acquisition and developmental drilling as previously
discussed.
The Company's effective income tax rate in recent years has been
significantly impacted by its net operating loss carryforwards. As of December
31, 1995, the Company's net operating loss and statutory depletion carryforwards
have been fully recognized for financial reporting purposes, resulting in a net
deferred tax asset of $530,000. Realization is dependent on generating
sufficient taxable income prior to expiration of net operating loss
carryforwards. Although realization is not assured, management believes it is
more likely than not that all of the deferred tax asset will be realized. The
amount of the deferred tax asset considered realizable, however, could be
reduced in the near-term if estimates of future taxable income during the
carryforward period are reduced.
25
<PAGE>
1994 versus 1993
- ----------------
Net income for 1994 was $4,794,000, compared with $3,871,000 in 1993.
The increase in net income was achieved through improved operating results
in the Company's contract drilling segment and also from a net gain of $742,000
recognized in conjunction with the sale of one of the Company's gas gathering
systems. Total revenues from continuing operations were
$43,895,000 in 1994 and $38,682,000 in 1993.
Oil and natural gas revenues increased 8 percent due to a 29 percent
increase in natural gas production and a 2 percent increase in oil
production between 1994 and 1993. Average natural gas and oil prices
received by the Company both decreased 10 percent partially offsetting the
increases in production. Average natural gas prices received by the
Company declined due to a 14 percent reduction in average spot market
prices coupled with a 14 percent reduction in volumes produced from certain
wells included under the Settlement Agreement which contains provisions for
prices which are higher than current spot market prices. The impact of the
higher price received under the Settlement Agreement increased pre-tax income by
approximately $1.8 and $1.9 million in 1994 and 1993, respectively.
In 1994, revenues from contract drilling operations increased by 16
percent as average rig utilization increased from 8 rigs in 1993 to 9.5
rigs in 1994. Daywork revenues represented 58 percent of total drilling
revenues in 1994 as opposed to 47 percent in 1993. Turnkey and footage
contracts typically provide for higher revenues since a greater portion of
the expense of drilling the well is born by the drilling contractor.
Operating margins (revenues less operating costs) were either slightly
improved or unchanged for all segments on the Company's operations when
comparing 1994 with 1993. Operating margins for the Company's oil and
natural gas operations were unchanged due primarily to increased production
offset by the decrease in average prices received for oil and natural gas.
Total operating costs from oil and natural gas operations increased 9 percent as
the Company increased production from reserves added primarily through
development drilling i n 1993 and 1994.
Operating margins for contract drilling improved from 10 percent in
1993 to 12 percent in 1994. Increased rig utilization helped provide
greater revenue in relation to fixed costs. Total operating costs for
contract drilling were up 12 percent in 1994 versus 1993 due to the
increased utilization.
Contract drilling depreciation increased 19 percent in response to
increased rig utilization. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 18 percent as the
Company increased its equivalent barrels of production by 22 percent. The
Company's average DD&A rate per equivalent barrel declined from $4.13 in
1993 to $4.08 in 1994.
26
<PAGE>
General and administrative expense increased 8 percent as certain
employee and reporting costs increased between the comparative years. Interest
expense increased 25 percent as the average interest rate on the Company's
outstanding bank debt increased from 6 percent in 1993 to 7.15 percent in 1994.
Outstanding bank debt was $12.4 million higher at December 31, 1994 when
compared with December 31, 1993 due to the financing of the December 15, 1994
Patrick acquisition.
IMPACT OF FINANCIAL ACCOUNTING PRONOUNCEMENTS
- ---------------------------------------------
In March 1995, Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed of" was issued. The statement establishes accounting standards for
the impairment of long-lived assets, such as the Company's drilling,
transportation and other equipment and will be effective for the Company
beginning with the year ending December 31, 1996. The Company does not believe
the new standard will have a material effect on the Company's financial
position or results of operations.
In October 1995, Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation" was issued. The statement requires
the computation of compensation for grants of stock, stock options and other
equity instrument s issued to employees based on fair value. The compensation
calculated is to be either recorded as an expense in the financial statements
or, alternatively, disclosed. The Company anticipates it will elect the
disclosure method of complying with the new standard. Under existing accounting
rules, the Company's stock option grants have not resulted in compensation
expense. Accordingly, under the provisions of the new statement, pro forma net
income to be disclosed will be lower than net income reported in the financial
statements.
27
<PAGE>
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
ASSETS 1995 1994
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 534 $ 2,641
Accounts receivable (less allowance for
doubtful accounts of $116 and $289) 10,398 8,173
Materials and supplies 2,048 1,498
Prepaid expenses and other 1,046 952
--------- ---------
Total current assets 14,026 13,264
--------- ---------
Net Assets of Discontinued Operations - 124
--------- ---------
Property and Equipment:
Drilling equipment 75,751 75,746
Oil and natural gas properties, on the full
cost method 175,225 157,393
Transportation equipment 3,695 3,341
Other 6,100 7,858
--------- ---------
260,771 244,338
Less accumulated depreciation, depletion,
amortization and impairment 164,752 153,833
--------- ---------
Net property and equipment 96,019 90,505
--------- ---------
Other Assets 877 40
--------- ---------
Total Assets $110,922 $103,933
========= =========
The accompanying notes are an integral part of the
consolidated financial statements
28
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY 1995 1994
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term debt $ 20 $ 496
Current portion of natural gas
purchaser prepayments (Note 4) - 1,580
Accounts payable 6,701 6,068
Accrued liabilities 3,976 3,051
Contract advances 410 158
---------- ----------
Total current liabilities 11,107 11,353
---------- ----------
Natural Gas Purchaser Prepayments (Note 4) 2,109 2,149
---------- ----------
Long-Term Debt 41,100 37,824
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value, 5,000,000
shares authorized, none issued - -
Common stock, $.20 par value, 40,000,000
shares authorized, 20,976,090 and
20,910,190 shares issued, respectively 4,195 4,182
Capital in excess of par value 50,181 50,086
Retained earnings (deficit) 2,418 (1,581)
Treasury stock, at cost (68,441 and
25,100 shares, respectively) (188) (80)
---------- ----------
Total shareholders' equity 56,606 52,607
---------- ----------
Total Liabilities and Shareholders' Equity $ 110,922 $ 103,933
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
29
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
1995 1994 1993
-------- -------- --------
Revenues: (In thousands except per share amounts)
Contract drilling $20,211 $16,952 $14,676
Oil and natural gas 31,187 26,001 24,073
Other 1,676 942 (67)
-------- -------- --------
Total revenues 53,074 43,895 38,682
Expenses: -------- -------- --------
Contract drilling:
Operating costs 18,041 14,909 13,269
Depreciation and impairment 2,596 2,030 1,713
Oil and natural gas:
Operating costs 12,003 8,799 8,098
Depreciation, depletion
and amortization 10,223 8,281 7,018
General and administrative 3,893 3,574 3,302
Interest 3,235 1,654 1,324
-------- -------- --------
Total expenses 49,991 39,247 34,724
-------- -------- --------
Income From Continuing Operations
Before Income Taxes 3,083 4,648 3,958
Income Tax Expense (Benefit) (668) 20 21
-------- -------- --------
Income From Continuing Operations 3,751 4,628 3,937
-------- -------- --------
Discontinued Operations:
Income (loss) from operations of
discontinued operations (net of
income taxes of $69 in 1995) (112) 166 (66)
Gain from sale of discontinued
operations (net of income taxes
of $221 in 1995) 360 - -
-------- -------- --------
Income(loss) from
discontinued operations 248 166 (66)
-------- -------- --------
Net Income $ 3,999 $ 4,794 $ 3,871
======== ======== ========
Net Earnings Per Common Share:
Continuing operations $ .18 $ .22 $ .19
======== ======== ========
Net income $ .19 $ .23 $ .19
======== ======== ========
Weighted Average Shares Outstanding 21,210 20,900 20,860
(Both Primary and Fully Diluted) ======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
30
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1993, 1994 and 1995
Capital
In Excess Retained
Common Of Par Earnings Treasury
Stock Value (Deficit) Stock Total
-------- -------- --------- -------- --------
(In thousands)
Balances,
January 1, 1993 $ 4,157 $49,841 $(10,246) $ - $43,752
Net income - - 3,871 - 3,871
Activity in employee
compensation plans
(78,706 shares) 15 136 - - 151
-------- -------- --------- -------- --------
Balances,
December 31, 1993 4,172 49,977 (6,375) - 47,774
Net income - - 4,794 - 4,794
Activity in employee
compensation plans
(48,685 shares) 10 109 - - 119
Purchase of treasury
stock (25,100
shares) - - - (80) (80)
-------- -------- --------- -------- --------
Balances,
December 31, 1994 4,182 50,086 (1,581) (80) 52,607
Net income - - 3,999 - 3,999
Activity in employee
compensation plans
(112,559 shares) 13 95 - 122 230
Purchase of treasury
stock (90,000
shares) - - - (230) (230)
-------- -------- --------- -------- --------
Balances,
December 31, 1995 $ 4,195 $50,181 $ 2,418 $ (188) $56,606
======== ======== ========= ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
31
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1995 1994 1993
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities:
Income from continuing operations $ 3,751 $ 4,628 $ 3,937
Adjustments to reconcile income
from continuing operations
to net cash provided (used) by
continuing operating activities:
Depreciation, depletion,
amortization and impairment 13,120 10,760 9,243
Gain on disposition of assets (723) (813) (49)
Employee stock compensation plans 231 119 151
Bad debt expense 55 - -
Deferred tax benefit (682) - -
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (2,280) 94 428
Materials and supplies (550) (74) (99)
Prepaid expenses and other (94) (396) 318
Accounts payable (1,151) (871) (1,632)
Accrued liabilities 925 824 (877)
Contract advances 252 148 8
Natural gas purchaser prepayments (1,620) (1,858) (1,743)
-------- -------- --------
Net cash provided
by continuing operating
activities 11,234 12,561 9,685
-------- -------- --------
Net cash flows provided by
discontinued operations
including changes in
working capital (259) 532 182
-------- -------- --------
Net cash provided by
operating activities 10,975 13,093 9,867
-------- -------- --------
The accompanying notes are an integral part of the
consolidated financial statements
32
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
1995 1994 1993
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions) $(20,634) $(28,227) $(11,946)
Proceeds from disposition of assets 4,613 2,038 709
Decrease in short-term investments - 41 664
(Acquisition) disposition
of other assets - 141 (45)
Proceeds of sale of
discontinued operations 369 - -
--------- --------- ---------
Net cash used in
investing activities (15,652) (26,007) (10,618)
--------- --------- ---------
Cash Flows From Financing Activities:
Borrowings under line of credit 39,700 63,700 43,400
Payments under line of credit (35,900) (51,300) (40,600)
Proceeds from notes payable
and other long-term debt - - 911
Payments on notes payable and
other long-term debt (1,000) (480) (367)
Acquisition of treasury stock (230) (80) -
--------- --------- ---------
Net cash provided by
financing activities 2,570 11,840 3,344
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents (2,107) (1,074) 2,593
Cash and Cash Equivalents,
Beginning of Year 2,641 3,715 1,122
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 534 $ 2,641 $ 3,715
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 3,214 $ 1,548 $ 1,326
Income taxes $ - $ 2 $ 2
The accompanying notes are an integral part of the
consolidated financial statements
33
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Principles of Consolidation
The consolidated financial statements include the accounts of Unit
Corporation and its directly and indirectly wholly owned subsidiaries (the
"Company"). The Company's investment in limited partnerships is accounted for
on the proportionate consolidation method, whereby its share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business
The Company is engaged in the development, acquisition and production of
oil and natural gas properties and the land contract drilling of oil and natural
gas wells primarily in the Anadarko, Arkoma and South Texas Basins. These
basins are located in Oklahoma, Texas, Kansas and Arkansas. Additional
producing properties are located in Canada and other states, including New
Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana, Alabama and
Mississippi. The Company has an interest in 2,635 wells and serves as operator
of 482 of those wells. Land contract drilling of oil and natural gas wells is
performed for a wide range of customers with the 22 drilling rigs owned and
operated by the Company.
Drilling Contracts
The Company accounts for "footage" and "turnkey" drilling contracts, in
which the Company assumes the risks associated with drilling the well, under the
completed-contract method and for "daywork" drilling contracts under the
percentage-of-completion method. The entire amount of the loss, if any, is
recorded when the loss is determinable.
The costs of uncompleted drilling contracts include expenses incurred to
date on "footage" or "turnkey" drilling contracts which are still in process.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and
all investments with maturities at date of purchase of three months or less
which are readily convertible into known amounts of cash.
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated useful
34
<PAGE>
lives, including a minimum provision of 20 percent of the active rate when the
equipment is idle. At December 31, 1995, the Company elected to take three rigs
out of service, which rigs and certain other components of the rig fleet were
written down by $254,000 to their estimated market value. The Company uses the
composite method of depreciation for drill pipe and collars and calculates the
depreciation by footage actually drilled compared to total estimated remaining
footage. Depreciation of other property and equipment is computed using the
straight-line method over the estimated useful lives of the assets ranging from
3 to 15 years.
Realization of the carrying value of the Company's drilling rigs is
evaluated utilizing estimated future net cash flows from utilization of the
Company rigs. Changes in these estimates could cause the Company to reduce the
carrying value of its rigs.
When property and equipment components are disposed of, the cost and the
related accumulated depreciation are removed from the accounts and any resulting
gain or loss is generally reflected in operations. For dispositions of drill
pipe and d rill collars, an average cost for the appropriate feet of drill pipe
and drill collars is removed from the asset account and charged to accumulated
depreciation and proceeds, if any, are credited to accumulated depreciation.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and
development activities on the full cost method of accounting prescribed by the
Securities and Exchange Commission ("SEC"). Accordingly, all productive and
non-productive costs incurred in connection with the acquisition, exploration
and development of oil and natural gas reserves are capitalized and amortized on
a composite units-of-production method based on proved oil and natural gas
reserves. The Company's determination of its oil and natural gas reserves are
reviewed annually by independent petroleum engineers. The average composite
rates used for depreciation, depletion and amortization ("DD&A") were $3.93,
$4.08 and $4.13 per equivalent barrel in 1995, 1994 and 1993, respectively. The
Company's calculation of DD&A includes estimated future expenditures to be
incurred in developing proved reserves and estimated dismantlement and
abandonment costs, net of estimated salvage values. In the event the
unamortized cost of oil and natural gas properties being amortized exceeds the
full cost ceiling, as defined by the SEC, the excess is charged to expense in
the period during which such excess occurs. The full cost ceiling is based
principally on the estimated future discounted net cash flows from the Company's
oil and natural gas properties. As discussed in Note 12, such estimates are
imprecise. Changes in these estimates or declines in oil and natural gas prices
could cause the Company in the near-term to reduce the carrying value of its oil
and natural gas properties.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
35
<PAGE>
current operations for services performed on oil and natural gas properties in
which the Company has an interest or on properties in which a partnership, of
which the Comp any is a general partner, has an interest. Accordingly, in 1994
the Company recorded $14,000 of contract drilling profits as a reduction of the
carrying value of its oil and natural gas properties rather than including these
profits in current operations. No contract drilling profits were realized on
such interests in 1995 and 1993.
Limited Partnerships
The Company, through its wholly owned subsidiary, Unit Petroleum
Company, is a general partner in eleven oil and natural gas limited partnerships
sold privately and publicly. Certain of the Company's officers and directors
own interests in some of these partnerships. Their interests were acquired
generally on the same basis as other outside investors.
The Company shares in partnership revenues and costs in accordance with
formulas prescribed in each limited partnership agreement. The partnerships
also reimburse the Company for certain administrative costs incurred on behalf
of the partner ships.
Income Taxes
Measurement of current and deferred income tax liabilities and assets
is based on provisions of enacted tax law; the effects of future changes in tax
laws or rates are not included in the measurement. Valuation allowances are
established where necessary to reduce deferred tax assets to the amount expected
to be realized. Income tax expense is the tax payable for the year and the
change during that year in deferred tax assets and liabilities.
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales. This
method allows for recognition of revenue which may be more or less than the
Company's share of pro-rata production from certain wells. Based upon the
Company's 1995 average spot market natural gas price of $1.47 per Mcf, the
Company estimates its balancing position to be approximately $4.5 million on
under-produced properties and approximately $2.7 million on over-produced
properties.
The Company's policy is to expense its pro-rata share of lease operating
costs from all wells as incurred. Such expenses relating to the Company's
balancing position on wells on which the Company has imbalances are not
material.
Financial Instruments and Concentrations of Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
36
<PAGE>
credit risk is considered by management to be limited due to the large number of
customers comprising the Company's customer base. In addition, at December 31,
1995 and 1994, the Company had a concentration of cash of $1.2 and $2.3 million,
respectively, with one bank.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Impact of Financial Accounting Pronouncements
In March 1995, Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed of" was issued. The statement establishes accounting standards for the
impairment of long-lived assets, such as the Company's drilling, transportation
and other equipment and will be effective for the Company beginning with the
year ending December 31, 1996. The Company does not believe the new standard
will have a material effect on the Company's financial position or results of
operations.
In October 1995, Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation" was issued. The statement requires
the computation of compensation for grants of stock, stock options and other
equity instrument s issued to employees based on fair value. The compensation
calculated is to be either recorded as an expense in the financial statements
or, alternatively, disclosed. The Company anticipates it will elect the
disclosure method of complying with the new standard. Under existing accounting
rules, the Company's stock option grants have not resulted in compensation
expense. Accordingly, under the provisions of the new statement, pro forma net
income to be disclosed will be lower than net income reported in the financial
statements.
Reclassifications
Certain reclassifications have been made in the 1993 and 1994
consolidated financial statements to conform them to classifications used in
1995.
NOTE 2 - DISCONTINUED OPERATIONS
- --------------------------------
On April 1, 1995, the Company's natural gas marketing operations were
combined with a third party also involved in natural gas marketing activities
into a business combination forming GED Gas Services L.L.C. ("GED"). The
combination was made to attain the increased volumes deemed necessary to
37
<PAGE>
profitably market third party natural gas. The Company owns a 34 percent
interest in GED. On November 1, 1995 GED sold its natural gas marketing
operation. This sale removed the Company from the third party natural gas
marketing business. The gain on the sale was $360,000 net of income tax of
$221,000. Prior years have been restated to present the Company's former
natural gas marketing activity as a discontinued operation.
Summary results of operations and financial position data of the
discontinued operations were as follows:
For the Year Ended December 31,
1995 1994 1993
------- ------- -------
(In Thousands)
Results of Operations:
Revenues attributable to
discontinued operations $13,548 $43,725 $31,636
Expenses attributable to
discontinued operations 13,729 43,559 31,702
------- ------- -------
Income (loss) attributable
to discontinued operations
before income taxes (181) 166 (66)
Income tax benefit 69 - -
------- ------- -------
Income (loss) attributable
to discontinued
operations $ (112) $ 166 $ (66)
======= ======= =======
December 31,
1995 1994
------- -------
(In Thousands)
Financial Position:
Current assets $ - $ 8,574
Net property plant and
equipment - 38
Current liabilities - (8,488)
------- -------
Net assets of discontinued
operations $ - $ 124
======= =======
NOTE 3 - WARRANTS
- -----------------
In 1987, the Company issued 2.873 million Units, consisting of three
shares of the Company's common stock and one warrant, at a price of $10.375 per
Unit. Each warrant entitles the holder to purchase one share of the Company's
38
<PAGE>
common stock a t a price of $4.375 anytime prior to the warrant's expiration on
August 30, 1996. The warrants, subject to certain restrictions, are callable by
the Company, in whole or in part, at $.50 per warrant. As of December 31, 1995
no warrants have been exercised.
NOTE 4 - NATURAL GAS PURCHASER PREPAYMENTS
- -------------------------------------------
In March 1988, the Company entered into a settlement agreement with a
natural gas purchaser. During early 1991, the Company and the natural gas
purchaser superseded the original agreement with a new settlement agreement
effective retroactively to January 1, 1991. Under these settlement agreements
("Settlement Agreement"), the Company has a prepayment balance of $2.1 million
at December 31, 1995 representing proceeds received from the purchaser as
prepayment for natural gas. This amount is net of natural gas recouped and net
of certain amounts disbursed to other owners (such owners, collectively with the
Company are referred to as the "Committed Interest") for their proportionate
share of the prepayments. The December 31, 1995 p repayment balance is subject
to recoupment in volumes of natural gas for a period ending the earlier of
recoupment or December 31, 1997 (the "Recoupment Period"). Additionally, the
purchaser is obligated to make monthly payments on behalf of the Committed
Interest in an amount calculated as a percentage of the Committed Interest's
share of the deliverability of the wells subject to the Settlement Agreement, up
to a maximum of $180,000 or a minimum of $90,000 per month for the year 1996.
Both t he maximum and minimum monthly payments decline annually through the
Recoupment Period. At December 31, 1997, the Committed Interest's prepayment
balance, if any, that has not been fully recouped in natural gas is subject to a
cash repayment limited to a maximum of $3 million to be made in equal annual
payments over a five year period with the first payment due June 1, 1998. The
prepayment amounts subject to recoupment from future production by the purchaser
are being recorded as liabilities a nd are reflected in revenues as recoupment
occurs. The portion of the prepayments that are estimated to be recouped in the
next twelve months has been included in current liabilities. The Company
anticipates the maximum balance of $3 million will b e unrecouped at December
31, 1997. At the end of the Recoupment Period, the terms of the Settlement
Agreement and the natural gas purchase contracts which are subject to the
Settlement Agreement will terminate.
39
<PAGE>
NOTE 5 - LONG-TERM DEBT
- ------------------------
Long-term debt consisted of the following as of December 31, 1995 and
1994:
1995 1994
--------- ---------
Revolving credit and term loan, (In thousands)
with interest at December 31,
1995 and 1994 of 8.2 percent
and 8.5 percent, respectively $ 41,100 $ 37,300
Other 20 1,020
--------- ---------
41,120 38,320
Less current portion 20 496
--------- ---------
Total long-term debt $ 41,100 $ 37,824
========= =========
At December 31, 1995, the Company's loan agreement ("Loan Agreement")
provided for a total loan commitment of $75 million consisting of a revolving
credit facility through August 31, 1997 and a term loan thereafter, maturing on
August 31, 200 1. Borrowings under the Loan Agreement are limited to a semi-
annual borrowing base computation which as of December 31, 1995 is $50 million.
Borrowings under the revolving credit facility bear interest at the
Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London Interbank
Offered Rates ("Libor Rate") plus 1.75 to 2.25 percent depending on the level of
debt as a percentage of the total borrowing base. Subsequent to August 1, 1997,
borrowings under the Loan Agreement bear interest at the Prime Rate plus .25
percent or the Libor rate plus 2.00 to 2.50 percent depending on the level of
debt as a percentage of the total borrowing base.
At the Company's election, any portion of the debt outstanding may be
fixed at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate
funding period the Company may not pay in part or in whole the outstanding
principal balance of t he note to which such Libor Rate option applies.
Borrowings under the Prime Rate option may be paid anytime in part or in whole
without premium or penalty.
A 1/2 of 1 percent facility fee is charged for any unused portion of the
borrowing base. Virtually all of the Company's drilling rigs are collateral for
such indebtedness and the balance of the Company's assets are subject to a
negative pledge.
The Loan Agreement includes prohibitions against (i) the payment of
dividends (other than stock dividends) during any fiscal year in excess of 25
percent of the consolidated net income of the Company during the preceding
fiscal year and only if working capital provided from operations during said
year is equal to or greater than 175 percent of current maturities of long-term
40
<PAGE>
debt at the end of such year, (ii) the incurrence by the Company or any of its
subsidiaries of additional debt with certain very limited exceptions and (iii)
the creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any property of the Company or any of its
subsidiaries, except in favor of its banks. The Loan Agreement also requires
that the Company maintain consolidated net worth of at least $48 million, a
modified current ratio of not less than 1 to 1, a ratio of long-term debt, as
defined in the Loan Agreement, to consolidated tangible net worth not greater
than 1 to 1 and a ratio of total liabilities, as defined in the Loan Agreement,
to consolidated tangible net worth not greater than 1.25 to 1. In addition,
working capital provided by operations, as defined in the Loan Agreement, cannot
be less than $12 million in any year.
Estimated annual principal payments under the terms of all long-term
debt from 1996 through 2000 are $20,000, $3,425,000, $10,275,000, $10,275,000
and $10,275,000. Based on the borrowing rates currently available to the
Company for debt with similar terms and maturities, long-term debt at December
31, 1995 approximates its fair value.
NOTE 6 - INCOME TAXES
- ---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income from continuing operations, to the
Company's effective income tax expense is as follows:
1995 1994 1993
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 1,048 $ 1,580 $ 1,346
Tax benefit of net operating
loss carryforward (1,730) (1,595) (1,331)
State income tax - 6 1
Other 14 29 5
-------- -------- --------
Income tax expense (benefit) $ (668) $ 20 $ 21
======== ======== ========
41
<PAGE>
Deferred tax assets and liabilities are comprised of the following at
December 31, 1995 and 1994:
1995 1994
--------- ---------
Deferred tax assets: (In thousands)
Allowance for losses $ 670 $ 521
Net operating loss carryforwards 17,058 18,190
Statutory depletion carryforward 2,260 2,500
Investment tax credit carryforward 3,530 3,530
--------- ---------
Gross deferred tax assets 23,518 24,741
Valuation allowance (3,530) (6,423)
Deferred tax liability-
Depreciation, depletion and amortization (19,458) (18,318)
--------- ---------
Net deferred tax asset $ 530 $ -
========= =========
The deferred tax asset valuation allowance reflects that the investment
tax credit carryforwards above may not be utilized before the expiration dates
as itemized below due in part to the effects of anticipated future exploratory
and development drilling costs.
Realization of the deferred tax asset is dependent on generating
sufficient taxable income prior to expiration of loss carryforwards. Although
realization is not assured, management believes it is more likely than not that
the deferred tax asset will be realized. The amount of the deferred tax asset
considered realizable, however, could be reduced in the near-term if estimates
of future taxable income during the carryforward period are reduced. Due to the
full utilization of such carryforwards, the Company's effective tax rate in
future years will approximate the statutory tax rate (both federal and state).
At December 31, 1995, the Company has net operating loss carryforwards
for regular tax purposes of approximately $44,891,000 and net operating loss
carryforwards for alternative minimum tax purposes of approximately $37,109,000
which expire i n various amounts from 1999 to 2007. The Company has investment
tax credit carryforwards of approximately $3,530,000 which expire from 1996 to
2000. In addition, a statutory depletion carryforward of approximately
$5,948,000, which may be carried forward indefinitely, is available to reduce
future taxable income, subject to statutory limitations. Based on revised
calculations, the estimated statutory depletion carryforward was reduced and the
estimated deferred tax liability relating to DD&A was increased in the current
year.
42
<PAGE>
NOTE 7 - BENEFIT AND COMPENSATION PLANS
- ---------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common stock
were authorized for issuance under the Plan. On May 3, 1995, the Company's
shareholders amended the Plan to increase by 250,000 shares the aggregate number
of shares of common stock that could be issued under the Plan. Under the terms
of the Plan, bonuses may be granted to employees in either cash or stock or a
combination thereof, and are payable in a lump sum or in annual installments
subject to certain restrictions. The Company issued 38,354 shares under the
Plan in 1993. No shares were issued under the Plan in 1995 or 1994.
At December 31, 1995, the Company also has a Stock Option Plan which
provides for the granting of options for up to 1,500,000 shares of common stock
to officers and employees. The plan permits the issuance of qualified or
nonqualified stock options. Options granted become exercisable at the rate of
20 percent per year one year after being granted and expire after ten years from
the original grant. The exercise price for options granted is based on market
value on the date of the grant .
Activity pertaining to the Stock Option Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES ------------------------------
--------- PER SHARE AGGREGATE
--------------- -----------
Outstanding at
January 1, 1993 752,000 $ 1.50 to 3.375 1,469,520
Granted 89,000 2.75 244,750
Exercised (12,000) 1.50 to 2.37 (19,740)
--------- ---------------- -----------
Outstanding at
December 31, 1993 829,000 1.50 to 3.375 1,694,530
Granted 102,500 3.00 307,500
Exercised (16,000) 1.50 to 2.37 (24,870)
--------- ---------------- -----------
Outstanding at
December 31, 1994 915,500 1.50 to 3.375 1,977,160
Granted 26,000 2.75 to 4.00 83,750
Exercised (65,900) 1.50 to 2.75 (108,900)
Canceled (10,000) 1.875 (18,750)
--------- ---------------- -----------
Outstanding at
December 31, 1995 865,600 $ 1.50 to 4.00 $1,933,260
========= ================ ===========
Options for 675,000, 676,400 and 610,500 shares were exercisable at
prices ranging from $1.50 to $3.375 at December 31, 1995, 1994 and 1993,
respectively.
43
<PAGE>
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock Option
Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the Company's
common stock ma y be issued upon exercise of the stock options. On the first
business day following each annual meeting of stockholders of the Company, each
person who is then a member of the Board of Directors of the Company and who is
not then an employee of the Company or any of its subsidiaries will be granted
an option to purchase 2,500 shares of common stock. The option price for each
stock option is the fair market value of the common stock on the date the stock
options are granted. No stock options m ay be exercised during the first six
months of its term except in case of death and no stock options are exercisable
after ten years from the date of grant.
Activity pertaining to the Directors' Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES ------------------------------
--------- PER SHARE AGGREGATE
-------------- -----------
Outstanding at
January 1, 1993 10,000 $ 1.75 $ 17,500
Granted 10,000 3.75 37,500
--------- -------------- -----------
Outstanding at
December 31, 1993 20,000 1.75 to 3.75 55,000
Granted 10,000 2.875 28,750
--------- -------------- -----------
Outstanding at
December 31, 1994 30,000 1.75 to 3.75 83,750
Granted 12,500 3.375 42,188
--------- -------------- -----------
Outstanding at
December 31, 1995 42,500(1) $1.75 to 3.75 $ 125,938
========= ============== ===========
- -------------
(1) All 42,500 options were exercisable at December 31, 1995.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in full
or on a partial basis. The Company made discretionary contributions under the
plan of 46,659, 32,685 and 28,352 shares of common stock and recognized expense
of $174,000, $130,000 and $162,000 in 199 5, 1994 and 1993, respectively.
Effective March 1, 1993, the Company adopted a salary deferral plan
("Deferral Plan"). The Deferral Plan allows participants to defer the
recognition of salary for income tax purposes until actual distribution of
benefits which occurs at either termination of employment, death or certain
44
<PAGE>
defined unforeseeable emergency hardships. Funds set aside in a trust to
satisfy the Company's obligation under the Deferral Plan at December 31, 1995,
1994 and 1993 totaled $271,000, $108,000 and $41, 000, respectively. The
Company recognizes payroll expense and records a liability at the time of
deferral.
NOTE 8 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through 1995,
with a subsidiary of the Company serving as General Partner. The Partnerships
were formed f or the purpose of conducting oil and natural gas acquisition,
drilling and development operations and serving as co-general partner with the
Company in any additional limited partnerships formed during that year. The
Partnerships participated on a proportionate basis with the Company in most
drilling operations and most producing property acquisitions commenced by the
Company for its own account during the period from the formation of the
Partnership through December 31 of each year. Pursuant to the terms of an
agreement and plan of merger, seven limited partnerships, in which the Company
was general partner, were consolidated into one new employee limited partnership
effective December 31, 1993.
Amounts received in the following years ended December 31 from both
public and private Partnerships for which the Company is a general partner are
as follows:
1995 1994 1993
-------- -------- --------
(In thousands)
Contract drilling $ 34 $ 53 $ 60
Well supervision and other fees $ 119 $ 226 $ 278
General and administrative
expense reimbursement $ 235 $ 209 $ 231
A subsidiary of the Company paid the Partnerships, for which the Company
or a subsidiary is the general partner, $18,000, $38,000 and $65,000 during the
years ended December 31, 1995, 1994 and 1993, respectively, for purchases of
natural gas production.
During 1995 and 1994, a bank owned by one of the Company's Directors was
a participant in the Company's Loan Agreement. The bank's total pro rata share
of the Company's line of credit is currently limited to not exceed $1.5
million.
45
<PAGE>
NOTE 9 - COMMITMENTS AND CONTINGENCIES
- --------------------------------------
The Company leases office space under the terms of operating leases
expiring through January 31, 2000. Future minimum rental payments under the
terms of the leases are approximately $264,000, $244,000, $246,000, $246,000 and
$21,000 in 1996, 1997, 1998, 1999 and 2000, respectively. Total rent expense
incurred by the Company was $307,000, $210,000 and $208,000 in 1995, 1994 and
1993, respectively.
The Company had letters of credit supported by its Loan Agreement
totaling $935,000 at December 31, 1995.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income
Limited Partnership agreements along with the employee oil and gas limited
partnerships require, upon the election of a limited partner, that the Company
repurchase the limited partner's interest at amounts to be determined by
appraisal in the future. Such repurchases in any one year are limited to 20
percent of the units outstanding. The Company made repurchases of $34,000,
$38,000 and $56,000 in 1995, 1994 and 1 993, respectively, for such limited
partners' interests.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion, will
result in judgements which would have a material adverse effect on the Company.
46
<PAGE>
NOTE 10 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
The Company operates in the United States in two industry segments which
are contract drilling and oil and natural gas exploration. The Company also has
natural gas production in Canada which is not significant. Selected financial
information by industry segment is as follows:
Depreciation,
Depletion,
Operating Amortization
Operating Profit Total Capital and Impairment
Revenues (Loss)(1) Assets(2) Expenditures Expense
---------- -------- -------- --------- ----------
(In thousands)
Year ended December 31, 1995:
Drilling $ 20,211 $ (426) $ 15,449 $ 1,556 $ 2,596
Oil and natural gas 31,187 8,961 92,033 19,308 10,223
---------- -------- -------- --------- ----------
51,398 $ 8,535 107,482 20,864 12,819
========
Other 1,676 3,440 1,089 301
---------- -------- --------- ----------
Total $ 53,074 $110,922 $ 21,953 $ 13,120
========== ======== ========= ==========
Year ended December 31, 1994:
Drilling $ 16,952 $ 13 $ 14,771 $ 1,115 $ 2,030
Oil and natural gas 26,001 8,921 83,082 25,110 8,281
---------- -------- -------- --------- ----------
42,953 $ 8,934 97,853 26,225 10,311
========
Other 942 5,956 764 449
Discontinued
operations - 124 - -
---------- -------- --------- ----------
Total $ 43,895 $103,933 $ 26,989 $ 10,760
========== ======== ========= ==========
Year ended December 31, 1993:
Drilling $ 14,676 $ (306) $ 15,738 $ 936 $ 1,713
Oil and natural gas 24,073 8,957 64,845 11,422 7,018
---------- -------- -------- --------- ----------
$ 38,749 $ 8,651 80,583 12,358 8,731
========
Other (67) 7,743 1,372 512
Discontinued
operations - 490 - -
---------- -------- --------- ----------
Total $ 38,682 $ 88,816 $ 13,730 $ 9,243
========== ======== ========= ==========
(1) Operating profit is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not include non-
47
<PAGE>
operating revenues, general corporate expenses, interest expense, income taxes,
provision for litigation or gain from litigation settlement.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash equivalents,
short-term investments, corporate leasehold improvements, furniture and
equipment.
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1995 and 1994 is as
follows:
Three Months Ended
-------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- --------- ----------
(In thousands except per share amounts)
Year ended December 31, 1995:
Revenues $ 12,388 $ 11,505 $ 14,117 $ 15,064
========= ========= ========= =========
Gross profit(1) $ 1,875 $ 1,819 $ 1,721 $ 3,120
========= ========= ========= =========
Income from continuing
operations $ 857 $ 102 $ 916 $ 1,876
Income (loss) from
discontinued
operations 99 (81) (35) (95)
Gain from sale of
discontinued
operations - - - 360
--------- --------- --------- ---------
Net Income $ 956 (2) $ 21 $ 881 (3) $ 2,141 (4)
========= ========= ========= =========
Earnings Per Common Share:
Continuing
operations $ .05 $ - $ .04 $ .09
Discontinued
operations - - - (.01)
Gain on sale of
discontinued
operations - - - .02
--------- --------- --------- ---------
Net income $ .05 (2) $ - $ .04 (3) $ .10 (4)
========= ========= ========= =========
48
<PAGE>
Three Months Ended
------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- --------- ---------
(In thousands except per share amounts)
Year ended December 31, 1994:
Revenues $ 10,587 $ 11,064 $ 11,939 $ 10,305
========= ========= ========= =========
Gross profit(1) $ 2,361 $ 2,754 $ 1,895 $ 1,924
========= ========= ========= =========
Income from continuing
operations $ 1,135 $ 1,407 $ 1,542 $ 544
Income from
discontinued
operations 76 18 48 24
--------- --------- --------- ---------
Net income $ 1,211 $ 1,425 $ 1,590 (5) $ 568
========= ========= ========= =========
Earnings Per Common Share:
Continuing
operations $ .06 $ .07 $ .07 $ .03
Discontinued
operations - - - -
--------- --------- --------- ---------
Net income $ .06 $ .07 $ .07 (5) $ .03
========= ========= ========= =========
(1) Gross Profit excludes other revenues, general and administrative
expense and interest expense.
(2) Includes $635,000 gain on sale of natural gas compressors.
(3) Includes $850,000 gain from the settlement of litigation.
(4) Includes a net income tax benefit of $530,000.
(5) Includes $742,000 net gain on sale of natural gas gathering system.
49
<PAGE>
NOTE 12 - OIL AND NATURAL GAS INFORMATION (UNAUDITED)
- -----------------------------------------------------
The capitalized costs at year end and costs incurred during the year
were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1995:
Capitalized costs:
Proved properties $ 171,259 $ 465 $ 171,724
Unproved properties 3,501 - 3,501
--------- -------- ---------
174,760 465 175,225
Less accumulated depreciation,
depletion, amortization
and impairment 91,739 379 92,118
--------- -------- ---------
Net capitalized costs $ 83,021 $ 86 $ 83,107
========= ======== =========
Cost incurred:
Unproved properties $ 1,338 $ - $ 1,338
Producing properties 9,183 - 9,183
Exploration 1,291 - 1,291
Development 7,486 10 7,496
--------- -------- ---------
Total costs incurred $ 19,298 $ 10 $ 19,308
========= ======== =========
1994:
Capitalized costs:
Proved properties $ 154,688 $ 455 $ 155,143
Unproved properties 2,250 - 2,250
--------- -------- ---------
156,938 455 157,393
Less accumulated depreciation,
depletion, amortization
and impairment 81,583 368 81,951
--------- -------- ---------
Net capitalized costs $ 75,355 $ 87 $ 75,442
========= ======== =========
Cost incurred:
Unproved properties $ 460 $ - $ 460
Producing properties 13,108 - 13,108
Exploration 1,825 - 1,825
Development 9,716 1 9,717
--------- -------- ---------
Total costs incurred $ 25,109 $ 1 $ 25,110
========= ======== =========
50
<PAGE>
USA Canada Total
--------- -------- ---------
(In thousands)
1993:
Capitalized costs:
Proved properties $ 129,612 $ 454 $ 130,066
Unproved properties 2,638 - 2,638
--------- -------- ---------
132,250 454 132,704
Less accumulated depreciation,
depletion, amortization
and impairment 73,419 314 73,733
--------- -------- ---------
Net capitalized costs $ 58,831 $ 140 $ 58,971
========= ======== =========
Cost incurred:
Unproved properties $ 732 $ - $ 732
Producing properties 1,241 - 1,241
Exploration 1,359 - 1,359
Development 8,084 6 8,090
--------- -------- ---------
Total costs incurred $ 11,416 $ 6 $ 11,422
========= ======== =========
51
<PAGE>
The results of operations before income taxes for producing activities
are provided below. Due to the Company's utilization of net operating loss
carryforwards, income taxes are not significant and have not been included.
USA Canada Total
-------- -------- --------
(In thousands)
1995:
Revenues $ 28,928 $ 53 $ 28,981
Production costs 9,914 16 9,930
Depreciation, depletion
and amortization 10,156 11 10,167
-------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing
costs) $ 8,858 $ 26 $ 8,884
======== ======== ========
1994:
Revenues $ 23,964 $ 67 $ 24,031
Production costs 7,011 19 7,030
Depreciation, depletion
and amortization 8,165 53 8,218
-------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing
costs) $ 8,788 $ (5) $ 8,783
======== ======== ========
1993:
Revenues $ 22,040 $ 67 $ 22,107
Production costs 6,439 15 6,454
Depreciation, depletion
and amortization 6,875 81 6,956
-------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing
costs) $ 8,726 $ (29) $ 8,697
======== ======== ========
52
<PAGE>
Estimated quantities of proved developed oil and natural gas reserves
and changes in net quantities of proved developed and undeveloped oil and
natural gas reserves were as follows:
USA Canada Total
---------------- ----------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ----- ----- ------- --------
(In thousands)
1995:
Proved developed and
undeveloped reserves:
Beginning of year 4,308 92,566 - 794 4,308 93,360
Revision of previous
estimates 910 9,525 - (10) 910 9,515
Extensions, discoveries
and other additions 305 7,910 - 48 305 7,958
Purchases of minerals
in place 500 10,892 - - 500 10,892
Sales of minerals in place (18) (938) - - (18) (938)
Production (577) (12,005) - (54) (577) (12,059)
------- -------- ----- ----- ------- --------
End of Year 5,428 107,950 - 778 5,428 108,728
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,521 80,110 - 359 3,521 80,469
End of year 4,697 94,975 - 350 4,697 95,325
1994:
Proved developed and
undeveloped reserves:
Beginning of year 3,304 71,379 - 861 3,304 72,240
Revision of previous
estimates (97) (571) - (14) (97) (585)
Extensions, discoveries
and other additions 601 17,426 - - 601 17,426
Purchases of minerals
in place 910 14,075 - - 910 14,075
Sales of minerals in place (4) (137) - - (4) (137)
Production (406) (9,606) - (53) (406) (9,659)
------- -------- ----- ----- ------- --------
End of Year 4,308 92,566 - 794 4,308 93,360
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,187 65,395 - 426 3,187 65,821
End of year 3,521 80,110 - 359 3,521 80,469
53
<PAGE>
USA Canada Total
---------------- ----------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ----- ----- ------- --------
(In thousands)
1993:
Proved developed and
undeveloped reserves:
Beginning of year 3,308 63,761 - 931 3,308 64,692
Revision of previous
estimates (132) 4,662 - - (132) 4,662
Extensions, discoveries
and other additions 549 9,169 - - 549 9,169
Purchases of minerals
in place 18 1,369 - - 18 1,369
Sales of minerals in place (42) (147) - - (42) (147)
Production (397) (7,435) - (70) (397) (7,505)
------- -------- ----- ----- ------- --------
End of Year 3,304 71,379 - 861 3,304 72,240
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,245 58,809 - 468 3,245 59,277
End of year 3,187 65,395 - 426 3,187 65,821
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made in
connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's reserves as
prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geological
and engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and natural gas reservoirs under existing economic and
operating conditions. Proved developed reserves are those reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are those reserves which are
expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required.
Estimates of oil and natural gas reserves require extensive judgments of
reservoir engineering data as explained above. Assigning monetary values to
such estimates does not reduce the subjectivity and changing nature of such
reserve estimate s. Indeed the uncertainties inherent in the disclosure are
compounded by applying additional estimates of the rates and timing of
production and the costs that will be incurred in developing and producing the
reserves. The information set forth herein is therefore subjective and, since
judgments are involved, may not be comparable to estimates submitted by other
54
<PAGE>
oil and natural gas producers. In addition, since prices and costs do not
remain static and no price or cost escalations or de-escalations have been
considered, the results are not necessarily indicative of the estimated fair
market value of estimated proved reserves nor of estimated future cash flows.
55
<PAGE>
The standardized measure of discounted future net cash flows ("SMOG")
was calculated using year-end prices and costs, and year-end statutory tax
rates, adjusted for permanent differences, that relate to existing proved oil
and natural gas reserves. SMOG as of December 31 is as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1995:
Future cash flows $320,916 $ 1,462 $322,378
Future production and
development costs 107,830 304 108,134
Future income tax expenses 49,437 660 50,097
--------- -------- ---------
Future net cash flows 163,649 498 164,147
10% annual discount for estimated
timing of cash flows 60,826 183 61,009
--------- -------- ---------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $102,823 $ 315 $103,138
========= ======== =========
1994:
Future cash flows $234,171 $ 1,255 $235,426
Future production and
development costs 105,876 311 106,187
Future income tax expenses 20,161 524 20,685
--------- -------- ---------
Future net cash flows 108,134 420 108,554
10% annual discount for estimated
timing of cash flows 30,116 170 30,286
--------- -------- ---------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 78,018 $ 250 $ 78,268
========= ======== =========
1993:
Future cash flows $214,800 $ 861 $215,661
Future production and
development costs 90,177 229 90,406
Future income tax expenses 17,097 244 17,341
--------- -------- ---------
Future net cash flows 107,526 388 107,914
10% annual discount for estimated
timing of cash flows 34,374 157 34,531
--------- -------- ---------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 73,152 $ 231 $ 73,383
========= ======== =========
56
<PAGE>
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1995:
Sales and transfers of oil and
natural gas produced,
net of production costs $(19,015) $ (36) $(19,051)
Net changes in prices and
production costs 28,857 112 28,969
Revisions in quantity estimates
and changes in production timing (6,620) (10) (6,630)
Extensions, discoveries and improved
recovery, less related costs 11,320 49 11,369
Purchases of minerals in place 11,897 - 11,897
Sales of minerals in place (968) - (968)
Accretion of discount 8,447 54 8,501
Net change in income taxes (11,727) (105) (11,832)
Other - net 2,614 1 2,615
--------- -------- ---------
Net change 24,805 65 24,870
Beginning of year 78,018 250 78,268
--------- -------- ---------
End of year $102,823 $ 315 $103,138
========= ======== =========
1994:
Sales and transfers of oil and
natural gas produced,
net of production costs $(16,953) $ (48) $(17,001)
Net changes in prices and
production costs (14,941) 206 (14,735)
Revisions in quantity estimates
and changes in production timing (482) (5) (487)
Extensions, discoveries and improved
recovery, less related costs 17,050 - 17,050
Purchases of minerals in place 13,426 - 13,426
Sales of minerals in place (138) - (138)
Accretion of discount 7,915 35 7,950
Net change in income taxes (457) (177) (634)
Other - net (554) 8 (546)
--------- -------- ---------
Net change 4,866 19 4,885
Beginning of year 73,152 231 73,383
--------- -------- ---------
End of year $ 78,018 $ 250 $ 78,268
========= ======== =========
57
<PAGE>
USA Canada Total
--------- -------- ---------
1993:
Sales and transfers of oil and
natural gas produced,
net of production costs $(15,359) $ (52) $(15,411)
Net changes in prices and
production costs (4,997) 73 (4,924)
Revisions in quantity estimates
and changes in production timing 483 (70) 413
Extensions, discoveries and improved
recovery, less related costs 12,886 - 12,886
Purchases of minerals in place 1,440 - 1,440
Sales of minerals in place (284) - (284)
Accretion of discount 7,619 36 7,655
Net change in income taxes (74) (8) (82)
Other - net 1,178 (4) 1,174
--------- -------- ---------
Net change 2,892 (25) 2,867
Beginning of year 70,260 256 70,516
--------- -------- ---------
End of year $ 73,152 $ 231 $ 73,383
========= ======== =========
The Company's SMOG and changes therein were determined in accordance
with Statement of Financial Accounting Standards No. 69. Certain information
concerning the assumptions used in computing SMOG and their inherent limitations
are discussed below. Management believes such information is essential for a
proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those reserves
nor their present worth. Assigning monetary values to the reserve quantity
estimation process does not reduce the subjective and ever-changing nature of
such reserve estimates. Additional subjectivity occurs when determining present
values because the rate of producing the reserves must be estimated. In
addition to errors inherent in predicting the future, variations from the
expected production rate could result from factors outside of management's
control, such as unintentional delays in development, environmental concerns or
changes in prices or regulatory controls. Also, the reserve valuation assumes
that all reserves will be disposed of by production. However, other factors
such as the sale of reserves in place could affect the amount of cash eventually
realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements in existence at year-end.
58
<PAGE>
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of existing
economic conditions.
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates to the future pretax net cash flows relating to
proved oil and natural gas reserves less the tax basis of the Company's
properties. The future income tax expenses also give effect to permanent
differences and tax credits and allowances relating to the Company's proved oil
and natural gas reserves.
Care should be exercised in the use and interpretation of the above
data. As production occurs over the next several years, the results shown may
be significantly different as changes in production performance, petroleum
prices and costs are likely to occur.
As disclosed in Note 4, the Company is receiving payments from a natural
gas purchaser which are subject to recoupment from future natural gas
production. The amounts received will be reflected in revenues and the reserves
and future net cash flows will be reduced as recoupment occurs.
59
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
We have audited the accompanying consolidated balance sheets of Unit Corporation
and subsidiaries as of December 31, 1995 and 1994 and the related consolidated
statements of operations, changes in shareholders' equity and cash flows and the
related financial statement schedule for each of the three years in the period
ended December 31, 1995. These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Unit Corporation
and subsidiaries as of December 31, 1995 and 1994, and the consolidated results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1995 in conformity with generally accepted accounting
principles. In addition, in our opinion, the financial statement schedule
referred to above, when consider ed in relation to the basic financial
statements taken as a whole, presents fairly, in all material respects, the
information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
February 20, 1996
60
<PAGE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure.
- --------------------
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
- ------------------------------------------------------------
The table below and accompanying footnotes set forth certain information
concerning each executive officer of the Company. Unless otherwise indicated,
each has served in the positions set forth for more than five years. Executive
officers a re elected for a term of one year. There are no family relationships
between any of the persons named.
NAME AGE POSITION
- ---------------- --- ----------------------------------------
King P. Kirchner 68 Chairman of the Board, Chief Executive Officer
and Director
John G. Nikkel 61 President, Chief Operating Officer and Director
Earle Lamborn 61 Senior Vice President, Drilling and Director
Philip M. Keeley 54 Senior Vice President, Exploration and
Production
Larry D. Pinkston 41 Vice President, Treasurer and Chief Financial
Officer
Mark E. Schell 38 General Counsel and Secretary
________
Mr. Kirchner, a co-founder of the Company, has been the Chairman of the
Board and a director since 1963 and was President until November 1983. Mr.
Kirchner is a Registered Professional Engineer within the State of Oklahoma,
having received degrees in Mechanical Engineering from Oklahoma State University
and in Petroleum Engineering from the University of Oklahoma.
Mr. Nikkel joined the Company in 1983 as its President and a director.
From 1976 until January 1982 when he co-founded Nike Exploration Company, Mr.
Nikkel was an officer and director of Cotton Petroleum Corporation, serving as
the President of that Company from 1979 until his departure. Prior to joining
Cotton, Mr. Nikkel was employed by Amoco Production Company for 18 years, last
serving as Division Geologist for Amoco's Denver Division. Mr. Nikkel
presently serves as President and a director of Nike Exploration Company. Mr.
Nikkel received a Bachelor of Science degree in Geology and Mathematics from
Texas Christian University.
61
<PAGE>
Mr. Lamborn has been actively involved in the oil field for over 40
years, joining the Company's predecessor in 1952 prior to it becoming a
publicly-held corporation. He was elected Vice President, Drilling in 1973 and
to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice
President, Exploration and Production. Prior to that time, Mr. Keeley co-
founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and serves as
Executive Vice President and a director of that company. From 1977 until 1982,
Mr. Keeley was employed by Cotton Petroleum Corporation, serving first as
Manager of Land and from 1979 as Vice President and a director. Before joining
Cotton, Mr. Keeley was employed for four years by Apexco, Inc. as Manager of
Land and prior thereto he was employed by Texaco, Inc. for nine years. He
received a Bachelor of Arts degree in Petroleum Land Management from the
University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as
Corporate Budget Director and Assistant Controller prior to being appointed as
Controller in February 1985. He has been Treasurer since December 1986 and was
elected to the position of Vice President and Chief Financial Officer in May
1989. He holds a Bachelor of Science Degree in Accounting from East Central
University of Oklahoma and is a Certified Public Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and
General Counsel. From 1979 until joining the Company, Mr. Schell was Counsel,
Vice President and a member of the Board of Directors of C & S Exploration, Inc.
He receive d a Bachelor of Science degree in Political Science from Arizona
State University and his Juris Doctorate degree from the University of Tulsa Law
School.
The balance of the information required in this Item 10 is incorporated
by reference from the Company's Proxy Statement to be filed with the Securities
and Exchange Commission in connection with the Company's 1996 annual meeting of
stockholders.
Item 11. Executive Compensation
- ---------------------------------
Information required by this item is incorporated by reference from the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1996 annual meeting of stockholders.
62
<PAGE>
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
Information required by this item is incorporated by reference from the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1996 annual meeting of stockholders.
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Information required by this item is incorporated by reference from the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1996 annual meeting of stockholders.
PART IV
63
<PAGE>
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements:
---------------------
Included in Part II of this report:
Consolidated Balance Sheets as of December 31, 1995 and 1994
Consolidated Statements of Operations for the years ended
December 31, 1995, 1994 and 1993
Consolidated Statements of Changes in Shareholders' Equity for the
years ended December 31, 1995, 1994 and 1993
Consolidated Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993
Notes to Consolidated Financial Statements
Report of Independent Accountants
2. Financial Statement Schedules:
------------------------------
Included in Part IV of this report for the years ended
December 31, 1995, 1994 and 1993:
Schedule II - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under which
they are required or because the required information is included in the
consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers assigned
such exhibits in the Exhibit Table of Item 601 of Regulation S-K.
3. Exhibits:
--------
2 Certificate of Ownership and Merger of the Company and Unit
Drilling Co., dated February 22, 1979 (filed as an Exhibit to the
Company's Registration Statement No. 2-63702, which is incorporated
herein by reference).
3.1.1 Certificate of Incorporation (filed as Exhibit 3.2 to the Company's
Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which
is incorporated herein by reference).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated July
21, 1988 (filed as an Exhibit to the Company's Annual Report under
cover of Form 10-K for the year ended December 31, 1989, which is
incorporated herein by reference).
64
<PAGE>
3.1.3 Restated Certificate of Incorporation of Unit Corporation dated
February 2, 1994 (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1993, which
is incorporated herein by reference).
3.2.1 By-Laws (filed as Exhibit 3.5 to the Company's Registration Statement
of Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein
by reference).
3.2.2 Amended and Restated By-Laws, dated June 29, 1988 (filed as an
Exhibit to the Company's Annual Report under cover of Form 10-K for
the year ended December 31, 1989, which is incorporated herein by
reference).
4.2.1 Form of Warrant Agreement between the Company and the Warrant Agent
(filed as Exhibit 4.1 to the Company's Registration statement on Form
S-2 as S.E.C. File No. 33-16116, which is incorporated herein by
reference).
4.2.2 Form of Warrant (filed as Exhibit 4.3 to the Company's Registration
Statement of Form S-2 as S.E.C. File No. 33-16116, which is
incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.2 on Form S-2 as
S.E.C. File No. 33-16116, which is incorporated herein by reference).
4.2.4 First Amendment to Warrant Agreement (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the quarter
ended March 31, 1992, which is incorporated herein by reference).
4.2.5 Second Amendment to Warrant Agreement (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the quarter
ended March 31, 1994, which is incorporated herein by reference).
4.2.6 Rights Agreement dated as of May 19, 1995 between the Company
and Chemical Bank, as Rights Agent (filed as Exhibit 1 to the
Company's Form 8-A filed May 23, 1995, File No. 1-92601 and
incorporated herein by reference).
10.1.14 Amended and Restated Credit Agreement dated as of January 17, 1992 by
and between Unit Corporation and Bank of Oklahoma N.A., F&M Bank and
Trust Company, Fourth National Bank of Tulsa and Western National
Bank of Tulsa (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1991, which
is incorporated herein by reference).
65
<PAGE>
10.1.16 First Amendment to Amended and Restated Credit Agreement dated as of
May 1, 1992, by and between Unit Corporation and Bank of Oklahoma,
N.A., F&M Bank and Trust Company, Fourth National Bank of Tulsa, and
Western National Bank of Tulsa (filed as an Exhibit to the Company's
Quarterly Report under cover of Form 10-Q for the quarter ended June
30, 1992, which is incorporated herein by reference).
10.1.17 Second Amendment to Amended and Restated Credit Agreement, dated
March 3, 1993 and effective as of March 1, 1993, by and between Unit
Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company,
Fourth National Bank of Tulsa, and Western National Bank of Tulsa
(filed as an Exhibit to the Company's Quarterly Report under cover
of Form 10-Q for the quarter ended March 31, 1993, which is
incorporated herein by reference).
10.1.18 Third Amendment to Amended and Restated Credit Agreement effective
as of March 31, 1994, by and between Unit Corporation and Bank of
Oklahoma, N.A., F&M Bank and Trust Company, Bank IV, Oklahoma, N.A.
and American National Bank and Trust Comp any of Shawnee (filed as
an Exhibit to the Company's Quarterly Report under cover of Form 10-
Q for the quarter ended March 31, 1994, which is incorporated herein
by reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement dated as
of December 12, 1994, by and between Unit Corporation and Bank of
Oklahoma, N.A., F&M Bank and Trust Company, Bank IV, Oklahoma, N.A.
and American National Bank and Trust Comp any of Shawnee (filed as
an Exhibit in Form 8-K dated December 15, 1994, which is
incorporated herein by reference).
10.1.20 Loan Agreement dated August 3, 1995 (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the quarter
ended June 30, 1995, which is incorporated herein by reference).
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership
(filed as Exhibit I to Unit Drilling and Exploration Company's
Registration Statement on Form S-1 as S.E.C. File No. 2-66347, which
is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership
(filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's
Registration Statement Form S-1 as S.E.C. File No. 2-92582, which is
incorporated herein by reference).
10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited
Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil and
Gas Program's Registration Statement of Form S-1 as S.E.C. File No.
2-89678, which is incorporated herein by reference).
66
<PAGE>
10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit 3.1 to Unit 1985 Employee
Oil and Gas Limited Partnership's Registration Statement on Form S-1
as S.E.C. File No. 2-95068, which is incorporated herein by
reference).
10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit 10.11 to the Company's
Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which
is incorporated herein by reference).
10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1989, which is incorporated herein by reference).
10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1989, which is incorporated herein by reference).
10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1989, which is incorporated herein by reference).
10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1990, which is incorporated herein by reference).
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1991, which is incorporated herein by reference).
10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1992, which is incorporated herein by reference).
10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1992, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as
Exhibit 10.16 to the Company's Registration Statement on Form S-4 as
S.E.C. File No. 33-7848, which is incorporated herein by
reference).
67
<PAGE>
10.2.22* The Company's Stock Option Plan (filed on the Company's Registration
Statement of Form S-8 as S.E.C. File No. 33-44103, which is
incorporated herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan (filed on
Form S-8 as S.E.C. File No. 33-49724, which is incorporated herein
by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed on Form S-8 as S.E.C.
File No. 33-53542, which is incorporated herein by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1993, which
is incorporated herein by reference).
10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December 31,
1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to the
Company's Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's Annual
Report, under cover of Form 10-K for the year ended December 31,
1994, which is incorporated herein by reference) .
10.2.29 Unit 1996 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed herewith).
10.5 Acquisition and Development Agreement, dated September 26, 1991,
between Registrant and Municipal Energy Agency of Nebraska (filed on
Form 8-K dated September 30, 1991, which is incorporated herein by
reference).
10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco
Exploration, Inc. and Aleco Production Company (as "Seller") and
Unit Petroleum Company (a "Buyer") and Helmerich & Payne, Inc. (a
"Buyer") (filed on Form 8-K dated May 21, 1992, which is
incorporated herein by reference).
10.7 Asset Purchase Agreement, dated as of November 28, 1994, between the
Registrant and Patrick Petroleum Corp of Michigan and American
National Petroleum Company (filed as an Exhibit in Form 8-K dated
December 15, 1994, which is incorporated herein by reference).
22.1 Subsidiaries of the Registrant (filed herewith).
68
<PAGE>
24.1 Consent of Independent Accountants (filed herewith).
27 Financial Data Schedules (filed herewith).
* Indicates a management contract or compensatory plan identified pursuant to
the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
No reports under Form 8-K were filed during the quarter ended
December 31, 1995.
69
<PAGE>
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance
Balance at charged to Deductions at
beginning costs & & net end of
Description of period expenses write-offs period
----------- -------- -------- --------- --------
(In thousands)
Year ended
December 31, 1995 $ 289 $ 55 $ 228 $ 116
======== ======== ======== ========
Year ended
December 31, 1994 $ 411 $ - $ 122 $ 289
======== ======== ======== ========
Year ended
December 31, 1993 $ 376 $ - $ (35 ) $ 411
======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance at Balance at
beginning end of
Description of period Additions Deductions period
----------- -------- -------- -------- --------
(In thousands)
Year ended
December 31, 1995 $ 6,423 $ - $ 2,893 $ 3,530
======== ======== ======== ========
Year ended
December 31, 1994 $ 8,218 $ - $ 1,795 $ 6,423
======== ======== ======== ========
Year ended
December 31, 1993 $ 12,245 $ - $ 4,027 $ 8,218
======== ======== ======== ========
70
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 19, 1996 By: /s/ John G. Nikkel
-------------- ---------------------------
JOHN G. NIKKEL
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities indicated on the 19th day of March, 1996.
Name Title
/s/ King P. Kirchner
- ------------------------------- Chairman of the Board and Chief
KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel
- ------------------------------- President and Chief Operating
JOHN G. NIKKEL Officer, Director
/s/ Earle Lamborn
- ------------------------------- Senior Vice President, Drilling,
EARLE LAMBORN Director
/s/ Larry D. Pinkston
- ------------------------------- Vice President, Chief Financial
LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz
- ------------------------------- Controller
STANLEY W. BELITZ
/s/ Don Bodard
- ------------------------------- Director
DON BODARD
/s/ Don Cook
- ------------------------------- Director
DON COOK
/s/ William B. Morgan
- ------------------------------- Director
WILLIAM B. MORGAN
/s/ John S. Zink
- ------------------------------- Director
JOHN S. ZINK
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
71
<PAGE>
EXHIBIT INDEX
-----------------
Exhibit
No. Description Page
- ------- --------------------------------------------- ----
10.2.29 Unit 1996 Employee Oil and Gas Limited
Partnership Agreement of
Limited Partnership.
22.1 Subsidiaries of the Registrant.
24.1 Consent of Independent Accountants.
27 Financial Data Schedule.
72
<PAGE>
EXHIBIT 10.2.29
<PAGE>
CONFIDENTIAL
For Private Placement Purposes Only Copy No. ____
UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
1000 Kensington Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
(918) 493-7700
A PRIVATE OFFERING
OF
UNITS OF LIMITED PARTNERSHIP INTEREST
_____________________________________
THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURI-
TIES ACT OF 1933, AS AMENDED, OR UNDER APPLICABLE STATE SECURITIES ACTS
IN RELIANCE ON EXEMPTIONS PROVIDED BY SUCH ACTS. THESE SECURITIES MAY
NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF AN EFFECTIVE REGISTRATION
UNDER SUCH ACTS OR AN OPINION OF COUNSEL ACCEPTABLE TO THE GENERAL
PARTNER THAT SUCH REGISTRATION IS NOT REQUIRED. FURTHER, THE RESALE OF
A UNIT MAY RESULT IN SUBSTANTIAL TAX LIABILITY TO THE INVESTOR. SEE
"FEDERAL INCOME TAX ASPECTS." ACCORDINGLY, THESE UNITS SHOULD BE
CONSIDERED ONLY FOR LONG-TERM INVESTMENT. SEE "PLAN OF DISTRIBUTION --
SUITABILITY OF INVESTORS."
_____________________________________
THE INFORMATION CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM
IS PROVIDED BY THE GENERAL PARTNER SOLELY FOR THE PERSONS RECEIVING IT
FROM THE GENERAL PARTNER AND ANY REPRODUCTION OR DISTRIBUTION OF THIS
PRIVATE OFFERING MEMORANDUM, IN WHOLE OR IN PART, OR THE DIVULGENCE OF
ANY OF ITS CONTENTS IS PROHIBITED AND MAY CONSTITUTE A VIOLATION OF
CERTAIN STATE SECURITIES LAWS. THE OFFEREE, BY ACCEPTING DELIVERY OF
THIS PRIVATE OFFERING MEMORANDUM, AGREES TO RETURN IT AND ALL ENCLOSED
DOCUMENTS TO THE GENERAL PARTNER IF THE OFFEREE DOES NOT UNDERTAKE TO
PURCHASE ANY OF THE UNITS OFFERED HEREBY.
_____________________________________
Private Offering Memorandum Date January 3, 1996
(i)
<PAGE>
500 Preformation
Units of Limited Partnership Interest
in the
UNIT 1996 EMPLOYEE
OIL AND GAS LIMITED PARTNERSHIP
_____________________________________
$1,000 Per Unit Plus Possible
Additional Assessments of $100 Per Unit
(Minimum Investment - 2 Units)
Minimum Aggregate Subscriptions Necessary
to Form Partnership - 50 Units
_____________________________________
A maximum of 500 (minimum of 50) units of limited partnership
interest ("Units") in the UNIT 1996 EMPLOYEE OIL AND GAS LIMITED
PARTNERSHIP, a proposed Oklahoma limited partnership (the "Partner-
ship"), are being offered privately only to certain employees of Unit
Corporation ("UNIT") and its subsidiaries and the directors of UNIT at
a price of $1,000 per Unit. Subscriptions shall be for not less than 2
Units ($2,000). The Partnership is being formed for the purpose of
conducting oil and gas drilling and development operations. Purchasers
of the Units will become Limited Partners in the Partnership. Unit
Petroleum Company ("UPC" or the "General Partner") will serve as
General Partner of the Partnership. UPC's address is 1000 Kensington
Tower I, 7130 South Lewis Avenue, Tulsa, Oklahoma 74136, telephone
(918) 493-7700.
THE RIGHTS AND OBLIGATIONS OF THE GENERAL PARTNER
AND THE LIMITED PARTNERS ARE GOVERNED BY THE
AGREEMENT OF LIMITED PARTNERSHIP (THE "AGREEMENT"),
A COPY OF WHICH ACCOMPANIES THIS MEMORANDUM AND IS
INCORPORATED HEREIN BY REFERENCE
AN INVESTMENT IN THE UNITS IS SPECULATIVE AND INVOLVES
A HIGH DEGREE OF RISK. SEE "RISK FACTORS". CERTAIN
SIGNIFICANT RISKS INCLUDE:
. Drilling to establish productive oil and natural gas
properties is inherently speculative.
. Participants will rely solely on the management
capability and expertise of the General Partner.
. Limited Partners must assume the risks of an illiquid
investment.
. Investment in the Units is suitable only for investors
having sufficient financial resources and who desire a
long term investment.
(continued on next page)
_____________________________________
(ii)
<PAGE>
. Conflicts of interest exist and additional conflicts of
interest may arise between the General Partner and the
Limited Partners, and there are no pre-determined
procedures for resolving any such conflicts.
. Significant tax considerations to be considered by an
investor include:
. possible audit of income tax returns of the
Partnership and/or the Limited Partners and
resulting reduction or elimination of tax benefits;
and
. Limited Partners will not benefit from Partnership
losses unless they have passive income from other
activities.
. There can be no assurance that the Partnership will have
adequate funds to provide cash distributions to the
Limited Partners. The amount and timing of any such
distributions will be within the complete discretion of
the General Partner.
. The amount of any cash distribution which a Limited
Partner may receive from the Partnership could be
insufficient to pay the tax liability incurred by such
Limited Partner with respect to income or gain allocated
to such Limited Partner by the Partnership.
. Certain provisions in the Agreement modify what would
otherwise be the applicable Oklahoma law as to the
fiduciary standards for general partners in limited
partnerships. Those standards in the Agreement could be
less advantageous to the Limited Partners than the
corresponding fiduciary standards otherwise applicable
under Oklahoma law. The purchase of Units may be deemed
as consent to the fiduciary standards set forth in the
Agreement.
_____________________________________
EXCEPT AS STATED HEREIN UNDER "ADDITIONAL INFORMATION," NO
PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PRIVATE OFFERING
MEMORANDUM IN CONNECTION WITH THIS OFFERING AND SUCH REPRESENTATIONS,
IF ANY, MAY NOT BE RELIED UPON. THE INFORMATION CONTAINED IN THIS
PRIVATE OFFERING MEMORANDUM IS AS OF THE DATE HEREOF UNLESS ANOTHER
DATE IS SPECIFIED.
_____________________________________
PROSPECTIVE INVESTORS ARE NOT TO CONSTRUE THE CONTENTS OF
THIS PRIVATE OFFERING MEMORANDUM AS LEGAL, BUSINESS, OR TAX ADVICE.
EACH INVESTOR SHOULD CONSULT HIS OR HER OWN ATTORNEY, BUSINESS ADVISOR
AND TAX ADVISOR AS TO LEGAL, BUSINESS, TAX AND RELATED MATTERS
CONCERNING HIS OR HER INVESTMENT. PROSPECTIVE INVESTORS ARE URGED TO
REQUEST ANY ADDITIONAL INFORMATION THEY MAY CONSIDER NECESSARY TO MAKE
AN INFORMED INVESTMENT DECISION.
(iii)
<PAGE>
_____________________________________
THE SECURITIES OFFERED HEREBY HAVE NOT BEEN APPROVED OR
DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION,
THE OKLAHOMA SECURITIES COMMISSION OR BY THE SECURITIES REGULATORY
AUTHORITY OF ANY OTHER STATE, NOR HAS ANY COMMISSION OR AUTHORITY
PASSED UPON OR ENDORSED THE MERITS OF THIS OFFERING OR THE ACCURACY OR
ADEQUACY OF THIS PRIVATE OFFERING MEMORANDUM. ANY REPRESENTATION
CONTRARY TO THE FOREGOING IS UNLAWFUL.
_____________________________________
THESE UNITS ARE BEING OFFERED SUBJECT TO PRIOR SALE, TO
WITHDRAWAL, CANCELLATION OR MODIFICATION OF THE OFFER WITHOUT NOTICE
AND TO THE FURTHER CONDITIONS SET FORTH HEREIN.
_____________________________________
IN CONNECTION WITH THE REGISTRATION OF THE PARTNERSHIP AS A
"TAX SHELTER" PURSUANT TO SECTION 6111 OF THE INTERNAL REVENUE CODE OF
1986, AS AMENDED, PLEASE NOTE THAT ISSUANCE OF A REGISTRATION NUMBER
DOES NOT INDICATE THAT AN INVESTMENT IN THE PARTNERSHIP OR THE CLAIMED
TAX BENEFITS THEREFROM HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE
INTERNAL REVENUE SERVICE.
_____________________________________
ADDITIONAL INFORMATION
Each prospective investor, or his or her qualified
representative named in writing, is hereby offered the opportunity (1)
to obtain additional information necessary to verify the accuracy of
the information supplied herewith or hereafter, and (2) to ask
questions and receive answers concerning the terms and conditions of
the offering. If you desire to avail yourself of the opportunity,
please contact:
Mark E. Schell, Esq.
1000 Kensington Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
(918) 493-7700
(iv)
<PAGE>
The following documents and instruments are available to
qualified offerees upon written request:
1. Amended and Restated Certificate of Incorporation and
By-Laws of UNIT.
2. Certificate of Incorporation and By-Laws of Unit
Petroleum Company.
3. UNIT's Employees' Thrift Plan.
4. UNIT's Stock Option Plan and related prospectuses
covering shares of Common Stock issuable upon exercise
of outstanding options.
5. UNIT'S Non Employee Directors' Stock Option Plan.
6. The Credit Agreement and the notes payable of
UNIT.
7. All periodic reports on Forms 10-K, 10-Q and 8-K and all
proxy materials filed by or on behalf of UNIT with the
Securities and Exchange Commission pursuant to the
Securities Exchange Act of 1934, as amended, during
calendar year 1995, the annual report to shareholders
and all quarterly reports to shareholders submitted by
UNIT to its shareholders during calendar year 1995.
8. The agreements of limited partnership for the prior oil
and gas drilling programs and prior employee programs of
Unit Petroleum Company, UNIT and Unit Drilling and
Exploration Company ("UDEC").
9. All periodic reports filed with the Securities and
Exchange Commission and all reports and information
provided to limited partners in all limited partnerships
of which Unit Petroleum Company, UNIT or UDEC now serves
or has served in the past as a general partner.
10. Form of nominee agreement to be entered into by the
Partnership with any party holding record title to
Partnership Properties as nominee of the Partnership.
11. The agreement of limited partnership for the Unit 1986
Energy Income Limited Partnership.
(v)
<PAGE>
SUMMARY OF CONTENTS
Page
SUMMARY OF PROGRAM........................................ 1
Terms of the Offering................................ 1
Risk Factors......................................... 2
Additional Financing................................. 5
Proposed Activities.................................. 5
Application of Proceeds.............................. 6
Participation in Costs and Revenues.................. 7
Compensation......................................... 8
Federal Income Tax Aspects........................... 8
RISK FACTORS.............................................. 8
Investment Risks..................................... 8
Tax Related Risks.................................... 16
Operational Risks................................... 18
TERMS OF THE OFFERING..................................... 21
General.............................................. 21
Limited Partnership Interests........................ 21
Subscription Rights.................................. 22
Payment for Units; Delinquent Installment............ 23
Right of Presentment................................. 24
Rollup or Consolidation of Partnership............... 26
ADDITIONAL FINANCING...................................... 27
Additional Assessments............................... 27
Prior Programs....................................... 28
Partnership Borrowings............................... 28
PLAN OF DISTRIBUTION...................................... 29
Suitability of Investors............................. 30
RELATIONSHIP OF THE PARTNERSHIP, THE GENERAL PARTNER
AND AFFILIATES............................................ 30
PROPOSED ACTIVITIES....................................... 31
General.............................................. 31
Partnership Objectives............................... 35
Areas of Interest.................................... 35
Transfer of Properties............................... 35
Record Title to Partnership Properties............... 36
Marketing of Reserves................................ 36
Conduct of Operations................................ 36
APPLICATION OF PROCEEDS................................... 37
(vi)
<PAGE>
PARTICIPATION IN COSTS AND REVENUES....................... 38
COMPENSATION.............................................. 40
Supervision of Operations............................ 40
Purchase of Equipment and Provision of Services...... 41
Prior Programs....................................... 42
MANAGEMENT................................................ 44
The General Partner.................................. 44
Officers, Directors and Key Employees................ 44
Prior Employee Programs.............................. 47
Ownership of Common Stock............................ 49
Interest of Management in Certain Transactions....... 52
CONFLICTS OF INTEREST..................................... 52
Acquisition of Properties and Drilling Operations.... 52
Participation in UNIT's Drilling or Income Programs.. 54
Transfer of Properties............................... 55
Partnership Assets................................... 56
Transactions with the General Partner or Affiliates.. 56
Right of Presentment Price Determination............. 57
Receipt of Compensation Regardless of Profitability.. 57
Legal Counsel........................................ 57
FIDUCIARY RESPONSIBILITY.................................. 57
General.............................................. 57
Liability and Indemnification........................ 58
PRIOR ACTIVITIES.......................................... 59
Prior Employee Programs.............................. 61
Results of the Prior Oil and Gas Programs............ 63
FEDERAL INCOME TAX ASPECTS................................ 70
General.............................................. 70
Summary of Certain Matters........................... 71
Partnership Classification........................... 71
Taxation of Limited Partners......................... 72
IRS Tax Shelter Registration......................... 80
Partnership Tax Returns and Tax Information.......... 80
Laws Subject to Change............................... 81
State and Local Taxes................................ 82
COMPETITION, MARKETS AND REGULATION....................... 82
Marketing of Production.............................. 82
Regulation of Partnership Operations................. 83
Natural Gas Price Regulation......................... 84
State Regulation of Oil and Gas Production........... 89
Legislative and Regulatory Production and Pricing
Proposals.......................................... 89
Production and Environmental Regulation.............. 91
(vii)
<PAGE>
SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT.............. 92
Partnership Distributions............................ 92
Deposit and Use of Funds............................. 93
Power and Authority.................................. 93
Rollup or Consolidation of the Partnership........... 94
Limited Liability.................................... 95
Records, Reports and Returns......................... 96
Transferability of Interests......................... 96
Amendments........................................... 99
Voting Rights........................................ 99
Exculpation and Indemnification of the
General Partner.................................... 100
Termination.......................................... 100
Insurance............................................ 101
COUNSEL................................................... 101
GLOSSARY.................................................. 102
FINANCIAL STATEMENTS...................................... 107
EXHIBIT A - AGREEMENT OF LIMITED PARTNERSHIP
EXHIBIT B - LEGAL OPINION
(viii)
<PAGE>
SUMMARY OF PROGRAM
This summary does not purport to be a complete description of the
terms and consequences of an investment in the Partnership and is
qualified in its entirety by the more detailed information appearing
throughout this Private Offering Memorandum (this "Memorandum"). For
definitions of certain terms used in this Memorandum, see "GLOSSARY".
Terms of the Offering
Limited Partnership Interests. Unit 1996 Employee Oil and Gas
Limited Partnership, a proposed Oklahoma limited partnership (the
"Partnership"), hereby offers 500 preformation units of limited
partnership interest ("Units") in the Partnership. The offer is made
only to certain employees of Unit Corporation ("UNIT") and its
subsidiaries and directors of UNIT (see "TERMS OF THE OFFERING -
Subscription Rights"). Unless the context otherwise requires, all
references in this Memorandum to UNIT shall include all or any of its
subsidiaries. Unit Petroleum Company ("UPC" or the "General Partner"),
a wholly owned subsidiary of UNIT, will serve as General Partner of the
Partnership.
To invest in the Units, the Limited Partner Subscription Agreement
and Suitability Statement (the "Subscription Agreement") (see
Attachment I to Exhibit A hereto) must be executed and forwarded to the
offices of the General Partner at its address listed on the cover of
this Memorandum. The Subscription Agreement must be received by the
General Partner not later than 5:00 P.M. Central Standard Time on
January 31, 1996 (extendable by the General Partner for up to 30 days).
Subscription Agreements may be delivered to the office of the General
Partner. No payment is required upon delivery of the Subscription
Agreement. Payment for the Units will be made either (i) in four equal
Installments, the first of such Installments being due on March 15,
1996 and the remaining three of such Installments being due on June 15,
1996, September 15, 1996 and December 15, 1996, respectively, or (ii)
through equal deductions from 1996 salary commencing immediately after
formation of the Partnership.
The purchase price of each Unit is $1,000, and the minimum permis-
sible purchase is two Units ($2,000) for each subscriber. Additional
Assessments of up to $100 per Unit may be required (see "ADDITIONAL
FINANCING - Additional Assessments"). Maximum purchases by employees
(other than directors) will be for an amount equal to one-half of their
base salaries for calendar year 1996. Each member of the Board of
Directors of UNIT may subscribe for up to 150 Units ($150,000). The
Partnership must sell at least 50 Units ($50,000) before the Partner-
ship will be formed. No Units will be offered for sale after the
Effective Date (see "GLOSSARY") except upon compliance with the
provisions of Article XIII of the Agreement. The General Partner may,
at its option, purchase Units as a Limited Partner, including any
amount that may be necessary to meet the minimum number of Units
1
<PAGE>
required for formation of the Partnership. The Partnership will
terminate on December 31, 2026, unless it is terminated earlier
pursuant to the provisions of the Agreement or by operation of law.
See "TERMS OF THE OFFERING - Limited Partnership Interests"; "TERMS OF
THE OFFERING - Subscription Rights"; and "SUMMARY OF THE LIMITED
PARTNERSHIP AGREEMENT - Termination."
Units will be offered only to those qualified employees of UNIT or
any of its subsidiaries at the date of formation of the Partnership
whose annual base salaries for 1996 have been set at $22,680 or more
and Directors of UNIT who meet certain financial requirements which
will enable them to bear the economic risks of an investment in the
Partnership and who can demonstrate that they have sufficient
investment experience and expertise to evaluate the risks and merits of
such an investment. The offering will be made privately by the
officers and directors of UPC or UNIT, except that in states which
require participation by a registered broker-dealer in the offer and
sale of securities, the Units will be offered through such broker-dealer as may
be selected by the General Partner. Any participating
broker-dealer may be reimbursed for actual out-of-pocket expenses.
Such reimbursements will be borne by the General Partner.
Subscription Rights. Only salaried employees of UNIT or any of
its subsidiaries who are exempt under the Fair Labor Standards Act and
whose annual base salaries for 1996 have been set at $22,680 or more
and directors of UNIT are eligible to subscribe for Units. Employees
may not purchase Units for an amount in excess of one-half of their
base salaries for calendar year 1996. Directors' subscriptions may not
be for more than 150 Units ($150,000). Only employees and directors
who are U.S. citizens are eligible to participate in the offering. In
addition, employees and directors must be able to bear the economic
risks of an investment in the Partnership and must have sufficient
investment experience and expertise to evaluate the risks and merits of
such an investment. See "TERMS OF THE OFFERING - Subscription Rights."
Right of Presentment. After December 31, 1997 and annually
thereafter, the Limited Partners will have the right to present their
Units to the General Partner for purchase. The General Partner will
not be obligated to purchase more than 20% of the then outstanding
Units in any one calendar year. The purchase price to be paid for the
Units will be determined by a specific valuation formula. See "TERMS
OF THE OFFERING - Right of Presentment" for a description of the
valuation formula and a discussion of the manner in which the right of
presentment may be exercised by the Limited Partners.
Risk Factors
An investment in the Partnership has many risks. The "RISK
FACTORS" section of this Memorandum contains a detailed discussion of
2
<PAGE>
the most important risks, organized into Investment Risks (the risks
related to the Partnership's investment in oil and gas properties and
drilling activities, to an investment in the Partnership and to the
provisions of the Agreement); Tax Risks (the risks arising from the tax
laws as they apply to the Partnership and its investment in oil and gas
properties and drilling activities); and Operational Risks (the risks
involved in conducting oil and gas operations). The following are
certain of the risks which are more fully described under "RISK
FACTORS". Each prospective investor should review the "RISK FACTORS"
section carefully before deciding to subscribe for Units.
Investment Risks:
Future oil and natural gas prices are unpredictable. If
oil and natural gas prices go down, the Partnership's
distributions, if any, to the Limited Partners will be
adversely affected.
The General Partner is authorized under the Agreement to
cause, in its sole discretion, the sale or transfer of
the Partnership's assets to, or the merger or
consolidation of the Partnership with, another
partnership, corporation or other business entity. Such
action could have a material impact on the nature of the
investment of all Limited Partners.
Except for certain transfers to the General Partner and
other restricted transfers, the Agreement prohibits a
Limited Partner from transferring Units. Thus, except
for the limited right of the Limited Partners after
December 31, 1997 to present their Units to the General
Partner for purchase, Limited Partners will not be able
to liquidate their investments.
The Partnership could be formed with as little as
$50,000 in Capital Contributions (excluding the Capital
Contributions of the General Partner). As the total
amount of Capital Contributions to the Partnership will
determine the number and diversification of Partnership
Properties, the ability of the Partnership to pursue its
investment objectives may be restricted in the event
that the Partnership receives only the minimum amount of
Capital Contributions.
The drilling and completion operations to be undertaken
by the Partnership for the development of oil and
natural gas reserves involve the possibility of a total
loss of an investment in the Partnership.
3
<PAGE>
The General Partner will have the exclusive management
and control of all aspects of the business of the
Partnership. The Limited Partners will have no
opportunity to participate in the management and control
of any aspect of the Partnership's activities.
Accordingly, the Limited Partners will be entirely
dependent upon the management skills and expertise of
the General Partner.
Conflicts of interest exist and additional conflicts of
interest may arise between the General Partner and the
Limited Partners, and there are no pre-determined
procedures for resolving any such conflicts.
Accordingly the General Partner could cause the
Partnership to take actions to the benefit of the
General Partner but not to the benefit of the Limited
Partners.
Certain provisions in the Agreement modify what would
otherwise be the applicable Oklahoma law as to the
fiduciary standards for a general partner in a limited
partnership. The fiduciary standards in the Agreement
could be less advantageous to the Limited Partners and
more advantageous to the General Partner than
corresponding fiduciary standards otherwise applicable
under Oklahoma law. The purchase of Units may be deemed
as consent to the fiduciary standards set forth in the
Agreement.
There can be no assurances that the Partnership will
have adequate funds to provide cash distributions to the
Limited Partners. The amount and timing of any such
distributions will be within the complete discretion of
the General Partner.
The amount of any cash distributions which Limited
Partners may receive from the Partnership could be
insufficient to pay the tax liability incurred by such
Limited Partners with respect to income or gain
allocated to such Limited Partners by the Partnership.
Tax Risks:
Tax laws and regulations applicable to partnership
investments may change at any time and these changes may
be applicable retroactively.
The Partnership may not qualify or may fail to continue
to qualify as a partnership for federal income tax
purposes.
4
<PAGE>
Certain allocations of income, gain, loss and deduction
of the Partnership among the Partners may be challenged
by the Internal Revenue Service (the "Service")
resulting in a Limited Partner having to report
additional taxable income or being denied a deduction.
Operational Risks:
The search for oil and gas is highly speculative and the
drilling activities conducted by the Partnership may
result in a well that may be dry or productive wells
that do not produce sufficient oil and gas to produce a
profit or result in a return of the Limited Partners'
investment.
Certain hazards may be encountered in drilling wells
which could lead to substantial liabilities to third
parties or governmental entities. In addition,
governmental regulations or new laws relating to
environmental matters could increase Partnership costs,
delay or prevent drilling a well, require the
Partnership to cease operations in certain areas or
expose the Partnership to significant liabilities for
violations of such laws and regulations.
Additional Financing
Additional Assessments. After the Aggregate Subscription received
from the Limited Partners has been fully expended or committed and the
General Partner's Minimum Capital Contribution has been fully expended,
the General Partner may make one or more calls for Additional
Assessments from the Limited Partners if additional funds are required
to pay the Limited Partners' share of Drilling Costs, Special
Production and Marketing Costs or Leasehold Acquisition Costs. The
maximum amount of total Additional Assessments which may be called for
by the General Partner is $100 per Unit. See "ADDITIONAL FINANCING --
Additional Assessments".
Partnership Borrowings. After the General Partner's Minimum
Capital Contribution has been expended, the General Partner may cause
the Partnership to borrow funds required to pay Drilling Costs, Special
Production and Marketing Costs or Leasehold Acquisition Costs of
Productive properties. Additionally, the General Partner may, but is
not required to, advance funds to the Partnership to pay such costs.
See "ADDITIONAL FINANCING -- Partnership Borrowings".
Proposed Activities
General. The Partnership is being formed for the purposes of
acquiring producing oil and gas properties and conducting oil and gas
drilling and development operations. The Partnership will, with
certain limited exceptions, participate on a proportionate basis with
5
<PAGE>
UPC in each producing oil and gas lease acquired and in each oil and
gas well commenced by UPC for its own account or by UNIT during the
period from January 1, 1996, if the Partnership is formed prior to such
date or from the date of the formation of the Partnership if subsequent
to January 1, 1996, until December 31, 1996, and will, with certain
limited exceptions, serve as a co-general partner with UNIT in any
drilling or income programs which may be formed by the General Partner
or UNIT in 1996. See "PROPOSED ACTIVITIES".
Partnership Objectives. The Partnership is being formed to
provide eligible employees and directors the opportunity to participate
in the oil and gas exploration and producing property acquisition
activities of UNIT during 1996. UNIT hopes that participation in the
Partnership will provide the participants with greater proprietary
interests in UNIT's operations and the potential for realizing a more
direct benefit in the event these operations prove to be profitable.
The Partnership has been structured to achieve the objective of
providing the Limited Partners with essentially the same economic
returns that UNIT realizes from the wells drilled or acquired during
1996.
Application of Proceeds
The offering proceeds will be used to pay the Leasehold Acquisi-
tion Costs incurred by the Partnership to acquire those producing oil
and gas leases in which the Partnership participates and the Leasehold
Acquisition Costs, exploration, drilling and development costs incurred
by the Partnership pursuant to drilling activities in which the
Partnership participates. The General Partner estimates (based on
historical operating experience) that such costs may be expended as
shown below based on the assumption of a maximum number of
subscriptions in the first column and a minimum number of subscriptions
in the second column:
$500,000 $50,000
Program Program
-------- -------
Leasehold Acquisition Costs
of Properties to Be Drilled.... $ 25,000 $ 2,500
Drilling Costs of Exploratory
Wells(1)....................... 25,000 2,500
Drilling Costs of Development
Wells(1)....................... 350,000 35,000
Leasehold Acquisition Costs of
Productive Properties.......... 100,000 10,000
Reimbursement of General
Partner's Overhead Costs(2)....
---------- ---------
Total...................... $ 500,000 $ 50,000
6
<PAGE>
(1) See "GLOSSARY."
(2) The Agreement provides that the General Partner shall be
reimbursed by the Partnership for that portion of its general and
administrative overhead expense attributable to its conduct of
Partnership business and affairs but such reimbursement will be
made only out of Partnership Revenue. See "COMPENSATION."
Participation in Costs and Revenues
Partnership costs, expenses and revenues will be allocated among
the Partners in the following percentages:
General Limited
COSTS AND EXPENSES Partner Partners
Organizational and offering costs
of the Partnership and any drilling
or income programs in which the
Partnership participates as a
co-general partner 100% 0%
All other Partnership costs and
expenses
Prior to time Limited Partner
Capital Contributions are
entirely expended 1% 99%
After expenditure of Limited
Partner Capital Contributions
and until expenditure of
General Partner's Minimum
Capital Contribution 100% 0%
After expenditure of General General Part- Limited Partners'
Partner's Minimum Capital ner's Per- Percentage(1)
Contribution centage(1)
REVENUES General Part- Limited Partners'
ner's Per- Percentage(1)
centage(1)
____________________
1) See "GLOSSARY."
7
<PAGE>
Compensation
The General Partner will not receive any management fees in connection
with the operation of the Partnership. The Partnership will reimburse the
General Partner for that portion of its general and administrative overhead
expense attributable to its conduct of Partnership business and affairs.
See "COMPENSATION."
Federal Income Tax Aspects
The General Partner has received an opinion from the law firm of Conner
& Winters, A Professional Corporation, to the effect that, for federal
income tax purposes, the Partnership will be classified as a partnership
and not as an association taxable as a corporation. Such opinion is based
on certain premises as stated therein and is not binding on the Service or
the courts. The General Partner will not apply for a ruling from the
Service with respect to such matter and the Partnership may not meet all
the conditions which must be met before a ruling will be issued. See
"FEDERAL INCOME TAX ASPECTS - Partnership Classification."
THIS MEMORANDUM CONTAINS AN EXPLANATION OF THE MORE SIGNIFICANT TERMS
AND PROVISIONS OF THE AGREEMENT OF LIMITED PARTNERSHIP WHICH IS ATTACHED AS
EXHIBIT A. THE SUMMARY OF THE AGREEMENT CONTAINED IN THIS MEMORANDUM IS
QUALIFIED IN ITS ENTIRETY BY SUCH REFERENCE AND ACCORDINGLY THE AGREEMENT
SHOULD BE CAREFULLY REVIEWED AND CONSIDERED.
RISK FACTORS
Prospective purchasers of Units should carefully study the information
contained in this Memorandum and should make their own evaluations of the
probability for the discovery of oil and natural gas through exploration.
INVESTMENT RISKS
Financial Risks of Drilling Operations
The Partnership will participate with the General Partner (including,
with certain limited exceptions, other drilling programs sponsored by it,
or UNIT) and, in some cases, other parties ("joint interest parties") in
connection with drilling operations conducted on properties in which the
Partnership has an interest. It is not anticipated that all such drilling
operations will be conducted under turnkey drilling contracts and, thus,
all of the parties participating in the drilling operations on a particular
property, including the Partnership, may be fully liable for their
proportionate share of all costs of such operations even if the actual
costs significantly exceed the original cost estimates. Further, if any
joint interest party defaults in its obligation to pay its share of the
costs, the other joint interest parties may be required to fund the
deficiency until, if ever, it can be collected from the defaulting party.
As a result of forced pooling or similar proceedings (see "COMPETITION,
8
<PAGE>
MARKETS AND REGULATION"), the Partnership may acquire larger fractional
interests in Partnership Properties than originally anticipated and, thus,
be required to bear a greater share of the costs of operations. As a
result of the foregoing, the Partnership could become liable for amounts
significantly in excess of the amounts originally anticipated to be
expended in connection with the operations and, in such event, would have
only limited means for providing needed additional funds (see "ADDITIONAL
FINANCING"). Also, if a well is operated by a company which does not or
cannot pay the costs and expenses of drilling or operating a Partnership
Well, the Partnership's interest in such well may become subject to liens
and claims of creditors who supplied services or materials in connection
with such operations even though the Partnership may have previously paid
its share of such costs and expenses to the operator. If the operator is
unable or unwilling to pay the amount due, the Partnership might have to
pay its share of the amounts owing to such creditors in order to preserve
its interest in the well which would mean that it would, in effect, be
paying for certain of such costs and expenses twice.
Dependence Upon General Partner
The Limited Partners will acquire interests in the Partnership, not in
the General Partner or UNIT. They will not participate in either increases
or decreases in the General Partner's or UNIT's net worth or the value of
its common stock. Nevertheless, because the General Partner is primarily
responsible for the proper conduct of the Partnership's business and
affairs and is obligated to provide certain funds that will be required in
connection with its operations, a significant financial reversal for the
General Partner or UNIT could have an adverse effect on the Partnership and
the Limited Partners' interests therein.
Under the Partnership Agreement, UPC is designated as the General
Partner of the Partnership and is given the exclusive authority to manage
and operate the Partnership's business. See "SUMMARY OF THE LIMITED
PARTNERSHIP AGREEMENT -- Power and Authority". Accordingly, Limited
Partners must rely solely on the General Partner to make all decisions on
behalf of the Partnership, as the Limited Partners will have no role in the
management of the business of the Partnership.
The Partnership's success will depend, in part, upon the management
provided by the General Partner, the ability of the General Partner to
select and acquire oil and gas properties on which Partnership Wells
capable of producing oil and natural gas in commercial quantities may be
drilled, to fund the acquisition of revenue producing properties, and to
market oil and natural gas produced from Partnership Wells.
Conflicts of Interest
UNIT and its subsidiaries have engaged in oil and gas exploration and
development and in the acquisition of producing properties for their own
account and as the sponsors of drilling and income programs formed with
9
<PAGE>
third party investors. It is anticipated that UNIT and its subsidiaries
will continue to engage in such activities. However, with certain
exceptions, it is likely that the Partnership will participate as a working
interest owner in all producing oil and gas leases acquired and in all oil
and gas wells commenced by the General Partner or UNIT for its own account
during the period from January 1, 1996, if the Partnership is formed prior
to such date, or from the date of the formation of the Partnership, if
subsequent to January 1, 1996, through December 31, 1996 and, with certain
limited exceptions, will be a co-general partner of any drilling or income
programs, or both, formed by the General Partner or UNIT in 1996. The
General Partner will determine which prospects will be acquired or drilled.
With respect to prospects to be drilled, certain of the wells which are
drilled for the separate account of the Partnership and the General Partner
may be drilled on prospects on which initial drilling operations were
conducted by UNIT or the General Partner prior to the formation of the
Partnership. Further, certain of the Partnership Wells will be drilled on
prospects on which the General Partner and possibly future employee
programs may conduct additional drilling operations in years subsequent to
1996. Except with respect to its participation as a co-general partner of
any drilling or income program sponsored by the General Partner or UNIT,
the Partnership will have an interest only in those wells begun in 1996 and
will have no rights in production from wells commenced in years other than
1996. Likewise, if additional interests are acquired in wells participated
in by the Partnership after 1996, the Partnership will generally not be
entitled to participate in the acquisition of such additional interests.
See "CONFLICTS OF INTEREST - Acquisition of Properties and Drilling
Operations."
The Partnership may enter into contracts for the drilling of some or
all of the Partnership Wells with affiliates of the General Partner.
Likewise the Partnership may sell or market some or all of its natural gas
production to an affiliate of the General Partner. These contracts may not
necessarily be negotiated on an arm's - length basis. The General Partner
is subject to a conflict of interest in selecting an affiliate of the
General Partner to drill the Partnership Wells and/or market the natural
gas therefrom. The compensation under these contracts will be determined
at the time of entering into each such contract, and the costs to be paid
thereunder or the sale price to be received will be one which is
competitive with the costs charged or the prices paid by unaffiliated
parties in the same geographic region. The General Partner will make the
determination of what are competitive rates or prices in the area. No
provision has been made for an independent review of the fairness and
reasonableness of such compensation. See "CONFLICTS OF INTERESTS -
Transactions with the General Partner or Affiliates".
Prohibition on Transferability; Lack of Liquidity
Except for certain transfers (i) to the General Partner, (ii) to or for
the benefit of the transferor Limited Partner or members of his or her
immediate family sharing the same residence, and (iii) by reason of death
10
<PAGE>
or operation of law, a Limited Partner may not transfer or assign Units.
The General Partner has agreed, however, that it will, if requested at any
time after December 31, 1997, buy Units for prices determined either by an
independent petroleum engineering firm or the General Partner pursuant to a
formula described under "TERMS OF THE OFFERING - Right of Presentment."
This obligation of the General Partner to purchase Units when requested is
limited and does not assure the liquidity of a Limited Partner's
investment, and the price received may be less than if the Limited Partner
continued to hold his or her Units. In addition similar commitments have
been made and may hereafter be made to investors in other oil and gas
drilling, income and employee programs sponsored by the General Partner or
UNIT. There can be no assurance that the General Partner will have the
financial resources to honor its repurchase commitments. See "TERMS OF THE
OFFERING - Right of Presentment."
Delay of Cash Distributions
For income tax purposes, a Limited Partner must report his or her
distributive share of the income, gains, losses and deductions of the
Partnership whether or not cash distributions are made. No cash
distributions are expected to be made earlier than the first quarter of
1997. In addition, to the extent that the Partnership utilizes its
revenues to repay outside borrowings or otherwise uses its own revenues to
finance its activities (see "ADDITIONAL FINANCING"), the funds available
for cash distributions by the Partnership may be reduced or unavailable.
It is possible that the amount of tax payable by a Limited Partner on his
or her distributive share of the income of a Partnership will exceed cash
distributions from the Partnership. See "FEDERAL INCOME TAX ASPECTS."
The date any distributions commence and their subsequent timing or
amount cannot be accurately predicted. The decision as to whether or not
the Partnership will make a cash distribution at any particular time will
be made solely by the General Partner.
Limitations on Voting and Other Rights of Limited Partners
The Agreement, as permitted under the Oklahoma Revised Uniform Limited
Partnership Act (the "Act"), eliminates or limits the rights of the Limited
Partners to take certain actions, such as:
withdrawing from the Partnership,
transferring Units without restrictions, or
consenting to or voting upon certain matters such as:
(i) admitting a new General Partner,
(ii) admitting Substituted Limited Partners, and
11
<PAGE>
(iii) dissolving the Partnership.
Furthermore, the Agreement imposes restrictions on the exercise of voting
rights granted to Limited Partners. See "SUMMARY OF THE LIMITED
PARTNERSHIP AGREEMENT -- Voting Rights." Without the provisions to the
contrary which are contained in the Agreement, the Act provides that
certain actions can be taken only with the consent of all Limited Partners.
Those provisions of the Agreement which provide for or require the vote of
the Limited Partners, generally permit the approval of a proposal by the
vote of Limited Partners holding a majority of the outstanding Units. See
"SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -- Voting Rights." Thus,
Limited Partners who do not agree with or do not wish to be subject to the
proposed action may nevertheless become subject to the action if the
required majority approval is obtained. Notwithstanding the rights granted
to Limited Partners under the Agreement and the Act, the General Partner
retains substantial discretion as to the operation of the Partnership.
Rollup or Consolidation of Partnership
Under the terms of the Agreement, at any time two years or more after
the Partnership has completed substantially all of its property
acquisition, drilling and development operations, the General Partner is
authorized to cause the Partnership to transfer its assets to, or to merge
or consolidate with, another partnership or a corporation or other entity
for the purpose of combining the oil and gas properties and other assets of
the Partnership with those of other partnerships formed for investment or
participation by the employees, directors and/or consultants of UNIT or any
of its subsidiaries. Such transfer or combination may be effected without
the vote, approval or consent of the Limited Partners. In such event, the
Limited Partners will receive interests in the transferee or resulting
entity which will mean that they will most likely participate in the
results of a larger number of properties but will have proportionately
smaller allocable interests therein. Any such transaction is required to
be effected in a manner which UNIT and the General Partner believe is fair
and equitable to the Limited Partners but there can be no assurance that
such transaction will in fact be in the best interests of the Limited
Partners. Limited Partners have no dissenters' or appraisal rights under
the terms of the Agreement or the Act. Such a transaction will result in
the termination and dissolution of the Partnership. While there can be no
assurance that the Partnership will participate in such a transaction, the
General Partner currently anticipates that the Partnership will, at the
appropriate time, be involved in such a transaction. See "TERMS OF
OFFERING", and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT."
Partnership Borrowings
The General Partner has the authority to cause the Partnership to
borrow additional funds in the future to pay certain costs of the
Partnership. While the use of additional financing to preserve the
Partnership's equity in oil and gas properties is intended to increase the
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Partnership's profits, such financing could have the effect of increasing
the Partnership's losses if the Partnership is unsuccessful. In addition,
the Partnership may have to mortgage its oil and gas properties and other
assets in order to obtain additional financing. If the Partnership
defaults on such indebtedness, the lender may foreclose and the Partnership
could lose its investment in such oil and gas properties and other assets.
See "ADDITIONAL FINANCING -- Partnership Borrowings."
Limited Liability
Under the Act a Limited Partner's liability for the obligations of the
Partnership is limited to such Limited Partner's Capital Contribution and
such Limited Partner's share of Partnership assets. In addition, if a
Limited Partner receives a return of any part of his or her Capital
Contribution, such Limited Partner is generally liable to the Partnership
for a period of one year thereafter (or six years in the event such return
is in violation of the Agreement) for the amount of the returned
contribution. A Limited Partner will not otherwise be liable for the
obligations of the Partnership unless, in addition to the exercise of his
or her rights and powers as a Limited Partner, such Limited Partner
participates in the control of the business of the Partnership.
The Agreement provides that by a vote of a majority in interest, the
Limited Partners may effect certain changes in the Partnership such as
termination and dissolution of the Partnership and amendment of the
Agreement. The exercise of any of these and certain other rights is
conditioned upon receipt of an opinion by counsel for the Limited Partners
or an order or judgment of a court of competent jurisdiction to the effect
that the exercise of such rights will not result in the loss of the limited
liability of the Limited Partners or cause the Partnership to be classified
as an association taxable as a corporation (see "SUMMARY OF THE LIMITED
PARTNERSHIP AGREEMENT - Amendments" and "SUMMARY OF THE LIMITED PARTNERSHIP
AGREEMENT - Termination"). As a result of certain judicial opinions it is
not clear that these rights will ever be available to the Limited Partners.
Nevertheless, in spite of the receipt of any such opinion or judicial
order, it is still possible that the exercise of any such rights by the
Limited Partners may result in the loss of the Limited Partners' limited
liability. The Partnership will be governed by the Act. The Act expressly
permits limited partners to vote on certain specified partnership matters
without being deemed to be participating in the control of the Partner-
ship's business and, thus, should result in greater certainty and more
easily obtainable opinions of counsel regarding the exercise of most of the
Limited Partners' rights.
If the Partnership is dissolved and its business is not to be
continued, the Partnership will be wound up. In connection with the
winding up of the Partnership, all of its properties may be sold and the
proceeds thereof credited to the accounts of the Partners. Properties not
sold will, upon termination of the Partnership, be distributed to the
Partners. The distribution of Partnership Properties to the Limited
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Partners would result in their having unlimited liability with respect to
such properties. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
Limited Liability."
Partnership Acting as Co-General Partner
It is currently anticipated that the Partnership will serve as a co-general
partner in any drilling or income programs formed by the General Partner or UNIT
during 1996. See "PROPOSED ACTIVITIES." Accordingly, the
Partnership generally will be liable for the obligation and recourse
liabilities of any such drilling or income program formed. While a Limited
Partner's liability for such claims will be limited to such Limited
Partners Capital Contribution and share of Partnership assets, such claims
if satisfied from the Partnership's assets could adversely affect the
operations of the Partnership.
Past-Due Installments; Acceleration; Additional Assessments
Installments and Additional Assessments (see "ADDITIONAL FINANCING")
are legally binding obligations and past-due amounts will bear interest at
the rate set forth in the Agreement; provided, however, that if the General
Partner determines that the total Aggregate Subscription is not required to
fund the Partnership's business and operations, then the General Partner
may, at its sole option, elect to release the Limited Partners from their
obligation to pay one or more Installments and amend any relevant
Partnership documents accordingly. It is currently anticipated that the
total Aggregate Subscription will be required to fund the Partnership's
business and operations. In the event an Installment is not paid when due
and the General Partner has not released the Limited Partners from their
obligation to pay such Installment, then the General Partner may, at its
sole option, purchase all Units of the director or employee who fails to
pay such Installment, at a price equal to the amount of the prior
Installments paid by such person. The General Partner may also bring legal
proceedings to collect any unpaid Installments not waived by it or
Additional Assessments. In addition, as indicated under "TERMS OF THE
OFFERING - Payment for Units; Delinquent Installment," if an employee's
employment with or position as a director of the General Partner, UNIT or
any affiliate thereof is terminated other than by reason of Normal Retire-
ment (see "GLOSSARY"), death or disability prior to the time the full
amount of the subscription price for his or her Units has been paid, all
unpaid Installments not waived by the General Partner as described above
will become due and payable upon such termination.
Partnership Funds
Except for Capital Contributions, Partnership funds are expected to be
commingled with funds of the General Partner or UNIT. Thus, Partnership
funds could become subject to the claims of creditors of the General
Partner or UNIT. The General Partner believes that its assets and net
worth are such that the risk of loss to the Partnership by virtue of such
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fact is minimal but there can be no assurance that the Partnership will not
suffer losses of its funds to creditors of the General Partner or UNIT.
Compliance With Federal and State Securities Laws
This offering has not been registered under the Securities Act of 1933,
as amended, in reliance upon exemptive provisions of said act. Further,
these interests are being sold pursuant to exemptions from registration in
the various states in which they are being offered and may be subject to
additional restrictions in such jurisdictions on transfer. There is no
assurance that the offering presently qualifies or will continue to qualify
under such exemptive provisions due to, among other things, the adequacy of
disclosure and the manner of distribution of the offering, the existence of
similar offerings conducted by the General Partner or UNIT or its
affiliates in the past or in the future, a failure or delay in providing
notices or other required filings, the conduct of other oil and gas
activities by the General Partner or UNIT and its affiliates or the change
of any securities laws or regulations.
If and to the extent suits for rescission are brought and successfully
concluded for failure to register this offering or other offerings under
the Securities Act of 1933, as amended, or state securities acts, or for
acts or omissions constituting certain prohibited practices under any of
said acts, both the capital and assets of the General Partner and the
Partnership could be adversely affected, thus jeopardizing the ability of
the Partnership to operate successfully. Further, the time and capital of
the General Partner could be expended in defending an action by investors
or by state or federal authorities even where the Partnership and the
General Partner are ultimately exonerated.
Nominee Agreements
The Partnership Agreement empowers the General Partner, UNIT or any of
their affiliates, to hold title to the Partnership Properties as nominee
for the benefit of the Partnership. If title to the Partnership Properties
is held in the name of a nominee, the nominee will act as nominee for the
Partnership pursuant to a form of Nominee Agreement to be entered into
between the nominee and the Partnership. In some jurisdictions, such
interests could be subject to the claims of creditors of such nominee. The
General Partner is of the opinion that the likelihood of the occurrence of
such claims is remote, due to the fact that executed nominee agreements
will appear in the files of the General Partner and the nominee (if other
than the General Partner). It is possible that the nominee agreement would
be disregarded, however, in which case Partnership Property could be
subject to claims and litigation in the event that the nominee failed to
pay its debts or became subject to the claims of creditors.
The General Partner may elect to hold title to Partnership Properties
permanently in the name of a nominee for the Partnership provided such
arrangement is evidenced by a nominee agreement and the nominee conducts no
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business or operations other than holding record title to interests in
properties. See "PROPOSED ACTIVITIES -- Record Title To Partnership
Properties." Based on certain representations discussed under "FEDERAL
INCOME TAX ASPECTS -- Taxation of Limited Partners -- Nominee Ownership of
Partnership Properties," Counsel is of the opinion that the Partnership
will be treated, for federal income tax purposes, as the owner of the
Partnership Properties held by the nominee for the account of the
Partnership.
Use of Partnership Funds to Exculpate and Indemnify the General Partner
The Agreement contains certain provisions which are intended to limit
the liability of the General Partner and its affiliates for certain acts or
omissions within the scope of the authority conferred upon them by the
Agreement. In addition, under the Agreement, the General Partner will be
indemnified by the Partnership against losses, judgments, liabilities,
expenses and amounts paid in settlement sustained by it in connection with
the Partnership so long as the losses, judgments, liabilities, expenses or
amounts were not the result of gross negligence or willful misconduct on
the part of the General Partner. See "SUMMARY OF THE LIMITED PARTNERSHIP
AGREEMENT -- Exculpation and Indemnification of the General Partner."
The Partnership Agreement May Limit the Fiduciary Obligation of the General
Partner to the Partnership and the Limited Partners
The Agreement contains certain provisions which modify what would
otherwise be the applicable Oklahoma law relating to the fiduciary
standards of the General Partner to the Limited Partners. The fiduciary
standards in the Agreement could be less advantageous to the Limited
Partners and more advantageous to the General Partner than the
corresponding fiduciary standards otherwise applicable under Oklahoma law
(although there are very few legal precedents clarifying exactly what
fiduciary standards would otherwise be applicable under Oklahoma law). The
purchase of Units may be deemed as consent to the fiduciary standards set
forth in the Agreement. See "FIDUCIARY RESPONSIBILITY." As a result of
these provisions in the Agreement, the Limited Partners may find it more
difficult to hold the General Partner responsible for acting in the best
interest of the Partnership and the Limited Partners than if the fiduciary
standards of the otherwise applicable Oklahoma law governed the situation.
TAX RELATED RISKS
Changes in Tax Laws
The Internal Revenue Code of 1986, as amended (the "Code"), and
regulations and interpretations thereof are subject to change by Congress,
the courts and administrative agencies. Regulations have not been issued
or proposed under many of the provisions of recent legislation. For these
reasons, no assurance can be given that the interpretations of the federal
income tax laws included herein will not be challenged or if challenged,
will be sustained. Notwithstanding enactment of additional legislation
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further modifying, reducing or eliminating any or all tax benefits, or new
interpretations of law which might require treatment different from that
described under "FEDERAL INCOME TAX ASPECTS," the Partnership is authorized
to expend the Capital Contributions of the Limited Partners and to conduct
the Partnership's business, affairs and operations as described in the
Agreement, and each item of Partnership Revenue, gain, loss, cost or
expense will be shared or borne in the manner specified therein.
Partnership Audits; Interest on Tax Deficiencies
If the Service audits a Partnership tax return, no assurance can be
given that tax adjustments will not be made. Any such adjustments could
increase the likelihood of audits of the personal returns of the Limited
Partners which could result in adjustments of any items of income, gain,
loss, deduction or credit included in those personal returns regardless of
whether those items relate to the Partnership. Any deficiency assessed
against a taxpayer will bear interest at an annual rate equal to the 3-month
Treasury bill rate plus three percentage points. This interest rate
will be adjusted quarterly, with the new rate becoming effective two months
after the date of each adjustment. The annual rate which commenced October
1, 1995 is 9% (compounded daily), but, as stated, such rate may change
every three months.
In addition, audits of Partnership taxable years will be conducted at
the Partnership level rather than at the Partner level. The Code also
gives certain authority to the "Tax Matters Partner" to deal with any
Service audit, assessment and administrative and judicial proceedings. The
General Partner will be the "Tax Matters Partner" for the Partnership. See
"FEDERAL INCOME TAX ASPECTS - Partnership Tax Returns and Tax Information."
Status as a Partnership
The tax benefits of oil and gas investments will be unavailable to the
Limited Partners if the Partnership is not held to be a partnership for
federal income tax purposes. The General Partner has not obtained a ruling
from the Service that the Partnership will be treated, for federal income
tax purposes, as a partnership rather than as an association taxable as a
corporation and the Partnership probably will not meet all of the
requirements set forth by the Service necessary to obtain such ruling (see
"FEDERAL INCOME TAX ASPECTS - Partnership Classification"). Although the
General Partner has received an opinion of Conner & Winters, a Professional
Corporation, based on certain premises and representations of the General
Partner as stated therein, that the Partnership will be classified as a
partnership for federal income tax purposes, such opinion is not binding
upon the Service and there is no assurance that partnership status will not
be challenged. Should the Partnership be held to be an association taxable
as a corporation, only the Partnership, and not the Partners, would be
entitled to the principal tax benefits, including the deduction for
intangible drilling and development costs, and the Partners' after-tax
investment return, if any, would be reduced. In such event the Partnership
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would be taxed on the income and the Partners would be taxed on
distributions from the Partnership as dividends to the extent of current or
accumulated earnings and profits of the Partnership. Excess distributions
would be treated first as a reduction of basis and the balance as capital
gain.
Tax Treatment of Partnership Allocations
There are various provisions in the Agreement pertaining to the
allocation among Partners of items of income, gain, loss, deduction and
credit. There can be no assurance that the allocation provisions of the
Agreement will not be challenged by the Service or that such a challenge,
if made, would not be sustained by the courts. Also, under the passive
activity loss rules, allocations of losses from the Partnership to Limited
Partners may not be deductible currently. See "FEDERAL INCOME TAX ASPECTS
- - Partnership Allocations, Partnership Losses and Limitations on Losses and
Credits from Passive Activities."
Disproportionate Tax Liability upon Transfer
Under the terms of the Agreement, distributions of Partnership Revenue
will be made to those persons who were the record holders of Units on the
day the distribution is made even if that person did not own his or her
Units during all of the calendar year with respect to which the
distribution is being made. See "SUMMARY OF THE LIMITED PARTNERSHIP
AGREEMENT - Partnership Distributions and Transferability of Interests."
However, in allocating Partnership Revenue for federal income tax purposes
between a transferor and a transferee of Units, generally each will be
allocated that portion of the income realized during the year that is equal
to the portion of the year that he or she owned the Units. Because of
these different allocation procedures, it is possible that a party to a
transfer of Units could be allocated a greater or lesser amount of
Partnership Revenue for federal income tax purposes than the amount of
distributions he or she actually receives.
OPERATIONAL RISKS
Risks Inherent in Oil and Gas Operations
The Partnership will be participating with the General Partner in
acquiring producing oil and gas leases and in the drilling of those oil and
gas wells commenced by the General Partner from the later of January 1,
1996 or the time the Partnership is formed through December 31, 1996 and,
with certain limited exceptions, serving as a co-general partner of any oil
and gas drilling or income programs, or both, formed by the General Partner
or UNIT during 1996.
All drilling to establish productive oil and natural gas properties is
inherently speculative. The techniques presently available to identify the
existence and location of pools of oil and natural gas are indirect, and,
therefore, a considerable amount of personal judgment is involved in the
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selection of any prospect for drilling. The economics of oil and natural
gas drilling and production are affected or may be affected in the future
by a number of factors which are beyond the control of the General Partner,
including (i) the general demand in the economy for energy fuels, (ii) the
worldwide supply of oil and natural gas, (iii) the price of, as well as
governmental policies with respect to, oil imports, (iv) potential
competition from competing alternative fuels, (v) governmental regulation
of prices for oil and natural gas, (vi) state regulations affecting
allowable rates of production, well spacing and other factors, and (vii)
availability of drilling rigs, casing and other necessary goods and
services. See "COMPETITION, MARKETS AND REGULATION." The revenues, if
any, generated from Partnership operations will be highly dependent upon
the future prices and demand for oil and natural gas. The factors
enumerated above affect, and will continue to affect, oil and natural gas
prices. Recently, prices for oil and natural gas have fluctuated over a
wide range.
Operating and Environmental Hazards
Operating hazards such as fires, explosions, blowouts, unusual
formations, formations with abnormal pressures and other unforeseen
conditions are sometimes encountered in drilling wells. On occasion,
substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce the funds available for
exploration and development or result in loss of Partnership Properties.
The Partnership will attempt to maintain customary insurance coverage, but
the Partnership may be subject to liability for pollution and other damages
or may lose substantial portions of its properties due to hazards against
which it cannot insure or against which it may elect not to insure due to
unreasonably high or prohibitive premium costs or for other reasons. The
activities of the Partnership may expose it to potential liability for
pollution or other damages under laws and regulations relating to
environmental matters (see "Government Regulation and Environmental Risks"
below).
Competition
The oil and gas industry is highly competitive. The Partnership will
be involved in intense competition for the acquisition of quality
undeveloped leases and producing oil and gas properties. There can be no
assurance that a sufficient number of suitable oil and gas properties will
be available for acquisition or development by the Partnership. The
Partnership will be competing with numerous major and independent companies
which possess financial resources and staffs larger than those available to
it. The Partnership, therefore, may be unable in certain instances to
acquire desirable leases or supplies or may encounter delays in commencing
or completing Partnership operations.
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Markets for Oil and Natural Gas Production
There is currently a worldwide surplus of oil production capacity.
Historically (prior to the early 1980s), world oil prices were established
and maintained largely as a result of the actions of members of OPEC to
limit, and maintain a base price for, their oil production. In more recent
years, however, members of OPEC have been unable to agree to and maintain
price and production controls, which has resulted in significant downward
pressure on oil prices. Although future levels of production by the
members of OPEC or the degree to which oil prices will be affected thereby
cannot be predicted, it is possible that prices for oil produced in the
future will be higher or lower than those currently available. There can
be no assurance that the Partnership will be able to market any oil that it
produces or, if such oil can be marketed, that favorable price and other
contractual terms can be negotiated. See "COMPETITION, MARKETS AND
REGULATION - Marketing of Production."
The natural gas market is also currently unsettled due to a number of
factors. In the past, production from natural gas wells in some geographic
areas of the United States has been curtailed for considerable periods of
time due to a lack of market demand. In addition, there may be an excess
supply of natural gas in areas where Partnership Wells are located. In
that event, it is possible that such Partnership Wells will be shut-in or
that natural gas in these areas will be sold on terms less favorable than
might otherwise be obtained. Competition for available markets has been
vigorous and there remains great uncertainty about prices that purchasers
will pay. In recent years, significant court decisions and regulatory
changes have affected the natural gas markets. As a result of such court
decisions, regulatory changes and unsettled market conditions, natural gas
regulations may be modified in the future and may be subject to further
judicial review or invalidation. The combination of these factors, among
others, makes it particularly difficult to estimate accurately future
prices of natural gas, and any assumptions concerning future prices may
prove incorrect. Natural gas surpluses could result in the Partnership's
inability to market natural gas profitably, causing Partnership Wells to
curtail production and/or receive lower prices for its natural gas,
situations which would adversely affect the Partnership's ability to make
cash distributions to its participants. See "COMPETITION, MARKETS AND
REGULATION."
In the event that the Partnership discovers or acquires natural gas
reserves, there may be delays in commencing or continuing production due to
the need for gathering and pipeline facilities, contract negotiation with
the available market, pipeline capacities, seasonal takes by the gas
purchaser or a surplus of available gas reserves in a particular area.
Government Regulation and Environmental Risks
The oil and gas business is subject to pervasive government regulation
under which, among other things, rates of production from producing
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properties may be fixed and the prices for gas produced from such producing
properties may be impacted. It is possible that these regulations
pertaining to rates of production could become more pervasive and stringent
in the future. The activities of the Partnership may expose it to
potential liability under laws and regulations relating to environmental
matters which could adversely affect the Partnership. Compliance with
these laws and regulations may increase Partnership costs, delay or prevent
the drilling of wells, delay or prevent the acquisition of otherwise
desirable producing oil and gas properties, require the Partnership to
cease operations in certain areas, and cause delays in the production of
oil and gas. See "COMPETITION, MARKETING AND REGULATION."
Leasehold Defects
In certain instances, the Partnership may not be able to obtain a title
opinion or report with respect to a producing property that is acquired.
Consequently, the Partnership's title to any such property may be
uncertain. Furthermore, even if certain technical defects do appear in
title opinions or reports with respect to a particular property, the
General Partner, in its sole discretion, may determine that it is in the
best interest of the Partnership to acquire such property without taking
any curative action.
TERMS OF THE OFFERING
General
500 Maximum Units; 50 Minimum Units
$1,000 Units; Minimum subscription: $2,000
Minimum Partnership: $50,000 in subscriptions
Maximum Partnership: $500,000 in subscriptions
Limited Partnership Interests
The Partnership hereby offers to certain employees (described under
"Subscription Rights" below) and directors of UNIT and its subsidiaries an
aggregate of 500 Units. The purchase price of each Unit is $1,000, and the
minimum permissible purchase by any eligible subscriber is two Units
($2,000). See "Subscription Rights" below for the maximum number of Units
that may be acquired by subscribers.
The Partnership will be formed as an Oklahoma limited partnership upon
the closing of the offering of Units made by this Memorandum. The General
Partner will be Unit Petroleum Company (the "General Partner", or "UPC"),
an Oklahoma corporation. Partnership operations will be conducted from the
General Partner's offices, the address of which is 1000 Kensington Tower I,
7130 South Lewis Avenue, Tulsa, Oklahoma 74136, telephone (918) 493-7700.
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The offering of Units will be closed on January 31, 1996 unless
extended by the General Partner for up to 30 days, and all Units subscribed
will be issued on the Effective Date. The offering may be withdrawn by the
General Partner at any time prior to such date if it believes it to be in
the best interests of the eligible employees and Directors or the General
Partner not to proceed with the offering.
If at least 50 Units ($50,000) are not subscribed prior to the
termination of the offering, the Partnership will not commence business.
The General Partner may, on its own accord, purchase Units and, in such
capacity, will enjoy the same rights and obligations as other Limited
Partners, except the General Partner will have unlimited liability. The
General Partner may, in its discretion, purchase Units sufficient to reach
the minimum Aggregate Subscription ($50,000). Because the General Partner
or its affiliates might benefit from the successful completion of this
offering (see "PARTICIPATION IN COSTS, AND REVENUES" and "COMPENSATION"),
investors should not expect that sales of the minimum Aggregate
Subscription indicate that such sales have been made to investors that have
no financial or other interest in the offering or that have otherwise
exercised independent investment discretion. Further, the sale of the
minimum Aggregate Subscription is not designed as a protection to investors
to indicate that their interest is shared by other unaffiliated investors
and no investor should place any reliance on the sale of the minimum
Aggregate Subscription as an indication of the merits of this offering.
Units acquired by the General Partner will be for investment purposes only
without a present intent for resale and there is no limit on the number of
Units that may be acquired by it.
Subscription Rights
Units are offered only to persons who are salaried employees of UNIT or
its subsidiaries at the date of formation of the Partnership and who are
exempt under the Fair Labor Standards Act and whose annual base salaries
for 1996 (excluding bonuses) have been set at $22,680 or more and to
Directors of UNIT. Only employees and Directors who are U.S. citizens are
eligible to participate in the offering. In addition, employees and
Directors must be able to bear the economic risks of an investment in the
Partnership and must have sufficient investment experience and expertise to
evaluate the risks and merits of such an investment. See "PLAN OF
DISTRIBUTION - Suitability of Investors."
Eligible employees and Directors are restricted as to the number of
Units they may purchase in the offering. The maximum number of Units which
can be acquired by any employee is that number of whole Units which can be
purchased with an amount which does not exceed one-half of the employee's
base salary for 1996. Each Director of UNIT may subscribe for a maximum of
150 Units (maximum investment of $150,000). At December 13, 1995 there
were approximately 112 Directors and employees eligible to purchase Units.
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Eligible employees and Directors may acquire Units through a
corporation or other entity in which all of the beneficial interests are
owned by them or permitted assignees (see "SUMMARY OF THE LIMITED
PARTNERSHIP AGREEMENT - Transferability of Interests"); provided that such
employees or Directors will be jointly and severally liable with such
entity for payment of the Capital Subscription.
If all eligible employees and Directors subscribed for the maximum
number of Units, the Units would be oversubscribed. In that event, Units
would be allocated among the respective subscribers in the proportion that
each subscription amount bears to total subscriptions obtained.
No employee is obligated to purchase Units in order to remain in the
employ of UNIT, and the purchase of Units by any employee will not obligate
UNIT to continue the employment of such employee. Units may be subscribed
for by the spouse or a trust for the minor children of eligible employees
and Directors.
Payment for Units; Delinquent Installment
The Capital Subscriptions of the Limited Partners will be payable
either (i) in four equal Installments, the first of such Installments being
due on March 15, 1996 and the remaining three of such Installments being
due on June 15, 1996, September 15, 1996 and December 15, 1996,
respectively, or (ii) by employees so electing in the space provided on the
Subscription Agreement, through equal deductions from 1996 salary paid to
the employee by the General Partner, UNIT or its subsidiaries commencing
immediately after formation of the Partnership. If an employee or Director
who has subscribed for Units (either directly or through a corporation or
other entity) ceases to be employed by or serve as a Director of the
General Partner, UNIT or any of its subsidiaries for any reason other than
death, disability or Normal Retirement prior to the time the full amount of
all Installments not waived by the General Partner as described below are
due, then the due date for any such unpaid Installments shall be
accelerated so that the full amount of his or her unpaid Capital
Subscription will be due and payable on the effective date of such
termination.
Each Installment will be a legally binding obligation of the Limited
Partner and any past due amounts will bear interest at an annual rate equal
to two percentage points in excess of the prime rate of interest of Bank of
Oklahoma, N.A., Tulsa, Oklahoma; provided, however, that if the General
Partner determines that the total Aggregate Subscription is not required to
fund the Partnership's business and operations, then the General Partner
may, at its sole option, elect to release the Limited Partners from their
obligation to pay one or more Installments. If the General Partner elects
to waive the payment of an Installment, it will notify all Limited Partners
promptly in writing of its decision and will, to the extent required, amend
the certificate of limited partnership and any other relevant Partnership
documents accordingly. It is currently anticipated that the total
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Aggregate Subscription will be required, however, to fund the Partnership's
business and operations.
In the event a Limited Partner fails to pay any Installment when due
and the General Partner has not released the Limited Partners from their
obligation to pay such Installment, then the General Partner, at its sole
option and discretion, may elect to purchase the Units of such defaulting
Limited Partner at a price equal to the total amount of the Capital
Contributions actually paid into the Partnership by such defaulting Limited
Partner, less the amount of any Partnership distributions that may have
been received by him or her. Such option may be exercised by the General
Partner by written notice to the Limited Partner at any time after the date
that the unpaid Installment was due and will be deemed exercised when the
amount of the purchase price is first tendered to the defaulting Limited
Partner. The General Partner may, in its discretion, accept payments of
delinquent Installments not waived by it but will not be required to do so.
In the event that the General Partner elects to purchase the Units of a
defaulting Limited Partner, it must pay into the Partnership the amount of
the delinquent Installment (excluding any interest that may have accrued
thereon) and pay each additional Installment, if any, payable with respect
to such Units as it becomes due. By virtue of such purchase, the General
Partner will be allocated all Partnership Revenues, be charged with all
Partnership costs and expenses attributable to such Units and will enjoy
the same rights and obligations as other Limited Partners, except the
General Partner will have unlimited liability.
Right of Presentment
After December 31, 1997, and annually thereafter, Limited Partners will
have the right to present their Units to the General Partner for purchase.
The General Partner will not be obligated to purchase more than 20% of the
then outstanding Units in any one calendar year. The purchase price to be
paid for the Units of any Limited Partner presenting them for purchase will
be based on the net asset value of the Partnership which shall be equal to:
(1) The value of the proved reserves attributable to the Partnership
Properties, determined as set forth below; plus
(2) The estimated salvage value of tangible equipment installed on
Partnership Wells less the costs of plugging and abandoning the
wells, both discounted at the rate utilized to determine the value
of the Partnership's reserves as set forth below; plus
(3) The lower of cost or fair market value of all Partnership
Properties to which proved reserves have not been attributed but
which have not been condemned, as determined by an independent
petroleum engineering firm or the General Partner, as the case may
be; plus
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(4) Cash on hand; plus
(5) Prepaid expenses and accounts receivable (less a reasonable reserve
for doubtful accounts); plus
(6) The estimated market value of all other Partnership assets not
included in (1) through (5) above, determined by the General
Partner; MINUS
(7) An amount equal to all debts, obligations and other liabilities of
the Partnership.
The price to be paid for each Limited Partner's interest of the net asset
value will be his or her proportionate share of such net asset value less
75% of the amount of any distributions received by him or her which are
attributable to the sales of the Partnership production since the date as
of which the Partnership's proved reserves are estimated.
The value of the proved reserves attributable to Partnership Properties
will be determined as follows:
(i) First, the future net revenues from the production and sale of
the proved reserves will be estimated as of the end of the
calendar year in which presentment is made based on an
independent engineering firm's report and its estimates of price
and cost escalations or, if no report was made, as determined by
the General Partner;
(ii) Next, the future net revenues from the production and sale of
proved reserves as determined above will be discounted at an
annual rate which is one percentage point higher than the prime
rate of interest being charged by the Bank of Oklahoma, N.A.,
Tulsa, Oklahoma, or any successor bank, as of the date such
reserves are estimated; and
(iii) Finally, the total discounted value of the future net revenues
from the production and sale of proved reserves will be reduced
by an additional 25% to take into account the risks and
uncertainties associated with the production and sale of the
reserves and other unforeseen uncertainties.
A Limited Partner who elects to have his Units purchased by the General
Partner should be aware that estimates of future net recoverable reserves
of oil and gas and estimates of future net revenues to be received
therefrom are based on a great many factors, some of which, particularly
future prices of production, are usually variable and uncertain and are
always determined by predictions of future events. Accordingly, it is
common for the actual production and revenues received to vary from earlier
estimates. Estimates made in the first few years of production from a
property will be based on relatively little production history and will not
25
<PAGE>
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
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formed for investment or participation by employees, directors and/or
consultants of UNIT or any of its subsidiaries; provided, however, that the
valuation of the oil and gas properties and other assets of all such
participating partnerships for purposes of such transfer or combination
shall be made on a consistent basis and in a manner which the General
Partner and UNIT believe is fair and equitable to the Limited Partners. As
a consequence of any such transfer or combination, the Partnership shall be
dissolved and terminated and the Limited Partners shall receive partnership
interests, stock or other equity interests in the transferee or resulting
entity. Any such action will cause the Limited Partners' attributable
interest in the Partnership Properties to be diluted but it will also
provide them with attributable interests in the properties and other assets
of the other partnerships participating in the consolidation. It also may
reduce somewhat the amount of their attributable shares of the direct and
indirect costs of administering the Partnership. However, there may be
certain adverse tax consequences resulting from such a transaction. See
"RISK FACTORS - Investment Risks - Roll-Up or Consolidation of
Partnership."
ADDITIONAL FINANCING
The General Partner will use its best efforts, consistent with
Partnership objectives, to acquire Productive properties and complete the
Partnership's drilling and development operations before the Aggregate
Subscription has been fully expended or committed. However, funds in
addition to the Aggregate Subscription may be required to pay costs and
expenses which are chargeable to the Limited Partners. In those instances
described below, the General Partner may call for Additional Assessments or
may apply Partnership Revenue allocable to the Limited Partners in payment
and satisfaction of such costs or the General Partner may, but shall not be
required to, fund the deficiency with Partnership borrowings to be repaid
with Partnership Revenue.
Additional Assessments
When the Aggregate Subscription has been fully expended or committed,
the General Partner may make one or more calls for any portion or all of
the maximum Additional Assessments of $100 per Unit. However, no
Additional Assessments may be required before the General Partner's Minimum
Capital Contribution has been fully expended. Such assessments may be used
to pay the Limited Partners' share of the Drilling Costs, Special
Production and Marketing Costs or Leasehold Acquisition Costs of Productive
properties which are chargeable to the Limited Partners. The amount of the
Additional Assessment so called shall be due and payable on or before such
date as the General Partner may set in such call, which in no event will be
earlier than thirty (30) days after the date of mailing of the call. The
notice of the call for Additional Assessments will specify the amount of
the assessment being required, the intended use of such funds, the date on
which the contributions are payable and describe the consequences of
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<PAGE>
nonpayment. Although the Limited Partners who do not respond will
participate in production, if any, obtained from operations conducted with
the proceeds from the aggregate Additional Assessments paid into the
Partnership, the amount of the unpaid Additional Assessment shall bear
interest at the annual rate equal to two (2) percentage points in excess of
the prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or
successor bank, as announced and in effect from time to time, until paid.
The Partnership will have a lien on the defaulting Limited Partner's
interest in the Partnership and the General Partner may retain Partnership
Revenue otherwise available for distribution to the defaulting Limited
Partner until an amount equal to the unpaid Additional Assessment and
interest is received. Furthermore, the General Partner may satisfy such
lien by proceeding with legal action to enforce the lien and the defaulting
Limited Partner shall pay all expenses of collection, including interest,
court costs and a reasonable attorney's fee.
Prior Programs
In the prior employee programs conducted by UNIT or the General Partner
in each of the years 1984 through 1995, Additional Assessments could be
called for as provided herein. At September 30, 1995, there had been no
calls for Additional Assessments in such programs. There can be no
assurance, however, that Additional Assessments will not be required to pay
Partnership costs.
Partnership Borrowings
At any time after the General Partner's Minimum Capital Contribution
has been fully expended, the General Partner may cause the Partnership to
borrow funds for the purpose of paying Drilling Costs, Special Production
and Marketing Costs or Leasehold Acquisition Costs of Productive
properties, which borrowings may be secured by interests in the Partnership
Properties and will be repaid, including interest accruing thereon, out of
Partnership Revenue. The General Partner may, but is not required to,
advance funds to the Partnership for the same purposes for which
Partnership borrowings are authorized. With respect to any such advances,
the General Partner will receive interest in an amount equal to the lesser
of the interest which would be charged to the Partnership by unrelated
banks on comparable loans for the same purpose or the General Partner's
interest cost with respect to such loan, where it borrows the same. No
financing charges will be levied by the General Partner in connection with
any such loan. If Partnership borrowings secured by interests in the
Partnership Wells and repayable out of Partnership Revenue cannot be
arranged on a basis which, in the opinion of the General Partner, is fair
and reasonable, and the entire sum required to pay such costs is not
available from Partnership Revenue, the General Partner may dispose of some
or all of the Partnership Properties upon which such operations were to be
conducted by sale, farm-out or abandonment.
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If the Partnership requires funds to conduct Partnership operations
during the period between any of the Installments due from the Limited
Partners, then, notwithstanding the foregoing, the General Partner shall
advance funds to the Partnership in an amount equal to the funds then
required to conduct such operations but in no event more than the total
amount of the Aggregate Subscription remaining unpaid. With respect to any
such advances, the General Partner shall receive no interest thereon and no
financing charges will be levied by the General Partner in connection
therewith. The General Partner shall be repaid out of the Installments
thereafter paid into the capital of the Partnership when due.
The Partnership may attempt to finance any expenses in excess of the
Partners' Capital Subscriptions by the foregoing means and any other means
which the General Partner deems in the best interests of the Partnership,
but the Partnership's inability to meet such costs could result in the
deferral of drilling operations or in the inability to participate in
future drilling or in non-consent penalties pursuant to which co-owners of
particular working interests recover several times the amount which would
have been funded by the Partnership in accordance with its ownership
interest before the Partnership would participate in revenues.
The use of Partnership Revenue allocable to the Limited Partners to pay
Partnership costs and expenses and to repay any Partnership borrowings will
mean that such revenue will not be available for distribution to the
Limited Partners. Nonetheless, the Limited Partners may incur income tax
liability by virtue of that revenue and, thus, may not receive
distributions from the Partnership in amounts necessary to pay such income
tax. However, the use of such revenue to pay Partnership costs and
expenses may generate additional deductions for the Limited Partners.
PLAN OF DISTRIBUTION
Units will be offered privately only to select persons who can
demonstrate to the General Partner that they have both the economic means
and investment expertise to qualify as suitable investors. It is
anticipated that the Units will be offered and sold by the officers and
directors of UPC or UNIT, except that in states which require participation
by a registered broker-dealer in the offer and sale of securities the Units
will be offered through such broker-dealer as may be selected by the
General Partner. Such broker-dealer's activities in connection with the
offering of interests in the Partnership will be limited solely to such
activities as are technically required by state laws with respect to the
offer of securities by brokers or dealers. Such broker-dealer will not
receive any fees or sales commission but will be reimbursed for actual out-of-
pocket expenses. Such expenses will be part of the organizational costs to be
paid by the General Partner.
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<PAGE>
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.
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UNIT CORPORATION
----------------
( ----------------------(-------------------(
( (
( (
Unit Petroleum Company Unit Drilling Company
---------------------- ---------------------
( General Partner
(
(
(
(
Unit 1996 Employee Oil
& Gas Limited
Partnership
-----------------------
( Limited Partners
(
(
(
(
Eligible Employees
and Directors
------------------------
PROPOSED ACTIVITIES
General
The Partnership will, with certain limited exceptions, participate in
all of UNIT's or UPC's oil and gas activities commenced during 1996. The
Partnership will acquire 5% of essentially all of UNIT's interest in such
activities. The activities will include (i) participating as a joint
working interest owner with UNIT or UPC in any producing leases acquired
and in any wells commenced by UNIT or UPC other than as a general partner
in a drilling or income program during 1996 and (ii) serving as a co-general
partner in any drilling or income programs, or both, formed by the General
Partner or UNIT during 1996.
Acquisition of Properties and Drilling Operations. The Partnership
will participate, to the extent of 5% of UPC or UNIT's final interest in
each well, as a fractional working interest holder in any producing leases
acquired and in any drilling operations conducted by UPC or UNIT for its
own account which are acquired or commenced, respectively, from January 1,
1996, or the time of the formation of the Partnership if subsequent to
January 1, 1996, until December 31, 1996, except for wells, if any:
(i) drilled outside the 48 contiguous United States;
(ii) drilled as part of secondary or tertiary recovery operations
which were in existence prior to formation of the Partnership;
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<PAGE>
(iii) drilled by third parties under farm-out or similar arrangements
with UNIT or the General Partner or whereby UNIT or the General
Partner may be entitled to an overriding royalty, reversionary or
other similar interest in the production from such wells but is
not obligated to pay any of the Drilling Costs thereof;
(iv) acquired by UNIT or the General Partner through the acquisition
by UNIT or the General Partner of, or merger of UNIT or the
General Partner with, other companies (However, this exception
may, at the discretion of Unit or the General Partner, be
waived); or
(v) with respect to which the General Partner does not believe that
the potential economic return therefrom justifies the costs of
participation by the Partnership.
Instances referred to in (v) could occur when UNIT or one of its
subsidiaries agrees to participate in the ownership of a prospect for its
own account in order to obtain the contract to drill the well thereon.
There may be situations where the potential economic return of the well
alone would not be sufficient to warrant participation by UNIT but when
considered in light of the revenues expected to be realized as a result of
the drilling contract, such participation is desirable from UNIT's stand-
point. However, in such a situation, the Partnership would not be entitled
to any of the revenues generated by the drilling contract so its
participation in the well would not be desirable.
For these purposes, the drilling of a well will be deemed to have
commenced on the "spud date," i.e., the date that the drilling rig is set
up and actual drilling operations are commenced. Any clearing or other
site preparation operations will not be considered part of the drilling
operations for these purposes.
Participation in Drilling or Income Programs. Except for certain
limited exceptions it is anticipated that the Partnership will participate
with UPC or UNIT as a co-general partner of any drilling or income
programs, or both, formed by UPC or UNIT and its affiliates during 1996.
The Partnership will be charged with 5% of the total costs and expenses
charged to the general partners and allocated 5% of the revenues allocable
to the general partners in any such program and UPC or UNIT will be charged
with the remaining 95% of the general partners' share of costs and expenses
and allocated the remaining 95% of the general partners' share of program
revenues.
UNIT or its affiliates formed drilling programs for outside investors
from 1979 through 1984. In 1987, the Unit 1986 Energy Income Limited
Partnership (the "1986 Energy Program") was formed primarily to acquire
interests in producing oil and gas properties. See "PRIOR ACTIVITIES".
All of the programs were formed as limited partnerships and interests in
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all of the programs other than the Unit 1979 Oil and Gas Program and the
1986 Energy Program were offered in registered public offerings. The 1979
Program and 1986 Energy Program were offered privately to a limited number
of sophisticated investors.
No drilling or income programs for third party investors were formed
in 1995. Although it does not currently contemplate doing so, UNIT may
form such drilling or income programs during 1996. If such a program is
formed, there would be only one or two such programs and they probably
would be privately offered. The precise revenue and cost sharing format of
any such programs has not been determined.
The cost and revenue sharing provisions of virtually all drilling
programs offered to third parties generally require the limited partners or
investors to bear a somewhat higher percentage of the program's drilling
and development costs than the percentage of program revenues to which they
are entitled. Likewise, the general partners will normally receive a
higher percentage of revenues than the percentage of drilling and
development costs which they are required to pay. The difference in these
percentages is often referred to as the general partners' "promote". Any
drilling program which UNIT or UPC may form in 1996 for outside investors
would likely have some amount of "promote" for the general partner(s).
Any income program may use the same or a similar format as that used
for the 1986 Partnership. In the 1986 Partnership, virtually all
partnership costs and expenses other than property acquisition costs are
allocated to the partners in the same percentages that partnership revenue
is being shared at the time such expenses are incurred, with property
acquisition costs and certain other expenses being charged 85% to the
accounts of the limited partners and 15% to the accounts of the general
partners. Partnership revenue in the 1986 Partnership is allocated 85% to
the limited partners' accounts and 15% to the general partners' accounts
until program payout (as defined in the agreement of limited partnership
for the 1986 Partnership). After program payout, the percentages of
partnership revenue allocable to the respective accounts of the partners
depend upon the length of the period during which program payout occurs and
range from 60% to the limited partners' accounts and 40% to the general
partners' accounts to 85% to the limited partners' accounts and 15% to the
general partners' accounts.
As co-general partners of any drilling or income programs that may be
formed by UNIT and/or UPC during 1996 and participated in by the
Partnership, UNIT and/or UPC and the Partnership will share the costs,
expenses and revenues allocable to the general partners on a proportionate
basis, 95% for the account of UNIT and/or UPC and 5% for the account of the
Partnership. The Partnership will not receive any portion of any
management fees payable to the general partners nor any fees or payments
for supervisory services which UNIT or UPC may render to such programs as
operator of program wells or other fees and payments which UNIT or UPC may
be entitled to receive from such programs for services rendered to them or
goods, materials, equipment or other property sold to them.
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<PAGE>
Extent and Nature of Operations. Although the General Partner
maintains a general inventory of prospects, it cannot predict with
certainty on which of those prospects wells will be started during 1996 nor
can it predict what producing properties, if any, will be acquired by it
during 1996. Further, since the General Partner anticipates that the
Partnership will acquire a small interest (either directly or through any
drilling or income programs of which it or UNIT serves as a general
partner) in approximately 30 to 70 wells (however, the exact number of
wells may vary greatly depending on the actual activity undertaken), it
would be impractical to describe in any detail all of the properties in
which the Partnership can be expected to acquire some interest.
The Partnership's drilling and development operations are expected to
include both Exploratory Wells and comparatively lower-risk Development
Wells. Exploratory Wells include both the high-risk "wildcat" wells which
are located in areas substantially removed from existing production and
"controlled" Exploratory Wells which are located in areas where production
has been established and where objective horizons have produced from
similar geological features in the vicinity. Based on UNIT's historical
profile of its drilling operations, it is presently anticipated that the
portion of the Aggregate Subscription expended for Partnership drilling
operations (see "APPLICATION OF PROCEEDS") will be spent approximately 6%
on Exploratory Wells and 94% on Development Wells. However, these
percentages may vary significantly.
Certain of the Partnership's Development Wells may be drilled on
prospects on which initial drilling operations were conducted by the
General Partner or UNIT prior to the formation of the Partnership.
Further, certain of the Partnership Wells will be drilled on prospects on
which the General Partner, UNIT or possibly future employee programs may
conduct additional drilling operations in years subsequent to 1996. In
either instance, the Partnership will have an interest only in those wells
begun in 1996 and will have no rights in production from wells commenced in
years other than 1996 even though such other wells may be located on
prospects or spacing units on which Partnership Wells have been drilled.
Furthermore, it is possible that in years subsequent to 1996, UNIT, UPC or
possibly future employee programs will acquire additional interests in
wells participated in by the Partnership. In such event the Partnership
will generally not be entitled to share in the acquisition of such
additional interests. With respect to the acquisition of producing
properties, UNIT will endeavor to diversify its investments by acquiring
properties located in differing geographic locations and by balancing its
investments between properties having high rates of production in early
years and properties with more consistent production over a longer term.
See "CONFLICTS OF INTERESTS - Acquisition of Properties and Drilling
Operations."
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Partnership Objectives
The Partnership is being formed to provide eligible employees and
directors the opportunity to participate in the oil and gas exploration and
producing property acquisition activities of UNIT during 1996. UNIT hopes
that participation in the Partnership will provide the participants with
greater proprietary interests in its operations and the potential for
realizing a more direct benefit in the event these operations prove to be
profitable. The Partnership has been structured to achieve the objective
of providing the Limited Partners with essentially the same economic
returns that UNIT realizes from the wells drilled or acquired during 1996.
Areas of Interest
The Agreement authorizes the Partnership to engage in oil and gas
exploration, drilling and development operations and to acquire producing
oil and gas properties anywhere in the United States, but the areas
presently under consideration are located in the states of Oklahoma, Texas,
Louisiana, Kansas, Arkansas, Colorado, Montana, North Dakota and Wyoming.
It is possible that the Partnership may drill in inland waterways,
riverbeds, bayous or marshes but no drilling in the open seas will be
attempted. Plans to conduct drilling and development operations or to
acquire producing properties in certain of these states may be abandoned if
attractive prospects cannot be obtained upon satisfactory terms or if the
Partnership is not fully subscribed.
Transfer of Properties
In the case of wells drilled or producing properties acquired by the
Partnership and UPC or UNIT for their own accounts and not through another
drilling or income program, the Partnership will acquire from UPC or UNIT a
portion of the fractional undivided working interest in the properties or
portions thereof comprising the spacing unit on which a proposed
Partnership Well is to be drilled or on which a producing Partnership Well
is located, and UPC or UNIT will retain for its own account all or a
portion of the remainder of such working interest. Such working interests
will be sold to the Partnership for an amount equal to the Leasehold
Acquisition Costs attributable to the interest being acquired. Neither
UNIT nor its affiliates will retain any overrides or other burdens on the
working interests conveyed to the Partnership, and the respective working
interests of UPC or UNIT and the Partnership in a property will bear their
proportionate shares of costs and revenues.
The Partnership's direct interest in a property will only encompass
the area included within the spacing unit on which a Partnership Well is to
be drilled or on which a producing Partnership Well is located, and, in the
case of a Partnership Well to be drilled, it will acquire that interest
only when the drilling of the well is ready to commence. If the size of a
spacing unit is ever reduced, or any subsequent well in which the
Partnership has no interest is drilled thereon, the Partnership will have
no interest in any additional wells drilled on properties which were part
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<PAGE>
of the original spacing unit unless such additional wells are commenced
during 1996. If additional interests in Partnership Wells are acquired in
years subsequent to 1996 the Partnership will generally not be entitled to
participate or share in the acquisition of such additional interests. In
addition, if the Partnership Well drilled on a spacing unit is dry or
abandoned, the Partnership will not have an interest in any subsequent or
additional well drilled on the spacing unit unless it is commenced during
1996. The Partnership will never own any significant amounts of
undeveloped properties or have an occasion to sell or farm out any
undeveloped Partnership Properties.
Transfers of properties to any drilling or income programs of which
the Partnership serves as a general partner will be governed by the
provisions of the agreement of limited partnership in effect with respect
thereto. If any such program is to be offered publicly, those provisions
will have to be consistent with the provisions contained in the Guidelines
for the Registration of Oil and Gas Programs adopted by the North American
Securities Administrators Association, Inc.
Record Title to Partnership Properties
Record title to the Partnership Properties will be held by the
Partnership or held in the name of a nominee for the Partnership under a
form of nominee agreement to be entered into between the nominee and the
Partnership. Under the form of nominee agreement, the nominee will
disclaim any beneficial interest in the Partnership Properties held as
nominee for the Partnership.
Marketing of Reserves
The General Partner has the authority to market the oil and gas
production of the Partnership. In this connection, it may execute on
behalf of the Partnership division orders, contracts for the marketing or
sale of oil, gas or other hydrocarbons or other marketing agreements.
Sales of the oil and gas production of the Partnership will be to
independent third parties or to the General Partner or its affiliates (see
"CONFLICTS OF INTEREST").
Conduct of Operations
The General Partner will have full, exclusive and complete discretion
and control over the management, business and affairs of the Partnership
and will make all decisions affecting the Partnership Properties. To the
extent that Partnership funds are reasonably available, the General Partner
will cause the Partnership to (1) test and investigate the Partnership
Properties by appropriate geological and geophysical means, (2) conduct
drilling and development operations on such Partnership Properties as it
deems appropriate in view of such testing and investigation, (3) attempt
completion of wells so drilled if in its opinion conditions warrant the
attempt and (4) properly equip and complete productive Partnership Wells.
The General Partner will also cause the Partnership's productive wells to
36
<PAGE>
be operated in accordance with sound and economical oil and gas recovery
practices.
The General Partner will operate certain drilling and productive wells
on behalf of the Partnership in accordance with the terms of the Agreement
(see "COMPENSATION"). In those cases, execution of separate operating
agreements will not be necessary unless third party owners are involved,
e.g., fractional undivided interest Partnership Properties and Partnership
Properties that are pooled or unitized with other properties owned by third
parties. In such cases, and in all cases where Partnership Properties are
operated by third parties, the General Partner will, where appropriate,
make or cause to be made and enter into operating agreements, pooling
agreements, unitization agreements, etc., in the form in general use in the
area where the affected property is located. The General Partner is also
authorized to execute production sales contracts on behalf of the
Partnership.
APPLICATION OF PROCEEDS
The Aggregate Subscription will be used to pay costs and expenses
incurred in the operations of the Partnership which are chargeable to the
Limited Partners. The organizational costs of the Partnership and the
offering costs of the Units will be paid by the General Partner.
If all 500 Units offered hereby are sold, the proceeds to the
Partnership would be $500,000. If the minimum 50 Units are sold, the
proceeds to the Partnership would be $50,000. The General Partner
estimates that the gross proceeds will be expended as follows:
$500,000 Program $50,000 Program
---------------- ---------------
Percent Amount Percent Amount
------- ------ ------- ------
Leasehold Acquisition Costs
of Properties to Be Drilled.. 5% $ 25,000 5% $ 2,500
Drilling Costs of Exploratory
Wells........................ 5% 25,000 5% 2,500
Drilling Costs of Develop-
ment Wells................... 70% 350,000 70% 35,000
Leasehold Acquisition Costs
of Productive Properties..... 20% 100,000 20% 10,000
Total..................... 100% $ 500,000 100% $50,000
The foregoing allocation between Drilling Costs and Leasehold
Acquisition Costs is solely an estimate and the actual percentages may
vary materially from this estimate. Funds otherwise available for
drilling Exploratory Wells will be reduced to the extent that such
funds are used in conducting development operations in which the
Partnership participates.
37
<PAGE>
Until Capital Contributions are invested in the Partnership's
operations, they will be temporarily deposited, with or without inter-
est, in one or more bank accounts of the Partnership or invested in
short-term United States government securities, money market funds,
bank certificates of deposit or commercial paper rated as "A1" or "P1"
as the General Partner deems advisable. Partnership funds other than
Capital Contributions may be commingled with the funds of the General
Partner or UNIT.
PARTICIPATION IN COSTS AND REVENUES
All costs of organizing the Partnership and offering Units therein
will be paid by the General Partner. All costs incurred in the offer-
ing and syndication of any drilling or income program formed by UPC or
UNIT and its affiliates during 1996 in which the Partnership
participates as a co-general partner will also be paid by the General
Partner. All other Partnership costs and expenses will be charged 99%
to the Limited Partners and 1% to the General Partner until such time
as the Aggregate Subscription has been fully expended. Thereafter and
until the General Partner's Minimum Capital Contribution has been fully
expended, all of such costs and expenses will be charged to the General
Partner. After the General Partner's Minimum Capital Contribution has
been fully expended, such costs and expenses will be charged to the
respective accounts of the General Partner and the Limited Partners on
the basis of their respective Percentages (see "GLOSSARY").
All Partnership Revenues will be allocated between the General
Partner and the Limited Partners on the basis of their respective
Percentages.
The General Partner's Minimum Capital Contribution will be deter-
mined as of December 31, 1996 and will be an amount equal to:
(a) all costs and expenses previously charged to the General
Partner as of that date, plus
(b) the General Partner's good faith estimate of the additional
amounts that it will have to contribute in order to fund the
Leasehold Acquisition Costs and Drilling Costs expected to be
incurred by the Partnership after that date.
The respective Percentages of the General Partner and the Limited
Partners will then be determined as of December 31, 1996 based on the
relative contributions of the Partners previously made and expected to
be made in the future during the remainder of the Partnership's
property acquisition and drilling phases. See "GLOSSARY - General
Partner's Minimum Capital Contribution", "General Partner's Percentage"
and " Limited Partners' Percentage." If the General Partner's estimate
of future Leasehold Acquisition Costs and Drilling Costs proves to be
38
<PAGE>
lower than the actual amount of such costs and expenses, the excess
amounts will be charged to the Partners on the basis of their
respective Percentages and the Limited Partners' share will be paid out
of their share of Partnership Revenues, Additional Assessments required
of them or the proceeds of Partnership borrowings. See "ADDITIONAL
FINANCING." If the General Partner's estimate of such costs and
expenses proves to be higher than the actual costs and expenses, the
General Partner will continue to bear Partnership costs and expenses
that would otherwise have been chargeable to the Limited Partners until
the total Partnership costs and expenses charged to it (including,
without limitation, offering and organizational costs, Operating
Expenses, general and administrative overhead costs and reimbursements
and Special Production and Marketing Costs as well as Leasehold
Acquisition Costs and Drilling Costs) since the formation of the
Partnership equals the General Partner's Minimum Capital Contribution.
In addition to actual contributions of cash or properties, any Partner
will be deemed to have contributed amounts of Partnership Revenues
allocated to it which are used to pay its share of Partnership costs
and expenses.
The following table presents a summary of the allocation of
Partnership costs, expenses and revenues between the General Partner
and the Limited Partners:
39
<PAGE>
General Limited
COSTS AND EXPENSES Partner Partners
------- --------
Organizational and offering costs
of the Partnership and any drilling
or income programs in which the
Partnership participates as a
co-general partner 100% 0%
All other Partnership Costs and
Expenses:
Prior to time Limited Partner
Capital Contributions are
entirely expended 1% 99%
After expenditure of Limited
Partner Capital Contributions
and until expenditure of
General Partner's Minimum
Capital Contribution 100% 0%
After expenditure of General General Part Limited Part
Partner's Minimum Capital ner's Per- ners' Per-
Contribution centage centage
REVENUES General Part Limited Part
ner's Per- ners' Per-
centage centage
COMPENSATION
Supervision of Operations
It is anticipated that the General Partner will operate most, if
not all, Partnership Properties during the drilling of Partnership
Wells and most, if not all, productive Partnership Wells. For the
General Partner's services performed as operator, the Partnership will
compensate the General Partner its pro rata portion of the compensation
due to the General Partner under the operating agreements, if any, in
effect with respect to such wells or, if none is in effect for such
wells, at rates no higher than those normally charged in the same or a
comparable geographic area by non-affiliated persons or companies
dealing at arm's length.
That portion of the General Partner's general and administrative
overhead expense that is attributable to its conduct of the actual and
necessary business, affairs and operations of the Partnership will be
40
<PAGE>
reimbursed by the Partnership out of Partnership Revenue. The General
Partner's general and administrative overhead expenses are determined
in accordance with industry practices. The costs and expenses to be
allocated include all customary and routine legal, accounting, geologi-
cal, engineering, travel, office rent, telephone, secretarial, sala-
ries, data processing, word processing and other incidental reasonable
expenses necessary to the conduct of the Partnership's business and
generated by the General Partner or allocated to it by UNIT, but will
not include filing fees, commissions, professional fees, printing costs
and other expenses incurred in forming the Partnership or offering
interests therein. The amount of such costs and expenses to be reim-
bursed with respect to any particular period will be determined by
allocating to the Partnership that portion of the General Partner's
total general and administrative overhead expense incurred during such
period which is equal to the ratio of the Partnership's total expendi-
tures compared to the total expenditures by the General Partner for its
own account. The portion of such general and administrative overhead
expense reimbursement which is charged to the Limited Partners may not
exceed an amount equal to 3% of the Aggregate Subscription during the
first 12 months of the Partnership's operations, and in each succeeding twelve-
month period, the lesser of (a) 2% of the Aggregate Subscription
and (b) 10% of the total Partnership Revenue realized in such twelve-month
period. Administrative expenses incurred directly by the
Partnership, or incurred by the General Partner on behalf of the
Partnership and reimbursable to the General Partner, such as legal,
accounting, auditing, reporting, engineering, mailing and other such
fees, costs and expenses are not considered a part of the general and
administrative expense reimbursed to the General Partner and the
amounts thereof will not be subject to the limitations described in the
preceding sentence.
Purchase of Equipment and Provision of Services
UNIT, through its subsidiary Unit Drilling Company, will probably
perform significant drilling services for the Partnership. In
addition, UNIT owns a 34% interest in GED Gas Services L.L.C., an
Oklahoma Limited Liability Company, which may purchase a portion of the
Partnership's gas production.
These persons are in the business of supplying such equipment and
services to non-affiliated parties in the industry and any such equip-
ment and such services will be acquired or provided at prices or rates
no higher than those normally charged in the same or comparable geo-
graphic area by non-affiliated persons or companies dealing at arms'
length. Production purchased by any affiliate of UNIT will be for
prices which are not less than the highest posted price (in the case of
crude oil) or prevailing price (in the case of natural gas) in the same
field or area.
UNIT or one of its affiliates may provide other goods or services
to the Partnership in which event the compensation received therefor
41
<PAGE>
will be subject to the same restrictions and conditions described above
and under "CONFLICTS OF INTEREST" below.
Prior Programs
UNIT was formed in 1986 in connection with a major reorganization
and recapitalization whereby UNIT acquired all of the assets and
liabilities of all of the limited partnerships formed by UNIT's prede-
cessor, Unit Drilling and Exploration Company ("UDEC"), during the
period of 1980 through 1983 in exchange for shares of UNIT's common
stock and UDEC was merged with a wholly owned subsidiary of UNIT
whereby UDEC was the surviving corporation and thereby became a wholly
owned subsidiary of UNIT. UNIT has conducted one oil and gas program
since the date of its formation, the 1986 Energy Program. The 1986
Energy Program was formed on June 12, 1987 with total subscriptions of
one million dollars. The Unit 1986 Employee Oil and Gas Limited
Partnership is a co-general partner with Unit Petroleum Company of the
1986 Energy Program. Direct compensation charged to or paid by the
partnerships and earned by the General Partners for their services in
connection with these programs through September 30, 1995, is set forth
below.
42
<PAGE>
Compensation for
Supervision and Reimbursement
Operation of of General Fees
Productive and Administrative Received as
Management Drilling and Overhead a Drilling
Program Fee(1) Wells(2)(3) Expense(2)(3)(4) Contractor(2)
- -------------- ----------- --------------- --------------- ----------------
1979.......... $ 150,000 $1,550,807 $2,184,910 $1,835,726
1980.......... 200,000 261,456 1,345,158 1,810,310
1981.......... 1,250,000 (5) 329,695 1,892,568 4,047,260
1981-II....... 450,000 158,406 1,607,706 1,629,201
1982-A........ 634,200 521,910 1,688,024 4,110,107
1982-B........ 316,650 331,594 1,224,023 4,945,437
1983-A........ 50,600 151,289 698,597 695,255
1984.......... -- 191,323 658,831 829,503
1984 Employee(*) -- 3,924 5,000 13,452
1985 Employee(*) -- 10,316 -- 54,892
1986 Employee(*) -- 23,505 -- 59,446
1986 Energy
Income Fund(**) -- 120,297 619,779 64,943
1987 Employee(*) -- 50,688 -- 97,079
1988 Employee(*) -- 93,854 -- 112,861
1989 Employee(*) -- 54,536 -- 165,436
1990 Employee(*) -- 28,884 -- 102,977
1991 Employee. -- 167,323 -- 144,722
1992 Employee. -- 36,604 -- 14,861
1993 Employee. -- 19,453 -- 68,504
Consolidated
Program(*) -- 26,511 -- --
1994 Employee. -- 13,123 -- 40,507
1995 Employee. -- 1,054 -- 10,039
_____________
(*) Effective December 31, 1993, pursuant to an Agreement and Plan of Merger,
this employee partnership was merged with and into the Unit Consolidated
Employee Oil and Gas Limited Partnership (the "Consolidated Program"), with the
latter being the surviving limited partnership. See Prior Activities.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
(1) Paid to both UDEC and a prior Key Employee Exploration Fund
as general partners. No management fee was payable to UDEC or any of
its affiliates by any of the 1984 - 1995 Employee Programs and no
management fee is payable by the Partnership to UNIT or any of its
affiliates.
(2) Paid only to UDEC.
43
<PAGE>
(3) In the case of compensation for supervision and operation of
productive wells and reimbursement of UNIT's general and administrative
overhead expense, the general partners generally were charged with and
paid a percentage of such amounts equal to the percentage of partner-
ship revenues being allocated to them.
(4) Although the partnership agreement for each of the 1985-1995
Employee Programs provides that the General Partner is entitled to
reimbursement for the general administrative and overhead expenses
attributable to each of such programs, the General Partner has to date
elected not to seek such reimbursement. However, there can be no
assurance that the General Partner will continue to forego such
reimbursement in the future.
(5) Includes a special allocation of gross revenues totaling
$500,000.
MANAGEMENT
The General Partner
UNIT was formed in 1986 in connection with a major reorganization
and recapitalization whereby UNIT acquired all of the assets and
liabilities of all of the limited partnerships formed by UNIT's prede-
cessor, UDEC, during the period of 1980 through 1983 in exchange for
shares of UNIT's common stock and UDEC was merged with a wholly owned
subsidiary of UNIT whereby UDEC was the surviving corporation and
thereby became a wholly owned subsidiary of UNIT. UPC was incorporated
in the State of Oklahoma on February 9, 1984 as Sunshine Development
Corporation ("SDC"). On October 8, 1985 pursuant to the terms of a
Stock Purchase Agreement," UDEC purchased all of the issued and
outstanding stock of SDC whereby SDC became a wholly owned subsidiary
of UDEC. On February 1, 1988, pursuant to the terms of an "Amended and
Restated Certificate of Incorporation", SDC was renamed Unit Petroleum
Company.
UPC's as well as UNIT's, principal office is at 1000 Kensington
Tower I, 7130 South Lewis Avenue, Tulsa, Oklahoma 74136 and its
telephone number is (918) 493-7700. UNIT through its various
subsidiaries is engaged in the onshore contract drilling of oil and gas
wells and in the exploration for and production of oil and gas. Unless
the context otherwise requires, references in this Memorandum to UNIT
include its predecessor as well as all or any of its subsidiaries.
Officers, Directors and Key Employees
The Partnership will have no directors or officers. The directors
of the General Partner are elected annually and serve until their
successors are elected and qualified. Directors of UNIT are elected at
the Annual Meeting of Shareholders for a staggered term of three years
each, or until their successors are duly elected and qualified. The
44
<PAGE>
executive officers of the General Partner are elected by and serve at
the pleasure of its Board of Directors. The names, ages and respective
positions of the directors and executive officers of UNIT are as
follows:
Name Age Position
---- --- --------
King P. Kirchner 68 Chairman of the Board and
Chief Executive Officer
John G. Nikkel 60 President, Chief
Operating Officer and
Director
O. Earle Lamborn 60 Senior Vice President,
Drilling and Director
Philip M. Keeley 54 Senior Vice President,
Exploration and
Production
Larry D. Pinkston 41 Vice President, Treasurer
and Chief Financial
Officer
Mark E. Schell 38 Secretary and General
Counsel
William B. Morgan 51 Director
Don Cook 70 Director
John S. Zink 67 Director
John H. Williams 77 Director
Don Bodard 75 Director
The names, ages and respective positions of the directors and
executive officers of UPC are as follows:
Name Age Position
---- --- --------
John G. Nikkel 60 Chairman of the Board
and President
Philip M. Keeley 54 Vice President and
Director
Mark E. Schell 38 Secretary, General Counsel
and Director
Larry D. Pinkston 41 Treasurer
45
<PAGE>
Mr. Kirchner, a co-founder of UNIT, has been the Chairman of the
Board and a Director since 1963 and was President until November, 1983.
Mr. Kirchner is a Registered Professional Engineer within the State of
Oklahoma, having received degrees in Mechanical Engineering from
Oklahoma State University and in Petroleum Engineering from the
University of Oklahoma.
Mr. Nikkel joined UNIT in 1983 as its President and a Director.
From 1976 until January 1982 when he co-founded Nike Exploration
Company, Mr. Nikkel was an officer and director of Cotton Petroleum
Corporation, serving as the President of that Company from 1979 until
his departure. Prior to joining Cotton, Mr. Nikkel was employed by
Amoco Production Company for 18 years, last serving as Division
Geologist for Amoco's Denver Division. Mr. Nikkel presently serves as
President and a Director of Nike Exploration Company. Mr. Nikkel
received a Bachelor of Science degree in Geology and Mathematics from
Texas Christian University.
Mr. Lamborn has been actively involved in the oil industry for
over 40 years, joining UNIT's predecessor in 1952 when it was a
privately-held corporation. He was elected Vice President-Drilling in
1973 and as Senior Vice President and Director in 1979.
Mr. Keeley joined UNIT in November, 1983 as Senior Vice President-
Exploration and Production. Prior to that time, Mr. Keeley co-founded
(with Mr. Nikkel) Nike Exploration Company in January, 1982, and serves
as Executive Vice President and a Director of that company. From 1977
until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation,
serving first as Manager of Land and from 1979 as Vice President and a
Director. Before joining Cotton, Mr. Keeley was employed for four
years by Apexco, Inc., as Manager of Land and prior thereto he was
employed by Texaco, Inc. for nine years. He received a Bachelor of
Arts degree in Petroleum Land Management from the University of
Oklahoma.
Mr. Pinkston joined UNIT in December, 1981. He served as
Corporate Budget Director and Assistant Controller prior to being
appointed Controller in February, 1985. He has been Treasurer since
December, 1986 and was elected to the position of Vice President and
Chief Financial Officer in May, 1989. He holds a Bachelor of Science
Degree in Accounting from East Central University of Oklahoma and is a
Certified Public Accountant.
Mr. Schell joined UNIT in January of 1987 as its Secretary and
General Counsel. From 1979 until joining UNIT, Mr. Schell was Counsel,
Vice President and a member of the Board of Directors of C&S
Exploration, Inc. He received a Bachelor of Science degree in
Political Science from Arizona State University and his Juris Doctorate
degree from the University of Tulsa Law School.
46
<PAGE>
Mr. Morgan was elected a Director of UNIT in February, 1988. Mr.
Morgan has been Executive Vice President and General Counsel of St.
John Medical Center, Inc., Tulsa, Oklahoma, since March 1, 1995. Prior
thereto, he was a Partner in the law firm of Doerner, Saunders, Daniel
and Anderson, Tulsa, Oklahoma.
Mr. Cook has served as a Director of UNIT since UNIT's inception
in 1963. He is a Certified Public Accountant and is a retired partner
in the accounting firm of Finley & Cook, Shawnee, Oklahoma.
Mr. Zink was elected a Director of UNIT in May, 1982. He is
founder of ZEECO, a privately held company engaged in the business of
designing and manufacturing combustion and pollution control equipment
used in the petroleum industry. He holds a Bachelor of Science degree
in Mechanical Engineering from Oklahoma State University. He is also a
director of Liberty Bancorp, Tulsa and Oklahoma City, Oklahoma, Matrix
Service Company, Tulsa, Oklahoma, and Chairman of the John Zink
Foundation.
Mr. Williams was elected a Director of UNIT in December of 1988.
Prior to retiring on December 31, 1978, he was Chairman of the Board
and Chief Executive Officer of The Williams Companies, Inc.
Mr. Bodard, a co-founder of UNIT, served as a Director from 1963
until February, 1988 when he resigned. From February, 1988 until
August 23, 1994, when Mr. Bodard was again elected to be a Director of
Unit, he served as a Consultant to the Board of Directors. He is Secretary-
Treasurer of Bodard & Hale Drilling Company, an Oklahoma
based drilling company and President of Bodard Drilling Company, Inc.
He is also Chairman of the Board of Ameribank, Shawnee, Oklahoma.
Prior Employee Programs
Since 1984, UNIT has formed limited partnerships for investment by
certain of its key employees and directors that participate with UNIT
in its exploration and production operations. The name, month of
formation and amount of limited partner capital subscriptions of each
of these limited partnerships (the "Employee Programs") are set forth below.
Limited Partners'
Name Formed Capital Subscriptions
---- ------ ---------------------
Unit 1984 Employee Oil and
Gas Program April 1984 $348,000
Unit 1985 Employee Oil and
Gas Limited Partnership January 1985 $378,000
Unit 1986 Employee Oil and
Gas Limited Partnership January 1986 $307,000
Unit 1987 Employee Oil and
Gas Limited Partnership March 1987 $209,000
47
<PAGE>
Unit 1988 Employee Oil and
Gas Limited Partnership April 29, 1988 $177,000
Unit 1989 Employee Oil and
Gas Limited Partnership December 30, 1988 $157,000
Unit 1990 Employee Oil and
Gas Limited Partnership January 19, 1990 $253,000
Unit 1991 Employee Oil and
Gas Limited Partnership January 7, 1991 $263,000
Unit 1992 Employee Oil and
Gas Limited Partnership January 23, 1992 $240,000
Unit 1993 Employee Oil and
Gas Limited Partnership January 21, 1993 $245,000
Unit 1994 Employee Oil and
Gas Limited partnership January 19, 1994 $284,000
Unit 1995 Employee Oil and
Gas Limited Partnership March 7, 1995 $454,000
One-half of the capital subscriptions from all limited partners
were required to be paid in the 1984 Employee Program, three-fourths of
the capital subscriptions from all limited partners were required to be
paid in the 1985 Employee Program and the 1986 Employee Program. All
of the capital subscriptions from all limited partners, including those
shown below, were required to be paid in the 1987 through 1995 Employee
Programs. The capital subscriptions of the following limited partners
to the 1993, 1994 and 1995 Employee Programs were as shown below:
Amount of Capital
Position with Subscription
Subscriber UNIT 1993 1994 1995
---------- ------------- ---- ---- ----
King P. Kirchner Chairman of the Board $50,000(1) $50,000(1) $50,000(1)
and Chief Executive
Officer
John G. Nikkel President, Chief $72,130(2) $98,000(2) $93,270(2)
Operating Officer
and Director
Philip M. Keeley Senior Vice President, $18,870(2) $22,000(2) $25,730(2)
Exploration and
Production
Don Bodard Director $50,000 $50,000 $200,000
__________________
48
<PAGE>
(1) Mr. Kirchner invested $50,000 indirectly in each of the 1993
Employee Program, the 1994 Employee Program, and the 1995 Employee
Program, through the King P. Kirchner Revocable Trust as permitted by
the limited partnership agreement of those Employee Programs.
(2) Messrs. Nikkel and Keeley have invested in the 1993, 1994 and
1995 Employee Programs both directly and through Nike Exploration
Company which is owned 71.4% by Mr. Nikkel and 28.6% by Mr. Keeley.
The amounts invested directly and indirectly through Nike Exploration
Company in the 1993, 1994 and 1995 Employee Programs by Messrs. Nikkel
and Keeley are set forth below:
Nike
Employee Mr. Nikkel Mr. Keeley Exploration
Program Directly Directly Company
-------- ---------- ---------- -----------
1993 $40,000 $ 6,000 $45,000
1994 $50,000 $10,000 $60,000
1995 $54,000 $10,000 $55,000
Ownership of Common Stock
UNIT's Common Stock is listed on the New York Stock Exchange as
reported on the Composite Tape. On November 21, 1995, there were
20,976,090 shares outstanding.
As of November 21, 1995, the only shareholders who owned of record
or who were known by UNIT to own beneficially more than 5 % of its
total outstanding shares of Common Stock were:
Name and Address % of
of Beneficial Owner Shares(1) Outstanding(1)
------------------- --------- --------------
King P. Kirchner
1000 Kensington Center 1,320,393(2) 6.30%
7130 South Lewis Avenue
Tulsa, Oklahoma 74136
Don Bodard
313 Masonic Building 1,682,928(3) 8.02%
Shawnee, Oklahoma 74801
Scottish Amicable Life
Assurance Society
7 Hanover Square 1,755,000(4) 8.36%
New York, New York 10004
Dimensional Fund Advisors Inc.
1299 Ocean Avenue, 11th Floor 1,273,600(5) 6.07%
Santa Monica, California 90401
49
<PAGE>
(1) The number of shares includes the shares presently issued and
outstanding plus the number of shares which any owner has the right to
acquire within 60 days after November 21, 1995, pursuant to the
exercise of currently exercisable warrants or stock options. For
purposes of calculating the percent of the shares outstanding held by
each owner, the total number of shares excludes the shares which all
other persons have the right to acquire within 60 days after November
21, 1995, pursuant to the exercise of currently exercisable warrants or
stock options.
(2) The number of shares includes 4,567 shares held under Unit's
401(k) Thrift Plan as of December 31, 1994.
(3) Includes options to purchase 2,500 shares of common stock
granted under Unit's Non-Employee Director's Stock Option Plan.
(4) This information is based on the most recent amendment, dated
February 13, 1989, to the Schedule 13D filed with the Securities and
Exchange Commission by Scottish Amicable Life Assurance Society ("Life
Assurance"), Scottish Amicable Pensions Investments Limited
("Pensions") and Scottish Amicable International Exempt Unit Trust
("Unit Trust"). Life Assurance holds sole voting and sole dispositive
power over 395,000 shares of common stock and 55,000 warrants and
shared voting power over 1,060,000 shares of common stock and 245,000
warrants. Unit Trust holds shared voting power over 470,000 shares of
common stock and 120,000 warrants. Pensions holds shared voting power
with respect to 590,000 shares of common stock and 125,000 warrants.
(5) This information is based on Amendment No. 1 to Schedule 13G,
dated February 10, 1993, filed with the Securities and Exchange
Commission by Dimensional Fund Advisors Inc. ("Dimensional").
Dimensional, a registered investment advisor, is deemed to have
beneficial ownership of 1,273,600 shares of common stock as of December
31, 1992, all of which shares are held in portfolios of DFA Investment
Dimensions Group Inc., a registered open-end investment company, or the
DFA Group Trust and DFA Participation Group Trust, investment vehicles
for qualified employee benefit plans, all of which Dimensional serves
as investment manager. Dimensional disclaims beneficial ownership of
all such shares.
As of November 21, 1995, the directors and officers of UNIT
(except Mr. Kirchner and Mr. Bodard whose holdings are given above)
owned of record or beneficially owned shares of UNIT Common Stock as
follows:
50
<PAGE>
Amount of
Beneficial % of
Name Ownership (1) Outstanding(1)
---- ------------- --------------
John Williams................ 11,000 (2) *
Don Cook..................... 16,138 (2) *
Philip M. Keeley............. 255,157 (3)(4) 1.21
O. Earle Lamborn............. 333,141 (4) 1.58
John G. Nikkel............... 333,300 (4) 1.58
Larry D. Pinkston............ 119,003 (4) *
Mark E. Schell............... 49,898 (4) *
John S. Zink................. 30,000 (2) *
William B. Morgan............ 20,000 (2) *
All Officers and Directors
as a Group (consisting
of 11 persons including
Mr. Kirchner).............. 4,170,958 (4)(5) 19.38
_______________
*Less than 1%
(1) The number of shares includes the shares presently issued and
outstanding plus the number of shares which any owner has the right to
acquire within 60 days after November 21, 1995, pursuant to the
exercise of currently exercisable warrants or stock options. For
purposes of calculating the percent of the shares outstanding held by
each owner, the total number of shares excludes the shares which all
other persons have the right to acquire within 60 days after November
21, 1995 pursuant to the exercise of currently exercisable warrants or
stock options.
(2) Includes unexercised stock options granted under UNIT's non-Employee
Directors' Stock Option Plan to each of the following, all of
which are currently exercisable at the discretion of the holder: Don
Cook, 10,000; William B. Morgan, 10,000; John H. Williams, 10,000; John
S. Zink, 10,000; Don Bodard, 2,500; and all non-Employee Directors as a
group, 42,500.
(3) Includes warrants to purchase 2,100 shares of common stock.
(4) Includes shares of common stock held under UNIT's 401(k)
thrift plan as of December 31, 1994 for the account of: Earle Lamborn,
6,681; John G. Nikkel, 24,886; Philip M. Keeley, 30,408; Larry D.
Pinkston, 9,538; and Mark E. Schell, 5,883.
(5) Includes options to purchase 541,900 shares of common stock
and warrants to purchase 2,100 shares of common stock.
51
<PAGE>
Interest of Management in Certain Transactions
Reference is made to "COMPENSATION" for a discussion of the
compensation for supervision and operation of productive wells and the
reimbursement of overhead expenses attributable to the Partnership's
operations to which UNIT is entitled under the terms of the Partnership
Agreement.
CONFLICTS OF INTEREST
There will be situations in which the individual interests of the
General Partner and the Limited Partners will conflict. Although the
General Partner is obligated to deal fairly and in good faith with the
Limited Partners and conduct Partnership operations using the standards
of a prudent operator in the oil and gas industry, such conflicts may
not in every instance be resolved to the maximum advantage of the
Limited Partners. Certain circumstances which will or may involve
potential conflicts of interest are as follows:
The General Partner currently manages and in the future will
sponsor and manage oil and natural gas drilling programs
similar to the Partnership.
The General Partner will decide which prospects the
Partnership will acquire.
The General Partner will act as operator for Partnership
Wells and will, through its affiliates, furnish drilling
and/or marketing services with respect to Partnership Wells,
the terms of which have not been negotiated by non-affiliated
persons.
The General Partner is a general partner of numerous other
partnerships, and owes duties of good faith dealing to such
other partnerships.
The General Partner and its affiliates engage in drilling,
operating and producing activities for other partnerships.
Acquisition of Properties and Drilling Operations
With certain limited exceptions it is anticipated that the
Partnership will participate in each producing property, if any,
acquired by the General Partner and in the drilling of each of the
wells, if any, commenced by the General Partner for its own account
during the period commencing January 1, 1996, or from the formation of
the Partnership if subsequent to January 1, 1996, through December 31,
1996 except for wells:
(i) drilled outside the 48 contiguous United States;
52
<PAGE>
(ii) drilled as part of secondary or tertiary recovery
operations which were in existence prior to formation of
the Partnership;
(iii) drilled by third parties under farm-out or similar
arrangements with UNIT or the General Partner or whereby
UNIT or the General Partner may be entitled to an
overriding royalty, reversionary or other similar interest
in the production from such wells but is not obligated to
pay any of the Drilling Costs thereof;
(iv) acquired by UNIT or the General Partner through the
acquisition by UNIT or the General Partner of, or merger of
UNIT or the General Partner with, other companies; or
(v) with respect to which the General Partner does not believe
that the potential economic return therefrom justifies the
costs and participation by the Partnership.
As a result, the Partnership may have an interest in wells located on
prospects on which producing wells have been drilled by UNIT or the
General Partner in prior years. Likewise, it is possible that the
Partnership will participate in the drilling of initial wells on
prospects on which some or all of the development or offset wells will
be drilled in years subsequent to 1996. In the latter case, the
Partnership would have no right to participate in the drilling of such
development or offset wells.
Sometimes UNIT will agree to participate in drilling operations on
a prospect which it may not believe are fully warranted from an econom-
ic standpoint if it believes that such participation is necessary for,
or will significantly increase its chances of, obtaining a contract to
drill the well with one of its drilling rigs and the revenues from the
contract make the economics of the entire arrangement desirable from
UNIT's standpoint. In such an instance, the Partnership would not be
entitled to any of the drilling contract revenues so the General
Partner will not cause the Partnership to participate in such a well.
However, an analysis of the economic potential of any proposed well is
a very inexact science and wells which have a very high potential
commonly prove to be dry or only marginally profitable and occasionally
a well with apparently very little promise may prove to be very profit-
able. Thus, there can be no assurance that the General Partner will
always make the most profitable decision from the Partnership's stand-
point in determining in which of such potential wells the Partnership
should or should not participate.
Because the Partnership will acquire an interest only in those
properties comprising the spacing unit on which each Partnership Well
is located, it will not be entitled to participate in other wells
drilled by the General Partner, UNIT or any of its affiliates in the
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<PAGE>
same prospect area unless the drilling of those wells commences during
the period from January 1, 1996, or from the formation of the
Partnership if subsequent to January 1, 1996, through December 31,
1996. If the size of a spacing unit in which the Partnership has an
interest is reduced, the Partnership will have no interest in any
additional well drilled on the property comprising the original spacing
unit unless it is commenced during the period from January 1, 1996, or
from the formation of the Partnership if subsequent to January 1, 1996,
through December 31, 1996. Likewise the Partnership would have no
interest in any increased density wells drilled on the original spacing
unit unless such wells were drilled during 1996. In addition, if
additional interests are acquired in wells participated in by the
Partnership after 1996, the Partnership will generally not be entitled
to participate in the acquisition of such additional interests.
Management believes that the apparent conflicts of interest arising
from these situations are mitigated by the fact that the Partnership is
expected to participate in all of UNIT's drilling operations (with the
exceptions noted above) conducted during the period. Thus, there is
little opportunity for the General Partner to selectively choose
Partnership drilling locations for the purpose of proving up other
properties of UNIT or its affiliates in which the Partnership has no
interest. Further, the Partnership will benefit in many instances by
its participation in the drilling of wells located on prospects
previously proved up by drilling operations conducted by UNIT prior to
formation of the Partnership.
Participation in UNIT's Drilling or Income Programs
If UNIT forms any drilling or income programs in 1996, it is
anticipated that the Partnership will serve as a co-general partner
with UNIT in any such drilling or income programs, or both. As the
other co-general partner of any such drilling or income program, UNIT
would have exclusive management and control over the business,
operations and affairs of the drilling or income program. Conflicts of
interest may arise between the limited partners and the general
partners of such drilling or income program and it is possible that
UNIT may elect to resolve those conflicts in favor of the limited
partners. Further, if any such drilling or income program is offered
publicly, the program agreement will be required to contain a number of
provisions concerning the conduct of program operations and handling
conflicts of interests required by the Guidelines for the Registration
of Oil and Gas Programs adopted by the North American Securities
Administrators Association, Inc. Such provisions may significantly
reduce the flexibility of UNIT in managing such programs or may affect
the profitability of the program operations or the transactions between
the general partners and the program.
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<PAGE>
Transfer of Properties
The General Partner or its affiliates are authorized to transfer
interests in oil and gas properties to the Partnership, in which case
the General Partner or its affiliate will receive an amount equal to
the Leasehold Acquisition Costs attributable to the interests being
acquired by the Partnership in the spacing unit on which the Partner-
ship Well is located or is to be drilled. The amount of the Leasehold
Acquisition Costs attributable to the fractional undivided interest in
a property transferred to the Partnership by the General Partner or any
affiliate shall not be reduced or offset by the amount of any gain or
profit the General Partner or its affiliate might have realized by any
prior sale or transfer of a fractional undivided interest in the
property to an unaffiliated third party for a price in excess of the
portion of the Leasehold Acquisition Costs of the property that is
attributable to the transferred interest. The Partnership will not be
reimbursed for or refunded any Leasehold Acquisition Costs if the size
of a spacing unit on which a Partnership Well is located or drilled is
reduced even though the Partnership will have no interest in any
subsequent wells drilled on the area encompassed by the original
spacing unit unless they are commenced during 1996.
A sale, transfer or conveyance to the Partnership of less than all
of the ownership of the General Partner or its affiliates in any
interest or property is prohibited unless:
(1) the interest retained by the General Partner or its
affiliates is a proportionate working interest;
(2) the obligations of the Partnership with respect to the
properties will be substantially the same proportionately as
those of the General Partner or its affiliates at the time it
acquired the properties; and
(3) the Partnership's interest in revenues will not be less than
the proportionate interest therein of the General Partner or
its affiliates when it acquired the properties.
With respect to the General Partner or its affiliates' remaining
interest, it may retain such interest for its own account or it may
sell, transfer, farm-out or otherwise convey all or a portion of such
remaining interest to non-affiliated industry members, which may occur
either before or after the transfer of the interests in the same
properties to the Partnership. The General Partner or its affiliates
may realize a profit on the interests or may be carried to some extent
with respect to its cost obligations in connection with any drilling on
such properties and any such profit or interests will be strictly for
the account of the General Partner or its affiliates and the
Partnership will have no claim with respect thereto. The General
Partner or its affiliates may not retain any overrides or other burdens
55
<PAGE>
on the property conveyed to the Partnership (other than overriding
royalty interests granted to geologists and other persons employed or
retained by the General Partner or its affiliates) and may not enter
into any farm-out arrangements with respect to its retained interest
except to non-affiliated third parties or other programs managed by the
General Partner or its affiliates.
Partnership Assets
The General Partner will not take any action with respect to
assets or property of the Partnership which does not benefit primarily
the Partnership as a whole. The General Partner will not utilize the
funds of the Partnership as compensating balances for the benefit of
the General Partner or its affiliates. All benefits from marketing
arrangements or other relationships affecting property of the Partner-
ship will be fairly and equitably apportioned according to the respec-
tive interests of the Partnership and the General Partner.
The Partnership Agreement provides that when the Partnership is
terminated, there will be an accounting with respect to its assets,
liabilities and accounts. The Partnership's physical property and its
oil and gas properties may be sold for cash. Except in the case of an
election by the General Partner to terminate the Partnership before the
tenth anniversary of the Effective Date, Partnership Properties may be
sold to the General Partner or any of its affiliates for their fair
market value as determined in good faith by the General Partner.
Transactions with the General Partner or Affiliates
UNIT provides through its subsidiary Unit Drilling Company
contract drilling services in the ordinary course of its business.
UNIT also owns a 34% of GED Gas Services L.L.C. which is engaged in the
business of marketing natural gas. It is anticipated that the
Partnership will obtain services, equipment and supplies from some or
all of such persons. In addition, UNIT may supply other goods or
services to the Partnership. The terms of any contracts or agreements
between the Partnership and UNIT or any affiliate will be no less
favorable to the Partnership than those of comparable contracts or
agreements entered into, and will be at prices not in excess of (or in
the case of purchases of production, less than) those charged in the
same geographical area, by non-affiliated persons or companies dealing
at arm's length.
For its services as a drilling contractor, Unit Drilling Company
will charge the Partnership on either a daywork (a specified per day
rate for each day a drilling rig is on the drill site), a footage (a
specified rate per foot drilled) or a turnkey (specified amount for
drilling the well) basis. The rate charged by Unit Drilling Company
for such services will be the same as those offered to unaffiliated
third parties in the same or similar geographic areas.
56
<PAGE>
Right of Presentment Price Determination
Under the terms of the Partnership Agreement, a Limited Partner
can, subject to certain conditions, require the General Partner to
purchase his or her Units at a price determined by the application of a
stated formula to the estimated future net revenues attributable to the
Partnership's estimated proved reserves. See "TERMS OF THE OFFERING -
Right of Presentment." It is anticipated that if an independent
engineering firm makes an evaluation of the proved reserves of the
Partnership, the result of that evaluation will be used in determining
the price to be paid to a Limited Partner exercising his or her right
of presentment. However, if no such independent evaluation is made,
the right of presentment purchase price will be determined by using the
proved reserves and future net revenue estimates of the technical staff
of the General Partner.
Receipt of Compensation Regardless of Profitability
The General Partner is entitled to receive its fees and other
compensation and reimbursements from the Partnership regardless of
whether the Partnership operates at a profit or loss. See "PARTICIPA-TION IN
COSTS AND REVENUES" and "COMPENSATION." Such fees, compensa-
tion and reimbursements will decrease the Limited Partners' share of
any profits generated by operations of the Partnership or increase
losses if such operations should prove unprofitable.
Legal Counsel
Conner & Winters, A Professional Corporation, serves as special
legal counsel for the General Partner. Such firm has performed legal
services for the General Partner and UNIT and is expected to render
legal services to the Partnership. Although such firm has indicated
its intention to withdraw from representation of the Partnership if
conflicts of interest do in fact arise, there can be no assurance that
representation of both the General Partner or UNIT and the Partnership
by such firm will not be disadvantageous to the Partnership.
FIDUCIARY RESPONSIBILITY
General
Under Oklahoma law, the General Partner will have a fiduciary duty
to the Limited Partners and consequently must exercise good faith,
fairness and loyalty in the handling of the Partnership's affairs. The
General Partner must provide Limited Partners (or their
representatives) with timely and full information concerning matters
affecting the business of the Partnership. Each Limited Partner may
inspect the Partnership's books and records upon reasonable prior
notice. The nature of the fiduciary duties of general partners is an
evolving area of law and prospective investors who have questions
57
<PAGE>
concerning the duties of the General Partner should consult with their
counsel.
Regardless of the fiduciary obligations of the General Partner,
the General Partner, UNIT or its affiliates, subject to any
restrictions or requirements set forth in the Agreement, may:
engage independently of the Partnership in all aspects of the
oil and gas business, either for their own accounts or for
the accounts of others;
sell interests in oil and gas properties held by them to,
purchase oil and gas production from, and engage in other
transactions with, the Partnership;
serve as general partner of other oil and gas drilling or
income partnerships, including those which may be in
competition with the Partnership; and
engage in other activities that may involve conflicts of
interest.
See "CONFLICTS OF INTEREST." Thus, unlike the strict duty of a
fiduciary who must act solely in the best interests of his beneficiary,
the Agreement permits the General Partner to consider, among other
things, the interests of other partnerships sponsored by the General
Partner, UNIT or its affiliates in resolving investment and other
conflicts of interest. The foregoing provisions permit the General
Partner to conduct its own operations and to act as the general partner
of more than one similar partnership or investment program and for the
Partnership to benefit from its experience resulting therefrom, but
relieves the General Partner of the strict fiduciary duty of a general
partner acting as such for only one investment program at a time.
These provisions are primarily intended to reconcile the applicable
duties under Oklahoma law with the fact that the General Partner will
manage and administer its own oil and gas operations and a number of
other oil and gas investment programs with which possible conflicts of
interests may arise and resolve such conflicts in a manner consistent
with the expectation of the investors in all such programs, the General
Partner's fiduciary duties and customary business practices and
statutes applicable thereto.
Liability and Indemnification
The Agreement provides that the General Partner will perform its
duties in an efficient and businesslike manner with due caution and in
accordance with established practices of the oil and gas industry. The
Agreement further provides that the General Partner and its affiliates
will not be liable to the Partnership or the Partners, and will be
indemnified by the Partnership, for any expense (including attorney
58
<PAGE>
fees), loss or damage incurred by reason of any act or omission
performed or omitted in good faith in a manner reasonably believed by
the General Partner or its affiliates to be within the scope of
authority and in the best interest of the Partnership or the Partners
unless the General Partner or its affiliates is guilty of gross
negligence or willful misconduct. While not totally certain under
Oklahoma law, absent specific provisions in the partnership agreement
to the contrary, a general partner of a limited partnership may be
liable to its limited partners if it fails to conduct the partnership
affairs with the same amount of care which ordinarily prudent persons
would use in similar circumstances. Consequently, the Agreement may be
viewed as requiring a lesser standard of duty and care than what
Oklahoma law might otherwise require of the General Partner.
Any claim against the Partnership for indemnification must be
satisfied only out of Partnership assets including insurance proceeds,
if any, and none of the Limited Partners will have personal liability
therefor.
The Limited Partners may have more limited rights of action than
they would have absent the liability and indemnification provisions
above. Moreover, indemnification enforced by the General Partner under
such provisions will reduce the assets of the Partnership. It should
be noted, however, that it is the position of the Securities and
Exchange Commission ("Commission") that any attempt to limit the
liability of a general partner or to indemnify a general partner under
the federal securities laws is contrary to public policy and,
therefore, unenforceable. The General Partner has been advised of the
position of the Commission.
Generally, the Limited Partners' remedy for the General Partner's
breach of a fiduciary duty will be to bring a legal action against the
General Partner to recover any damages, generally measured by the
benefits earned by the General Partner as a result of the fiduciary
breach. Additionally, Limited Partners may also be able to obtain
other forms of relief, including injunctive relief. The Act provides
that a limited partner may bring an action in the name of a limited
partnership (a partnership derivative action) to recover a judgment in
its favor if general partners with authority to do so have refused to
bring the action or if an effort to cause such general partners to
bring the action is not likely to succeed.
PRIOR ACTIVITIES
UNIT has been engaged in oil and gas exploration and development
operations since late 1974 and has conducted oil and gas drilling
programs using the limited partnership format since 1979. The follow-
ing table depicts the drilling results achieved as of September 30,
1995 by UNIT during each year since 1975. Because of the
unpredictability of oil and gas exploration in general, such results
59
<PAGE>
should not be considered indicative of the results that may be achieved
by the Partnership.
Gross Wells(2) Net Wells(3)
Year Ended ---------------------- -------------------------
July 31(1) Total Oil Gas Dry Total Oil Gas Dry
----- --- --- --- ----- --- --- ---
1975 Exploratory........ 2 0 2 0 .01 0 .01 0
Development........ 4 0 2 2 .07 0 .03 .04
----- --- --- --- ----- --- --- ---
6 0 4 2 .08 0 .04 .04
----- --- --- --- ----- --- --- ---
1976 Exploratory........ 1 0 0 1 .01 0 0 .01
Development........ 8 0 6 2 .29 0 .28 .01
----- --- --- --- ----- --- --- ---
9 0 6 3 .30 0 .28 .02
----- --- --- --- ----- --- --- ---
1977 Exploratory........ 9 0 3 6 1.50 0 .45 1.05
Development........ 16 0 9 7 2.00 0 .70 1.30
----- --- --- --- ----- --- --- ---
25 0 12 13 3.50 0 1.15 2.35
----- --- --- --- ----- --- --- ---
1978 Exploratory........ 8 1 1 6 1.17 .34 .15 .68
Development........ 26 0 13 13 2.64 0 .76 1.88
----- --- --- --- ----- --- --- ---
34 1 14 19 3.81 .34 .91 2.56
----- --- --- --- ----- --- --- ---
1979 Exploratory........ 10 0 5 5 1.40 0 .76 .64
Development........ 16 1 8 7 1.99 .06 .95 .98
----- --- --- --- ----- --- --- ---
26 1 13 12 3.39 .06 1.71 1.62
----- --- --- --- ----- --- --- ---
1980 Exploratory........ 1 0 1 0 1.28 0 .23 1.05
Development........ 10 0 8 2 3.13 0 .85 2.28
----- --- --- --- ----- --- --- ---
11 0 9 2 4.41 0 1.08 3.33
----- --- --- --- ----- --- --- ---
Year Ended
December 31(1)
1981 Exploratory........ 14 1 4 9 1.12 .02 .16 .94
Development........ 66 18 29 19 7.38 2.96 1.77 2.65
----- --- --- --- ----- --- --- ---
Total 80 19 33 28 8.50 2.98 1.93 3.59
----- --- --- --- ----- --- --- ---
1982 Exploratory........ 40 5 9 26 3.39 .60 .32 2.47
Development........ 100 22 51 27 11.70 4.70 2.71 4.29
----- --- --- --- ----- --- --- ---
Total 140 27 60 53 15.09 5.30 3.03 6.76
----- --- --- --- ----- --- --- ---
1983 Exploratory........ 6 2 0 4 1.31 .72 0 .59
Development........ 72 18 26 28 8.01 3.45 1.17 3.39
----- --- --- --- ----- --- --- ---
Total 78 20 26 32 9.32 4.17 1.17 3.98
----- --- --- --- ----- --- --- ---
1984 Exploratory........ 2 1 1 0 .52 .49 .03 0
Development........ 50 15 22 13 6.81 3.42 2.74 .65
----- --- --- --- ----- --- --- ---
Total 52 16 23 13 7.33 3.91 2.77 .65
----- --- --- --- ----- --- --- ---
1985 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 38 11 16 11 8.32 2.89 2.39 3.04
----- --- --- --- ----- --- --- ---
Total 38 11 16 11 8.32 2.89 2.39 3.04
----- --- --- --- ----- --- --- ---
1986 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 21 4 6 11 3.85 .81 1.01 2.03
----- --- --- --- ----- --- --- ---
Total 21 4 6 11 3.85 .81 1.01 2.03
----- --- --- --- ----- --- --- ---
1987 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 46 23 10 13 11.91 7.95 1.76 2.34
----- --- --- --- ----- --- --- ---
Total 46 23 10 13 11.91 7.95 1.76 2.34
----- --- --- --- ----- --- --- ---
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1988 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 39 20 10 9 22.56 14.77 4.05 3.74
----- --- --- --- ----- --- --- ---
Total 39 20 10 9 22.56 14.77 4.05 3.74
----- --- --- --- ----- --- --- ---
1989 Exploratory........ 3 0 1 2 1.97 0 .47 1.50
Development........ 40 12 15 13 18.83 8.81 4.13 5.89
----- --- --- --- ----- --- --- ---
Total 43 12 16 15 20.80 8.81 4.60 7.39
----- --- --- --- ----- --- --- ---
1990 Exploratory........ 5 0 2 3 1.22 0 .12 1.10
Development........ 35 11 14 10 16.53 8.38 3.52 4.63
----- --- --- --- ----- --- --- ---
Total 40 11 16 13 17.75 8.38 3.64 5.73
----- --- --- --- ----- --- --- ---
1991 Exploratory........ 4 0 0 4 .82 0 0 .82
Development........ 28 10 9 9 15.88 8.61 3.91 3.36
----- --- --- --- ----- --- --- ---
Total 32 10 9 13 16.70 8.61 3.91 4.18
----- --- --- --- ----- --- --- ---
1992 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 18 1 11 6 5.81 1.00 3.33 1.48
----- --- --- --- ----- --- --- ---
Total 18 1 11 6 5.81 1.00 3.33 1.48
----- --- --- --- ----- --- --- ---
1993 Exploratory........ 1 0 0 1 .10 0 0 .10
Development........ 16 9 6 1 12.48 8.98 3.32 .18
----- --- --- --- ----- --- --- ---
Total 17 9 6 2 12.58 8.98 3.32 .28
----- --- --- --- ----- --- --- ---
1994 Exploratory........ 3 0 1 2 1.71 0 .95 .76
Development........ 57 5 40 12 25.79 4.75 14.14 6.90
----- --- --- --- ----- --- --- ---
Total 60 5 41 14 27.50 4.75 15.09 7.66
----- --- --- --- ----- --- --- ---
Period of January 1, 1995
to September 30, 1995
Exploratory........ 0 0 0 0 0 0 0 0
Development........ 28 10 16 2 9.28 3.91 4.69 .68
----- --- --- --- ----- --- --- ---
Total 28 10 16 2 9.28 3.91 4.69 .68
----- --- --- --- ----- --- --- ---
________________
(1) Except as indicated, the figures used in this table relate to
wells drilled and completed during each of the 12 month periods ended
July 31 or December 31, as the case may be. Oil wells and gas wells
shown include both producing wells and wells capable of production.
(2) "Gross Wells" refers to the total number of wells in which
there was participation by UNIT.
(3) "Net Wells" refers to the aggregate leasehold working inter-
est of UNIT in such wells. For example, a 50% leasehold working
interest in a well drilled represents 1.0 Gross Well, but a .50 Net
Well.
Prior Employee Programs
During the period of 1979 to 1983, persons who were designated key
employees of UNIT by its board of directors participated in the Unit
Key Employee Exploration Funds (the "Funds"). These Funds were formed
as general partnerships for the purpose of participating in 10% of all
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<PAGE>
of the exploration and development operations conducted by UNIT during
a specified period. Except for the Fund formed in 1983, each of the
prior Funds served as one of the general partners in at least one of
the prior drilling programs sponsored by UNIT and was allocated 10% of
the expenses and revenues allocable to the general partners as a group.
In each of these Funds the costs charged to it in connection with its
operations were financed with the proceeds of bank borrowings and out
of the Funds' share of revenues.
The 1983 Fund served as the sole capital limited partner in the
Unit 1983-A Oil and Gas Program and as such made no contribution to the
capital of that program and shared in 10% of the costs and revenues
otherwise allocable to the General Partner after the distributions to
the General Partner from the program equaled the amount of its contri-
butions thereto plus UNIT's interest costs with respect to the unrecov-
ered amount of its contributions.
Because of the differences in structure, format and plan of
operations between the prior Funds and the Partnership and because of
the uncertainties which are inherent in oil and gas operations general-
ly, the results achieved by the prior Funds should not be considered
indicative of the results the Partnership may achieve.
For each year from 1984 through 1995, a separate Employee Program
was formed as an Oklahoma limited partnership with UNIT or UPC as its
sole general partner (UPC now serves as the sole general partner of
each of these Employee Programs) and with eligible employees and
directors of UNIT and its subsidiaries who subscribed for units therein
as the limited partners. Each Employee Program participated on a
proportionate basis (to the extent of 10% of the General Partner's
interest in each case except for the 1986 and 1987 Employee Programs,
in which case the percentage participation was 15% and the 1992-1995
Employee Programs, in which case the percentage was 5%) in all of
UNIT's oil and gas exploration and development operations conducted
during the calendar year for which the program was formed beginning
with its date of formation if it was formed after January 1. Although
the terms and provisions of these Employee Programs are virtually
identical to those of the Partnership, because of the unpredictability
of oil and gas exploration and development in general, the results for
the Employee Programs shown below should not be considered indicative
of the results that may be achieved by the Partnership.
The Funds and the Employee Programs have participated in either
10% or 5% (15% in the case of the 1986 and 1987 Employee Programs) of
virtually all of UNIT's or the General Partner's exploration and
development operations conducted since the latter half of 1979. Thus,
the drilling results of these partnerships would be proportionate to
those drilling results of UNIT for the periods beginning after the
fiscal year ended July 31, 1979 shown above.
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<PAGE>
Results of the Prior Oil and Gas Programs
In each of the General Partner's prior oil and gas programs other
than the Unit 1983-A Oil and Gas Program and the Unit 1984 Oil and Gas
Limited Partnership, one of the prior Funds also served as a general
partner. The 1983 Fund served as the sole capital limited partner of
the Unit 1983-A Oil and Gas Program and the 1984 Employee Program
serves as a general partner of the Unit 1984 Oil and Gas Limited
Partnership. The Unit 1979 Oil and Gas Program was the first limited
partnership drilling program of which UNIT was a sponsor. The revenue
sharing terms of the 1979 Program are generally 70% to the limited
partners and 30% to the general partners until 150% program payout at
which time the revenues are to be shared 55% to the limited partners
and 45% to the general partners. The revenue sharing terms of the Unit
1980 Oil and Gas Program were generally 60% to the limited partners and
40% to the general partners. The revenue sharing terms of the Unit
1981 Oil and Gas Program were generally 70% to the limited partners and
30% to the general partners until program payout and 50% to the limited
partners and 50% to the general partners thereafter. The revenue
sharing terms of the Unit 1981-II Oil and Gas Program, the Unit 1982-A
Oil and Gas Program and the Unit 1982-B Oil and Gas Program (60% to the
limited partners and 40% to the general partners) were substantially
the same as those of the Unit 1983-A Oil and Gas Program and the Unit
1984 Oil and Gas Limited Partnership (65% to the limited partners and
35% to the general partner) except that the general partners' cost
percentage and the general partners' revenue share in each of those
prior programs could not be less than 25%. The following tables depict
the drilling results at September 30, 1995, and the economic results at
September 30, 1995 of prior oil and gas programs and the 1984-1995
Employee Programs. On September 12, 1986, in connection with a major
restructuring and recapitalization, UNIT acquired all of the assets and
liabilities of the programs formed during 1980 through 1983 and these
programs have now been dissolved. Effective December 31, 1993,
pursuant to an Agreement and Plan of Merger, dated as of December 28,
1993, all of the assets and all of the liabilities of the 1984, 1985,
1986, 1987, 1988, 1989 and 1990 Employee Programs were merged with and
consolidated into a new Employee Program called the Unit Consolidated
Employee Oil and Gas Limited Partnership, an Oklahoma Limited
Partnership which was formed November 30, 1993 (the "Consolidated
Program"). The Consolidated Program holds no assets other than those
acquired in the merger with the 1984 through 1990 Employee Programs.
The Unit 1979 Oil and Gas Program continues in existence as do the
1991, 1992, 1993, 1994 and 1995 Employee Programs. Certain of these
programs have not completed all of their drilling and development
operations. Moreover, because of the unpredictability of oil and gas
exploration and development in general, the results shown below should
not be considered indicative of the results that may be achieved by the
Partnership.
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<PAGE>
DRILLING RESULTS
----------------
As of September 30, 1995
Gross Wells Net Wells
-------------------- ----------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- -------------------- ----------------------
1979 Exploratory Wells 6 0 2 4 2.43 0.00 0.65 1.78
Development Wells 21 16 1 4 17.28 14.14 0.03 3.11
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 27 16 3 8 19.71 14.14 0.68 4.89
---- ---- ---- ---- ----- ----- ---- ----
1980(1) Exploratory Wells 15 2 5 8 5.65 0.50 2.14 3.01
Development Wells 32 5 15 12 12.77 1.17 5.75 5.85
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 47 7 20 20 18.42 1.67 7.89 8.86
---- ---- ---- ---- ----- ----- ---- ----
1981(1) Exploratory Wells 11 1 4 6 4.61 0.33 0.88 3.40
Development Wells 67 14 34 19 21.77 5.03 6.61 10.13
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 78 15 38 25 26.38 5.36 7.49 13.53
---- ---- ---- ---- ----- ----- ---- ----
1981-II(1)Exploratory Wells 13 1 5 7 5.21 0.25 1.12 3.84
Development Wells 45 3 29 13 9.07 0.69 4.78 3.60
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 58 4 34 20 14.28 0.94 5.90 7.44
---- ---- ---- ---- ----- ----- ---- ----
1982-A(1) Exploratory Wells 11 3 1 7 3.55 0.78 0.00 2.77
Development Wells 69 23 22 24 25.22 13.09 3.59 8.54
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 80 26 23 31 28.77 13.87 3.59 11.31
---- ---- ---- ---- ----- ----- ---- ----
1982-B(1) Exploratory Wells 4 1 1 2 2.28 0.80 0.08 1.40
Development Wells 41 16 9 16 18.60 9.47 1.01 8.12
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 45 17 10 18 20.88 10.27 1.09 9.52
---- ---- ---- ---- ----- ----- ---- ----
1983-A(1) Exploratory Wells 1 1 0 0 1.00 1.00 0.00 0.00
Development Wells 26 14 10 2 6.60 4.39 1.27 0.94
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 27 15 10 2 7.60 5.39 1.27 0.94
---- ---- ---- ---- ----- ----- ---- ----
1984 Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells 21 1 10 10 5.89 .38 3.08 2.43
---- ---- ---- ---- ----- ----- ---- ----
Total.......... 21 1 10 10 5.89 .38 3.08 2.43
---- ---- ---- ---- ----- ----- ---- ----
(1) On September 12, 1986, Unit acquired all of the assets and liabilities of
this
Program and the Program has been dissolved.
EMPLOYEE PROGRAMS
As of September 30, 1995
Gross Wells Net Wells
-------------------- ----------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- ----- ---- ---- ---- ----- ----- ---- ----
1984(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 25 4 12 9 .14 .02 .06 .06
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 25 4 12 9 .14 .02 .06 .06
----- ---- ---- ---- ----- ----- ---- ----
1985(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 30 8 10 12 .38 .12 .08 .18
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 30 8 10 12 .38 .12 .08 .18
----- ---- ---- ---- ----- ----- ---- ----
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<PAGE>
1986(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 18 6 8 4 .48 .12 .30 .06
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 18 6 8 4 .48 .12 .30 .06
----- ---- ---- ---- ----- ----- ---- ----
1987(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 21 12 5 4 1.17 .74 .25 .18
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 21 12 5 4 1.17 .74 .25 .18
----- ---- ---- ---- ----- ----- ---- ----
1988(1) Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 29 15 9 5 1.55 1.03 .28 .24
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 29 15 9 5 1.55 1.03 .28 .24
----- ---- ---- ---- ----- ----- ---- ----
1989(1) Exploratory Wells
Empl. Development Wells 32 7 14 11 1.48 .59 .36 .53
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 32 7 14 11 1.48 .59 .36 .53
----- ---- ---- ---- ----- ----- ---- ----
1990(1) Exploratory Wells 5 0 2 3 .122 0 .01 .11
Empl. Development Wells 34 11 14 9 1.65 .83 .35 .46
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 39 11 16 12 1.78 .83 .36 .57
----- ---- ---- ---- ----- ----- ---- ----
1991 Exploratory Wells 4 0 0 4 .08 0 0 .08
Empl. Development Wells 28 10 9 9 1.59 .86 .39 .34
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 32 10 9 13 1.67 .86 .39 .42
----- ---- ---- ---- ----- ----- ---- ----
1992 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 18 1 11 6 .29 .05 .17 .07
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 18 1 11 6 .29 .05 .17 .07
----- ---- ---- ---- ----- ----- ---- ----
1993 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 16 9 6 1 .63 .45 .17 .01
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 16 9 6 1 .63 .45 .17 .01
----- ---- ---- ---- ----- ----- ---- ----
1994 Exploratory Wells 3 0 1 2 .09 0 .05 .04
Empl. Development Wells 57 5 40 12 1.29 .24 .70 .35
----- ---- ---- ---- ----- ----- ---- ----
Total.......... 60 5 41 14 1.38 .24 .75 .39
----- ---- ---- ---- ----- ----- ---- ----
1995(2) Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 28 10 16 2 .46 .20 .23 .03
----- ---- ---- ---- ----- ----- ---- ----
Total......... 28 10 16 2 .46 .20 .23 .03
----- ---- ---- ---- ----- ----- ---- ----
_______________
(1) Effective December 31, 1993 this Program was merged with and into
the Consolidated Program.
(2) It is anticipated that this program may participate in
approximately 17 additional wells.
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<PAGE>
GENERAL PARTNERS' PAYOUT TABLE(1)
As of September 30, 1995
Total
Total Revenues Total Revenues
Expenditures Before Before Deducting
Including Deducting Operating Costs
Operating Operating for 3 Months Ended
Program Costs(2) Costs September 30, 1995
- --------------------------- ---------- ---------- ------------------
1979....................... $7,518,410 $9,217,733 $48,817
1980....................... 4,043,599 4,044,424 -
1981....................... 8,325,594 6,338,173 -
1981-II.................... 6,642,875 3,995,616 -
1982-A..................... 9,190,842 6,782,893 -
1982-B..................... 4,213,710 3,126,326 -
1983-A..................... 2,277,514 1,312,531 -
1984....................... 2,103,902 1,433,619 13,438
1984 Employee(*)........... 1,542 1,745 -
1985 Employee(*)........... 2,820 1,808 -
1986 Energy Income Fund(**) 1,114,154 1,148,459 16,985
1986 Employee(*)........... 4,403 6,813 -
1987 Employee(*)........... 624,354 815,358 -
1988 Employee(*)........... 1,196,564 1,588,132 -
1989 Employee(*)........... 1,424,525 1,171,961 -
1990 Employee(*)........... 653,563 525,572 -
1991 Employee.............. 1,563,776 1,278,890 59,720
1992 Employee.............. 153,259 146,733 7,084
1993 Employee.............. 350,873 267,466 24,150
Consolidated Program....... 1,349 3,387 390
1994 Employee.............. 848,610 298,486 95,225
1995 Employee.............. 108,386 5,769 3,217
__________
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
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<PAGE>
LIMITED PARTNERS' PAYOUT TABLE(1)
As of September 30, 1995
Total
Total Revenues Total Revenues
Expenditures Before Before Deducting
Including Deducting Operating Costs
Operating Operating for 3 Months Ended
Program Costs(2) Costs September 30, 1995
- --------------------------- ----------- ----------- ------------------
1979....................... $13,131,350 $16,846,061 $ 59,901
1980....................... 17,688,367 6,949,008 -
1981....................... 37,073,946 15,768,826 -
1981-II.................... 18,638,600 7,028,946 -
1982-A..................... 24,866,078 12,708,949 -
1982-B..................... 12,069,566 5,367,312 -
1983-A..................... 3,770,856 1,922,177 -
1984....................... 2,683,124 1,495,249 13,520
1984 Employee(*)........... 120,942 171,540 -
1985 Employee(*)........... 277,901 178,984 -
1986 Energy Income Fund(**) 2,300,313 2,841,218 25,609
1986 Employee(*)........... 435,858 676,972 -
1987 Employee(*)........... 341,846 469,830 -
1988 Employee(*)........... 333,898 446,044 -
1989 Employee(*)........... 179,593 175,331 -
1990 Employee(*)........... 300,852 188,848 -
1991 Employee.............. 410,152 341,562 15,948
1992 Employee.............. 394,905 380,177 18,312
1993 Employee.............. 324,336 248,022 22,447
Consolidated Program....... 136,913 335,644 38,631
1994 Employee.............. 341,816 122,819 38,998
1995 Employee.............. 149,675 10,343 5,953
__________
(*) Effective December 31, 1993, this program was merged with and into
the Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
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<PAGE>
GENERAL PARTNERS' NET CASH TABLE(1)
As of September 30, 1995
Total
Revenues
Less Total
Operating Revenues
Total Total Costs for Distributed
Expenditures Revenues 3 Months for 3 Months
Less Less Ended Total Ended
Operating Operating Sept.30, Revenues Sept. 30,
Program Costs(2) Costs 1995 Distributed 1995
- ---------------------- ----------- ---------- -------- ------------ -----------
1979.................. $2,833,478 $4,532,801 $7,509 3,622,294 7,000
1980.................. 2,628,978 2,629,803 - 2,635,751 -
1981.................. 6,546,160 4,558,739 - 5,368,272 -
1981-II............... 4,817,145 2,169,886 - 2,609,000 -
1982-A................ 6,297,972 3,890,023 - 3,755,000 -
1982-B................ 2,565,504 1,478,120 - 1,158,000 -
1983-A................ 1,380,331 415,348 - 819,000 -
1984.................. 922,964 252,681 (10,637) 552,741 -
1984 Employee(*)...... 874 1,077 - 1,000 -
1985 Employee(*)...... 2,300 1,288 - 1,035 -
1986 Energy Income
Fund(**).............. 223,419 257,724 (154) 296,203 2,000
1986 Employee(*)...... 2,698 5,108 17,845 4,486 -
1987 Employee(*)...... 357,368 548,372 - 465,800 -
1988 Employee(*)...... 770,272 1,161,840 - 942,800 -
1989 Employee(*)...... 1,010,133 752,569 - 607,900 -
1990 Employee(*)...... 466,272 338,281 - 266,600 -
1991 Employee......... 1,050,303 765,417 28,922 639,600 32,000
1992 Employee......... 98,317 91,791 3,302 65,500 4,000
1993 Employee......... 288,975 205,568 16,382 134,700 23,000
Consolidated Program.. 14 2,052 208 2,325 895
1994 Employee......... 766,036 215,912 66,774 88,000 80,000
1995 Employee......... 104,273 1,656 875 - -
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
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<PAGE>
LIMITED PARTNERS' NET CASH TABLE(1)
As of September 30, 1995
Total
Revenues Total
Less Revenues
Operating Distributed
Total Total Costs for for 3
Expenditures Revenues 3 Months Months
Less Less Ended Total Ended
Capital Operating Operating Sept.30, Revenues Sept. 30,
Program Contributed Costs(2) Costs 1995 Distributed 1995
- ------------- ---------- ---------- ----------- ------- ---------- --------
1979......... $3,000,000 $6,197,490 $ 9,912,201 $ 9,412 $5,896,401 $ -
1980......... 12,000,000(3) 14,469,265 3,729,906 - 760,000 -
1981......... 29,255,000(4) 32,700,741 11,395,621 - 5,335,065 -
1981-II...... 15,000,000 16,603,760 4,994,106 - 1,710,001 -
1982-A....... 21,140,000 21,591,442 9,434,313 - 6,342,000 -
1982-B....... 10,555,000 9,935,850 3,233,596 - 2,828,740 -
1983-A....... 2,530,000 2,993,705 1,145,026 - 227,700 -
1984......... 1,575,000 2,034,041 846,166 8,826 510,341 13,230 (5)
1984 Employee(*) 174,000 86,664 137,262 - 125,280 -
1985 Employee(*) 283,500 227,670 128,753 - 182,644 -
1986 Energy
Income Fund(**)
1,000,000 1,088,143 1,629,050 456 1,452,100 -
1986 Employee(*) 229,750 267,008 508,122 - 460,007 -
1987 Employee(*) 209,000 207,060 335,044 - 324,845 -
1988 Employee(*) 177,000 214,712 326,858 - 281,630 -
1989 Employee(*) 157,000 157,306 153,044 - 147,737 -
1990 Employee(*) 253,000 254,483 142,479 - 180,895 -
1991 Employee.. 253,000 273,842 205,252 7,760 177,525 8,679 (6)
1992 Employee.. 240,000 253,628 238,900 8,590 197,760 8,400 (7)
1993 Employee.. 245,000 267,336 191,022 15,275 141,120 20,825 (8)
Consolidated
Program........ - 1,564 200,295 20,529 197,012 28,343 (9)
1994 Employee.. 284,000 308,089 89,092 27,377 37,772 28,968(10)
1995 Employee.. 346,550 143,995 4,664 2,719 - -
__________
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
(1) Amounts reflect the accrual method of accounting.
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<PAGE>
(2) Does not include expenditures of $237,600, $920,453,
$2,252,900, $1,480,248, $2,079,268, $985,371 and $241,076 which were
obtained from bank borrowings and used to pay the limited partners'
share of sales commissions of $237,600, $722,453, $1,940,400,
$1,183,248, $1,656,468, $827,046 and $190,476 and organization costs of
$--0--, $198,000, $312,500, $297,000, $422,800, $158,325 and $50,600
for the 1979, 1980, 1981, 1981-II, 1982-A, 1982-B and 1983-A Programs,
respectively.
(3) Includes original subscriptions of limited partners totaling
$10,000,000 and additional assessments totaling $2,000,000.
(4) Includes original subscriptions of limited partners totaling
$25,000,000 and additional assessments totaling $4,255,000.
(5) In November 1995, the 1984 Program made a distribution of
$6,930 to that program's limited partners.
(6) In November 1995, the 1991 Employee Program made a
distribution of $6,049 to that program's limited partners.
(7) In November 1995, the 1992 Employee Program made a
distribution of $10,320 to that program's limited partners.
(8) In November 1995, the 1993 Employee Program made a
distribution of $17,150 to that program's limited partners.
(9) In November 1995, the Consolidated Program made a
distribution of $17,464 to that program's limited partners.
(10) In November 1995, the 1994 Employee Program made a
distribution of $11,076 to that program's limited partners.
FEDERAL INCOME TAX ASPECTS
General
The following discussion of federal income tax considerations is
based on existing provisions of the Internal Revenue Code of 1986, as
amended ("Code"), existing and proposed Treasury Regulations, existing
administrative interpretations, and existing court decisions. No
assurance can be given that legislation, Treasury Regulations,
administrative interpretations, or court decisions will not
significantly change existing law, or that any of such changes will not
be applied retroactively.
Conner & Winters, A Professional Corporation, tax counsel to the
Partnership ("Counsel"), is of the opinion that to the extent the
summary of federal income tax consequences to the Limited Partners set
forth in this "FEDERAL INCOME TAX ASPECTS" section and under the
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<PAGE>
heading "RISK FACTORS--Tax Related Risks" involves matters of law,
these statements are accurate in all material respects under the Code,
Treasury Regulations, and existing interpretations thereof and address
the material federal income tax considerations relating to an
investment in the Partnership. An opinion of counsel is not binding on
the Service or the courts. Accordingly, it is possible that the
Service will successfully challenge the tax treatment of certain
matters discussed herein.
BECAUSE EACH INDIVIDUAL'S TAX SITUATION WILL BE DIFFERENT, EACH
PROSPECTIVE INVESTOR SHOULD CONSULT HIS OR HER OWN TAX ADVISOR
CONCERNING FEDERAL, STATE, AND LOCAL INCOME AND OTHER TAX LAWS THAT MAY
APPLY TO HIS OR HER PARTICIPATION. THE TAX ASPECTS DESCRIBED BELOW DO
NOT CONSTITUTE, AND SHOULD NOT BE CONSIDERED AS, LEGAL OR TAX ADVICE.
Summary of Certain Matters
Assuming the accuracy of certain factual matters identified below,
the Partnership will be classified, for federal income tax purposes, as
a partnership and not as a corporation and the income of the
Partnership will not be subject to federal income tax. Instead each
Limited Partner will include in computing his or her income tax his or
her distributive share of the items of income, gain, loss, deduction
(including an allowance for depletion with respect to income from the
Partnership's oil and gas properties), and credit of the Partnership.
Except as noted below, the distributive share for federal income tax
purposes of each Limited Partner will be determined as provided in the
Agreement. Moreover, distributions from the Partnership will not, in
general, be subject to income tax. It is expected the income of the
Partnership will be passive income which may be used to offset a
Limited Partner's losses from other passive activities.
Partnership Classification
The federal income tax consequences summarized herein depend on
the classification of the Partnership as a partnership and not as an
association taxable as a corporation for federal income tax purposes.
In Counsel's opinion, the Partnership will be treated as a partnership
for federal income tax purposes assuming the satisfaction at all times
of the following conditions:
(i) A duly executed Certificate of Limited Partnership
for the Partnership will be filed with the Oklahoma Secretary of
State in compliance with the Act and the organization and
operation of the Partnership will be in accordance with the
Agreement and the Act;
(ii) The General Partner will continue to serve as such
and is neither controlled by nor is it acting as agent for the
Limited Partners or any Persons affiliated with the Limited
Partners;
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<PAGE>
(iii) The General Partner has and will maintain
substantial assets which can be reached by a creditor of the
Partnership, exclusive of its interests in the Partnership and
notes and accounts receivable from and payable to the Partnership.
At the time of admission of Limited Partners to the Partnership,
the General Partner will have a net worth equal to at least 10% of
the total Capital Contributions made to the Partnership, excluding
any net worth attributable to any interest of the General Partner
in the Partnership. For purposes of satisfying this net worth
requirement, assets will be valued based upon their current fair
market value. The General Partner will use its best efforts to
ensure that the net worth of the General Partner continues to meet
these requirements throughout the term of the Partnership;
(iv) The General Partner will, in the aggregate, at all
times during the existence of the Partnership, receive at least 1%
of each material item of the Partnership's income, gain, loss,
deduction, or credit;
(v) In excess of 90% of the gross income of the
Partnership will be interest income, (excluding interest
identified in Section 7704(d)(2) of the Code) dividends, and gains
derived from the exploration, development, mining, or production,
processing, refining, transportation, or the marketing of minerals
or natural resources, or gain from the sale or disposition of
interests in oil and gas properties or other items described in
Section 7704(d) of the Code; and
(vi) There are no other documents or agreements which
alter, modify, or change in any way the validity and accuracy of
the above assumptions and information.
If the Partnership were classified as a corporation for federal income
tax purposes, then (a) the taxable income of the Partnership would be
subject to the corporate federal income tax, (b) the income, gains,
losses, deductions and credits of the Partnership (including deductions
for depletion with respect to income from oil and gas properties) would
not be taken into account by the Limited Partners in computing federal
income tax, and (c) distributions by the Partnership would be treated
as ordinary income (not subject to depletion) to the extent of the
current and accumulated earnings and profits of the Partnership. As a
result, the after-tax investment return of a Limited Partner by reason
of an investment in the Partnership would likely be significantly
reduced. The following discussion assumes that the Partnership will be
classified as a partnership and not as a corporation for federal income
tax purposes.
Taxation of Limited Partners
A Limited Partner must report for a taxable year his or her share
of the Partnership's items of income, gain, loss, deduction, and credit
for the Partnership's taxable year that ends during or with the Limited
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<PAGE>
Partner's taxable year, whether or not any cash is actually distributed
to the Limited Partner. Revenues from the Partnership's sale of oil
and gas production are taxable to Limited Partners as ordinary income
subject to depletion and other deductions discussed below.
Partnership Allocations. The allocations of items of income,
gain, loss, deduction, and credit of the Partnership are discussed
under "PARTICIPATION IN COSTS AND REVENUES" in this Memorandum.
Counsel is of the opinion that, except as discussed in the following
paragraph, the allocations provided in the Agreement will be respected
for federal income tax purposes because they have "substantial economic
effect," as that term is defined in Treasury Regulations Section 1.704-1(b)(the
"704(b) Regulations"), to the extent the allocations do not
result in any Limited Partner having a deficit in his or her capital
account (after taking into account the adjustments required by Section 1.704-
1(b)(2)(ii)(d) of the 704(b) Regulations). It is possible the
Service could adopt an interpretation of the 704(b) Regulations
different than that relied upon by Counsel.
Code Section 613A(c)(7)(D) requires the depletable basis of oil
and gas properties owned by a partnership be allocated to the partners
in accordance with their interest in the capital or income of the
partnership. The Partnership will allocate the basis in each
Partnership Property to the Partners in accordance with their interest
in the capital of the Partnership on December 31, 1996. Due to a lack
of authority relating to the allocation of basis in oil or gas
properties consistent with the policy underlying the applicable Code
Section, Counsel is unable to opine that the manner in which the
Partnership will allocate the basis of each Partnership Property (and
therefore any associated cost depletion deductions) to the Limited
Partners will comply with the relevant Code and Treasury Regulation
requirements. Notwithstanding this uncertainty, Counsel does not
believe that any reallocation of the basis of Partnership Properties in
response to a Service challenge of the proposed method of allocation
would differ significantly from the proposed method which is set out in
the Agreement.
Partnership Losses. Subject to the "passive loss" limitation
rules described under "Limitations on Losses and Credits from Passive
Activities" below and the limitations on miscellaneous itemized
deductions, each Limited Partner may deduct his or her share of the
Partnership's taxable loss, if any, on his or her own federal income
tax return only to the extent of the lesser of the Limited Partner's
tax basis in his or her Units at the end of the Partnership's fiscal
year in which the loss occurs or the amount that the Limited Partner is
"at risk" with respect to an activity of the Partnership. Partnership
losses which exceed the Limited Partner's tax basis or "at risk" amount
may be deducted in any subsequent year to the extent the Limited
Partner's tax basis and "at risk" amounts are increased above zero. A
Limited Partner's adjusted tax basis in the Partnership will initially
be equal to his or her Capital Contribution. This basis will be
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<PAGE>
increased by (i) the Limited Partner's additional cash contributions,
if any, (ii) the Limited Partner's distributive share of income and
gain, (iii) the Limited Partner's share of any nonrecourse borrowing of
the Partnership, and (iv) the excess of the Limited Partner's
deductions for depletion over the basis of the Limited Partner's share
of Partnership Properties subject to depletion. The basis will be
decreased (but not below zero) by (i) distributions to the Limited
Partner from the Partnership, (ii) the Limited Partner's distributive
share of the Partnership deductions and losses, (iii) the Limited
Partner's depletion deduction on the Limited Partner's share of
Partnership Revenues, (iv) and decreases in the Limited Partner's share
of nonrecourse borrowings of the Partnership, and (v) the Limited
Partner's share of nondeductible expenses of the Partnership which are
not properly chargeable to the Partnership capital accounts for federal
income tax purposes. A Limited Partner's aggregate "at risk" amount
for all Partnership activities will generally be equal to the amount he
or she pays for his or her Units plus, in certain cases, his or her
share of Partnership Revenues less prior deductions, losses, and cash
distributions.
Limitations on Losses and Credits from Passive Activities. Code
Section 469 imposes limits on the ability of individuals and certain
closely held corporations to use losses and credits from so-called
"passive activities" to offset taxable income and tax liability arising
from nonpassive sources. With the exception of that portion of
Partnership Revenues that is portfolio income, as defined below, and
any gain or loss from the disposition of a Partnership property that
the Treasury Regulations described below classify as not arising from a
passive activity, based on the anticipated activities of the
Partnership (and assuming the business of the Partnership is conducted
as described in this Memorandum), Counsel is of the opinion that the
Limited Partners' distributive shares of items of income, gain, loss,
deduction, and credit of the Partnership derived from the Partnership's
oil and gas operations (other than oil and gas production payments
owned by the Partnership) and the sale of oil and gas properties will
be treated as derived from a passive activity.
Generally, a taxpayer's deductions and credits from passive
activities may be used to reduce his or her tax liability in a given
taxable year only to the extent his or her liability arises from
passive activities. In determining the amount of income from passive
activities in any taxable year, a taxpayer must exclude "portfolio
income." Portfolio income includes interest, dividends, annuities or
royalties, unless such income is derived in the ordinary course of
certain types of trades or businesses, less (a) expenses (other than
interest) directly and clearly allocable to such income and (b)
interest expenses properly allocable to such income. For this purpose,
portfolio income also includes any gain or loss from the disposition of
property that produces portfolio income or that is held for investment,
as well as income derived from oil and gas production payments. Any
income, gain, or loss attributable to an investment of working capital
(such as unexpended Capital Contributions) will also be treated as
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<PAGE>
portfolio income. Prospective investors should note that the portfolio
income of the Partnership must be reported as taxable income of the
Partnership, without reduction for any of the expenses of the
Partnership (other than those described in clauses (a) and (b) of the
second sentence of this paragraph), and that each Limited Partner will
be required to pay federal income tax on his or her share of such
portfolio income, even if no corresponding distribution is made by the
Partnership to the Limited Partners. Based on representations of the
General Partner, Counsel believes that the activities of the
Partnership which involve the exploration, development and production
of oil and gas will constitute the conduct of a trade or business.
Consequently, the portfolio income of the Partnership will primarily
consist of interest, if any, earned on its invested cash reserves
pending their investment in oil and gas properties and/or drilling
activities. Prospective investors should be aware, however, that the
Department of Treasury has reserved the right to recharacterize other
types of income from passive activities as portfolio income.
To the extent a taxpayer's aggregate losses from all passive
activities exceed his or her aggregate income from all passive
activities in a given taxable year, the taxpayer has a "passive
activity loss" for the year. Similarly, a "passive activity credit"
arises in any year to the extent taxpayer's tax credits (with certain
limited exceptions) arising from all passive activities exceed his or
her tax liabilities allocable to all passive activities. A passive
loss or credit may be carried forward to successive taxable years until
fully utilized against income from passive activities in such years;
however, passive losses and credits may not be carried back to prior
years.
In addition, where a taxpayer disposes of his or her entire
interest in a passive activity in a transaction in which all of the
gain or loss realized on the disposition is recognized, any loss from
that activity that was suspended by the passive loss rules will cease
to be treated as a passive loss and any loss on the disposition will
not be treated as arising from a passive activity. Such losses will be
allowed as deductions against income in the following order: (i) gain
recognized on the disposition; (ii) net income or gain for the taxable
year from all passive activities; and (iii) any other income or gain.
Under Section 469(k) of the Code, the limitations on losses and
credits from passive activities will be applied separately to a
partnership which is considered "publicly traded" under Code Section
7704. For this purpose, a publicly traded partnership is one the
interests in which are (a) traded on an established securities market
or (b) readily tradeable on a secondary market (or the substantial
equivalent thereof). Under the Agreement, the Limited Partners are
prohibited from transferring their Units except under very limited
circumstances. Based on the representation of the General Partner that
it and the Partnership will adhere to the transferability restrictions
in the Agreement, Counsel is of the opinion that the Partnership will
not be considered publicly traded under Code Section 7704.
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<PAGE>
Intangible Drilling and Development Costs. The Partnership will
participate in the drilling of wells on the oil and gas properties in
which it acquires an interest. Currently, federal tax laws permit
immediate write-offs of certain intangible drilling and development
costs against a taxpayer's income. Assuming an appropriate election by
the Partnership under Section 263(c) of the Code, intangible drilling
and development costs may be deducted as an expense for income tax
purposes (subject to the limitations described above under "Partnership
Losses"). These costs include expenditures for services and materials
having no salvage value which are provided or utilized in preparing a
drill site and drilling, testing and completing a well.
Generally, a taxpayer may not deduct a greater portion of the
intangible drilling and development costs incurred with respect to a
particular well than the portion of the well owned by it when the costs
are incurred. In the event the Partnership acquires interests in
certain oil and gas properties with respect to which drilling
activities have already commenced prior to the Partnership's
investment, that portion of the Partnership's acquisition cost for such
properties which represents its share of the drilling costs previously
incurred will not be deductible by the Limited Partners as intangible
drilling and development costs. Instead such amounts will be
capitalized as part of the depletable basis of such properties. Also,
it is possible that because the General Partner's and the Limited
Partners' ultimate revenue interests in the Partnership will not be
finally determined until after December 31, 1996 (see "PARTICIPATION IN
COSTS AND REVENUES"), the Service may attempt to disallow deductions
claimed by the Limited Partners for all or a portion of the intangible
drilling and development costs specially allocated to them pursuant to
the Agreement. The law provides for a recapture of intangible drilling
and development costs, requiring the taxpayer to treat as ordinary
income any gain on the disposition of oil and gas properties (or any
interest in any oil and gas partnership) to the extent of intangible
drilling and development costs deducted with respect to such
properties.
In some cases, the agreements under which the Partnership acquires
an interest in a property may require the Partnership to pay a share of
the costs attributable thereto which is disproportionately greater than
the working interest acquired. In such cases, generally, the excess
portion of intangible drilling and development costs must be
capitalized as additional leasehold costs. However, full deductibility
is obtainable under certain arrangements and in certain circumstances.
The General Partner will seek to structure the agreements for the
acquisition of properties in a manner which will permit the deduction
of the full amount of the intangible drilling and development costs
paid but there can be no assurance that it will be able to do so or
that the arrangements will be recognized for federal income tax
purposes. Since all of the facts and terms of such arrangements are
not currently known, it is not practicable to predict the outcome of a
challenge to the full deductibility of such costs.
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Depletion. The Partnership will be the owner of economic
interests in its oil and gas properties (except for certain production
payments). The Limited Partners are entitled to a deduction for
depletion with respect to a Partnership's production and sale of oil
and gas from these properties. With respect to each oil and gas
property, a Limited Partner's deduction for each year is the greater of
cost depletion or percentage depletion. Percentage depletion with
respect to a property is equal to 15% of the gross income attributable
to the production from such property, subject to certain limitations.
Percentage depletion is allowable even if the taxpayer has no basis in
the property and continues to be allowable after the taxpayer has fully
depleted his or her basis in the property. Cost depletion allows the
leasehold cost of each producing Partnership Property to be recovered
over its productive life based on units of production. To determine
the per unit (i.e., barrels of oil or cubic feet of gas) allowance, the
adjusted tax basis for the property is divided by the estimated total
units recoverable therefrom. The cost depletion deduction is the per
unit allowance multiplied by the number of units sold during the year.
Depletion computed under this method cannot exceed the cost or other
basis of the producing property. In the case of the Partnership, the
cost or percentage depletion allowance is computed separately by the
Partners, and not by the Partnership.
Nominee Ownership of Partnership Properties. In the event the
Partnership Properties are not held in the name of the Partnership, it
is anticipated that all of the Partnership Properties will be held in
the record name of Unit Texas Company ("UNIT Nominee"), an affiliate of
UNIT and a wholly-owned subsidiary of Unit Petroleum Company. In
Counsel's opinion the Partnership will be treated, for federal income
tax purposes, as the owner of the Partnership Properties held by UNIT
Nominee for its benefit assuming the accuracy at the time of formation
of the Partnership, and the continuing accuracy thereafter, of the
following representations of the General Partner:
(i) A nominee/agent agreement ("Nominee Agreement") in
substantially the form of the Nominee Agreement attached as
Exhibit I to Counsel's opinion included as Exhibit B to this
Memorandum will be executed by and between UNIT Nominee, as agent,
and the Partnership before any interests in oil and gas properties
are acquired by UNIT Nominee as agent for the Partnership;
(ii) The terms and provisions of the Nominee Agreement
entered into as provided above will be adhered to by each party
thereto and, in particular, UNIT Nominee will be held out as the
agent and not the principal in all dealings with third parties
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relating to the oil and gas properties which UNIT Nominee holds as
agent for the Partnership; and
(iii) The beneficial ownership of any oil and gas
property interests to be assigned to the Partnership will be
assigned to the Partnership by delivery to UNIT Nominee, as agent
for the Partnership, of an enforceable written assignment, in
substantially the form of Exhibit II to Counsel's opinion included
as Exhibit B to this Memorandum, properly executed by the
assignor.
If the Service were to argue successfully that UNIT Nominee should be
treated as the tax owner of the Partnership's oil and gas properties,
there would be significant adverse federal income tax consequences to
the Limited Partners, such as the unavailability of depletion
deductions in respect of income from oil and gas properties.
Reimbursement of Expenses. The Agreement provides that the
General Partner shall be reimbursed by the Partnership, subject to
limitations based on a percentage of the Aggregate Subscription, for
that portion of its general and administrative overhead expenses
attributable to its conduct of the Partnership's business and affairs.
Such reimbursement will be charged to the accounts of the Partners in
the same proportions that Partnership Revenue is being shared at the
time such expenses are incurred and will be paid from Partnership
Revenue. Generally, the reimbursements paid to the General Partner
will be currently deductible to the extent they represent ordinary and
necessary business expenses incurred by the Partnership in the course
of its business for services rendered by the General Partner. As all
of the facts regarding the nature of the services to be rendered are
not known and may vary according to the circumstances presented, it is
not practical to predict whether all or a substantial portion of such
reimbursement will be deductible, if challenged, and there can be no
assurance that any such challenge would not ultimately be upheld.
Sales and Distributions. The Partnership's gain on a sale of an
interest in an oil and gas property will be measured by the difference
between the sale proceeds (including the amount of any indebtedness to
which the property is subject) and the adjusted basis of the property.
Consequently, the amount of tax payable by a Limited Partner on his or
her share of the Partnership's allocable share of such gain may in some
cases exceed his or her share of cash proceeds therefrom. Gain
realized by the Partnership (and, thus, the Limited Partners) on a sale
of an oil and gas property will be ordinary income to the extent of the
recapture of depreciation, depletion and intangible drilling and
development costs. In that regard, the Partnership's cost of acquiring
and improving equipment such as pipe, casing, tubing, storage tanks and
pumps will be capitalized and depreciated.
Cash distributions to a Limited Partner will not be taxable except
that amounts distributed in excess of the Limited Partner's tax basis
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will be taxable. Generally, any amounts distributed to a Limited
Partner in excess of his or her tax basis will be capital gain except
to the extent of ordinary income attributable to the Limited Partner's
share of recapture items (discussed in the preceding paragraph). When
a Limited Partner's share of Partnership nonrecourse debt is reduced
for any reason, the amount of the reduction is deemed to be a cash
distribution. Like an actual cash distribution, the deemed
distribution reduces a Limited Partner's adjusted tax basis of his or
her Units.
Generally, a Limited Partner will realize a gain or loss on the
disposition of his or her Units measured by the difference between the
amount realized on the disposition and the Limited Partner's adjusted
basis for such Units. Since a Limited Partner's share of Partnership
nonrecourse indebtedness must be included in the amount realized upon
the disposition of the Units, any gain realized on the disposition may
result in a tax liability greater than the cash proceeds, if any, from
the disposition.
The Code requires each person who transfers an interest in a
limited partnership possessing "unrealized receivables" or
"substantially appreciated inventory items" to report the transfer to
the limited partnership. It is expected that the Partnership will be
deemed to possess these items. A transferring Limited Partner will be
required to report to the General Partner the name, address, and
taxpayer identification number of the person acquiring Units and the
date on which the Units are transferred. This report to the General
Partner must be submitted at the time of sale, or no later than seven
days after receipt by the transferor of the purchaser's taxpayer
identification number. When the General Partner is notified of any
transfers of Units, the identity of the transferor and transferee will
be provided to the Service together with any other information required
by Treasury Regulations. Failure by a Limited Partner to report a
transfer covered by this provision may result in a penalty of $50 per
occurrence.
The Code permits a partnership to elect, pursuant to Sections 734,
743, and 754, to adjust a partner's share of the tax basis of
partnership property following redemption of an interest, death of a
partner, or a purchase of a partnership interest by such partner.
Because of the tax accounting complexities inherent in, and the
substantial expense incident to, making such an election to adjust the
tax basis, the General Partner does not presently intend to make such
elections on behalf of the Partnership, although it is empowered to do
so by the Agreement. The absence of any such election may, in some
circumstances, result in a reduction in the value of Units to any
potential purchaser. Once a Section 754 election is made on behalf of
the Partnership, the tax basis of its property must be adjusted upon
all future transfers of interests in the Partnership to any transferee.
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IRS Tax Shelter Registration
Section 6111 of the Code requires an organizer of a "tax shelter"
to register the tax shelter with the Secretary of the Treasury and to
obtain an identification number which must be included on the tax
returns of investors in that tax shelter. Under Temporary Treasury
Regulations interpreting Section 6111, the Partnership would constitute
a "tax shelter" required to register. While not necessarily agreeing
with the expansive interpretation of the registration requirements in
the Temporary Treasury Regulations, the General Partner will take all
necessary steps to comply with the registration requirements because
there are onerous penalties for failing to register as a "tax shelter."
After the General Partner has caused the Partnership to be
registered in compliance with the requirements, the Service will assign
a registration number to the Partnership. The General Partner will
furnish this registration number to the Limited Partners. ISSUANCE OF
A REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN THE
PARTNERSHIP OR THE CLAIMED TAX BENEFITS THEREFROM HAVE BEEN REVIEWED,
EXAMINED OR APPROVED BY THE INTERNAL REVENUE SERVICE. Each Partner
must (i) report the Partnership's registration number on Treasury Form
8271 and attach this form to his or her federal income tax return for
each taxable year in which he or she is a Partner, and (ii) furnish the
Partnership's registration number to each person to whom he or she
transfers Units.
Partnership Tax Returns and Tax Information
Information returns filed by the Partnership are subject to audit
by the Service. Prospective investors should note that a federal
income tax audit of the Partnership's tax information returns may
result in an audit of the returns of the Limited Partners, and that an
examination could result in adjustments both to items related to the
Partnership and to unrelated items.
Interest paid by individuals in respect of an underpayment of tax
is nondeductible. The interest rate for an underpayment of tax is set
quarterly at the federal short-term rate plus 3 percentage points. The
underpayment rate which commenced October 1, 1995 is 9%, compounded
daily.
The tax treatment of Partnership items will be determined at the
Partnership level, rather than in separate proceedings with the
Partners. Thus, the availability and amount of the tax deductions
taken by the Limited Partners will depend not only on the general legal
principles discussed herein, but also upon various determinations of
the General Partner. These determinations are subject to challenge by
the Service on factual or other grounds. Generally, each Partner is
required to treat Partnership items on his or her return consistently
with the treatment on the Partnership return. Where this treatment is
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inconsistent, a statement must be filed by the Partner identifying the
inconsistency. If the consistency requirement is not satisfied and the
identifying statement is not filed, the Service may assess a deficiency
against the Partner before audit proceedings are completed at the
Partnership level. Additionally, if a taxpayer fails to show properly
on a return any amount that is shown on an information return, the
taxpayer's failure may be treated as negligence and subject to a
penalty equal to 20% of the underpayment of tax attributable to the
negligence.
The General Partner is to be designated pursuant to Treasury
Regulations as the tax matters partner ("TMP"). The TMP is responsible
for protecting the interests of the Partners in the audit process. In
the Agreement, the General Partner is designated as the TMP and, as
such, is given the right, on behalf of the Partnership, to determine
whether to challenge a final Partnership administrative adjustment
proposed by the Service. If the TMP determines not to challenge an
administrative adjustment, any Partner with at least a 1% interest in
the Partnership and any requesting group of Partners that together have
at least a 5% interest in the Partnership may challenge it.
Generally, the period for assessment with respect to Partnership
items for any Partnership taxable year will not expire before three
years from (a) the date of filing the Partnership return or, if later,
(b) the last date prescribed for filing such return determined without
extensions. The period may be extended for all Partners by agreement
with the TMP (or other person authorized in writing by the
Partnership).
The procedures regarding the audit of partnerships and the
authority of the TMP are complex and cannot be described completely
herein. Each prospective investor is urged to seek the advise of his
or her individual tax advisor with respect to those audit provisions.
Laws Subject to Change
The tax aspects described above are based upon interpretations of
the Code as it has been amended to the date of this Memorandum and as
Counsel understand it. Federal income tax laws and regulations and
interpretations thereof are subject to change by Congress, and the
courts and administrative agencies. Regulations have not been issued
or proposed under most of the provisions of recent legislation. For
these reasons, no assurance can be given that the foregoing
interpretations will not be challenged or if challenged, will be
sustained or that the favorable tax aspects described above will be
available in future years.
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State and Local Taxes
In addition to the federal income tax aspects described above,
prospective investors should consider with their advisors the state tax
consequences of an investment in Units.
COMPETITION, MARKETS AND REGULATION
The oil and gas industry is highly competitive in all its phases.
The Partnership will encounter strong competition from both major
independent oil companies and individuals, many of which possess
substantial financial resources, in acquiring economically desirable
prospects and equipment and labor to operate and maintain Partnership
Properties. There are likewise numerous companies and individuals
engaged in the organization and conduct of oil and gas drilling pro-
grams and there is a high degree of competition among such companies
and individuals in the offering of their programs.
Marketing of Production
The availability of a ready market for any oil and gas produced
from Partnership Wells will depend upon numerous factors beyond the
control of the Partnership, including the extent of domestic production
and importation of oil and gas, the proximity of Partnership Wells to
gas pipelines and the capacity of such gas pipelines, the marketing of
other competitive fuels, fluctuation in demand, governmental regulation
of production, refining and transportation, general national and
worldwide economic conditions, and the pricing, use and allocation of
oil and gas and their substitute fuels.
The demand for gas decreased significantly in the 1980s due to
economic conditions, conservation and other factors. As a result of
such reduced demand and other factors, including the Power Plant and
Industrial Fuel Use Act (the "Fuel Use Act") which related to the use
of oil and gas in the United States in certain fuel burning
installations, many pipeline companies began purchasing gas on terms
which were not as favorable to sellers as terms governing purchases of
gas prior thereto. Spot market gas prices declined generally during
that period. While the Fuel Use Act has been repealed and the General
Partner expects that the markets for gas will improve, there can be no
assurance that such improvement will occur. As a result, it is
possible that there may be significant delays in selling any gas from
Partnership Properties. In addition, production of gas, if any, from
Partnership Wells may be dedicated to long-term gas purchase contracts
with gas purchasers. In such event, the price received upon the sale
of such gas might be higher or lower than if such gas had not been so
dedicated.
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In the event the Partnership acquires an interest in a gas well or
completes a productive gas well, or a well that produces both oil and
gas, the well may be shut in for a substantial period of time for lack
of a market if the well is in an area distant from existing gas
pipelines. The well may remain shut in until such time as a gas
pipeline, with available capacity, is extended to such an area or until
such time as sufficient wells are drilled to establish adequate
reserves which would justify the construction of a gas pipeline,
processing facilities, if necessary, and a transmission system.
The worldwide supply of oil has been largely dependent upon rates
of production of foreign reserves. Although in recent years the demand
for oil has slightly increased in this country, imports of foreign oil
continue to increase. Consequently, the prices for domestic oil
production have remained low. Future domestic oil prices will depend
largely upon the actions of foreign producers with respect to rates of
production and it is virtually impossible to predict what actions those
producers will take in the future. Prices may also be affected by
political and other factors relating to the Middle East. As a result,
it is possible that prices for oil, if any, produced from a Partnership
Well will be lower than those currently available or projected at the
time the interest therein is acquired. In view of the many
uncertainties affecting the supply and demand for crude oil and natural
gas, and the change in the makeup of the Congress of the United States
and the resulting potential for a different focus for the United States
energy policy, the General Partner is unable to predict what future gas
and oil prices will be.
Regulation of Partnership Operations
Production of any oil and gas found by the Partnership will be
affected by state and federal regulations. All states in which the
Partnership intends to conduct activities have statutory provisions
regulating the production and sale of oil and gas. Such statutes, and
the regulations promulgated in connection therewith, generally are
intended to prevent waste of oil and gas and to protect correlative
rights and the opportunities to produce oil and gas as between owners
of a common reservoir. Certain state regulatory authorities also
regulate the amount of oil and gas produced by assigning allowable
rates of production to each well or proration unit. Pertinent state
and federal statutes and regulations also extend to the prevention and
clean-up of pollution. These laws and regulations are subject to
change and no predictions can be made as to what changes may be made or
the effect of such changes on the Partnership's operations.
Under the laws and administrative regulations of the State of
Oklahoma regarding forced pooling, owners of oil and gas leases or
unleased mineral interests may be required to elect to participate in
the drilling of a well with other fractional undivided interest owners
within an established spacing unit or to sell or farm out their inter-
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est therein. The terms of any such sale or farm-out are generally
those determined by the Oklahoma Corporation Commission to be equal to
the most favorable terms then available in the area in arm's length
transactions although there can be no assurance that this will be the
case. In addition, if properties become the subject of a forced
pooling order, drilling operations may have to be undertaken at a time
or with other parties which the General Partner feels may not be in the
best interest of the Partnership. In such event, the Partnership may
have to farm out or assign its interest in such properties. In addi-
tion, if a property which might otherwise be acquired by the Partner-
ship becomes subject to such an order, it may become unavailable to the
Partnership. Finally, as a result of forced pooling proceedings
involving a Partnership Property, the Partnership may acquire a larger
than anticipated interest in such property, thereby increasing its
share of the costs of operations to be conducted.
Natural Gas Price Regulation
Partnership Revenues are likely to be dependent on the sale and
transportation of natural gas that may be subject to regulation by the
Federal Energy Regulatory Commission ("FERC"). Historically the sale
of natural gas has been regulated by the FERC under the Natural Gas Act
of 1938 ("NGA") and/or the Natural Gas Policy Act of 1978 ("NGPA").
Under the NGPA, natural gas is divided into numerous, complex
categories based on, among other things, when, where and how deep the
gas well was drilled and whether the gas was committed to interstate or
intrastate commerce on the day before the date of enactment of the
statute. These categories determine whether the natural gas remains
subject to non-price regulation under the NGA and/or to maximum price
restrictions under the NGPA. In addition to setting ceiling prices for
natural gas, FERC approval is required for both the commencement and
abandonment of sales of certain categories of gas in interstate
commerce for resale and for the transportation of natural gas in
interstate commerce. FERC has general investigatory and other powers,
including limited authority to set aside or modify terms of gas
purchase contracts subject to its jurisdiction. Price and non-price
regulation of natural gas produced from most wells drilled after 1978
has terminated. That gas may be sold without prior regulatory approval
and at whatever price the market will bear.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989
(the "Wellhead Decontrol Act") became effective. Consequently, due to
this statutory deregulation and FERC's issuance of Order No. 547
discussed below, as of January 7, 1993 the price of virtually all gas
produced by producers not affiliated with interstate pipelines has been
deregulated by FERC.
Market determined prices for deregulated categories of natural gas
fluctuate in response to market pressures which currently favor
purchasers and disfavor producers. As a result of the deregulation of
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a greater proportion of the domestic United States gas market and an
increased availability of natural gas transportation, a competitive
trading market for gas has developed. For several reasons the supply
of gas has exceeded demand. The General Partner cannot reliably
predict at this time whether such supply/demand imbalance will improve
or worsen from a producer's viewpoint.
During the past several years, FERC has adopted several
regulations designed to create a more competitive, less regulated
market for natural gas. These regulations have materially affected the
market for natural gas.
FERC's initial major initiative was adoption of its "open-access
transportation program," through Order No.s 436 and 500. Regulation of
Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436,
50 Fed. Reg. 42,408 (October 18, 1985), vacated and remanded,
Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir. 1987),
cert. denied, 485 U.S. 1006 (1988), readopted on an interim basis,
Order No. 500, 52 Fed. Reg. 30,344 (Aug. 14, 1987), remanded, American
Gas Association v. FERC, 888 F.2d 136 (D.C. Cir. 1989), readopted,
Order No. 500-H, 54 Fed. Reg. 52,344 (Dec. 21, 1989), reh'g granted in
part and denied in part, Order No. 500-I, 55 Red. Reg. 6605 (Feb. 26,
1990), aff'd in part and remanded in part, American Gas Association v.
FERC, 912 F.2d 1496 (D.C. Cir. 1990), cert. denied, 111 S. Ct. 957
(1991). Order 436 implemented three key requirements: (1)
jurisdictional pipelines were required to permit their firm sales
customers to convert their firm sales entitlements to a volumetrically
equivalent amount of firm transportation service over a five-year
period; (2) jurisdictional pipelines were required to offer their open-access
transportation services without discrimination or preference;
and (3) jurisdictional pipelines were required to design maximum rates
to ration capacity during peak periods and to maximize throughput for
firm service during off-peak periods and for interruptible service
during all periods. The availability of transportation under Order 500
greatly expanded the free trading market for natural gas, including the
establishment of an active and viable spot market.
Subsequently, in Order 636 the FERC focused on whether the
resulting regulatory structure provided all gas sellers with the same
regulatory opportunity to compete for gas purchasers. It decided that
the form of bundled pipeline services (gas sales and transportation)
was unduly discriminatory and anticompetitive. The FERC concluded that
"the pipelines' bundled, city-gate firm sales service gives pipelines
an undue advantage over other gas sellers because of the superior
quality of the 'no-notice' aspect of the transportation embedded within
the bundled, city-gate, firm sales service compared to the firm and
interruptible transportation available for the gas of nonpipeline gas
sellers." Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation; and Regulation of Natural
Gas Pipelines After Wellhead Decontrol, Order No. 636, 57 Fed. Reg.
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13,267 (Apr. 16, 1992), III FERC Stats. & Regs. Preambles Paragraph
30,939, at 30,406. Order 636 was clarified in August 1992 and
finalized in November 1992. Regulations of Natural Gas Pipelines After
Partial Wellhead Decontrol, and Order Denying Rehearing in Part,
Granting Rehearing in Part, and Clarifying Order No. 636, Order No.
636-A, 57 Fed. Reg. 36,128 (Aug. 12, 1992), III FERC Stats. & Regs.
Preambles Paragraph 30,950; Regulation of Natural Gas Pipelines After
Partial Wellhead Decontrol; Order Denying Rehearing and Clarifying
Order Nos. 636 and 636-A, Order No. 636-B, 57 Fed. Reg. 57,911 (Dec. 8,
1992).
Order 636, a complex regulation, is expected to have a major
impact on gas pipeline operations, services and rates. Among other
things, Order 636 requires each interstate pipeline company to
"unbundle" its traditional wholesale services and create and make
available on an open and nondiscriminatory basis numerous constituent
services (such as gathering services, storage services, firm and
interruptible transportation services, and stand-by sales services) and
to adopt a new rate making methodology (Straight Fixed Variable) to
determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate makes gas sales as a merchant
in the future, it will do so in direct competition with all other
sellers pursuant to private contracts; however, pipeline companies have
or will become "transporters only." Order 636 also allows pipeline
companies to act as agents for their customers in arranging the
transportation of gas purchased from any supplier, including the
pipeline itself, and to charge a negotiated fee for such agency
services. The FERC required each pipeline company to develop the
specific terms of service in individual proceedings and to submit for
approval by FERC a compliance filing which set forth the pipeline
company's new, detailed procedures. The new rules are subject to
pending court challenges by numerous parties. In addition, many of the
individual pipeline restructurings are the subject of pending appeals,
either before the FERC or in the courts.
On November 8, 1992, FERC published Order 636-B. Regulation of
Natural Gas Pipelines After Partial Wellhead Decontrol; Order Denying
Rehearing and Clarifying Order Nos. 636 and 636-A, Order No. 636-B, 57
Fed. Reg. 57,911 (Dec. 8, 1992). Order 636-B essentially upholds
without significant change Order Nos. 636 and 636-A. FERC also stated
that it will accept no further petitions for rehearing. Thus, Order
636 constitutes final agency action.
In essence, the goal of Order 636 is to make a pipeline's position
as gas merchant indistinguishable from that of a non-pipeline supplier.
It, therefore, pushes the point of sale of gas by pipelines upstream,
perhaps all the way to the wellhead. Order 636 also requires pipelines
to give firm transportation customers flexibility with respect to
receipt and delivery points (except that a firm shipper's choice of
delivery point cannot be downstream of the existing primary delivery
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point) and to allow "no-notice" service (which means that gas is
available not only simultaneously but also without prior nomination,
with the only limitation being the customer's daily contract demand) if
the pipeline offered no-notice city-gate sales service on May 18, 1992.
Thus, this separation of pipelines' sales and transportation allows
non-pipeline sellers to acquire firm downstream transportation rights
and thus to offer buyers what is effectively a bundled city-gate sales
service and it permits each customer to assemble a package of services
that serves its individual requirements. But it also makes more
difficult the coordination of gas supply and transportation.
The results of these changes could increase the marketability of
natural gas and place the burden of obtaining supplies of natural gas
for local distribution systems directly on distributors who would no
longer be able to rely on the aggregation of supplies by the interstate
pipelines. Such distributors may return to longer term contracts with
suppliers who can assure a secure supply of natural gas. A return to
longer term contracts and the attendant decrease in gas available for
the spot market could improve gas prices. The primary beneficiaries of
these changes should be gas marketers and the producers who are able to
demonstrate the availability of an assured long-term supply of natural
gas to local distribution purchasers and to large end users. However,
due to the still evolutionary nature of Order 636 and its
implementation, it is not possible at this time to project the impact
Order 636 will have on the Partnership's ability to sell gas directly
into gas markets previously served by the gas pipelines.
As a corollary to Order 636, FERC issued Order 547, which is a
blanket certificate of public convenience and necessity pursuant to
Section 7 of the NGA that authorizes any person who is not an
interstate pipeline or an affiliate thereof to make sales for resale at
negotiated rates in interstate commerce of any category of gas that is
subject to the Commission's NGA jurisdiction. (There are certain
requirements which must be met before an affiliated marketer of an
interstate pipeline can avail itself of this certification.)
Regulations Governing Blanket Marketer Sales Certificates, Order No.
547, 57 Fed. Reg. 57,952 (Dec. 8, 1992) (to be codified at 18 C.F.R.
Sections 284.401 - .402). The blanket certificates are effective
January 7, 1993, and do not require any further application by a
person. The goal of Order 457, in conjunction with Orders 636, 636-A
and 636-B, is to provide all merchants of natural gas a "level playing
field" so that gas merchants who are not interstate pipelines are on an
equal footing with interstate pipeline merchants who are afforded
blanket sales certificates pursuant to Order 636.
The FERC is also modifying its traditional use of cost-of-service
rate regulation in order to prevent pipelines from exercising market
power. However, the FERC has begun to allow individual companies to
depart from cost-of-service regulation and set market-based rates if
they can show they lack significant market power or have mitigated
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market power. See, e.g., Richmond Gas Storage Systems, 59 FERC
Paragraph 61,316 (1992); El Paso Natural Gas Company, 54 FERC Paragraph
61,316, reh'g granted and denied in part, 56 FERC Paragraph 61,290
(1990); Transcontinental Gas Pipe Line Corp., 53 FERC Paragraph 61,446,
reh'g granted and denied in part, 57 FERC Paragraph 61,345 (1991).
Since the FERC has stated that "[w]here companies have market power, market-
based rates are not appropriate," in order to "enhance
productive efficiency in non-competitive markets," the FERC recently
issued a rule allowing pipelines (and electric utilities) "to propose
incentive rate mechanisms as alternatives to traditional cost-of-service
regulations." Incentive Ratemaking for Interstate Natural Gas
Pipelines, Oil Pipelines, and Electric Utilities; Policy Statement on
Incentive Regulation, 57 Fed. Reg. 55,231 (Nov. 24, 1992). The FERC
has established five specific regulatory standards for implementing
specific incentive mechanisms: they should (1) be prospective, (2) be
voluntary, (3) be understandable, (4) result in quantifiable benefits
to consumers including an upper limit on the risk to consumers that the
incentive rates would be higher than rates they would have paid under
traditional regulation, and (5) demonstrate how they maintain or
enhance incentives to improve the quality of service.
Other regulatory actions have included elimination of minimum take
and minimum bill provisions of pipeline sales tariffs (Order 380) and
authorization of automatic abandonment authority upon expiration or
termination of the underlying contracts (Order 490). The latter order
is currently before the United States Court of Appeals for the Sixth
Circuit. FERC has also provided several forms of "blanket"
certificates authorizing sales of gas with pregranted abandonment.
In addition, in Order 451, FERC established an alternative maximum
lawful price for certain NGPA Section 104 and 106 gas produced from
wells drilled prior to 1975 (so-called "old gas") which otherwise would
be subject to lower ceiling prices. FERC provided, however, that the
higher price could be collected only where the parties amended the
contract or pursuant to complicated "good faith negotiation" rules
which permit purchasers facing requests for increased prices to seek
reduction of certain higher prices and authorize abandonment of both
the higher cost and lower cost supplies if agreement cannot be reached.
After the Fifth Circuit vacated Order 451 as an invalid exercise of
FERC's authority, the United States Supreme Court reversed that
decision and upheld the entirety of Order 451.
The issuance of Order 636 and its future interpretation, as well
as the future interpretation and application by FERC of all of the
above rules and its broad authority, or of the state and local
regulations by the relevant agencies, could affect the terms and
availability of transportation services for transportation of natural
gas to customers and the prices at which gas can be sold on behalf of
the Partnership. For instance, as a result of Order 636, more
interstate pipeline companies have begun divesting their gathering
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systems, either to unregulated affiliates or to third persons, a
practice which could result in separate, and higher, rates for
gathering a producer's natural gas. In proceedings during mid and late
1994 allowing various interstate natural gas companies' spindowns or
spinoffs of gathering facilities, the FERC held that, except in limited
circumstances of abuse, it generally lacks jurisdiction over a
pipeline's gathering affiliates, which neither transport natural gas in
interstate commerce nor sell gas in interstate commerce for resale.
However, pipelines spinning down gathering systems have to include two
Order No. 497 standards of conduct in their tariffs: nondiscriminatory
access to transportation for all sources of supply and no tying of
pipeline transportation service to any service by the pipeline's
gathering affiliate. In addition, if unable to reach a mutually
acceptable gathering contract with a present user of the gathering
facilities, the pipeline must offer a two-year "default contract" to
existing users of the gathering facilities. Consequently, the General
Partner cannot reliably predict at this time how regulation will
ultimately impact Partnership Revenue.
State Regulation of Oil and Gas Production
Most states in which the Partnership may conduct oil and gas
activities regulate the production and sale of oil and natural gas.
Those states generally impose requirements or restrictions for
obtaining drilling permits, the method of developing new fields, the
spacing and operation of wells and the prevention of waste of oil and
gas resources. In addition, most states regulate the rate of
production and may establish maximum daily production allowable from
both oil and gas wells on a market demand or conservation basis. Until
recently there has been no limit on allowable daily production on the
basis of market demand, although at some locations production continues
to be regulated for conservation or market purposes. In 1987 the
Oklahoma Corporation Commission (the "OCC") promulgated production
allowable reductions with respect to relatively high capability gas
wells (i.e., those capable of open flowing more than 2,000,000 cubic
feet per day) and the law enacted by the Oklahoma legislature during
March 1992 gives the OCC power to set statewide (versus only field-by-field)
production limits for all natural gas wells producing in the
State to prevent waste and to protect the interests of the public
against production of natural gas reserves in amounts in excess of the
reasonable market demand therefor. The General Partner cannot predict
whether the OCC, or any other state regulatory agency, may issue
additional allowable reductions which may adversely affect the
Partnership's ability to produce its gas reserves.
Legislative and Regulatory Production and Pricing Proposals
A number of legislative and regulatory proposals continually are
advanced which, if put into effect, could have an impact on the
petroleum industry. The various proposals involve, among other things,
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an oil import fee, restructuring how oil pipeline rates are determined
and implemented, providing purchasers with "market-out" options in
existing and future gas purchase contracts, eliminating or limiting the
operation of take-or-pay clauses and eliminating or limiting the
operation of "indefinite price escalator clauses" (e.g., pricing
provisions which allow prices to escalate by means of reference to
prices being paid by other purchasers of natural gas or prices for
competing fuels). Proposals concerning these and other matters have
been and will be made by members of the President's office, Congress,
regulatory agencies and special interest groups. The General Partner
cannot predict what legislation or regulatory changes, if any, may
result from such proposals or any effect therefrom on the Partnership.
Several states have either proposed or enacted regulations that
could significantly revise current systems of regulating gas
production. On April 27, 1992, the Texas Railroad Commission ("TRC")
unanimously approved a new proration system that limits gas production
so that it more closely tracks market demand. These rules eliminate
monthly purchaser nominations as the starting point for determining
reservoir market demand and instead the TRC makes an initial
determination of reservoir market demand for prorated fields each month
using production in the same month from the previous year and the
operator's forecast for demand for that month. This initial
determination is subject to four adjustments: (1) capability adjustment
(downward revisions to the extent necessary to reflect the capability
of wells); (2) reservoir forecast correction adjustment (a correction
factor that tracts discrepancies between reservoir production and the
adjusted reservoir forecast during the most recently reported
production month); (3) supplemental change adjustment (adjustment to
account for new wells and changes in well capability or well test
status including upward revisions of allowables to cover overproduction
from a non-prorated well); and (4) commission adjustment by reservoir
(any other adjustments that the TRC determines are necessary to fix the
reservoir allowable equal to the lawful market demand, including the
correction of any inaccuracies in the initial market demand
determination). Individual well allowable determinations are
determined by an enhanced capability determination routine. A well
capacity is determined as the lesser of the latest TRC well
deliverability test on file or the highest monthly production during
the last six months. Alternatively, an operator may submit a
substitute capability determination that has been determined by a
registered professional engineer.
During March 1992, the Oklahoma legislature enacted a law which
places statewide limits on gas production, as well as a new mechanism
for capping gas output, during times of slow demand. This law limits
Oklahoma's largest gas wells during summertime production (March
through October) to no more than the greater of 750,000 cubic feet per
day or 25% of their total capacity and, during the high-demand winter
heating season (November through February), those wells will be
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restricted to no more than the greater of 1,000,000 cubic feet per day
or 40% of their total capacity, unless and until the OCC promulgates
other production limitations. Other states, including Louisiana, New
Mexico and Wyoming, are also reported to be contemplating whether to
institute new rules governing gas production in those States.
The effect of these regulations could be to decrease allowable
production on Partnership Properties and thereby to decrease
Partnership Revenues. However, by decreasing the amount of natural gas
available in the market, such regulations could also have the effect of
increasing prices of natural gas, although there can be no assurance
that any such increase will occur. There can also be no assurance that
the proposed regulations described above will be adopted or that they
will be adopted upon the terms set forth above. Additionally, such
proposals, if adopted, are likely to be challenged in the courts and
there can be no assurance as to the outcome of any such challenge.
Production and Environmental Regulation
Certain states in which the Partnership may drill and own produc-
tive properties control production from wells through regulations
establishing the spacing of wells, limiting the number of days in a
given month during which a well can produce and otherwise limiting the
rate of allowable production.
In addition, the federal government and various state governments
have adopted laws and regulations regarding protection of the
environment. These laws and regulations may require the acquisition of
a permit before or after drilling commences, impose requirements that
increase the cost of operations, prohibit drilling activities on
certain lands lying within wilderness areas or other environmentally
sensitive areas and impose substantial liabilities for pollution
resulting from drilling operations, particularly operations in offshore
waters or on submerged lands.
A past, present, or future release or threatened release of a
hazardous substance into the air, water, or ground by the Partnership
or as a result of disposal practices may subject the Partnership to
liability under the Comprehensive Environmental Response, Compensation
and Liability Act, as amended ("CERCLA"), the Resource Conservation
Recovery Act ("RCRA"), the Clean Water Act, and/or similar state laws,
and any regulations promulgated pursuant thereto. Under CERCLA and
similar laws, the Partnership may be fully liable for the cleanup costs
of a release of hazardous substances even though it contributed to only
part of the release. While liability under CERCLA and similar laws may
be limited under certain circumstances, typically the limits are so
high that the maximum liability would likely have a significant adverse
effect on the Partnership. In certain circumstances, the Partnership
may have liability for releases of hazardous substances by previous
owners of Partnership Properties. Additionally, the discharge or
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substantial threat of a discharge of oil by the Partnership into United
States waters or onto an adjoining shoreline may subject the
Partnership to liability under the Oil Pollution Act of 1990 and
similar state laws. While liability under the Oil Pollution Act of
1990 is limited under certain circumstances, the maximum liability
under those limits would still likely have a significant adverse effect
on the Partnership. The Partnership's operations generally will be
covered by the insurance carried by the General Partner or UNIT, if
any. However, there can be no assurance that such insurance coverage
will always be in force or that, if in force, it will adequately cover
any losses or liability the Partnership may incur.
Violation of environmental legislation and regulations may result
in the imposition of fines or civil or criminal penalties and, in
certain circumstances, the entry of an order for the removal,
remediation and abatement of the conditions, or suspension of the
activities, giving rise to the violation. The General Partner believes
that the Partnership will comply with all orders and regulations
applicable to its operations. However, in view of the many uncertain-
ties with respect to the current controls, including their duration and
possible modification, the General Partner cannot predict the overall
effect of such controls on such operations. Similarly, the General
Partner cannot predict what future environmental laws may be enacted or
regulations may be promulgated and what, if any, impact they would have
on operations or Partnership Revenue.
SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT
The business and affairs of the Partnership and the respective
rights and obligations of the Partners will be governed by the Agree-
ment. The following is a summary of certain pertinent provisions of
the Agreement which have not been as fully discussed elsewhere in this
Memorandum but does not purport to be a complete description of all
relevant terms and provisions of the Agreement and is qualified in its
entirety by express reference to the Agreement. Each prospective
subscriber should carefully review the entire Agreement.
Partnership Distributions
The General Partner will make quarterly determinations of the
Partnership's cash position. If it determines that excess cash is
available for distribution, it will be distributed to the Partners in
the same proportions that Partnership Revenue has been allocated to
them after giving effect to previous distributions and to portions of
such revenues theretofore used or expected to be thereafter used to pay
costs incurred in conducting Partnership operations or to repay Part-
nership borrowings. It is expected that no cash distributions will be
made earlier than the first quarter of 1997. Distributions of cash
determined by the General Partner to be available therefor will be made
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to the Limited Partners quarterly and to the General Partner at any
time. All Partnership funds distributed to the Limited Partners shall
be distributed to the persons who were record holders of Units on the
day on which the distribution is made. Thus, regardless of when an
assignment of Units is made, any distribution with respect to the Units
which are assigned will be made entirely to the assignee without regard
to the period of time prior to the date of such assignment that the
assignee holds the Units.
The Partnership will terminate automatically on December 31, 2026
unless prior thereto the General Partner or Limited Partners holding a
majority of the outstanding Units elect to terminate the Partnership as
of an earlier date. Upon termination of the Partnership, the debts,
liabilities and obligations of the Partnership will be paid and the
Partnership's oil and gas properties and any tangible equipment,
materials or other personal property may be sold for cash. The cash
received will be used to make certain adjusting payments to the
Partners (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
Termination"). Any remaining cash and properties will then be
distributed to the Partners in proportion to and to the extent of any
remaining balances in the Partners' capital accounts and then in
undivided percentage interests to the Partners in the same proportions
that Partnership Revenues are being shared at the time of such
termination (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
Termination").
Deposit and Use of Funds
Until required in the conduct of the Partnership's business,
Partnership funds, including, but not limited to, the Capital Contribu-
tions, Partnership Revenue and proceeds of borrowings by the Partner-
ship, will be deposited, with or without interest, in one or more bank
accounts of the Partnership in a bank or banks to be selected by the
General Partner or invested in short-term United States government
securities, money market funds, bank certificates of deposit or commer-
cial paper rated as "A1" or "P1" as the General Partner, in its sole
discretion, deems advisable. Any interest or other income generated by
such deposits or investments will be for the Partnership's account.
Except for Capital Contributions, Partnership funds from any of the
various sources mentioned above may be commingled with funds of the
General Partner and may be used, expended and distributed as authorized
by the terms and provisions of the Agreement. The General Partner will
be entitled to prompt reimbursement of expenses it incurs on behalf of
the Partnership.
Power and Authority
In managing the business and affairs of the Partnership, the
General Partner is authorized to take such action as it considers
appropriate and in the best interests of the Partnership (see Section
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10.1 of the Agreement). The General Partner is authorized to engage
legal counsel and otherwise to act with respect to Service audits,
assessments and administrative and judicial proceedings as it deems in
the best interests of the Partnership and pursuant to the provisions of
the Code.
The General Partner is granted a broad power of attorney authoriz-
ing it to execute certain documents required in connection with the
organization, qualification, continuance, modification and termination
of the Partnership on behalf of the Limited Partners (see Sections 1.5
and 1.6 of the Agreement). Certain actions, such as an assignment for
the benefit of its creditors or a sale of substantially all of the
Partnership Properties, except in connection with the termination,
roll-up or consolidation of the Partnership, cannot be taken by the
General Partner without the consent of a majority in interest of the
Limited Partners and the receipt of an opinion of counsel as described
under "Assignments by the General Partner" below (see Sections 10.15
and 12.1 of the Agreement).
The Agreement provides that the General Partner will either
conduct the Partnership's drilling and production operations and
operate each Partnership Well or arrange for a third party operator to
conduct such operations. The General Partner will, on behalf of the
Partnership, enter into an appropriate operating agreement with the
other owners of properties to be developed by the Partnership authoriz-
ing either the General Partner or a third party operator to conduct
such operations. The Partnership Agreement further provides that the
Partnership will take such action in connection with operations pursu-
ant to such operating agreements as the General Partner, in its sole
discretion, deems appropriate and in the best interests of the Partner-
ship, and the decision of the General Partner with respect thereto will
be binding upon the Partnership.
Rollup or Consolidation of the Partnership
Two years or more after the Partnership has completed substan-
tially all of its property acquisition, drilling and development
operations, the General Partner may, without the vote, consent or
approval of the Limited Partners, cause all or substantially all of the
oil and gas properties and other assets of the Partnership to be sold,
assigned or transferred to, or the Partnership merged or consolidated
with, another partnership or a corporation, trust or other entity for
the purpose of combining the assets of two or more of the oil and gas
partnerships formed for investment or participation by employees,
directors and/or consultants of UNIT or any of its subsidiaries;
provided, however, that the valuation of the oil and gas properties and
other assets of all such participating partnerships for purposes of
such transfer or combination shall be made on a consistent basis and in
a manner which the General Partner and UNIT believe is fair and equita-
ble to the Limited Partners. As a consequence of any such transfer or
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combination, the Partnership will be dissolved and terminated and the
Limited Partners shall receive partnership interests, stock or other
equity interests in the transferee or resulting entity. See "RISK
FACTORS - Investment Risks - Roll-Up or Consolidation of the
Partnership."
Limited Liability
Under the Act, a limited partner is not generally liable for
partnership obligations unless he takes part in the control of the
business. The Agreement provides that the Limited Partners cannot bind
or commit the Partnership or take part in the control of its business
or management of its affairs, and that the Limited Partners will not be
personally liable for any debts or losses of the Partnership. However,
the amounts contributed to the Partnership by the Limited Partners and
the Limited Partners' interests in Partnership assets, including
amounts of undistributed Partnership Revenue allocable to the Limited
Partners, will be subject to the claims of creditors of the Partner-
ship. A Limited Partner (or his or her estate) will be obligated to
contribute cash to the Partnership, even if the Limited Partner is
unable to do so because of death, disability or any other reason, for:
(1) any unpaid contribution which the Limited Partner agreed
to make to the Partnership; and
(2) any return, in whole or in part, of the Limited Part-
ner's contribution to the extent necessary to discharge Partner-
ship liabilities to all creditors who extended credit or whose
claims arose before such return.
Liability of a Limited Partner is limited by the Act to one year
for any return of his or her contribution not in violation of the
Partnership Agreement or such Act and six years on any return of his or
her contribution in violation of the Partnership Agreement or such Act.
A partner is deemed to have received a return of his or her
contribution to the extent that a distribution to him or her reduces
his or her share of the fair value of the net assets of the Partnership
below the value of his or her contribution which has not been
distributed to him or her. How this provision applies to a partnership
whose primary assets are producing oil and gas properties or other
depleting assets is not entirely clear. The Agreement provides that
for the purposes of this provision, the value of a Limited Partner's
contribution which has not been distributed to him or her at any point
in time will be the Limited Partner's Percentage of the stated capital
of the Partnership allocated to the Limited Partners as reflected in
its financial statements as of such point in time.
Maintenance of limited liability of the Limited Partners in other
jurisdictions in which the Partnership may operate may require compli-
ance with certain legal requirements of those jurisdictions. In such
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jurisdictions, the General Partner shall cause the Partnership to
operate in such a manner as it, on the advice of responsible counsel,
deems appropriate to avoid unlimited liability for the Limited Partners
(see Sections 1.5, 12.1 and 12.2 of the Agreement). After the termina-
tion of the Partnership, any distribution of Partnership Properties to
the Limited Partners would result in their having unlimited liability
with respect to such properties.
Although the Partnership will, with certain limited exceptions,
serve as a co-general partner of any drilling or income programs formed
by UNIT or UPC in 1996 (see "PROPOSED ACTIVITIES"), the general
liability of the Partnership will not flow through to the Limited
Partners.
Records, Reports and Returns
The General Partner will maintain adequate books, records, ac-
counts and files for the Partnership and keep the Limited Partners
informed by means of written interim reports rendered within 60 days
after each quarter of the Partnership's fiscal year. The reports will
set forth the source and disposition of Partnership Revenues during the
quarter.
Engineering reports on the Partnership Properties will be prepared
by the General Partner for each year for which the General Partner
prepares such a report in connection with its own activities. Such
report will include an estimate of the total oil and gas proven re-
serves of the Partnership, the dollar value thereof and the value of
the Limited Partners' interest in such reserve value. The report shall
also contain an estimate of the life of the Partnership Properties and
the present worth of the reserves. Each Limited Partner will receive a
summary statement of such report which will reflect the value of the
Limited Partners' interest in such reserves.
The General Partner will timely file the Partnership's income tax
returns and by March 15 of each year or as soon thereafter as practica-
ble, furnish each person who was a Limited Partner during the prior
year all available information necessary for inclusion in his or her
federal income tax return. (See Section 8.1 of the Agreement).
Transferability of Interests
Restrictions. A Limited Partner may not transfer or assign Units
except for certain transfers:
to the General Partner;
to or for the benefit of himself or herself, his or her
spouse, or other members of the transferor Limited Partner's
immediate family sharing the same residence;
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to any corporation or other entity whose beneficial owners
are all Limited Partners or permitted assignees;
by the General Partner to any person who at the time of such
transfer is an employee of the General Partner, UNIT or its
subsidiaries; and
by reason of death or operation of law.
Further, no sale or exchange of any Units may be made if the sale
of such interest would, in the opinion of counsel for the Partnership,
result in a termination of the Partnership for purposes of Section 708
of the Code, violate any applicable securities laws or cause the
Partnership to be treated as an association taxable as a corporation
for federal income tax purposes; provided, however, that this condition
may be waived by the General Partner, in its sole discretion. More-
over, in no event shall all or any portion of a Limited Partner's Units
be assigned to a minor or an incompetent, except by will, intestate
succession, in trust, or pursuant to the Uniform Gifts to Minors Act.
As the offer and sale of the Units are not being registered under
the Securities Act of 1933, as amended, they may be sold, transferred,
assigned or otherwise disposed of by a Limited Partner only if, in the
opinion of counsel for the Partnership, such transfer or assignment
would not violate, or cause the offering of the Units to be violative
of, such act or applicable state securities laws, including investor
suitability standards thereunder. Because of the structure and antici-
pated operation of the Partnership, Rule 144 under the Securities Act
of 1933 will not be available to Limited Partners in connection with
any such sales.
Assignees. An assignee of a Limited Partner does not automatical-
ly become a Substituted Limited Partner, but has the right to receive
the same share of Partnership Revenue and distributions thereof to
which the assignor Limited Partner would have been entitled. A Limited
Partner who assigns his or her Partnership interest ceases to be a
Limited Partner, except that until a Substituted Limited Partner is
admitted in his or her place, the assignor retains the statutory rights
of an assignor of a Limited Partner's interest under the partnership
laws of the State of Oklahoma. The assignee of a Partnership interest
who does not become a Substituted Limited Partner and desires to make a
further assignment of such interest is subject to all of the
restrictions on transferability of Partnership interests described
herein and in the Partnership Agreement.
In the event of the death, incapacity or bankruptcy of a Limited
Partner, his or her legal representatives will have all the rights of a
Limited Partner only for the purpose of settling or liquidating his or
her estate and such power as the decedent, incompetent or bankrupt
Limited Partner possessed to assign all or any part of his or her
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interest in the Partnership and to join with such assignee in
satisfying conditions precedent to such assignee's becoming a
Substituted Limited Partner.
A purported sale, assignment or transfer of a Limited Partner's
interest will be recognized by the Partnership when it has received
written notice of such sale or assignment in form satisfactory to the
General Partner, signed by both parties, containing the purchaser's or
assignee's acceptance of the terms of the Agreement and a representa-
tion by the parties that the sale or assignment was lawful. Such sale
or assignment will be recognized as of the date of such notice, except
that if such date is more than 30 days prior to the time of filing,
such sale or assignment will be recognized as of the time the notice
was filed with the Partnership. Distributions of Partnership Revenue
will be made only to those persons who were record owners of Units on
the day any such distribution is made (see "RISK FACTORS - Tax Related
Risks - Disproportionate Tax Liability upon Transfer").
Substituted Limited Partners. No Limited Partner has the right to
substitute an assignee as a Limited Partner in his or her place. The
General Partner, however, has the right in its sole discretion to
permit such assignee to become a Substituted Limited Partner and any
such permission by the General Partner is binding and conclusive
without the consent or approval of any Limited Partner. Any
Substituted Limited Partner must, as a condition to receiving any
interest of the Limited Partner, agree in writing to be bound by the
terms and conditions of the Partnership Agreement, pay or agree to pay
the costs and expenses incurred by the Partnership in taking the
actions necessary in connection with his or her substitution as a
Limited Partner and satisfy the other conditions specified in Article
XIII of the Partnership Agreement.
Assignments by the General Partner. The General Partner may not
sell, assign, transfer or otherwise dispose of its interest in the
Partnership except with the prior consent of a majority in interest of
the Limited Partners, provided that no such consent is required if the
sale, assignment or transfer is pursuant to a bona fide merger, other
corporate reorganization or complete liquidation, sale of substantially
all of the General Partner's assets (provided the purchasers agree to
assume the duties and obligations of the General Partner) or any sale
or transfer to UNIT or any affiliate of UNIT. Any consent of the
Limited Partners will not be effective without an opinion of counsel to
the Partnership or an order or judgment of a court of competent juris-
diction to the effect that the exercise of such right will not be
deemed to evidence that the Limited Partners are taking part in the
management of the Partnership's business and affairs and will not
result in a loss of any Limited Partner's limited liability or cause
the Partnership to be classified as an association taxable as a corpo-
ration for federal income tax purposes (see Section 12.1 of the Agree-
ment). Any transferee of the General Partner's interest may become a
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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;
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Terminate and dissolve the Partnership; or
Approve any amendments to the Agreement which may be proposed
by the General Partner;
provided, however, any approvals, consents or elections of the Limited
Partners will not become effective unless prior to the exercise thereof
the General Partner is furnished with an opinion of counsel for the
Partnership, or an order or judgment of any court of competent
jurisdiction, that the exercise of such rights:
Will not be deemed to evidence that the Limited Partners are
taking part in the control or management of the Partnership's
business affairs;
Will not result in the loss of any Limited Partner's limited
liability under the Act; and
Will not result in the Partnership being classified as an
association taxable as a corporation for federal income tax
purposes.
Exculpation and Indemnification of the General Partner
Pursuant to the Agreement, neither the General Partner or any
affiliate thereof will have any liability to the Partnership or to any
Partners therein for any loss suffered by the Partnership or such
Partner that arises out of any action or inaction of the General
Partner or any affiliate thereof if the General Partner or affiliate
thereof in good faith determined that such course of conduct was in the
best interest of the Partnership, the General Partner or affiliate was
acting on behalf of or performing services for the Partnership, such
liability or loss was not the result of gross negligence or wilful
misconduct by the General Partner or affiliates thereof, and payments
arising from such indemnification or agreement to hold harmless are
receivable only out of the tangible net assets of the Partnership.
Termination
The Partnership will terminate automatically on December 31, 2026.
In addition, upon the dissolution (other than pursuant to a merger, or
other corporate reorganization or sale), bankruptcy, legal disability
or withdrawal of the General Partner, the Partnership shall immediately
be dissolved and terminated. The Act provides, however, that the
Limited Partners may elect to reform and reconstitute themselves as a
limited partnership within 90 days after such dissolution under the
provisions in the Partnership Agreement or under any other terms. The
Partnership may terminate sooner if a majority in interest of the
Limited Partners or the General Partner elects to dissolve and termi-
nate the Partnership as of an earlier date. Such right to accelerate
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termination of the Partnership by the Limited Partners will not be
available unless prior to any exercise thereof the Limited Partners
proposing such termination obtain and furnish to the General Partner an
opinion, order or judgment in the form referred to above under "Trans-
ferability of Interests - Assignments by the General Partner." The
withdrawal, expulsion, dissolution, death, legal disability, bankruptcy
or insolvency of any Limited Partner will not effect a dissolution or
termination of the Partnership. In the event of an election to termi-
nate the Partnership prior to expiration of its stated terms, 90 days'
prior written notice must be given to all Partners specifying the
termination date which must be the last day of a calendar month follow-
ing such 90 day period unless an earlier date is approved by Limited
Partners holding a majority of the outstanding Units.
When the Partnership is terminated, there will be an accounting
with respect to its assets, liabilities and accounts. The Partner-
ship's physical property and its oil and gas properties may be sold for
cash. Except in the case of an election by the General Partner to
terminate the Partnership before the tenth anniversary of the Effective
Date, Partnership Properties may be sold to the General Partner or any
of its affiliates for their fair market value as determined in good
faith by the General Partner.
Upon termination, all of the Partnership's debts, liabilities and
obligations, including expenses incurred in connection with the termi-
nation and the sale or distribution of Partnership assets, will be
paid. All Partnership borrowings will be paid in full. When the
specified payments have all been made, the remaining cash and proper-
ties of the Partnership, if any, will be distributed to the Partners as
set forth under "Partnership Distributions" above (see Section 16.4 of
the Agreement). Such distribution will result in the Limited Partners'
having unlimited liability with respect to any Partnership Properties
distributed to them.
Insurance
The General Partner will use its best efforts to obtain such
insurance as it deems prudent to serve as protection against liability
for loss and damage. Such insurance may include, but is not limited
to, public liability, automotive liability, workers' compensation and
employer's liability insurance and blowout and control of well
insurance.
COUNSEL
Conner & Winters, A Professional Corporation, 2400 First National
Tower, Tulsa, Oklahoma, has acted as special counsel ("Counsel") to the
General Partner in connection with certain aspects of this offering.
Counsel has assisted in the preparation of the Agreement and this
Memorandum. In connection with the preparation of this Memorandum,
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Counsel has relied entirely upon information submitted to it by the
General Partner. Certain of this information has been verified by
Counsel in the course of its representation, but no systematic effort
has been made to verify all of the material information contained
herein, and much of such information is not subject to independent
verification. In addition, Counsel has made no independent
investigation of the financial information concerning the General
Partner. Further, while passing on certain legal matters, Counsel has
not passed on the investment merits nor is it qualified to do so.
Because substantial portions of the information contained in this
Memorandum have not been independently verified, each investor must
make whatever independent inquiries the investor or his or her advisors
deem necessary or desirable to verify or confirm the statements made
herein.
GLOSSARY
As used herein and in the Agreement, the following terms and
phrases will have the meanings indicated.
(a) "Additional Assessments" are amounts required to be
contributed by the Limited Partners to the Partnership upon a call
therefor by the General Partner in the manner described under
"ADDITIONAL FINANCING - Additional Assessments."
(b) An "affiliate" of another person is (1) any person
directly or indirectly owning, controlling or holding with power
to vote 10% or more of the outstanding voting securities of such
other person; (2) any person 10% or more of whose outstanding
voting securities are directly or indirectly owned, controlled, or
held with power to vote, by such other person; (3) any person
directly or indirectly controlling, controlled by, or under common
control with such other person; (4) any officer, director, trustee
or partner of such other person; and (5) if such other person is
an officer, director, trustee or partner, any company for which
such person acts in any such capacity.
(c) The "Aggregate Subscription" is the sum of the Capital
Subscriptions of all Limited Partners.
(d) "Agreement" and "Partnership Agreement" refers to the
Agreement of Limited Partnership attached as Exhibit A to this
Private Offering Memorandum.
(e) The "Capital Contribution" of a Limited Partner is the
amount of the Capital Subscription actually paid in by him or her,
or by any predecessor in interest, to the capital of the
Partnership including any payments made by deductions from salary.
The "Capital Contribution" of the General Partner includes the
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<PAGE>
amounts contributed to the Partnership or paid by the General
Partner or by any Limited Partner whose Units are purchased by the
General Partner pursuant to Section 4.2 of the Agreement because
of a default by such Limited Partner in the payment of an
Installment or pursuant to Article XV of the Agreement, including
payments made by deductions from the salary of such Limited
Partner.
(f) The "Capital Subscription" of a Limited Partner or his
or her assignee (including the General Partner where Units are
transferred pursuant to Section 4.2 of the Agreement) is the
amount specified in the Subscription Agreement executed by such
Limited Partner for payment by him or her to the capital of the
Partnership in accordance with the provisions of the Agreement,
reduced by the amounts thereof from which the Limited Partners
have been released by the General Partner of their obligation to
pay.
(g) A "Development Well" means a well intended to be drilled
within the proved areas of a known oil or gas reservoir to the
depth of a stratigraphic horizon known to be productive.
(h) "Director" refers to the duly elected directors of UNIT
as well as all honorary directors and consultants to the Board of
Directors of UNIT.
(i) "Drilling Costs" are those costs incurred in drilling,
testing, completing and equipping a well to the point that it
proves to be dry and is abandoned or is ready to commence commer-
cial production of oil or gas therefrom.
(j) "Effective Date" refers to the date on which the certif-
icate evidencing formation of the Partnership is filed with the
Secretary of State of the State of Oklahoma as required by the Act
(54 Okla. Stat. 1991, Section 309).
(k) An "Exploratory Well" means a well drilled to find
production in an unproven area, to find a new reservoir in a field
previously found to be productive or to extend greatly the limits
of a known reservoir.
(l) A "farm-out" is an agreement whereby the owner of an oil
and gas property agrees to assign such property, usually retaining
some interest therein such as an overriding royalty, a production
payment, a net profits interest or a carried working interest,
subject in most cases, however, to the drilling of one or more
wells or other performance by the prospective assignee as a
condition of the assignment.
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(m) The "General Partner's Minimum Capital Contribution" is
that amount equal to the total of (i) all Partnership costs and
expenses charged to its account from the time of the formation of
the Partnership through December 31, 1996, plus (ii) the General
Partner's estimate of the total Leasehold Acquisition Costs and
Drilling Costs expected to be incurred by the Partnership subse-
quent to December 31, 1996, if any, minus (iii) the amount, if
any, of the unexpended Aggregate Subscription at December 31,
1996.
(n) The "General Partner's Percentage" is that percentage
determined by dividing the amount of the General Partner's Minimum
Capital Contribution by the total of (i) the General Partner's
Minimum Capital Contribution plus (ii) the Aggregate Subscription.
(o) "Installments" refer to the periodic payments of the
Capital Subscription, which are payable either (i) in four equal
installments due on March 15, 1996, June 15, 1996, September 15,
1996 and December 15, 1996, respectively, or (ii) if an employee
so elects, through equal deductions from 1996 salary commencing
immediately after formation of the Partnership.
(p) "Leasehold Acquisition Costs" with respect to proper-
ties, if any, acquired by the Partnership from non-affiliated
parties mean the actual costs to the Partnership of and in
acquiring the properties, and, with respect to properties acquired
by the Partnership from the General Partner, UNIT or its
affiliates are, without duplication, the sum of:
(1) the prices paid by the General Partner, UNIT or its
affiliates in acquiring an oil and gas property,
including purchase option fees and charges, bonuses and
penalties, if any;
(2) title insurance or examination costs, broker's
commissions, filing fees, recording costs, transfer
taxes, if any, and like charges incurred in connection
with the acquisition of such property;
(3) a pro rata portion of the actual, necessary and
reasonable expenses of the General Partner, UNIT or its
affiliates for seismic and geophysical services;
(4) rentals, shut-in royalties and ad valorem taxes paid by
the General Partner, UNIT or its affiliates with respect
to such property to the date of its transfer to the
Partnership;
104
<PAGE>
(5) interest and points actually incurred on funds used by
the General Partner, UNIT or its affiliates to acquire
or maintain such property; and
(6) such portion of the General Partner's, UNIT or its
affiliates' reasonable, necessary and actual expenses
for geological, engineering, drafting, accounting, legal
and other like services allocated to the acquisition,
operations and maintenance of the property in accordance
with generally accepted industry practices, except for
expenses in connection with the past drilling of wells
which are not producers of sufficient quantities of oil
or gas to make commercially reasonable their continued
operations, and provided that the costs and expenses
enumerated in (4), (5) and (6) above with respect to any
particular property shall have been incurred not more
than thirty-six (36) months prior to the acquisition of
such property by the Partnership.
In the event a fractional undivided interest in a property is sold
or transferred by the General Partner, UNIT or any affiliate to an
unaffiliated third party for an amount in excess of that portion
of the original cost of the property attributable to the
transferred interest, the amount of such excess shall not reduce
or be offset against the amount of the Leasehold Acquisition Costs
attributable to any interest in the same property which is
transferred to the Partnership.
(q) "Limited Partners" are those persons who acquire Units
in the Partnership upon its formation and those transferees of
Units who are accepted as Substituted Limited Partners. The
General Partner may also be a Limited Partner if it subscribes for
Units or if it subsequently acquires Units by (i) the exercise by
a Limited Partner of his or her right of presentment; (ii) a
purchase by the General Partner of the Units of a Limited Partner
who defaults in the payment of an Installment; or (iii) any other
assignment or transfer.
(r) The "Limited Partners' Percentage" is that percentage
determined by dividing the amount of the Aggregate Subscription by
the total of (i) the General Partner's Minimum Capital Contribu-
tion plus (ii) the Aggregate Subscription.
(s) "Normal Retirement" means retirement under the terms of
a pension or similar retirement plan adopted by the General
Partner, UNIT or any subsidiary with whom a Limited Partner is
employed as in effect at the time of retirement.
(t) "Oil and gas properties" are oil and gas leasehold
working interests, fee interests, mineral interests, royalty
105
<PAGE>
interests, overriding royalty interests, production payments,
options or rights to lease or acquire such interests, geophysical
exploration permits and any tangible or intangible properties or
other rights incident thereto, whether real, personal or mixed.
(u) "Operating Expenses" are expenditures made and costs
incurred in producing and marketing oil or gas from completed
wells, including, in addition to labor, fuel, repairs, hauling,
material, supplies, utility charges and other costs incident to or
necessary for the maintenance or operation of such wells or the
marketing of production therefrom, ad valorem, severance and other
such taxes (other than windfall profit taxes), insurance and
casualty loss expense and compensation to well operators or others
for services rendered in conducting such operations.
(v) The General Partner and the Limited Partners are some-
times collectively referred to as the "Partners."
(w) "Partnership Agreement" and "Agreement" refer to the
Agreement of Limited Partnership attached as Exhibit A to this
Private Offering Memorandum.
(x) The "Partnership Properties" are oil and gas properties
or interests therein acquired by the Partnership or properties
acquired by any partnership or joint venture in which the Partner-
ship is a partner or joint venturer, whether acquired by purchase,
option exercise or otherwise.
(y) "Partnership Revenue" refers to the Partnership's gross
revenues from all sources, including interest income, proceeds
from sales of production, the Partnership's share of revenues from
partnerships or joint ventures of which it is a member, sales or
other dispositions of Partnership Properties or other Partnership
assets, provided that contributions to Partnership capital by the
Partners and the proceeds of any Partnership borrowings are
specifically excluded and dry-hole and bottom-hole contributions
shall be treated as reductions of the costs giving rise to the
right to receive such contributions.
(z) "Partnership Wells" are any and all of the oil and gas
wells in which the Partnership has an interest, either directly or
indirectly through any other partnership or joint venture.
(aa) "Productive properties" are oil and gas properties that
have been tested by drilling and determined to be capable of
producing oil or gas in commercial quantities.
(bb) A "spacing unit" is a drilling and spacing, production
or similar unit established by any regulatory body with jurisdic-
tion, or in the absence of such a regulatory body or action
106
<PAGE>
thereby, the acreage attributable to wells drilled under the
normal spacing pattern in such area or if no such spacing unit is
designated, in keeping with generally accepted industry practices,
or the largest of such units in the event of multiple objective
formations.
(cc) "Special Production and Marketing Costs" are costs and
expenses that are not normally and customarily incurred in connec-
tion with drilling, producing and marketing operations, including
without limitation, costs incurred in constructing compressor
plants, gasoline plants, gas gathering systems, natural gas
processing plants, pipeline systems and salt water disposal
systems and costs incurred in installing pressure maintenance and
secondary or tertiary production projects.
(dd) "Subscription Agreement" refers to the form of Limited
Partner Subscription Agreement and Suitability Statement attached
as Attachment I to the Partnership Agreement.
(ee) A "Substituted Limited Partner" is a transferee, donee,
heir, legatee or other recipient of all or any portion of a
Limited Partner's interest in the Partnership with respect to whom
all conditions and consents required to become a Substituted
Limited Partner under Article XIII of the Partnership Agreement
have been satisfied and given.
(ff) A "Unit" is a preformation unit of limited partnership
interest of a Limited Partner in the Partnership representing a
Capital Subscription of One Thousand Dollars ($1,000).
FINANCIAL STATEMENTS
On January 1, 1988 all of the oil and natural gas properties
previously owned by Unit Drilling and Exploration Company ("UDEC") and
UNIT were transferred into Sunshine Development Company through a
contribution of capital. Included in the transfer were all interests
previously owned by UDEC in numerous General and Limited Partnerships
sponsored by UDEC. Effective February 1, 1988, Sunshine Development
Company, a wholly owned subsidiary of UDEC, pursuant to an "Amended and
Restated Certificate of Incorporation" was renamed Unit Petroleum
Company and became a wholly owned subsidiary of UNIT.
Unit Petroleum Company functions as the operating entity for all
oil and natural gas exploration and production activities including
operating any partnerships for UNIT.
The consolidated balance sheet of Unit Petroleum Company at
October 31, 1995 is unaudited and includes all adjustments which UNIT
107
considers necessary for a fair presentation of the financial position
of Unit Petroleum Company at October 31, 1995.
108
<PAGE>
Unit Petroleum Company and Subsidiary
Consolidated Balance Sheet
(In Thousands)
October 31,
1995
-----------
(Unaudited)
Assets
------
Current Assets:
Cash and cash equivalents $ 133
Accounts receivable 5,463
Materials and supplies, at lower of
cost or market 1,793
Other 121
----------
7,510
----------
Property and Equipment:
Oil and natural gas properties, on the
full cost method 171,079
Other 323
----------
171,402
Less accumulated depreciation, depletion,
amortization and impairment (90,533)
----------
Net property and equipment 80,869
----------
Other Assets 1
----------
Total Assets $ 88,380
==========
Liabilities and Shareholder Equity
----------------------------------
Current Liabilities:
Accounts payable $ 3,267
Amount Payable to Parent 8,317
Contract advances 99
Accrued liabilities 1,072
----------
Total current liabilities 12,755
----------
Long-Term Portion of Natural Gas Purchaser Prepayment 2,309
----------
Shareholder Equity:
Common stock, $1.00 per value,
500 shares authorized and outstanding 1
Capital in excess of par value 31,486
Retained earnings 41,829
----------
Total Shareholder Equity 73,316
----------
Total Liabilities and Shareholder Equity $ 88,380
==========
109
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EXHIBIT A
<PAGE>
EXHIBIT A
UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
AGREEMENT OF LIMITED PARTNERSHIP
A-1
<PAGE>
INDEX
Page
----
ARTICLE I Formation of Limited Partnership........ A-4
ARTICLE II Definitions............................. A-6
ARTICLE III Purposes and Powers of the Partnership.. A-10
ARTICLE IV Partner Capital Contributions........... A-13
ARTICLE V Deposit and Use of Capital Contributions
and Other Partnership Funds.......... A-15
ARTICLE VI Sharing of Costs, Capital Accounts and
Allocation of Charges and Income..... A-17
ARTICLE VII Fiscal Year, Accountings and
Reports.............................. A-23
ARTICLE VIII Tax Returns and Elections............... A-23
ARTICLE IX Distributions........................... A-24
ARTICLE X Rights, Duties and Obligations of the
General Partner...................... A-24
ARTICLE XI Compensation and Reimbursements......... A-31
ARTICLE XII Rights and Obligations of Limited
Partners............................. A-32
ARTICLE XIII Transferability of Limited Partner's
Interest............................. A-33
ARTICLE XIV Assignments by the General Partner...... A-36
ARTICLE XV Limited Partners' Right of Presentment.. A-37
ARTICLE XVI Termination and Dissolution of
Partnership.......................... A-39
ARTICLE XVII Notices................................ A-41
ARTICLE XVIII Amendments............................. A-42
ARTICLE XIX General Provisions..................... A-42
A-2
<PAGE>
ATTACHMENT I Limited Partner Subscription
Agreement and Suitability Statement.... I-1
A-3
<PAGE>
UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
AGREEMENT OF LIMITED PARTNERSHIP
THIS AGREEMENT OF LIMITED PARTNERSHIP (this "Agreement") is made and
entered into by and among Unit Petroleum Company, an Oklahoma corporation,
hereinafter referred to as the "General Partner" or "UPC" (which term shall
include any successors or assigns of UPC), and each of those persons who have
executed a counterpart of the Limited Partner Subscription Agreement and
Suitability Statement attached as Attachment I to this Agreement that have been
accepted by the General Partner, said persons being hereinafter collectively
referred to as the "Limited Partners".
WITNESSETH THAT:
ARTICLE I
Formation of Limited Partnership
1.1 The parties to this Agreement hereby form a Limited Partnership
(the "Partnership") pursuant to the Revised Uniform Limited Partnership
Act of the State of Oklahoma (the "Act"). The terms and provisions
hereof will be construed and interpreted in accordance with the terms and
provisions of the Act and if any of the terms and provisions of this
Agreement should be deemed inconsistent with those terms and provisions
of the Act which under the Act may not be altered by agreement of the
parties, the Act will be controlling, but otherwise this Agreement will
be controlling.
1.2 The Partnership will be conducted under the name of "Unit 1996
Employee Oil and Gas Limited Partnership" in Oklahoma, and under such
name or variations of such name as the General Partner deems appropriate
to comply with the laws of the other jurisdictions in which the
Partnership does business.
1.3 The principal office of the Partnership will be 1000 Kensington
Tower I, 7130 South Lewis Avenue, P.O. Box 702500, Tulsa, Oklahoma 74136,
or at such other location as may from time to time be designated by the
General Partner, and the Partnership's agent for service of process shall
be Unit Corporation ("UNIT", which term shall include all or any of its
subsidiaries or affiliates unless the context otherwise requires) at the
same address.
1.4 The Partnership will be effective on the date on which the
certificate evidencing formation of the Partnership is filed with the
Secretary of State of the State of Oklahoma. Its business and operations
A-4
<PAGE>
will not be commenced prior to such date. The Partnership will continue
in existence until December 31, 2026, unless sooner terminated pursuant
to any provisions of this Agreement.
1.5 The parties hereto will execute such certificates and other
documents, and the General Partner will file, record and publish such
certificates and documents, as may be necessary or appropriate to comply
with the requirements for the formation and operation of a limited
partnership under the Act and as the General Partner, upon advice of
counsel, deems necessary or appropriate to comply with requirements of
applicable laws governing the formation and operations of a limited
partnership (or a partnership in which special partners have a limited
liability) in all other jurisdictions where the Partnership desires to
conduct business, including, but not limited to, filings under the
Fictitious Name Act, Assumed Name Act or similar law in effect in the
counties, parishes and other governmental jurisdictions in which the
Partnership conducts business. The General Partner shall not be required
to deliver or mail a copy of the certificate of limited partnership or
any amendments thereto filed pursuant to the Act to the Limited Partners.
1.6 Each Limited Partner by his or her execution of a counterpart
of the Subscription Agreement irrevocably constitutes and appoints the
General Partner such Limited Partner's true and lawful attorney and
agent, with full power and authority in such Limited Partner's name,
place and stead, to execute, sign, acknowledge, swear to, deliver, file
and record in the appropriate public offices (i) all certificates or
other instruments (including, without limitation, counterparts of this
Agreement) and amendments thereto which the General Partner deems
appropriate to qualify or continue the Partnership as a limited part-
nership (or a partnership in which special partners have limited
liability) in the jurisdictions in which the Partnership conducts
business; (ii) all instruments and amendments thereto which the General
Partner deems appropriate to reflect any change or modification of this
Agreement, the admission of additional or substitute Partners in
accordance with the terms of this Agreement, the release or waiver of the
Limited Partners from the obligation to pay in one or more of the
installments of their Capital Subscriptions pursuant to Section 4.2 below
and the termination of the Partnership and the cancellation of the
certificate of limited partnership; (iii) all conveyances and other
instruments which the General Partner deems appropriate to evidence and
reflect any sales or transfers, including sales or transfers upon or in
connection with the dissolution and termination of the Partnership; and
(iv) all consents to transfers of Partnership interests, to the admission
of substitute or additional Partners or to the withdrawal or reduction of
any Partner's invested capital, to the extent that such actions are
authorized by the terms of this Agreement. The Power of Attorney granted
herein is irrevocable and is a power coupled with an interest and will
A-5
<PAGE>
survive the death, disability, dissolution, bankruptcy, insolvency or
incapacity of a Limited Partner.
ARTICLE II
Definitions
2.1 Whenever used in this Agreement the following terms will have
the meanings described below:
(a) The "Additional Assessments" of the Limited Partners are
those amounts, if any, which they are required to pay into the
capital of the Partnership pursuant to Section 5.3 of this
Agreement.
(b) An "affiliate" of another person is (1) any person
directly or indirectly owning, controlling or holding with power to
vote 10% or more of the outstanding voting securities of such other
person; (2) any person 10% or more of whose outstanding voting
securities are directly or indirectly owned, controlled, or held
with power to vote, by such other person; (3) any person directly or
indirectly controlling, controlled by, or under common control with
such other person; (4) any officer, director, trustee or partner of
such other person; and (5) if such other person is an officer,
director, trustee or partner, any company for which such person acts
in any such capacity.
(c) The "Aggregate Subscription" is the sum of the Capital
Subscriptions of all Limited Partners.
(d) The "Capital Contribution" of a Limited Partner is the
amount of the Capital Subscription actually paid in by him or her,
or by any predecessor in interest, to the capital of the
Partnership, including any payments made by deductions from salary.
The "Capital Contribution" of the General Partner includes the
amounts contributed to the Partnership or paid by the General
Partner or by any Limited Partner whose Units are purchased by the
General Partner including purchases pursuant to Section 4.2 of this
Agreement because of a default by such Limited Partner in the
payment of a subscription installment or pursuant to Article XV of
this Agreement, including payments made by deductions from the
salary of such Limited Partner.
(e) The "Capital Subscription" of a Limited Partner or his or
her assignee (including the General Partner where Units are trans-
ferred pursuant to Section 4.2 of this Agreement) is the amount
A-6
<PAGE>
specified in the Subscription Agreement executed by such Limited
Partner for payment by him or her to the capital of the Partnership
in accordance with the provisions of this Agreement, reduced by the
amount thereof from which the Limited Partner has been released by
the General Partner of his or her obligation to pay pursuant to
Section 4.2 hereof.
(f) "Drilling Costs" are those costs incurred in drilling,
testing, completing and equipping a Partnership Well to the point
that it proves to be dry and is abandoned or is ready to commence
commercial production of oil or gas therefrom.
(g) "Effective Date" refers to the date on which the certif-
icate evidencing formation of the Partnership is filed with the
Secretary of State of the State of Oklahoma as required by the Act
(54 Okla. Stat. 1991, Section 309).
(h) A "farm-out" is an agreement whereby the owner of an oil
and gas property agrees to assign such property, usually retaining
some interest therein such as an overriding royalty, a production
payment, a net profits interest or a carried working interest,
subject in most cases, however, to the drilling of one or more wells
or other performance by the prospective assignee as a condition of
the assignment.
(i) The "General Partner's Minimum Capital Contribution" is
that amount equal to the total of (i) all Partnership costs and
expenses charged to its account from the time of the formation of
the Partnership through December 31, 1996, plus (ii) the General
Partner's estimate of the total Leasehold Acquisition Costs and
Drilling Costs expected to be incurred by the Partnership subsequent
to December 31, 1996, minus (iii) the amount, if any, of the
unexpended Aggregate Subscription at December 31, 1996.
(j) The "General Partner's Percentage" is that percentage
determined by dividing the amount of the General Partner's Minimum
Capital Contribution by the total of (i) the General Partner's
Minimum Capital Contribution plus (ii) the Aggregate Subscription.
(k) "Leasehold Acquisition Costs" with respect to properties,
if any, acquired by the Partnership from non-affiliated parties mean
the actual costs to the Partnership of and in acquiring the
properties, and, with respect to properties acquired by the
Partnership from the General Partner, UNIT or its affiliates, are,
without duplication, the sum of: (1) the prices paid by the General
Partner, UNIT or its affiliates in acquiring an oil and gas
property, including purchase option fees and charges, bonuses and
A-7
<PAGE>
penalties, if any; (2) title insurance or examination costs,
broker's commissions, filing fees, recording costs, transfer taxes,
if any, and like charges incurred in connection with the acquisition
of such property; (3) a pro rata portion of the actual, necessary
and reasonable expenses of the General Partner, UNIT or its
affiliates for seismic and geophysical services; (4) rentals, shut-in
royalties and ad valorem taxes paid by the General Partner, UNIT
or its affiliates with respect to such property to the date of its
transfer to the Partnership; (5) interest and points actually
incurred on funds used by the General Partner, UNIT or its
affiliates to acquire or maintain such property; and (6) such
portion of the General Partner's, UNIT's or its affiliates'
reasonable, necessary and actual expenses for geological,
engineering, drafting, accounting, legal and other like services
allocated to the acquisition, operations and maintenance of the
property in accordance with generally accepted industry practices,
except for expenses in connection with the past drilling of wells
which are not producers of sufficient quantities of oil or gas to
make commercially reasonable their continued operations, and
provided that the costs and expenses enumerated in (4), (5) and (6)
above with respect to any particular property shall have been
incurred not more than thirty-six (36) months prior to the
acquisition of such property by the Partnership. In the event a
fractional undivided interest in a property is sold or transferred
by the General Partner, UNIT or any affiliate to an unaffiliated
third party for an amount in excess of that portion of the original
cost of the property attributable to the transferred interest, the
amount of such excess shall not reduce or be offset against the
amount of the Leasehold Acquisition Costs attributable to any
interest in the same property which is transferred to the
Partnership.
(l) "Limited Partners" are those persons who acquire Units in
the Partnership upon its formation and those transferees of Units
who are accepted as Substituted Limited Partners. The General
Partner may also be a Limited Partner if it subscribes for Units or
if it subsequently acquires Units by (i) the exercise by a Limited
Partner of his or her right of presentment; (ii) a purchase by the
General Partner of the Units of a Limited Partner who defaults in
the payment of any subscription installment; or (iii) any other
assignment or transfer.
(m) The "Limited Partners' Percentage" is that percentage
determined by dividing the amount of the Aggregate Subscription by
the total of (i) the General Partner's Minimum Capital Contribution
plus (ii) the Aggregate Subscription.
A-8
<PAGE>
(n) "Normal Retirement" means retirement under the provision
of a pension or similar retirement plan adopted by the General
Partner, UNIT or any subsidiary with whom a Limited Partner is
employed as in effect at the time of the employee's retirement.
(o) "Oil and gas properties" are oil and gas leasehold working
interests, fee interests, mineral interests, royalty interests,
overriding royalty interests, production payments, options or rights
to lease or acquire such interests, geophysical exploration permits
and any tangible or intangible properties or other rights incident
thereto, whether real, personal or mixed.
(p) "Operating Expenses" are expenditures made and costs
incurred in producing and marketing oil or gas from completed wells,
including, in addition to labor, fuel, repairs, hauling, material,
supplies, utility charges and other costs incident to or necessary
for the maintenance or operation of such wells or the marketing of
production therefrom, ad valorem, severance and other such taxes
(other than windfall profit taxes), insurance and casualty loss
expense and compensation to well operators or others for services
rendered in conducting such operations.
(q) The General Partner and the Limited Partners are sometimes
collectively referred to as the "Partners".
A-7
<PAGE>
(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.
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(u) "Productive properties" are oil and gas properties that
have been tested by drilling and determined to be capable of
producing oil or gas in commercial quantities.
(v) "Special Production and Marketing Costs" are costs and
expenses that are not normally and customarily incurred in connec-
tion with drilling, producing and marketing operations, including
without limitation, costs incurred in constructing compressor
plants, gasoline plants, gas gathering systems, natural gas
processing plants, pipeline systems and salt water disposal systems
and costs incurred in installing pressure maintenance and secondary
or tertiary production projects.
(w) "Subscription Agreement" refers to the form of Limited
Partner Subscription Agreement and Suitability Statement attached as
Attachment I to this Agreement.
(x) A "Substituted Limited Partner" is a transferee, donee,
heir, legatee or other recipient of all or any portion of a Limited
Partner's interest in the Partnership with respect to whom all
conditions and consents required to become a Substituted Limited
Partner under Article XIII have been satisfied and given.
(y) A "Unit" is a preformation unit of limited partnership
interest of a Limited Partner in the Partnership representing a
Capital Subscription of One Thousand Dollars ($1,000).
ARTICLE III
Purposes and Powers of the Partnership
3.1 The purposes of the Partnership will be to acquire productive
oil and gas properties and to explore for, produce, treat, transport and
market oil, gas or both, or products derived therefrom, anywhere in the
United States. It is contemplated that all or most of the Partnership's
operations will be conducted as part of the operations of the General
Partner and its affiliates, but the Partnership may engage in operations
on its own or in conjunction with unaffiliated third parties. In
accomplishing such purposes the Partnership may:
(a) acquire oil and gas properties, either alone or in
conjunction with other parties;
(b) conduct geological and geophysical investigations,
including, without limitation, seismic exploration, core drilling
and other means and methods of exploration;
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(c) drill, equip, complete, rework, reequip, recomplete, plug
back, deepen, plug and abandon Partnership Wells as the General
Partner deems advisable;
(d) acquire and dispose of tangible lease and well equipment
for use or used in connection with Partnership Wells;
(e) employ or retain such personnel and obtain such legal,
accounting, geological, geophysical, engineering and other profes-
sional services and advice as the General Partner may deem advisable
in the course of the Partnership's operations under this Agreement;
(f) either pay or elect not to pay delay rentals or shut-in
royalties on Partnership Properties as appropriate in the judgment
of the General Partner, it being understood that the General Partner
will not be liable for failure to make correct or timely payments of
delay rentals or shut-in royalties if such failure was due to any
reason other than gross negligence or lack of good faith;
(g) make or give dry-hole or bottom-hole or other contribu-
tions of oil and gas properties, money or both, to encourage
drilling by others in the vicinity of or on Partnership Properties;
(h) negotiate for and accept dry-hole, bottom-hole or other
contributions of oil and gas properties, cash or both, as consid-
eration for the drilling of a Partnership Well, with oil and gas
properties so acquired, if any, to become Partnership Properties;
(i) pay all ad valorem taxes levied or assessed against the
Partnership Properties, all taxes upon or measured by the production
of oil or gas or other hydrocarbons therefrom, and all other taxes
(other than income taxes) directly relating to operations conducted
under this Agreement;
(j) enter into and operate pursuant to operating agreements
with respect to Partnership Properties naming either the General
Partner, any of its affiliates or a third party as operator, or
enter into partnership agreements with third parties whereby the
Partnership may be either a general or a limited partner (including
any partnerships formed or sponsored by the General Partner or in
which the General Partner may also be a partner), which operating or
partnership agreements shall contain such terms, provisions and
conditions as the General Partner deems appropriate;
(k) execute all documents or instruments of any kind which the
General Partner deems appropriate for carrying out the purposes of
the Partnership, including, without limitation, unitization
agreements, gasoline plant contracts, recycling agreements and
agreements relating to pressure maintenance and secondary or
tertiary production projects;
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(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;
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(s) purchase, sell or pledge payments out of production from
Partnership Properties; and
(t) perform any and all other acts or activities customary or
incident to exploration for or development, production and marketing
of oil and gas.
ARTICLE IV
Partner Capital Contributions
4.1 The General Partner will have the unrestricted right to admit
such parties as Limited Partners as it deems advisable. By their
execution of the Subscription Agreement, the Limited Partners severally
agree, subject to the acceptance of their subscription by the General
Partner, to be bound by the terms hereof as Limited Partners.
4.2 The Capital Subscriptions of the Limited Partners will be
payable either (i) in four equal installments on March 15, 1996, June 15,
1996, September 15, 1996, and December 15, 1996, respectively, or (ii) by
employees so electing, through equal deductions from 1996 salary paid to
the employee by the General Partner, UNIT or its subsidiaries commencing
immediately after the Effective Date. Notwithstanding the foregoing, if
in the judgment of the General Partner, the entire amount of the
Aggregate Subscription is not required for purposes of conducting the
business, operations and affairs of the Partnership, the General Partner
may, at its sole option, elect to release the Limited Partners from the
obligation to pay in one or more of the installments of their Capital
Subscriptions. If Units are acquired by a corporation or other entity,
the beneficial owners of the interests therein shall be jointly and
severally liable for the payment of the Capital Subscription. If an
employee or director who has subscribed for Units (either directly or
through a corporation or other entity) ceases to be employed by or a
director of the General Partner, UNIT or any of its subsidiaries for any
reason other than death, disability or Normal Retirement prior to the
time the full amount of his or her Capital Subscription is paid, then the
due date for any unpaid amount shall be accelerated so that the full
amount of his or her unpaid Capital Subscription shall be due and payable
on the effective date of such termination. The Capital Subscriptions
shall be legally binding obligations of the Limited Partners and any past
due amounts shall bear interest at the annual rate equal to two (2)
percentage points in excess of the prime rate of interest of Bank of
Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in
effect from time to time, until paid. Further, in the event a Limited
Partner fails to pay any installment when due, the General Partner, at
its sole option and discretion, may elect to purchase the Units of such
defaulting Limited Partner at a price equal to the total amount of the
Capital Contributions actually paid into the Partnership by such
defaulting Limited Partner, less the amount of any Partnership
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distributions that may have been received by him or her. Such option may
be exercised by the General Partner by written notice to the Limited
Partner at any time after the date that the unpaid installment was due
and shall be deemed exercised when the amount of the purchase price is
first tendered to the defaulting Limited Partner. The General Partner
may, in its discretion, accept payments of delinquent installments but
shall not be required to do so. In the event that the General Partner
elects to purchase the Units of a defaulting Limited Partner, it shall
pay into the Partnership the amount of the delinquent installment
(excluding any interest that may have accrued thereon) and shall pay each
additional installment, if any, payable with respect to such Units as it
becomes due. By virtue of such purchase, the General Partner shall be
allocated all Partnership Revenues and be charged with all Partnership
costs and expenses attributable to such Units otherwise allocable or
chargeable to the defaulting Limited Partner to the extent provided in
Section 13.9.
4.3 If the Partnership requires funds to conduct Partnership
operations during the period between any of the installments due as set
forth in Section 4.2 above, then, notwithstanding the provisions of
Section 5.4 below, the General Partner shall advance funds to the
Partnership in an amount equal to the funds then required to conduct such
operations but in no event more than the total amount of the Aggregate
Subscription remaining unpaid. With respect to any such advances, the
General Partner shall receive no interest thereon and no financing
charges will be levied by the General Partner in connection therewith.
The General Partner shall be repaid out of the Capital Subscription
installments thereafter paid into the capital of the Partnership when
due.
4.4 Additional Assessments required by the General Partner pursuant
to Section 5.3 of this Agreement will be payable in cash on such date as
the General Partner may set in its written notice, but in no event will
such assessments be due earlier than thirty (30) days after the date of
mailing of the notice. Notice of the General Partner's call for
Additional Assessments shall specify the amount required, the manner in
which the additional funds will be expended, the date on which such
amounts are payable, and the consequences of non-payment. The General
Partner will not be required to accept late payments of such amounts, but
it may in its discretion do so.
4.5 The General Partner will contribute to the capital of the
Partnership amounts equal to the total of all costs paid by the Part-
nership that are charged to the General Partner's account as such costs
are incurred.
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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
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expenses of collection, including interest, court costs and a reasonable
attorney's fee.
5.4 After the General Partner's Minimum Capital Contribution has
been fully expended, the General Partner may cause the Partnership to
borrow funds for the purpose of paying Drilling Costs, Special Production
and Marketing Costs or Leasehold Acquisition Costs of productive
properties, which borrowings may be secured by interests in the Part-
nership Properties and will be repaid, including interest accruing
thereon, out of Partnership Revenue allocable to the accounts of the
Partners on whose behalf the proceeds of such borrowings are expended.
The General Partner may, but is not required to, advance funds to the
Partnership for the same purposes for which Partnership borrowings are
authorized by this Section 5.4. With respect to any such advances, the
General Partner shall receive interest in an amount equal to the lesser
of the interest which would be charged to the Partnership by unrelated
banks on comparable loans for the same purpose or the General Partner's
interest cost with respect to such loan, where it borrows the same. No
financing charges will be levied by the General Partner in connection
with any such loan. If Partnership borrowings secured by interests in
the Partnership Properties and repayable out of Partnership Revenue
cannot be arranged on a basis which, in the opinion of the General
Partner, is fair and reasonable, and the entire sum required to pay costs
of the type referred to above is not available from Partnership Revenue,
the Partnership may elect not to drill or participate in the drilling of
a well or the General Partner may dispose of the Partnership Properties
upon which such operations were to be conducted by sale (subject to any
other applicable provisions of this Agreement), farm-out or abandonment.
5.5 The General Partner may utilize Partnership Revenue allocable
to the respective accounts of the Partners to pay any Partnership costs
and expenses properly chargeable to the accounts of such Partners.
5.6 With respect to any Partnership activity and subject to the
restrictions set forth in Sections 5.3 and 5.4 above, it shall be in the
sole discretion of the General Partner whether to call for Additional
Assessments, arrange for borrowings on behalf of the Partners, utilize
Partnership Revenue or sell (subject to any other applicable provisions
of this Agreement), farm-out or abandon Partnership Properties.
5.7 The Partnership Properties and production therefrom may be
pledged, mortgaged or otherwise encumbered as security for borrowings by
the Partnership authorized by Section 5.4 above, provided that the holder
of indebtedness arising by virtue of such borrowings may not have or
acquire, at any time as a result of making any such loans, any direct or
indirect interest in the profits, capital or property of the Partnership
other than as a secured creditor.
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ARTICLE VI
Sharing of Costs, Capital Accounts and
Allocation of Charges and Income
6.1 All costs of organizing the Partnership and offering Units
therein will be paid by the General Partner. All costs incurred in the
offering and syndication of any drilling or income program formed by UPC
or UNIT and its affiliates during 1996 in which the Partnership
participates as a co-general partner will also be paid by the General
Partner.
6.2 All other Partnership costs and expenses will be charged 99% to
the accounts of the Limited Partners and 1% to the account of the General
Partner until such time as the Aggregate Subscription has been fully
expended. Thereafter and until the General Partner's Minimum Capital
Contribution has been fully expended, all of such costs and expenses will
be charged to the General Partner. After the General Partner's Minimum
Capital Contribution has been fully expended, such costs and expenses
will be charged to the respective accounts of the General Partner and the
Limited Partners on the basis of their respective Percentages.
6.3 All Partnership Revenues will be allocated between the General
Partner and the Limited Partners on the basis of their respective
Percentages.
6.4 Partnership costs, expenses and Revenues which are charged and
allocated to the Limited Partners shall be charged and allocated to their
respective accounts in the proportion the Units of each Limited Partner
bear to the total number of outstanding Units.
6.5 Capital accounts shall be established and maintained for each
Partner in accordance with tax accounting principles and with valid
regulations issued by the U.S. Treasury Department under subsection
704(b) (the "704 Regulations") of the Internal Revenue Code of 1986, as
amended (the "Code"). To the extent that tax accounting principles and
the 704 Regulations may conflict, the latter shall control. In connec-
tion with the establishment and maintenance of such capital accounts, the
following provisions shall apply:
(a) Each Partner's capital account shall be (i) increased by
the amount of money contributed by him or her to the Partnership,
the fair market value of property contributed by him or her to the
Partnership (net of liabilities securing such contributed property
that the Partnership is considered to assume or take subject to
under section 752 of the Code) and allocations to him or her of
Partnership income and gain (except to the extent such income or
gain has previously been reflected in his or her capital account by
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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
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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
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(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
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increased a deficit balance in such Limited Partner's capital
account as of the end of the Partnership's taxable year to
which such allocation related (after taking into consideration
the numbered items specified in Subsection 6.5(e) hereof);
(ii) any Limited Partner that is not obligated to
restore any deficit balance in such Limited Partner's capital
account who unexpectedly receives an adjustment, allocation or
distribution specified in Subsection 6.5(e) hereof shall be
allocated items of income and gain in an amount and manner
sufficient to eliminate such deficit balance as quickly as
possible; and
(iii) in the event any allocations of loss, deduc-
tion, credit or allowance are made to a Limited Partner or the
General Partner pursuant to clause (i) of this Subsection
6.6(e), then such Limited Partner and/or the General Partner
shall be subsequently allocated all items of income and gain
pro rata as they were allocated the item(s) of loss, deduction,
credit or allowance under such clause (i) until the aggregate
amount of such allocations of income and gain is equal to the
aggregate amount of any such allocations of loss, deduction,
credit or allowance allocated to such Partner(s) pursuant to
clause (i) of this Subsection 6.6(e).
(f) Notwithstanding any other provision of this Agreement, if,
under any provision of this Agreement, the capital account of any
Partner is adjusted to reflect the difference between the basis to
the Partnership of Partnership Property and such property's fair
market value, then all items of income, gain, loss and deduction
with respect to such property shall be allocated among the Partners
so as to take account of the variation between the basis of such
property and its fair market value at the time of the adjustment to
such Partner's capital account in accordance with the requirements
of subsection 704(c) of the Code, or in the same manner as provided
under subsection 704(c) of the Code.
6.7 Notwithstanding anything to the contrary that may be expressed
or implied in this Agreement, the interest of the General Partner in each
material item of Partnership income, gain, loss, deduction or credit
shall be equal to at least one percent of each such item at all times
during the existence of the Partnership. In determining the General
Partner's interest in such items, Units owned by the General Partner
shall not be taken into account.
6.8 Except as provided in subsections (a) through (d) of this
Section 6.8, in the case of a change in a Partner's interest in the
Partnership during a taxable year of the Partnership, all Partnership
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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.
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ARTICLE VII
Fiscal Year, Accountings and Reports
7.1 Unless the Code requires otherwise, the fiscal year of the
Partnership will be the calendar year and the books of the Partnership
will be kept in accordance with usual and customary accounting practices
on the accrual method.
7.2 Within sixty (60) days after the end of each quarter of each
Partnership fiscal year, each person who was a Limited Partner during
such period will be furnished a report setting forth the source and
disposition of Partnership funds during the quarter.
7.3 Not later than the end of the fiscal year in which all
Partnership Wells are drilled and completed, and sufficient production
history has been obtained on Partnership Wells to evaluate properly the
reserves attributable thereto, the General Partner will make an evalua-
tion of Partnership Properties as of the last day of such fiscal year.
The report shall include an estimate of the total oil and gas proven
reserves of the Partnership and the dollar value thereof and the value of
the Limited Partner's interest in such reserve value. It shall also
contain an estimate of the present worth of the reserves. Each Limited
Partner will receive a summary statement of such report reflecting the
Limited Partners' interest in such reserve value.
ARTICLE VIII
Tax Returns and Elections
8.1 Unless the Code requires otherwise, the General Partner will
cause the Partnership to elect the calendar year as its taxable year and
will timely file all Partnership income tax returns required to be filed
by the jurisdictions in which the Partnership conducts business or
derives income. By March 15 of each year or as soon thereafter as
practicable, the General Partner will furnish all available information
necessary for inclusion in the income tax returns of each person who was
a Limited Partner during the prior fiscal year. The General Partner
shall be the "Tax Matters Partner" for the Partnership pursuant to the
provisions of Section 6231 of the Code subject to the provisions of
Section 10.22 below.
8.2 The Partnership will elect to deduct intangible drilling and
development costs currently as an expense for income tax purposes and
will elect to use the available depreciation method which, in the General
Partner's judgment, is in the best interest of the Partners.
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8.3 The General Partner shall have the right in its sole discretion
at any time to make or not to make such other elections as are authorized
or permitted by any law or regulation for income tax purposes (including
any election under Section 754 of the Code).
ARTICLE IX
Distributions
9.1 The Partnership's available cash will be distributed to the
Limited Partners and the General Partner in the same proportions that
Partnership Revenue has been allocated to them after giving effect to
previous distributions and to portions of such revenue theretofore used
or retained to pay costs incurred or expected to be incurred in con-
ducting Partnership operations or to repay borrowings theretofore or
expected to be thereafter obtained by the Partnership. Within forty-five
(45) days after the end of each calendar quarter, the General Partner
will determine the amount of cash available for distribution to the
Limited Partners and will distribute such amount, if any, as promptly
thereafter as reasonably possible. Distributions of cash to the General
Partner may be at any time the General Partner determines there is cash
available therefor. The General Partner's determination of the cash
available for distribution will be conclusive and binding upon all
Partners. All Partnership funds distributed to the Limited Partners
shall be distributed to the persons who were record holders of Units on
the day on which the distribution is made.
ARTICLE X
Rights, Duties and Obligations of the General Partner
10.1 Subject to the limitations of this Agreement, the General
Partner will have full, exclusive and complete discretion in the
management and control of the business of the Partnership and will make
all decisions affecting its business and affairs or the Partnership
Properties. The General Partner will have, subject to the provisions of
this Article X, full power and authority to take any action described in
Article III above and execute and deliver in the name of and on behalf of
the Partnership such documents or instruments as the General Partner
deems appropriate for the conduct of Partnership business. No person,
firm or corporation dealing with the Partnership will be required to
inquire into the authority of the General Partner to take any action or
make any decision.
10.2 The General Partner will perform the duties imposed upon it
under this Agreement in an efficient and businesslike manner with due
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caution and in accordance with established practices of the oil and gas
industry, but the General Partner shall not be liable, responsible or
accountable in damages or otherwise to the Partnership or any of the
Partners for, and the Partnership shall indemnify, defend against and
save harmless the General Partner, from any expense (including attorneys'
fees), loss or damage incurred by reason of any act or omission performed
or omitted in good faith on behalf of the Partnership or the Partners,
and in a manner reasonably believed by the General Partner to be within
the scope of the authority granted by this Agreement and in the best
interests of the Partnership or the Partners, provided that the General
Partner is not guilty of gross negligence or willful misconduct with
respect to such acts or omissions, and further provided that the
satisfaction of any indemnification and any saving harmless shall be from
and limited to Partnership assets including insurance proceeds, if any,
and no Partner shall have any personal liability on account thereof. For
purposes of this Section 10.2 only, the term General Partner includes the
General Partner, affiliates of the General Partner and any officer,
director or employee of the General Partner or any of its affiliates such
that all of such parties are covered by the indemnities provided herein.
10.3 The General Partner will utilize its organization and employees
and will hire outside consultants for the Partnership as necessary in
order to provide experienced, qualified and competent personnel to
conduct the Partnership's business. With certain limited exceptions it
is the intent of the Partners that the Partnership participate as a co-general
partner of any oil and gas drilling or income programs, or both, formed by the
General Partner or UNIT for third party investors during
1996 and to participate on a proportionate working interest basis in each
producing oil and gas lease acquired and in the drilling of each oil and
gas well commenced by the General Partner or UNIT for its own account
during the period from the later of January 1, 1996 or the Effective Date
through December 31, 1996 (except for wells, if any, (i) drilled outside
of the 48 contiguous United States; (ii) drilled as part of secondary or
tertiary recovery operations which were in existence prior to the
formation of the Partnership; (iii) drilled by third parties under farm-out or
similar arrangements with the General Partner or UNIT or whereby the General
Partner or UNIT may be entitled to an overriding royalty,
reversionary or other similar interest in the production from such wells
but is not obligated to pay any of the Drilling Costs thereof; (iv)
acquired by UNIT or the General Partner through the acquisition by UNIT
or the General Partner of, or merger of UNIT or the General Partner with,
other companies; or (v) with respect to which the General Partner does
not believe that the potential economic return therefrom justifies the
costs of participation by the Partnership).
10.4 The General Partner, UNIT or any affiliate thereof will
transfer to the Partnership interests in oil and gas properties com-
prising the spacing unit on which a Partnership Well is located or is to
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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
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sole judgment deems appropriate in light of the area, any applicable
drilling or expiration dates and any other material factors.
10.7 Partnership Properties shall be transferred to the Partnership
after the decision to acquire a productive property or the commitment to
drill a Partnership Well thereon has been made. The Partnership shall
acquire interests in only those properties of the General Partner or UNIT
which comprise the spacing unit on which the Partnership Well is drilled
or on which a producing Partnership Well is located. If a spacing unit
on which a Partnership Well is drilled or located is ever reduced, or any
subsequent well in which the Partnership has no interest is drilled
thereon, the Partnership will have no interest in any such subsequent or
additional wells drilled on properties which were a part of the original
spacing unit unless any such additional well is commenced during 1996 or
is drilled by a drilling or income program of which the Partnership is a
partner. Likewise if UNIT, UPC or any affiliate, including any oil and
gas partnership subsequently formed for investment or participation by
employees, directors and/or consultants of UNIT or any of its
subsidiaries, acquires additional interests in Partnership Wells after
1996 the Partnership generally will not be entitled to participate in the
acquisition of such additional interests. In addition, if a Partnership
Well drilled on a spacing unit is dry or abandoned, the Partnership will
not have an interest in any subsequent or additional well drilled on the
spacing unit unless it is commenced during 1996 or is drilled by a
drilling or income program of which the Partnership is a partner.
10.8 The General Partner, UNIT or its affiliates will either conduct
the Partnership's drilling and production operations and operate each
Partnership Well or arrange for a third party operator to conduct such
operations. The General Partner will, on behalf of the Partnership,
enter into appropriate operating agreements with other owners of
Partnership Wells authorizing the General Partner, its affiliates or a
third party operator to conduct such operations. The Partnership will
take such action in connection with operations pursuant to said operating
agreements as the General Partner, in its sole discretion, deems
appropriate and in the best interests of the Partnership, and the
decision of the General Partner with respect thereto will be binding upon
the Partnership.
10.9 The General Partner will cause the Partnership to plug and
abandon its dry holes and abandoned wells in accordance with rules and
regulations of the governmental regulatory body having jurisdiction.
10.10 The General Partner may pool or unitize Partnership Proper-
ties with other oil and gas properties when such pooling or unitization
is required by a governmental regulatory body, when well spacing as
determined by any such body requires such pooling or unitization, or
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when, in the General Partner's opinion, such pooling or unitization is in
the best interests of the Partnership.
10.11 The General Partner will have authority to make and enter
into contracts for the sale of the Partnership's share of oil or gas
production from Partnership Wells, including contracts for the sale of
such production to the General Partner, UNIT or its affiliates; provided,
however, that the production purchased by the General Partner, UNIT or
any of its affiliates will be for prices which are not less than the
highest posted price (in the case of crude oil production) or prevailing
price (in the case of natural gas production) in the same field or area.
10.12 The General Partner will use its best efforts to procure and
maintain for the Partnership, and at its expense, such insurance coverage
with responsible companies as may be reasonably available for such
premium costs as would not be considered to be unreasonably high or
prohibitive with respect to each item of coverage and as the General
Partner considers necessary for the protection of the Partnership and the
Partners. The coverage will be in such amounts and will cover such risks
as the General Partner believes warranted by the operations conducted
hereunder. Such risks may include but will not necessarily be limited to
public liability and automobile liability, each covering bodily injury,
death and property damage, workmen's compensation and employer's
liability insurance and blowout and control of well insurance.
10.13 In order to conduct properly the business of the Partnership,
and in order to keep the Partners properly informed, the General Partner
will:
(a) maintain adequate records and files identifying the
Partnership Properties and containing all pertinent information in
regard thereto that is obtained or developed pursuant to this
Agreement;
(b) maintain a complete and accurate record of the acquisition
and disposition of each Partnership Property;
(c) maintain appropriate books and records reflecting the
Partnership's revenue and expense and each Partner's participation
therein;
(d) maintain a capital account for each Partner with appro-
priate records as necessary in order to reflect each Partner's
interest in the Partnership and furnish required tax information;
and
(e) keep the Limited Partners informed by means of written
reports on the acquisition of Partnership Properties and the
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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.
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10.18 The General Partner may cause the Partnership to hold
Partnership Properties in the Partnership's name, or in the name of the
General Partner, UNIT, any affiliates thereof or some third party as
nominee for the Partnership. If record title to a Partnership Property
is to be held permanently in the name of a nominee, such nominee
arrangement will be evidenced and documented by a nominee agreement
identifying the Partnership Properties so held and disclaiming any
beneficial interest therein by the nominee.
10.19 The General Partner will be generally liable for the debts
and obligations of the Partnership, provided that any claims against the
Partnership shall be satisfied first out of the assets of the Partnership
and only thereafter out of the separate assets of the General Partner.
10.20 The Partnership may not make any loans to the General
Partner, UNIT or any of its affiliates.
10.21 The General Partner will use its best efforts at all times
to maintain its net worth at a level that is sufficient to insure that
the Partnership will be classified for federal income tax purposes as a
partnership, rather than as an association taxable as a corporation, on
account of the net worth of the General Partner.
10.22 The Tax Matters Partner designated in Section 8.1 above is
authorized to engage legal counsel and accountants and to incur expense
on behalf of the Partnership in contesting, challenging and defending
against any audits, assessments and administrative or judicial proceed-
ings conducted or participated in by the Internal Revenue Service with
respect to the Partnership's operations and affairs.
10.23 At any time two years or more after the Partnership has
completed substantially all of its property acquisition, drilling and
development operations, the General Partner may, without the vote,
consent or approval of the Limited Partners, cause all or substantially
all of the oil and gas properties and other assets of the Partnership to
be sold, assigned or transferred to, or the Partnership merged or
consolidated with, another partnership or a corporation, trust or other
entity for the purpose of combining the assets of two or more of the oil
and gas partnerships formed for investment or participation by employees,
directors and/or consultants of UNIT or any of its subsidiaries;
provided, however, that the valuation of the oil and gas properties and
other assets of all such participating partnerships for purposes of such
transfer or combination shall be made on a consistent basis and in a
manner which the General Partner and UNIT believe is fair and equitable
to the Limited Partners. As a consequence of any such transfer or
combination, the Partnership shall be dissolved and terminated pursuant
to Article XVI hereof and the Limited Partners shall receive partnership
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interests, stock or other equity interests in the transferee or resulting
entity.
ARTICLE XI
Compensation and Reimbursements
11.1 For the General Partner's services performed as operator of
productive Partnership Wells located on Partnership Properties and as
operator during the drilling of Partnership Wells, the Partnership will
compensate the General Partner at rates no higher than those normally
charged in the same or a comparable geographic area by non-affiliated
persons or companies dealing at arm's length. The General Partner will
not receive compensation for such services performed in connection with
the operation of Partnership Wells operated by third party operators, but
such third party operators will be compensated as provided in the
operating agreements in effect with respect to such wells and the
Partnership will pay its proportionate share of such compensation.
11.2 The General Partner will be reimbursed by the Partnership out
of Partnership Revenues for that portion of its general and administra-
tive overhead expense that is attributable to its conduct of the actual
and necessary business, affairs and operations of the Partnership. The
General Partner's general and administrative overhead expenses will be
determined in accordance with industry practices. The allocable costs
and expenses will include all customary and routine legal, accounting,
geological, engineering, travel, office rent, telephone, secretarial,
salaries, data processing, word processing and other incidental reason-
able expenses necessary to the conduct of the Partnership's business and
generated by the General Partner or allocated to it by UNIT, but will not
include filing fees, commissions, professional fees, printing costs and
other expenses incurred in forming the Partnership or offering interests
therein. Also excluded will be any general and administrative overhead
expense of the General Partner or UNIT which may be attributable to its
services as an operator of Partnership Wells for which it receives
compensation pursuant to Section 11.1 above. The portion of the General
Partner's general and administrative overhead expense to be reimbursed by
the Partnership with respect to any particular period will be determined
by allocating to the Partnership that portion of the General Partner's
total general and administrative overhead expense incurred during such
period which is equal to the ratio of the Partnership's total
expenditures compared to the total expenditures by the General Partner
for its own account. The portion of such general and administrative
overhead expense reimbursement which is charged to the Limited Partners
may not exceed an amount equal to 3% of the Aggregate Subscription during
the first 12 months of the Partnership's operations, and in each
succeeding twelve-month period, the lesser of (a) 2% of the Aggregate
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Subscription and (b) 10% of the total Partnership Revenue realized in
such twelve-month period. Administrative expenses incurred directly by
the Partnership, or incurred by the General Partner on behalf of the
Partnership and reimbursable to the General Partner, such as legal,
accounting, auditing, reporting, engineering, mailing and other such
fees, costs and expenses are not to be deemed a part of the general and
administrative expense of the General Partner which is to be reimbursed
pursuant to this Section 11.2 and the amounts thereof will not be subject
to the limitations described in the preceding sentence.
ARTICLE XII
Rights and Obligations of Limited Partners
12.1 The Limited Partners, in their capacity as such, cannot
transact any business for the Partnership or take part in the control of
its business or management of its affairs. Limited Partners will have no
power to execute any agreements on behalf of, or otherwise bind or
commit, the Partnership. They may give consents and approvals as herein
provided and exercise the rights and powers granted to them in this
Agreement, it being understood that the exercise of such rights and
powers will be deemed to be matters affecting the basic structure of the
Partnership and not the exercise of control over its business; provided,
however, that exercise of any of the rights and powers granted to the
Limited Partners in Sections 10.15, 12.3, 14.1, 16.1 and 18.1 will not be
authorized or effective unless prior to the exercise thereof the General
Partner is furnished an opinion of counsel for the Partnership or an
order or judgment of any court of competent jurisdiction to the effect
that the exercise of such rights or powers (i) will not be deemed to
evidence that the Limited Partners are taking part in the control of or
management of the Partnership's business and affairs, (ii) will not
result in the loss of any Limited Partner's limited liability and (iii)
will not result in the Partnership being classified as an association
taxable as a corporation for federal income tax purposes.
12.2 The Limited Partners will not be personally liable for any
debts or losses of the Partnership. Except as otherwise specifically
provided herein, no Partner will be responsible for losses of any other
Partners.
12.3 Except as otherwise provided in this Agreement, no Limited
Partner will be entitled to the return of his contribution. Distribu-
tions of Partnership assets pursuant to this Agreement may be considered
and treated as returns of contributions if so designated by law or,
subject to Section 12.1, by agreement of the General Partner and Limited
Partners holding a majority of the outstanding Units. The value of a
Limited Partner's undistributed contribution determined for the purposes
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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
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(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
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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
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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
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the transferring General Partner will, upon making a proper accounting to
the substitute General Partner, be relieved of any further duties or
obligations hereunder with respect to Partnership operations thereafter
occurring.
ARTICLE XV
Limited Partners' Right of Presentment
15.1 After December 31, 1997, each Limited Partner will have the
option, subject to the terms and conditions set forth in this Article XV,
to require the General Partner to purchase all (but not less than all) of
his or her Units, provided that the option may not be exercised after the
date of any notice that will effect a dissolution and termination of the
Partnership pursuant to Article XVI below. Any such exercise shall be
effected by written notice thereof delivered to the General Partner.
15.2 Sales of Limited Partners' Units pursuant to this Article XV
will be effective, and the purchase price for such interests will be
determined, as of the close of business on the last day of the calendar
year in which the Limited Partner's notice exercising his or her option
is given, or, at the General Partner's election, as of 7:00 o'clock A.M.
on the following day.
15.3 The purchase price to be paid for the Units of any Limited
Partner who exercises the option granted in this Article XV will be
determined in the following manner. First, future gross revenues
expected to be derived from the production and sale of the proved
reserves attributable to Partnership Properties will be estimated, as of
the end of the calendar year in which presentment is made, by the
independent engineering firm preparing a report on the reserves of the
Partnership, or if no such firm is preparing a report as of the end of
the calendar year in which the option is exercised, then by the General
Partner. Next, future net revenues will be calculated by deducting
anticipated expenses (including Operating Expenses and other costs that
will be incurred in producing and marketing such reserves and any gross
production, excise, or other taxes, other than federal income taxes,
based on the oil and gas production of the Partnership or sales thereof)
from estimated future gross revenues. The estimates of price and cost
escalations to be used in such calculations will be those of such
independent engineering firm or the General Partner, whichever is making
the determination. Then the present worth of the future net revenues
will be calculated by discounting the estimated future net revenues at
that rate per annum which is one (1) percentage point higher than the
prime rate of interest being charged by Bank of Oklahoma, N.A., Tulsa,
Oklahoma, or any successor bank, as such prime rate of interest is
announced by said bank as of the date such reserves are estimated. This
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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
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be entitled to priority in the following year. Contemporaneously with
the closing of any such sale, the Limited Partner will execute such
certificates or other documents and perform such acts as the General
Partner deems necessary to effect the sale and transfer of the
liquidating Limited Partner's Units to the General Partner and to
preserve the limited liability status of the Partnership under the laws
of the jurisdictions in which it is doing business.
15.5 As used in Sections 15.3 and 15.4 above, the term "proved
reserves" shall have the meaning ascribed thereto in Regulation S-X
adopted by the Securities and Exchange Commission.
ARTICLE XVI
Termination and Dissolution of Partnership
16.1 The Partnership will terminate automatically on December 31,
2026, unless prior thereto, subject to Section 12.1 above, the General
Partner or Limited Partners holding a majority of the outstanding Units
elect to terminate the Partnership as of an earlier date. In the event
of such earlier termination, ninety (90) days' written notice will be
given to all other Partners. The termination date will be specified in
such notice and must be the last day of any calendar month following
expiration of the ninety (90) day period unless an earlier date is
approved by Limited Partners holding a majority of the outstanding Units.
16.2 Upon the dissolution (other than pursuant to a merger or other
corporate reorganization), bankruptcy, legal disability or withdrawal of
the General Partner (other than pursuant to Section 14.1 above), the
Partnership shall immediately be dissolved and terminated; provided,
however, that nothing in this Agreement shall impair, restrict or limit
the rights and powers of the Partners under the laws of the State of
Oklahoma and any other jurisdiction in which the Partnership is doing
business to reform and reconstitute themselves as a limited partnership
within ninety (90) days following the dissolution of the Partnership
either under provisions identical to those set forth herein or under any
other provisions. The withdrawal, expulsion, dissolution, death, legal
disability, bankruptcy or insolvency of any Limited Partner will not
effect a dissolution or termination of the Partnership.
16.3 Upon termination of the Partnership by action of the Limited
Partners pursuant to Section 16.1 hereof or as a result of an event under
Section 16.2 hereof, a party designated by the Limited Partners holding
a majority of the outstanding Units will act as Liquidating Trustee. In
any other case, the General Partner will act as Liquidating Trustee.
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16.4 As soon as possible after December 31, 2026, or the date of the
notice of or event causing an earlier termination of the Partnership, the
Liquidating Trustee will begin to wind up the Partnership's business and
affairs. In this regard:
(a) The Liquidating Trustee will furnish or obtain an
accounting with respect to all Partnership accounts and the account
of each Partner and with respect to the Partnership's assets and
liabilities and its operations from the date of the last previous
audit of the Partnership to the date of such dissolution;
(b) The Liquidating Trustee may, in its discretion, sell any
or all productive and non-productive properties which, except in the
case of an election by the General Partner to terminate the
Partnership prior to the tenth anniversary of the Effective Date,
may be sold to the General Partner or any of its affiliates for
their fair market value as determined in good faith by the General
Partner;
(c) The Liquidating Trustee shall:
(i) pay all of the Partnership's debts, liabilities and
obligations to its creditors, including the General Partner;
and
(ii) pay all expenses incurred in connection with the
termination, liquidation and dissolution of the Partnership and
distribution of its assets as herein provided;
(d) The Liquidating Trustee shall ascertain the fair market
value by appraisal or other reasonable means of all assets of the
Partnership remaining unsold, and each Partner's capital account
shall be charged or credited, as the case may be, as if such
property had been sold at such fair market value and the gain or
loss realized thereby had been allocated to and among the Partners
in accordance with Article VI hereof; and
(e) On or as soon as practicable after the effective date of
the termination, all remaining cash and any other properties and
assets of the Partnership not sold pursuant to the preceding
subsections of this Section 16.4 will be distributed to the Partners
(i) in proportion to and to the extent of any remaining balances in
the Partners' capital accounts and then (ii) in undivided interests
to the Partners in the same proportions that Partnership Revenues
are being shared at the time of such termination, provided, that:
(i) the various interests distributed to the respective
Partners will be distributed subject to such liens, encum-
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brances, restrictions, contracts, operating agreements,
obligations, commitments or undertakings as existed with
respect to such interests at the time they were acquired by the
Partnership or were subsequently created or entered into by the
Partnership;
(ii) if interests in the Partnership Wells that are not
subject to any operating agreement are to be distributed, the
Partners will, concurrently with the distribution, enter into
standard form operating agreements covering the subsequent
operation of each such well which will, if the termination is
effected pursuant to Section 16.1 above, be in a form satis-
factory to the General Partner and will name the General
Partner or its designee as operator; and
(iii) no Partner shall be distributed an interest in
any asset if the distribution would result in a deficit balance
or increase the deficit balance in its capital account (after
making the adjustments referred to in this Section 16.4
relating to distributions in kind).
16.5 If the General Partner has a deficit balance in its capital
account following the distribution(s) provided for in Section 16.4(e)
above, as determined after taking into account all adjustments to its
capital account for the taxable year of the Partnership during which such
distribution occurs, it shall restore the amount of such deficit balance
to the Partnership within ninety (90) days and such amount shall be
distributed to the other Partners in accordance with their positive
capital account balances.
16.6 Notwithstanding anything to the contrary in this Agreement,
upon the dissolution and termination of the Partnership, the General
Partner will contribute to the Partnership the lesser of: (a) the deficit
balance in its capital account; or (b) the excess of 1.01 percent of the
total Capital Contributions of the Limited Partners over the capital
previously contributed by the General Partner.
ARTICLE XVII
Notices
17.1 All notices, consents, requests, demands, offers, reports and
other communications required or permitted shall be deemed to be given or
made when personally delivered to the party entitled thereto, or when
sent by United States mail in a sealed envelope, with postage prepaid,
addressed, if to the General Partner, to 1000 Kensington Tower I, 7130
South Lewis Avenue, P. O. Box 702500, Tulsa, Oklahoma 74136, and, if to
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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,
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such counsel must be qualified and experienced in the fields of federal
income taxation and partnership and securities laws.
19.3 This Agreement and the Subscription Agreement may be executed
in multiple counterpart copies, each of which will be considered an
original and all of which constitute one and the same instrument.
19.4 This Agreement will be deemed to have been executed and
delivered in the State of Oklahoma and will be construed and interpreted
according to the laws of that State.
19.5 This Agreement and all of the terms and provisions hereof will
be binding upon and will inure to the benefit of the Partners and their
respective heirs, executors, administrators, trustees, successors and
assigns.
EXECUTED in the name of and on behalf of the undersigned General
Partner this _____ day of ________________, 1996 but effective as of the
Effective Date.
"General Partner"
UNIT PETROLEUM COMPANY
Attest:
By By
Mark E. Schell, Secretary John G. Nikkel, President
(CORPORATE SEAL)
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<PAGE>
LIMITED PARTNER SUBSCRIPTION AGREEMENT AND
SUITABILITY STATEMENT
(ALL INFORMATION WILL BE TREATED CONFIDENTIALLY)
Unit 1996 Employee Oil and Gas Limited Partnership
c/o Unit Petroleum Company
1000 Kensington Center
7130 South Lewis Avenue
Tulsa, Oklahoma 74136
RE: Unit 1996 Employee Oil and
Gas Limited Partnership
Gentlemen:
In connection with the subscription of the undersigned
for units of limited partnership interest ("Units") in Unit 1996
Employee Oil and Gas Limited Partnership (the "Partnership") which
the undersigned tenders herewith to Unit Petroleum Company (the
"General Partner"), the undersigned is hereby furnishing the
Partnership and the General Partner the information set forth
herein below and makes the representations and warranties set forth
below, to indicate whether the undersigned is a suitable subscriber
for Units in the Partnership. As a condition precedent to
investing in the Partnership, the undersigned hereby represents,
warrants, covenants and agrees as follows:
1. The undersigned acknowledges that he or she has
received and reviewed a copy of the Private Offering Memorandum
(the "Offering Memorandum") dated January 3, 1996, of Unit 1996
Employee Oil and Gas Limited Partnership, relating to the offering
of Units in the Partnership, and all Exhibits thereto, including
the Agreement of Limited Partnership (the "Agreement"), and
understands that the Units will be offered to others on the terms
and in the manner described in the Offering Memorandum. The
undersigned hereby subscribes for the number of Units set forth
below pursuant to the terms of the Offering Memorandum and tenders
his or her Capital Subscription as required and agrees to pay his
or her Additional Assessments upon call or calls by the General
Partner; and the undersigned acknowledges that he or she shall have
the right to withdraw this subscription only up until the time the
General Partner executes and accepts the undersigned's subscription
and that the General Partner may reject any subscription for any
reason without liability to it; and, further, the undersigned
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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
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<PAGE>
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
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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
---
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(ii) The undersigned is a salaried employee of
Unit Corporation ("UNIT") or any of its subsidiaries at
the date of formation of the Partnership whose annual
base salary for 1996 has been set at $22,680 or more, or
the undersigned is a director of UNIT;
____ YES ____ NO
and
(e) The undersigned _____ is or _____ is not a
citizen of the United States.
12. The undersigned represents and agrees that he or she
has had sufficient opportunity to make inquiries of the General
Partner in order to supplement information contained in the
Offering Memorandum respecting the offering, and that any
information so requested has been made available to his or her
satisfaction, and he or she has had the opportunity to verify such
information. The undersigned further agrees and represents that he
or she has knowledge and experience in business and financial
matters, and with respect to investments generally, and in
particular, investments generally comparable to the offering, so as
to enable him or her to utilize such information to evaluate the
risks of this investment and to make an informed investment
decision. The following is a brief description of the
undersigned's experience in the evaluation of other investments
generally comparable to the offering:
________________________________________________________________
________________________________________________________________
________________________________________________________________
________________________________________________________________
13. The undersigned is aware that the Partnership and
the General Partner have been and are relying upon the
representations and warranties set forth in this Limited Partner
Subscription Agreement and Suitability Statement, in part, in
determining whether the offering meets the conditions specified in
Rules of the Securities and Exchange Commission and the exemption
from registration provided by Sections 3(b) and/or 4(2) of the Act.
14. All of the information which the undersigned has
furnished the General Partner herein or previously with respect to
the undersigned's financial position and business experience is
correct and complete as of the date of this Agreement, and, if
there should be any material change in such information prior to
the closing of the offering period of the Units, the undersigned
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will immediately furnish such revised or corrected information to
the General Partner. The undersigned agrees that the foregoing
representations and warranties shall survive his or her admission
to the Partnership, as well as any acceptance or rejection of a
subscription for the Units.
LIMITED PARTNER SIGNATURE PAGES
If the subscription tendered hereby of the undersigned is
accepted by the General Partner, the undersigned hereby executes
and swears to the Agreement of Limited Partnership of Unit 1996
Employee Oil and Gas Limited Partnership as a Limited Partner,
thereby agreeing to all the terms thereof and duly appoints the
General Partner, with full power of substitution, his or her true
and lawful attorney to execute, file, swear to and record any
Certificate of Limited Partnership or amendments thereto or
cancellation thereof and any other instruments which may be
required by law in any jurisdiction to permit qualification of the
Partnership as a limited partnership or for any other purposes
necessary to implement the Partnership's purposes.
THE SECURITIES REPRESENTED BY THIS CERTIFICATE HAVE NOT
BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, THE
OKLAHOMA SECURITIES ACT OR OTHER APPLICABLE STATE SECURITIES ACTS.
THE SECURITIES HAVE BEEN ACQUIRED FOR INVESTMENT AND MAY NOT BE
SOLD OR TRANSFERRED FOR VALUE IN THE ABSENCE OF AN EFFECTIVE
REGISTRATION OF THEM UNDER THE SECURITIES ACT OF 1933, AS AMENDED,
AND/OR THE OKLAHOMA SECURITIES ACT, OR ANY OTHER APPLICABLE ACT, OR
AN OPINION OF COUNSEL TO UNIT 1996 EMPLOYEE OIL AND GAS LIMITED
PARTNERSHIP THAT SUCH REGISTRATION IS NOT REQUIRED UNDER SUCH ACT.
The undersigned hereby subscribes for _____ Units
(minimum subscription: 2 Units) at a price of $1,000 per Unit for
a total Capital Subscription (as defined in Article II of the
Agreement) of $________________, which shall be due and payable
either:
(Check One)
_______ (a) in four equal installments on March 15, 1996, June
15, 1996, September 15, 1996 and December 15, 1996, respectively;
or
_______ (b) through equal deductions from 1996 salary of the
undersigned commencing immediately after the Effective Date (as
defined in Article II of the Agreement).
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<PAGE>
RESIDENT
LIMITED PARTNER ADDRESS (If placing Units
in the name of spouse
________________ _________________ or trustee for minor
child or children,
________________ _________________ please provide name,
Signature address of such spouse
or trustee and Social
________________ Mailing Address Security or Tax
Please Print Name if different: Identification Number)
TAX I.D. OR
_________________ SOCIAL SECURITY NO.
Date: ___________ _________________ ___________________
ACCEPTED THIS _____ DAY OF ________, 1996.
UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
By ____________________________________
Authorized Officer of Unit
Petroleum Company, General Partner
Upon completion, an executed copy of this Limited Partner
Subscription Agreement and Suitability Statement should be returned
to Unit 1996 Employee Oil and Gas Limited Partnership, Attention
Mark E. Schell, 1000 Kensington Tower I, 7130 South Lewis Avenue,
Tulsa, Oklahoma, 74136. The General Partner, after acceptance,
will return a copy of the accepted Subscription Agreement to the
Limited Partner.
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<PAGE>
EXHIBIT B
<PAGE>
"CONNER & WINTERS" Letter Head
A Professional Corporation
Lawyers
2400 First National Tower
15 East Fifth Street
Tulsa, Oklahoma 74103-4391
(981) 586-5711
FAX (918) 586-8982
January 3, 1996
Unit Petroleum Company
1000 Galleria Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
Re: Unit 1996 Employee Oil and Gas Limited Partnership
Gentlemen:
We have acted as counsel for Unit Petroleum Company, an Oklahoma
corporation (the "General Partner"), which will be the General Partner in the
Unit 1996 Employee Oil and Gas Limited Partnership, A proposed Oklahoma
limited partnership (the "Partnership"). You have requested our opinions
regarding (i) the legality of the interests to be issued in the Partnership and
(ii) certain federal income tax matters concerning the Partnership.
We have reviewed and relied upon the accuracy of the facts and information
set forth in the Private Offering Memorandum dated January 3, 1996 (the
"Memorandum"), covering the offer and sale of units of limited partnership
interest ("Units") in the Partnership, the Agreement of Limited Partnership
included as Exhibit A to the Memorandum (the "Partnership Agreement"),
the consolidated balance sheet of the General Partner dated November 30, 1995,
and such other documents and matters as we have considered necessary in order
to render this opinion. Capitalized terms used herein have the meaning
assigned to them in the Memorandum, except as otherwise specifically indicated.
In rendering our opinions we have assumed the accuracy of and relied upon
certain representations made by you. Our opinions are conditioned upon the
initial and continuing accuracy of such representations and of the following
representations provided us:
<PAGE>
Unit Petroleum Company
January 3, 1996
Page 2
1. As of the date of the Memorandum, the Memorandum did not contain any
untrue statement of a material fact or omit to state a material fact required
to be stated therein or necessary to make the statements therein not
misleading.
2. The balance sheet of the General Partner included in the Memorandum
presents fairly its financial position as of the date indicated; said balance
sheet has been prepared in conformity with generally accepted accounting
principles applied on a consistent basis; and since the date of the most recent
balance sheet of the General Partner included in the Memorandum through the
date hereof, there has not been any material adverse change in its financial
position.
3. There is not now pending nor, to the knowledge of the General Partner
of UNIT, threatened any action, suit or proceeding by the Internal Revenue
Service under Sections 6700 or 7408 of the Internal Revenue Code relating to
the promoter penalty referred to in Section 6700 of the Code with respect to
any partnerships sponsored by the General Partner or UNIT. Neither the General
Partner, UNIT, nor, to the knowledge of any of them, any participant in such
partnerships has received any pre-filing notifications referred to in Revenue
Procedure 83-73 with respect to such partnerships or the Partnership from the
Internal Revenue Service.
4. A duly executed certificate of limited partnership for the
Partnership will be filed with the Oklahoma Secretary of State in compliance
with the Act and the organization and operation of the Partnership will be in
accordance with the Act, the Agreement and the representations made in the
Memorandum.
5. General Partner has and will maintain substantial assets which can be
reached by a creditor of the Partnership, exclusive of all interests in the
Partnership and notes and accounts receivable from and payable to the
Partnership. At the time of admission of Limited Partners to the Partnership,
the General Partner will have a minimum net worth equal to at least 10% of the
Capital Contributions made to the Partnership, excluding any net worth
attributable to any interest of the General Partner in the Partnership. For
purposes of this net worth determination, assets will be valued based upon
their current fair market value. The General Partner will use its best efforts
to ensure that the net worth of the General Partner continues to meet or exceed
an amount equal to 10% of the total Capital Contributions of the Limited
Partners in the Partnership.
6. The General Partner will, in the aggregate, at all times during the
existence of the Partnership, receive at least one percent (1%) of each
material item of the Partnership's income, gain, loss, deduction or credit
(other than by reason of the ownership of Units by the General Partner).
7. A nominee/agent agreement ("Nominee Agreement") in substantially the
form of the Nominee Agreement attached hereto as Exhibit I will be executed by
<PAGE>
Unit Petroleum Company
January 3, 1996
Page 3
and between Unit Texas Company, an Oklahoma corporation, as agent, and the
Partnership before any interests in oil and gas properties are acquired in the
name of Unit Texas Company as agent for the Partnership.
8. The terms and provisions of the Nominee Agreement entered into as
provided above will be adhered to by each party thereto and, in particular,
Unit Texas Company will be held out as agent and not the principal in all
dealings with third parties relating to the oil and gas properties which Unit
Texas Company holds as agent for the Partnership.
9. The beneficial ownership of any oil and gas property interests to be
assigned to the Partnership will be assigned to the Partnership by delivery to
Unit Texas Company, as agent for the Partnership, of an enforceable written
assignment, in substantially the form of Exhibit II hereto, properly executed
by the assignor.
10. The General Partner will accept subscriptions for at least 50 Units
in the Partnership by the termination of the offering period.
11. The Partnership Agreement will be duly executed by the General
Partner and the Subscription Agreement will be executed and delivered by those
persons who purchase Units as Limited Partners of the Partnership.
12. In excess of 90 percent of the gross income of the Partnership will be
interest income (excluding interest identified in section 7704(d)(2) of the
Internal Revenue Code), dividends, and gain derived from the exploration,
develpment, mining, or prodution, processing, refining, transportation, or the
marketing of minerals or natural resources, or gain from the sale or disposition
of interests in oil and gas properties or other items described in section 7704
(d) of the Internal Revenue Code.
13. The truth and accuracy of the representations in each of the
Subscription Agreements.
14. There are no other documents or agreements which alter, modify, or
change in any way the validity and accuracy of the above assumption and
information.
Based on the foregoing:
1. Legality of Interests. It is our opinion that the Partnership will
be duly organized and validly existing; the Units will be legally issued, fully
paid and non-assessable except as disclosed in the Memorandum; the Partnership
will be a limited partnership under the Act and the liability of each Limited
Partner will be limited as provided by the Act assuming the Limited Partners
exercise only such rights as are provided in the Partnership Agreement.
<PAGE>
Unit Petroleum Company
January 3, 1996
Page 4
2. Federal Income Tax Aspects. We have provided, as our opinion, the
discussion of various tax matters set forth in the Memorandum under the
headings "Summary of Program -- Federal Income Tax Aspects," "Risk Factors --
Tax Related Risks," and "Federal Income Tax Aspects." We hereby confirm that
the statements under those headings in the Memorandum which attribute certain
opinions to us are correct. In addition, we are of the opinion that such
discussions in the Memorandum address all material tax issues involved in
connection with the offer and sale of Units in the Partnership and that such
discussions fairly summarize federal income tax laws and consequences relating
to the matters set forth therein.
In addition to and not in limitation of the foregoing and taking into
account Circular 230, it is our opinion that (except where there manner or
treatment is stated to be uncertain) the tax treatment set forth in the
Memorandum is more likely than not the proper treatment. The discussions and
conclusions set forth in the Memorandum are based upon our interpretation of
the Internal Revenue Code as amended to date and existing Treasury Regulations,
rules and case law. We can give no assurance that changes in such statutes or
Regulations or in the interpretation thereof will not affect the opinions
herein expressed or the conclusions set forth in the Memorandum. In view of
the changes made by the tax legislation in recent years and the fact that
a number of regulations and interpretations thereof have not been adopted or
issued and by reason of the fact that the recent legislation, as well as
existing regulations and rules, will be subject to new and ongoing judicial and
administrative interpretations, there can be no assurance that the discussions
of tax matters set forth in the Memorandum will not be subject to different
interpretations.
We hereby consent to the inclusion of this opinion as an exhibit to
the Memorandum and to the reference in the Memorandum to our having rendered
such opinion.
Very truly yours,
CONNER & WINTERS,
A Professional Corporation
<PAGE>
EXHIBIT 22.1
<PAGE>
EXHIBIT 22.1
SUBSIDIARIES OF THE REGISTRANT
State or Province Percentage
Subsidiary of Incorporation Owned
- ------------------------------------- ---------------- ----------
Unit Drilling and Exploration Company Delaware 100%
Mountain Front Pipeline Company, Inc. Oklahoma 100%
Unit Drilling Company Oklahoma 100%
Unit Petroleum Company (1) Oklahoma 100%
Petroleum Supply Company Oklahoma 100%
Unit Energy Canada, Inc. Alberta 100%
- -------------
(1) Unit Petroleum Company owns 100% of one subsidiary corporation, namely:
Unit Texas Company Oklahoma
<PAGE>
EXHIBIT 24.1
<PAGE>
EXHIBIT 24.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
Unit Corporation on Form S-8 (File No.'s 33-19652, 33-44103,33-49724, 33-64323
and 33-53542) and Form S-3 (File No. 33-16116) of our report dated February 20,
1996, on our audits of the consolidated financial statements and financial
statement schedule of Unit Corporation as of December 31, 1995 and 1994, and for
the years ended December 31, 1995, 1994 and 1993, which report is included in
this Annual Report on Form 1 0-K.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
March 19, 1996
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
The schedule contains summary financial information extracted from the
Consolidated Financial Statements of Unit Corporation and Subsidiaries under
cover of Form 10-K for December 31, 1995 and is qualified in its entirety by
reference to such financial statements.
</LEGEND>
<CIK> 0000798949
<NAME> UNIT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 534
<SECURITIES> 0
<RECEIVABLES> 10,514
<ALLOWANCES> 116
<INVENTORY> 2,048
<CURRENT-ASSETS> 14,026
<PP&E> 260,771
<DEPRECIATION> 164,752
<TOTAL-ASSETS> 110,922
<CURRENT-LIABILITIES> 11,107
<BONDS> 0
0
0
<COMMON> 4,195
<OTHER-SE> 52,411
<TOTAL-LIABILITY-AND-EQUITY> 110,922
<SALES> 0
<TOTAL-REVENUES> <F1> 53,074
<CGS> 0
<TOTAL-COSTS> <F1> 42,863
<OTHER-EXPENSES> 3,893
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 3,235
<INCOME-PRETAX> 3,083
<INCOME-TAX> (688)
<INCOME-CONTINUING> 3,751
<DISCONTINUED> <F2> 248
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,999
<EPS-PRIMARY> .19
<EPS-DILUTED> .19
<FN>
<F1> Total revenues and total costs were reduced in 1995 as compared to prior
quarters by a business combination in the Company's natural gas marketing
segment which left the Company with a 34 percent equity interest in the new
resulting entity of GED Gas Services, L.L.C..
<F2> GED Gas Services, L.L.C. sold its natual gas marketing operation to a third
party in the fourth quarter of 1995 removing the Company from third party
natural gas marketing operations. Prior year financial information was
restated to present the Company's former natural gas marketing activity as
a discontinued operation.
</FN>
</TABLE>
