<PAGE>
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, 1996
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 information 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 10, 1997 - $171,630,448
Number of Shares of Common Stock
Outstanding on March 10, 1997 - 24,176,734
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 7, 1997 are incorporated by
reference in Part III.
Exhibit Index - See Page 76
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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. . . . . . . . . . . . . . . . . . . . . . . . 18
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . 18
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . 19
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . 21
Item 8. Financial Statements and Supplementary Data. . . . . . . . . . . 29
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure. . . . . . . . . . . . . . . . . . . 65
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . 65
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . 67
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . 67
Item 13. Certain Relationships and Related Transactions . . . . . . . . . 67
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . 68
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
<PAGE>
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1996
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 regional offices in Moore, Oklahoma,
Booker, Texas and 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.
1
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As of December 31, 1996, the Company had 5,204 Mbbls and 129,161 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 located primarily in Oklahoma, Texas, Louisiana and
New Mexico and to a lesser extent in Arkansas, North Dakota, Colorado, Wyo-
ming, Montana, Alabama, Mississippi and Canada. As of December 31, 1996,
the Company had an interest in a total of 2,247 wells in the United States
and served as the operator of 502 wells. The Company also had an interest
in 64 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 explora-
tion 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,
1996 1995 1994
Wells drilled: Gross Net Gross Net Gross Net
- -------------- ------ ------ ------ ------ ------ ------
Exploratory:
Oil.............. - - - - - -
Natural gas...... - - - - 1 .98
Dry.............. - - - - 2 .80
------ ------ ------ ------ ------ ------
Total - - - - 3 1.78
====== ====== ====== ====== ====== ======
Development:
Oil.............. 10 8.35 15 4.70 5 5.00
Natural gas...... 55 19.46 26 7.02 40 13.46
Dry.............. 7 4.26 6 2.27 12 7.26
------ ------ ------ ------ ------ ------
Total 72 32.07 47 13.99 57 25.72
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
- ------------------------------------------------------------
Oil - USA........ 717 197.71 750 207.80 675 177.68
Oil - Canada..... - - - - - -
Gas - USA........ 1,530 242.09 1,820 232.03 1,089 179.99
Gas - Canada..... 64 1.60 65 1.63 61 1.53
------ ------ ------ ------ ------ ------
Total 2,311 441.40 2,635 441.46 1,825 359.20
====== ====== ====== ====== ====== ======
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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
------- ------- ------- -------
1996
----
USA 455,713 115,326 29,245 19,124
Canada 39,040 976 - -
------- ------- ------- -------
Total 494,753 116,302 29,245 19,124
======= ======= ======= =======
1995
----
USA 548,674 117,403 24,810 12,866
Canada 31,360 784 - -
------- ------- ------- -------
Total 580,304 118,187 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
======= ======= ======= =======
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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,
1996 1995 1994
-------- -------- --------
Average sales price per barrel
of oil produced:
USA $ 20.40 $ 16.65 $ 15.13
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 2.21 $ 1.61 $ 1.86
Canada $ 1.18 $ 0.98 $ 1.27
Oil production (Mbbls):
USA 579 577 406
Canada - - -
-------- -------- --------
Total 579 577 406
======== ======== ========
Natural gas production (MMcf):
USA 12,974 12,005 9,606
Canada 51 54 53
-------- -------- --------
Total 13,025 12,059 9,659
======== ======== ========
Average production expense per
equivalent Mcf:
USA $ .68 $ 0.64 $ 0.58
Canada $ .27 $ 0.30 $ 0.37
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,
1996 1995 1994
------- ------- -------
Oil (Mbbls):
USA 5,204 5,428 4,308
Canada - - -
------- ------- -------
Total 5,204 5,428 4,308
======= ======= =======
Natural gas (MMcf):
USA 128,408 107,950 92,566
Canada 753 778 794
------- ------- -------
Total 129,161 108,728 93,360
======= ======= =======
4
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Further information relating to oil and natural gas operations is
presented in Notes 1,4,11 and 13 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
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 compres-
sors, trucks and other support equipment.
In September 1996, the Company purchased one 1,500 horsepower rig and
one 2,500 horsepower rig and 36,000 feet of drill pipe for $1.7 million
bringing the Companies operational rig fleet at December 31, 1996 to 24
with rated depth capacities ranging from 5,000 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. At December 31,
1996, the Company had 3 of its larger horsepower rigs in South 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 in high demand due to increases
in the Company's rig utilization so the Company has increased its drill
pipe acquisitions to maintain current utilization levels. 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 availability of
additional equipment, drill pipe and qualified labor not only within the
Company but in the industry as a whole.
5
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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,
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Number of operational rigs owned
at end of period 24 22 25 25 26
Average number of rigs utilized(1) 14.7 10.9 9.5 8.0 5.5
Number of wells drilled 130 111 95 84 56
Total footage drilled (feet in 1000's) 1,468 1,196 1,027 788 527
- -------------------
(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 10, 1997, 20 of the Company's 24 drilling rigs were oper-
ating under contract.
The following table sets forth, as of March 10, 1997, the type and
approximate depth capability of each of the Company's drilling rigs:
Approximate
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-75A 15,000
BDW 1350-M 20,000
SU-15 North Texas Machine 12,000
SU-15 North Texas Machine 12,000
National 110-UE 20,000
Continental Emsco C-1-E 20,000
Gardner Denver 1500-E 25,000
Mid-Continent 914-EC 20,000
Mid-Continent 1220-EB 25,000
6
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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. In the last 6 months of 1996, the Company's
drilling operations showed significant improvements in rig utilization, but
it is anticipated that competition within the industry 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 conditions 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 1996, turnkey revenue represented approximately 8 percent of
the Company's contract drilling revenues. To date, the Company has not
experienced significant losses in performing turnkey contracts.
7
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Customers. During the fiscal year ended December 31, 1996, 10
contract drilling customers accounted for approximately 22 percent of the
Company's total revenues and approximately 3 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 drill-
ing was pursuant to contracts containing terms and conditions comparable to
those contained in the Company's customary drilling contracts with non-
affiliated operators.
Further information relating to contract drilling operations is
presented in Notes 1 and 11 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 was accounted for as a discontinued operation and accordingly, the
1995 and prior year financial information were 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.
8
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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. 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 com-
petitive. 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 sub-
stantially 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 are 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 8 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 activi-
ties 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.
9
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Under the terms of the partnership agreements of each limited part-
nership, 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 the 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.
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 10, 1997, the Company had approximately 402 employees in
its land contract drilling operations, 59 employees in its oil and natural
gas operations and 25 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 ade-
quate. The Company's insurance policies do not, however, provide protec-
tion 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
10
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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 ex-
pending 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 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 preven-
tion 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 regula-
tions; 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.
11
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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.
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 that 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 firm 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 of 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
12
<PAGE>
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 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. Due to the continuing judicial review of Order 636 and the
continuing 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.
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. For instance, as a result of
Order 636, more interstate pipeline companies have begun divesting their
gathering systems, either to unregulated affiliates or to third persons, a
practice which could result in separate, and higher, rates for gathering a
producer's natural gas. In proceedings during mid and late 1994 allowing
various interstate natural gas companies' spindowns or spinoffs of
gathering facilities, the FERC held that, except in limited circumstances
of abuse, it generally lacks jurisdiction over a pipeline's gathering
affiliates, which neither transport natural gas in interstate commerce nor
sell gas in interstate commerce for resale. However, pipelines spinning
down gathering systems have to include two Order No. 497 standards of
conduct in their tariffs: nondiscriminatory access to transportation for
all sources of supply and no tying of pipeline transportation service to
any service by the pipeline's gathering affiliate. In addition, if unable
to reach a mutually acceptable gathering contract with a present user of
the gathering facilities, the FERC required that the pipeline must offer a two-
year "default contract" to existing users of the gathering facilities. However,
on appeal, while the United States Court of Appeals for the
District of Columbia upheld the FERC's allowing the spinning down of
gathering facilities to a non-regulated affiliate, in Conoco Inc. v. FERC,
90 F.3d 536, 552-53 (D.C. Cir. 1996)the D.C. Circuit remanded the FERC's
default contract mechanism.
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,
13
<PAGE>
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 dramatically 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 Company 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, 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
14
<PAGE>
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.
SAFE HARBOR STATEMENT OF FURTHER 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
or drilling operations, 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.
Statement in this Annual Report on Form 10-K under the captions
"Business" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations", as well as oral statements that may be made by
the Company or by officers, directors or employees of the Company acting on
the Company's behalf, that are not historical facts constitute "forward-
looking statements" within the meaning of the Private Securities Litigation
Reform Act of 1995. Words such as "believes", "anticipates" and similar
expressions, although not inclusive, identify forward-looking statements.
Such forward-looking 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 following discussion outlines certain factors that in the future could
cause the Company's consolidated results for 1997 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.
15
<PAGE>
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 resulting at times in large
difference in such prices even on a month to month basis. 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, 1996, 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 before income taxes of $1,180,000 and $540,000, respectively. During
1996, 97% 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 the 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 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 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.
16
<PAGE>
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, unforseen 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.
17
<PAGE>
Item 3. Legal Proceedings
- --------------------------
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, 1996.
18
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 18, 1997, the Company had 2,862 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:
1996 1995
QUARTER High Low High Low
------- ------- ------- ------- -------
First $ 6 $ 4 $ 3 1/4 $ 2 1/2
Second $ 7 3/8 $ 5 3/4 $ 3 7/8 $ 2 7/8
Third $ 7 1/8 $ 5 1/2 $ 4 1/4 $ 3 1/4
Fourth $10 1/8 $ 5 7/8 $ 4 3/4 $ 3 1/2
19
<PAGE>
Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
1996 1995 1994 1993 1992
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $72,070 $53,074 $43,895 $38,682 $33,744
======= ======= ======= ======= =======
Income From Continuing
Operations $ 8,333 $ 3,751(1) $ 4,628(2) $ 3,937 $ 1,631(3)
======= ======= ======= ======= =======
Net Income $ 8,333 $ 3,999(1) $ 4,794(2) $ 3,871 $ 1,087(3)
======= ======= ======= ======= =======
Earnings Per Common Share:
Continuing Operations:
Primary $.37 $.18(1) $.22(2) $.19 $.08(3)
==== ==== ==== ==== ====
Fully Diluted $.36 $.18(1) $.22(2) $.19 $.08(3)
==== ==== ==== ==== ====
Net Income:
Primary $.37 $.19(1) $.23(2) $.19 $.05(3)
==== ==== ==== ==== ====
Fully Diluted $.36 $.19(1) $.23(2) $.19 $.05(3)
==== ==== ==== ==== ====
Total Assets $137,993 $110,922 $103,933 $ 88,816 $ 83,960
======== ======== ======== ======== ========
Long-Term Debt $ 40,600 $ 41,100 $ 37,824 $ 25,919 $ 22,298
======== ======== ======== ======== ========
Long-Term Portion
of Natural Gas
Purchaser Prepayments $ 2,276 $ 2,109 $ 2,149 $ 4,417 $ 5,924
======== ======== ======== ======== ========
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
20
<PAGE>
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1996, 1995 and 1994 activity.
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------------------------------------------------------------------------
Results of Operations
- ---------------------
Financial Condition and Liquidity
- ---------------------------------
The Company's loan agreement ("Loan Agreement"), provides for a total
commitment of $75 million, consisting of a revolving credit facility
through August 1, 1999 and a term loan thereafter, maturing on August 1,
2003. 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 $52 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, 1996, borrowings under the Loan
Agreement totaled $40.6 million. At February 21, 1997, borrowings under the
Loan Agreement totaled $36.0 million with $13.1 million available for
future borrowings. The interest rate on the bank debt was 7.2 and 7.0
percent at December 31, 1996 and February 21, 1997, 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. 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, 1996
and February 21, 1997, $35.0 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, 1996 was $78.2 million, making
the Company's ratio of long-term debt-to-equity .52 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 1996 was $20.7 million as compared to
$11.2 million in 1995.
The Company's capital expenditures during 1996 were $36.5 million. The
majority of the capital expenditures, $25.6 million, were made in the
Company's oil and natural gas operations with $20.2 million and $2.3
million used for exploration and development drilling and producing
21
<PAGE>
property acquisitions, respectively. Capital expenditures made by the
Company's contract drilling operations were $9.9 million in 1996. The
drilling expenditures principally consisted of the purchase and
refurbishment of two drilling rigs acquired in September 1996, the
refurbishment of two drilling rigs already owned by the Company and the
acquisition of over 110,000 feet of drill pipe. The Company's drilling
rigs are composed of large components some of which, on a rotational basis,
are required to be overhauled to assure continued proper performance. Such
capital expenditures will continue in future years with approximately $6.0
million projected for 1997.
During 1997, the Company's oil and natural gas subsidiary plans to
continue its focus on its developmental drilling as increased spot market
natural gas prices in late 1996 and into early 1997 lessened the
availability of economical producing property acquisitions. The majority
of the Company's capital expenditures are discretionary and primary
directed toward increasing reserves and future growth. Current operations
are not dependent of the Company's ability 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 $31 million on its exploration capital
expenditure program in 1997.
At December 31, 1995, the Company had 2.873 million warrants
outstanding. The warrants entitled the holders to purchase one share of
common stock at a price of $4.375 per share. Prior to the warrants
expiration on August 30, 1996, 2.86 million warrants were exercised
providing $12.5 million in additional capital to the Company.
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,
1996 prepayment balance of $2.3 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"). During 1997, 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 $156,000 or a minimum of
$80,000 per month. The monthly payments will end at the end of 1997.
If natural gas is taken during a month, the value of such natural gas is
credited toward the monthly amount the purchaser is required to pay. In
the event the purchaser takes volumes of natural gas valued in excess of
its monthly payment obligations, the value taken in excess is applied to
reduce any then outstanding Prepayment Balance. The Company currently
believes that sufficient natural gas deliverability is available to enable
the Committed Interest to receive substantially all of the maximum monthly
payments during 1997. At the end of the Recoupment Period, the Settlement
22
<PAGE>
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. 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 $0.6, $1.6 and $1.8
million in 1996, 1995 and 1994, respectively.
Average oil prices received by the Company in 1996 ranged from $16.90
in February to $24.00 in December. The Company's average price received
for oil during 1996 was $20.40. Natural gas prices received by the Company
in 1996 ranged from an average of $1.71 in September to an average of $3.60
in December. Average natural gas prices received by the Company were
volatile throughout 1996 and averaged $2.20 for the year as a whole.
Average oil prices received early in the first quarter of 1997 were 5
percent lower than average prices received by the Company at December 31,
1996 while average natural gas spot prices dropped 10 percent from the
December 31, 1996 price. Oil prices within the industry remain largely
dependent upon world market developments for crude oil. Prices for natural
gas are influenced by weather conditions and supply imbalances,
particularly in the domestic market, and by world wide oil price levels.
Any drop in spot market natural gas prices would have a significant adverse
effect on the value of the Company's reserves and further large drops in
prices 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 Company operationally by, for example, adversely
impacting future demand for its drilling rigs or financially by reducing
the price received for its oil and natural gas sales and also by adversely
effecting 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.
The Company's ability to utilize its full complement of drilling rigs,
is being restricted due to the lack of qualified labor and certain
supporting equipment not only within the Company but in the industry as a
whole. The Company's ability to utilize its drilling rigs at any given
time is dependent on a number of factors, including but not limited to, the
price of both oil and natural gas, the availability of labor and the
Company's ability to supply the type of equipment required. The Company's
management expects that these factors will continue to influence the
Company's rig utilization during 1997.
23
<PAGE>
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, 120,100
shares have been repurchased at prices ranging from $2.5 to $8.275 per
share. During the first quarters of 1996 and 1995, 44,686 and 46,659,
respectively, of the purchased shares were reissued as the Company's
matching contribution to its 401(k) Employee Thrift Plan. At December 31,
1996, 28,755 treasury shares were held by the Company.
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. This 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 was accounted for as a discontinued
operation and accordingly, the 1995 and prior year financial information
reflect this treatment.
Effects of Inflation
- ---------------------
The effects of inflation on the Company's operations in previous years
have been minimal due to low inflation rates. However, during the third
and fourth quarters of 1996 as drilling rig day rates and drilling rig
utilization has increased, the impact of inflation has intensified as
shortages in related equipment, third party services and qualified labor
increased. The impact on the Company in the future will depend on the
relative increase, if any, the Company may realize in its drilling rig
rates and the selling price of its oil and natural gas. If industry
activity continues to increase substantially, shortages in support
equipment such as drill pipe, third party services and qualified labor will
occur resulting in additional corresponding increases in material and labor
costs. These market conditions may limit the Company's ability to realize
improvements in operating profits.
24
<PAGE>
Results of Operations
1996 versus 1995
- ----------------
Net income for 1996 was $8,333,000, compared with $3,999,000 in 1995.
Increased natural gas production from new wells drilled along with higher
oil and natural gas prices, contract drilling day rates and rig utilization
all combined to produce the large increase in 1996 net income. Net income
in 1995 included $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 of 1995, 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 income tax benefit. Net income in the
fourth quarter of 1995 was 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.
Oil and natural gas revenues increased 38 percent in 1996 due to a 8
percent increase in natural gas production combined with a 23 and 37
percent increase in average oil and natural gas prices received by the
Company, respectively. Oil production remained virtually unchanged from
1995 levels. Average natural gas spot market prices received by the Company
increased by 46 percent while volumes produced from certain wells included
under the Settlement Agreement, which contains provisions for prices which
are higher than current spot market prices, dropped by 46 percent. The
impact of higher prices received under the Settlement Agreement increased pre-
tax income by approximately $0.6 and $1.6 million in 1996 and 1995,
respectively.
In 1996, revenues from contract drilling operations increased by 43
percent as average rig utilization increased from 10.9 rigs operating in
1995 to 14.7 rigs operating in 1996, and daywork revenues per rig per day
increased 12 percent. Total daywork revenues represented 68 percent of
total drilling revenues in 1996 and 57 percent in 1995. 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) for the Company's oil
and natural gas operations were 69 percent in 1996 compared to 62 percent
in 1995. Increased operating margins resulted primarily from the increase
in natural gas production and the increases in both oil and natural gas
prices received by the Company between the two years. Total operating costs
increased 12 percent primarily due to the additional costs associated with
oil and natural gas production from new wells drilled in 1996.
Operating margins for contract drilling increased from 11 percent in
1995 to 16 percent in 1996. Margins in 1996 improved due to increases in
daily rig rates and utilization. Margins in 1995 were limited by initial
start up costs incurred in the first quarter of 1995 to establish rigs in
25
<PAGE>
the South Texas Basin and by unusually wet weather conditions during the
second quarter of 1995 which delayed rig moves and depressed rig
utilization. Total operating costs for contract drilling were up 34
percent in 1996 versus 1995 due to increased drilling rig utilization.
Contract drilling depreciation increased 13 percent in response to
increased rig utilization. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 6 percent as the
Company increased its equivalent barrels of production by 6 percent. The
Company's average DD&A rate per equivalent barrel declined from $3.93 in
1995 to $3.90 in 1996.
General and administrative expenses increased 6 percent as certain
employee costs increased between the comparative years. Interest expense
decreased 2 percent as the average interest rate on the Company's
outstanding bank debt decreased from 8.52 percent in 1995 to 7.69 percent
in 1996. The decrease in average interest rate was partially offset by an
8 percent increase in bank debt outstanding in 1996 primarily due to the
financing of new wells drilled and the additional rigs and drill pipe
purchased during 1996.
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 has been fully recognized for financial reporting purposes;
therefore, the Company's effective income tax rate increased in 1996 to
approximately the statutory rate.
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 was 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 economic conditions did 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. 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.
26
<PAGE>
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 were higher than 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.
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 delayed 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.
27
<PAGE>
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.
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 1995 and 1994 was
significantly impacted by its net operating loss carryforwards. As of
December 31, 1995, the Company's net operating loss and statutory depletion
carryforwards had been fully recognized for financial reporting purposes,
resulting in a net deferred tax asset of $530,000 at December 31, 1995.
28
<PAGE>
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
ASSETS 1996 1995
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 547 $ 534
Accounts receivable (less allowance for
doubtful accounts of $104 and $116) 15,842 10,398
Materials and supplies 2,302 2,048
Prepaid expenses and other 1,464 1,046
--------- ---------
Total current assets 20,155 14,026
--------- ---------
Property and Equipment:
Drilling equipment 84,409 75,751
Oil and natural gas properties, on the full
cost method 200,610 175,225
Transportation equipment 2,413 3,695
Other 6,485 6,100
--------- ---------
293,917 260,771
Less accumulated depreciation, depletion,
amortization and impairment 176,211 164,752
--------- ---------
Net property and equipment 117,706 96,019
--------- ---------
Other Assets 132 877
--------- ---------
Total Assets $137,993 $110,922
========= =========
The accompanying notes are an integral part of the
consolidated financial statements
29
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY 1996 1995
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term debt $ - $ 20
Accounts payable 6,893 6,701
Accrued liabilities 4,516 3,976
Contract advances 1,300 410
---------- ----------
Total current liabilities 12,709 11,107
---------- ----------
Natural Gas Purchaser Prepayments (Note 4) 2,276 2,109
---------- ----------
Long-Term Debt 40,600 41,100
---------- ----------
Deferred Income Taxes 4,198 -
---------- ----------
Commitments and Contingencies (Note 10)
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, 24,157,312 and
20,976,090 shares issued, respectively 4,831 4,195
Capital in excess of par value 62,735 50,181
Retained earnings (deficit) 10,751 2,418
Treasury stock, at cost (28,755 and
68,441 shares, respectively) (107) (188)
---------- ----------
Total shareholders' equity 78,210 56,606
---------- ----------
Total Liabilities and Shareholders' Equity $ 137,993 $ 110,922
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
30
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
1996 1995 1994
-------- -------- --------
Revenues: (In thousands except per share amounts)
Contract drilling $28,819 $20,211 $16,952
Oil and natural gas 43,013 31,187 26,001
Other 238 1,676 942
-------- -------- --------
Total revenues 72,070 53,074 43,895
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 24,259 18,041 14,909
Depreciation and impairment 2,944 2,596 2,030
Oil and natural gas:
Operating costs 13,409 12,003 8,799
Depreciation, depletion
and amortization 10,807 10,223 8,281
General and administrative 4,122 3,893 3,574
Interest 3,162 3,235 1,654
-------- -------- --------
Total expenses 58,703 49,991 39,247
-------- -------- --------
Income From Continuing Operations
Before Income Taxes 13,367 3,083 4,648
-------- -------- --------
Income Tax Expense (Benefit):
Current 4 14 20
Deferred 5,030 (682) -
-------- -------- --------
Total income taxes 5,034 (668) 20
-------- -------- --------
Income From Continuing Operations 8,333 3,751 4,628
-------- -------- --------
Discontinued Operations:
Income (loss) from operations of
discontinued operations (net of
income tax benefit of $69 in 1995) - (112) 166
Gain from sale of discontinued
operations (net of income taxes
of $221 in 1995) - 360 -
-------- -------- --------
Income from
discontinued operations - 248 166
-------- -------- --------
Net Income $ 8,333 $ 3,999 $ 4,794
======== ======== ========
31
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS - CONTINUED
Year Ended December 31,
1996 1995 1994
-------- -------- --------
(In thousands except per share amounts)
Earnings Per Common Share:
Continuing operations:
Primary $ .37 $ .18 $ .22
======== ======== ========
Fully diluted $ .36 $ .18 $ .22
======== ======== ========
Net income:
Primary $ .37 $ .19 $ .23
======== ======== ========
Fully diluted $ .36 $ .19 $ .23
======== ======== ========
Weighted Average Shares Outstanding:
Primary 22,708 21,210 20,900
======== ======== ========
Fully diluted 22,867 21,210 20,900
======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
32
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1994, 1995 and 1996
Capital
In Excess Retained
Common Of Par Earnings Treasury
Stock Value (Deficit) Stock Total
-------- -------- --------- -------- --------
(In thousands)
Balances,
January 1, 1994 $ 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
Net income - - 8,333 - 8,333
Activity in employee
compensation plans
(321,667 shares) 64 615 - 123 802
Issuance of stock on
exercise of
warrants
(2,859,555 shares) 572 11,939 - - 12,511
Purchase of treasury
stock (5,000
shares) - - - (42) (42)
-------- -------- --------- -------- --------
Balances,
December 31, 1996 $ 4,831 $62,735 $ 10,751 $ (107) $78,210
======== ======== ========= ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
33
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1996 1995 1994
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities:
Income from continuing operations $ 8,333 $ 3,751 $ 4,628
Adjustments to reconcile income
from continuing operations
to net cash provided (used) by
continuing operating activities:
Depreciation, depletion,
amortization and impairment 14,079 13,120 10,760
Gain on disposition of assets (185) (723) (813)
Employee stock compensation plans 214 231 119
Bad debt expense - 55 -
Deferred tax benefit 5,030 (682) -
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (5,444) (2,280) 94
Materials and supplies (254) (550) (74)
Prepaid expenses and other (418) (94) (396)
Accounts payable (2,288) (1,151) (871)
Accrued liabilities 540 925 824
Contract advances 890 252 148
Natural gas purchaser prepayments 167 (1,620) (1,858)
-------- -------- --------
Net cash provided
by continuing operating
activities 20,664 11,234 12,561
-------- -------- --------
Net cash flows from
discontinued operations
including changes in
working capital - (259) 532
-------- -------- --------
Net cash provided by
operating activities 20,664 10,975 13,093
-------- -------- --------
The accompanying notes are an integral part of the
consolidated financial statements
34
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
1996 1995 1994
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions $(34,111) $(20,634) $(28,227)
Proceeds from disposition of assets 1,009 4,613 2,038
Decrease in short-term investments - - 41
(Acquisition) disposition
of other assets 215 - 141
Proceeds of sale of
discontinued operations - 369 -
--------- --------- ---------
Net cash used in
investing activities (32,887) (15,652) (26,007)
--------- --------- ---------
Cash Flows From Financing Activities:
Borrowings under line of credit 31,500 39,700 63,700
Payments under line of credit (32,000) (35,900) (51,300)
Payments on notes payable and
other long-term debt (20) (1,000) (480)
Proceeds from sale of common stock 12,798 - -
Acquisition of treasury stock (42) (230) (80)
--------- --------- ---------
Net cash provided by
financing activities 12,236 2,570 11,840
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents 13 (2,107) (1,074)
Cash and Cash Equivalents,
Beginning of Year 534 2,641 3,715
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 547 $ 534 $ 2,641
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 3,189 $ 3,214 $ 1,548
Income taxes $ 63 $ - $ 2
The accompanying notes are an integral part of the
consolidated financial statements
35
<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 2,311 wells and
serves as operator of 502 of those wells. Land contract drilling of oil
and natural gas wells is performed for a wide range of customers using the
24 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.
36
<PAGE>
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated
useful lives, including a minimum provision of 20 percent of the active
rate when the equipment is idle. At December 31, 1995, the Company elected
to take three rigs out of service, and at that time, the three drilling
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 comput-
ed 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 property and
equipment is reviewed for possible impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable.
Assets determined to be impaired based on estimated future net cash flows
are reduced to estimated fair value. Changes in such estimates could cause
the Company to reduce the carrying value of its property and equipment.
When property and equipment components are disposed of, the cost and
the related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For dispo-
sitions of drill pipe and drill collars, an average cost for the
appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and
development activities on the full cost method of accounting prescribed by
the Securities and Exchange Commission ("SEC"). Accordingly, all produc-
tive and non-productive costs incurred in connection with the acquisition,
exploration and development of oil and natural gas reserves are capitalized
and amortized on a composite units-of-production method based on proved oil
and natural gas reserves. The Company's determination of its oil and
natural gas reserves are reviewed annually by independent petroleum
engineers. The average composite rates used for depreciation, depletion and
amortization ("DD&A") were $3.90, $3.93 and $4.08 per equivalent barrel in
1996, 1995 and 1994, 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 13, 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.
37
<PAGE>
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties
in which the Company has an interest or on properties in which a part-
nership, of which the Company is a general partner, has an interest.
Accordingly, in 1994 the Company recorded $14,000 of contract drilling
profits as a reduction of the carrying value of its oil and natural gas
properties rather than including these profits in current operations. No
contract drilling profits were realized on such interests in 1996 and 1995.
Limited Partnerships
The Company, through its wholly owned subsidiary, Unit Petroleum
Company, is a general partner in twelve oil and natural gas limited part-
nerships sold privately and publicly. Certain of the Company's officers
and directors own interests in some of these partnerships. Their interests
were acquired generally on the same basis as other outside investors.
The Company shares in partnership revenues and costs in accordance
with formulas prescribed in each limited partnership agreement. The
partnerships also reimburse the Company for certain administrative costs
incurred on behalf of the partnerships.
Income Taxes
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 1996 average spot market natural gas price of $2.15 per
Mcf, the Company estimates its balancing position to be approximately
$6.4 million on under-produced properties and approximately $3.2 million on
over-produced properties.
The Company's policy is to expense its pro-rata share of lease oper-
ating costs from all wells as incurred. Such expenses relating to the
Company's balancing position on wells on which the Company has imbalances
are not material.
38
<PAGE>
Stock Based Compensation
The Company applies APB Opinion 25 in accounting for its stock option
plans. Under this standard, no compensation expense is recognized for
grants of options which include an exercise price equal to or greater than
the market price of the stock on the date of grant. Accordingly, based on
the Company's grants in 1996, 1995 and 1994 no compensation expense has
been recognized. As allowed by Financial Accounting Standard No. 123
"Accounting for Stock-Based Compensation," the Company has disclosed the
pro forma effects of recording compensation for such option grants based on
fair value in Note 7 to the financial statements.
Self Insurance
The Company utilizes self insurance programs for employee group health
and worker's compensation. Self insurance cost are accrued based upon the
aggregate of estimated liabilities for reported claims and claims incurred
but not yet reported.
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
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, 1996 and 1995, the Company had a concentration of cash of
$2.6 million and $1.2 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.
39
<PAGE>
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 forming GED Gas Services L.L.C. ("GED"). The combination was
made to attain the increased volumes deemed necessary to 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.
The Company's former natural gas marketing activity has been presented
as a discontinued operation. Summary results of operations data of the
discontinued operations were as follows:
For the Year Ended December 31,
1996 1995 1994
-------- -------- --------
(In Thousands)
Results of Operations:
Revenues attributable to
discontinued operations $ - $13,548 $43,725
Expenses attributable to
discontinued operations - 13,729 43,559
-------- -------- --------
Income (loss) attributable
to discontinued operations
before income taxes - (181) 166
Income tax benefit - 69 -
-------- -------- --------
Income (loss) attributable
to discontinued
operations $ - $ (112) $ 166
======== ======== ========
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 entitled the holder to purchase one share of the
Company's common stock at a price of $4.375. Prior to the warrants
expiration on August 30, 1996, 2.86 million warrants were exercised
providing $12.5 million in additional capital to the Company.
40
<PAGE>
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 $2.3 million at December 31, 1996 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, 1996 prepayment balance is subject to recoupment in volumes of natural
gas for a period ending the earlier of recoupment or December 31, 1997 (the
"Recoupment Period"). During 1997, 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 $156,000 or a minimum of $80,000 per month. 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 and are reflected in revenues as recoupment
occurs. The Company anticipates the maximum balance of $3 million will be
unrecouped at December 31, 1997 and accordingly, the prepayment balance at
December 31, 1996 is reported as a long-term liability. 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.
41
<PAGE>
NOTE 5 - LONG-TERM DEBT
- ------------------------
Long-term debt consisted of the following as of December 31, 1996 and
1995:
1996 1995
--------- ---------
Revolving credit and term loan, (In thousands)
with interest at December 31,
1996 and 1995 of 7.2 percent
and 8.2 percent, respectively $ 40,600 $ 41,100
Other - 20
--------- ---------
40,600 41,120
Less current portion - 20
--------- ---------
Total long-term debt $ 40,600 $ 41,100
========= =========
At December 31, 1996, the Company's loan agreement ("Loan Agreement")
provided for a total loan commitment of $75 million consisting of a revolv-
ing credit facility through August 1, 1999 and a term loan thereafter,
maturing on August 1, 2003. Borrowings under the Loan Agreement are
limited to a semi-annual borrowing base computation which as of December
31, 1996 is $52 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 1.25 to 1.75 percent depending
on the level of debt as a percentage of the total borrowing base.
Subsequent to August 1, 1999, borrowings under the Loan Agreement bear
interest at the Prime Rate plus .25 percent or the Libor rate plus 1.50 to
2.00 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 the 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 facility fee of 1/2 of 1 percent 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 preced-
ing 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
42
<PAGE>
long-term 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 liabil-
ities, 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 1997 through 2001 are $0, $0, $3,383,000, $10,150,000 and
$10,150,000. Based on the borrowing rates currently available to the
Company for debt with similar terms and maturities, long-term debt at
December 31, 1996 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:
1996 1995 1994
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 4,545 $ 1,048 $ 1,580
Tax benefit of net operating
loss carryforward - (1,730) (1,595)
State income tax 499 - 6
Other (10) 14 29
-------- -------- --------
Income tax expense (benefit) $ 5,034 $ (668) $ 20
======== ======== ========
43
<PAGE>
Deferred tax assets and liabilities are comprised of the following at
December 31, 1996 and 1995:
1996 1995
--------- ---------
Deferred tax assets: (In thousands)
Allowance for losses $ 443 $ 670
Net operating loss carryforwards 17,586 17,058
Statutory depletion carryforward 2,260 2,260
Investment tax credit carryforward 3,530 3,530
--------- ---------
Gross deferred tax assets 23,819 23,518
Valuation allowance (3,530) (3,530)
Deferred tax liability-
Depreciation, depletion and amortization (24,487) (19,458)
--------- ---------
Net deferred tax asset (liability) $ (4,198) $ 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.
At December 31, 1996, the Company has net operating loss carryforwards
for regular tax purposes of approximately $46,279,000 and net operating
loss carryforwards for alternative minimum tax purposes of approximately
$37,636,000 which expire in various amounts from 1999 to 2011. The Company
has investment tax credit carryforwards of approximately $3,530,000 which
expire from 1997 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.
44
<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. No shares
were issued under the Plan in 1996, 1995 or 1994.
At December 31, 1996, 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 to date was based on the fair market value on the date of
the grant.
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
--------- --------
Outstanding at
January 1, 1994 829,000 $ 2.04
Granted 102,500 3.00
Exercised (16,000) 1.55
--------- --------
Outstanding at
December 31, 1994 915,500 2.16
Granted 26,000 3.22
Exercised (65,900) 1.65
Canceled (10,000) 1.88
--------- --------
Outstanding at
December 31, 1995 865,600 2.23
Granted 149,500 8.75
Exercised (371,200) 1.59
Canceled (7,100) 2.92
--------- --------
Outstanding at
December 31, 1996 636,800 $ 4.13
========= ========
45
<PAGE>
OUTSTANDING OPTIONS
--------------------------------------
WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE
EXERCISE OF REMAINING EXERCISE
PRICES SHARES CONTRACTUAL LIFE PRICE
-----------------------------------------------------------
$1.50-$4.00 487,300 5 years $2.72
$8.75 149,500 10 years $8.75
EXERCISABLE OPTIONS
-----------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
------------------------------------
$1.50-$4.00 375,000 $ 2.64
$8.75 - $ -
Options for 375,000, 675,000 and 676,400 shares were exercisable with
weighted average exercise prices of $2.64, $2.06 and $1.95 at December 31,
1996, 1995 and 1994, respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued upon exercise of the stock options.
On the first business day following each annual meeting of stockholders of
the Company, each person who is then a member of the Board of Directors of
the Company and who is not then an employee of the Company or any of its
subsidiaries will be granted an option to purchase 2,500 shares of common
stock. The option price for each stock option is the fair market value of
the common stock on the date the stock options are granted. No stock
options may be exercised during the first six months of its term except in
case of death and no stock options are exercisable after ten years from the
date of grant.
46
<PAGE>
Activity pertaining to the Directors' Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
-------- --------
Outstanding at
January 1, 1994 20,000 $ 2.75
Granted 10,000 2.88
-------- --------
Outstanding at
December 31, 1994 30,000 2.79
Granted 12,500 3.38
-------- --------
Outstanding at
December 31, 1995 42,500 2.96
Granted 12,500 6.88
-------- --------
Outstanding at
December 31, 1996 55,000(1) $ 3.85
======== ========
- -------------
(1) All 55,000 options were exercisable at December 31, 1996.
47
<PAGE>
The Company applies APB Opinion 25 in accounting for its Stock Option
Plan and Non-Employee Director's Stock Option Plan. Accordingly, based on
the nature of the Company's grants of options, no compensation cost has
been recognized in 1996 and 1995. Had compensation been determined on the
basis of fair value pursuant to FASB Statement No. 123, net income and
earnings per share would have been reduced as follows:
1996 1995
------ ------
Net Income (In thousands):
As reported $8,333 $3,999
====== ======
Pro forma $8,244 $3,971
====== ======
Primary Earnings per Share:
As reported $ .37 $ .19
===== =====
Pro forma $ .36 $ .19
===== =====
Fully Diluted Earnings per Share:
As reported $ .36 $ .19
===== =====
Pro forma $ .36 $ .19
===== =====
The fair value of each option granted is estimated using the Black-
Scholes model. The Company's volatility of stock was 0.51 based on
previous stock performance. Dividend yield was estimated to remain at zero
with a risk free interest rate of 6.55 and 6.45 percent in 1996 and 1995,
respectively. Expected life ranged from 1 to 10 years based on prior
experience depending on the vesting periods involved and the make up of
participating employees within each grant. Fair value of options granted
during 1996 and 1995 under the Stock Option Plan were $753,000 and $14,000,
respectively, and under the Non-Employee Stock Option Plan were $56,000 and
$27,000, respectively.
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 44,686, 46,659 and 32,685 shares of common stock and
recognized expense of $268,000, $174,000 and $130,000 in 1996, 1995 and
1994, respectively.
48
<PAGE>
The Company provides a salary deferral plan ("Deferral Plan") which
allows participants to defer the recognition of salary for income tax
purposes until actual distribution of benefits which occurs at either
termination of employment, death or certain defined unforeseeable emergency
hardships. Funds set aside in a trust to satisfy the Company's obligation
under the Deferral Plan at December 31, 1996 and 1995 totaled $492,000 and
$271,000 respectively. The Company recognizes payroll expense and records
a liability at the time of deferral.
Effective January 1, 1997, the Company adopted a separation benefit
plan ("Separation Plan"). The Separation Plan allows eligible employees
whose employment with the Company is involuntarily terminated or, in the
case of an employee who has completed 20 years of service, voluntarily or
involuntarily terminated, to receive benefits equivalent to 4 week's salary
for every whole year of service completed with the Company up to a maximum
of 104 weeks. Benefits received under the Separation Plan will be reduced
by the amount of any other benefits received from other disability or
severance plans which may be in effect during the payment period. To
receive payments the recipient must waive any claims against the Company
in exchange for receiving the separation benefits. Benefits associated
with this plan will begin to be recognized in 1997 for anticipated payments
under the Separation Plan.
NOTE 8 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through
1996, with a subsidiary of the Company serving as General Partner. The
Partnerships were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as co-general
partner with the Company in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with the Company in most drilling operations and most producing property
acquisitions commenced by the Company for its own account during the period
from the formation of the Partnership through December 31 of each year.
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 for the following years ended December 31:
1996 1995 1994
-------- -------- --------
(In thousands)
Contract drilling $ 37 $ 34 $ 53
Well supervision and other fees $ 349 $ 356 $ 226
General and administrative
expense reimbursement $ 105 $ 235 $ 209
49
<PAGE>
A subsidiary of the Company paid the Partnerships, for which the
Company or a subsidiary is the general partner, $31,000, $18,000 and
$38,000 during the years ended December 31, 1996, 1995 and 1994,
respectively, for purchases of natural gas production.
During 1996, 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 an amount not to exceed $1.5 million.
NOTE 9 - SHAREHOLDER RIGHTS PLAN
- --------------------------------
The Company maintains a Shareholder Rights Plan (the "Plan") designed
to deter coercive or unfair takeover tactics, to prevent a person or group
from gaining control of the Company without offering fair value to all
shareholders and to deter other abusive takeover tactics which are not in
the best interest of shareholders.
Under the terms of the Plan, each share of common stock is accompanied
by one right, which given certain acquisition and business combination
criteria, entitles the shareholder to purchase from the Company one one-
hundredth of a newly issued share of Series A Participating Cumulative
Preferred Stock at a price subject to adjustment by the Company or to
purchase from an acquiring Company certain shares of its common stock or
the surviving company's common stock at 50 percent of its value.
The rights become exercisable 10 days after the Company learns that an
acquiring person (as defined in the Plan) has acquired 15 percent or more
of the outstanding common stock of the Company or 10 business days after
the commencement of a tender offer which would result in a person owning 15
percent or more of such shares. The Company can redeem the rights for
$0.01 per right at any date prior to the earlier of (i) the close of
business on the tenth day following the time the Company learns that a
person has become an acquiring person or (ii) May 19, 2005 (the "Expiration
Date"). The rights will expire on the Expiration Date, unless redeemed
earlier by the Company.
50
<PAGE>
NOTE 10 - COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
The Company leases office space under the terms of operating leases
expiring through January 31, 2002. Future minimum rental payments under
the terms of the leases are approximately $368,000, $348,000, $341,000,
$93,000 and $70,000 in 1997, 1998, 1999, 2000, and 2001, respectively.
Total rent expense incurred by the Company was $323,000, $307,000 and
$210,000 in 1996, 1995 and 1994, respectively.
The Company had letters of credit supported by its Loan Agreement
totaling $1,070,000 at December 31, 1996.
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 $30,000, $34,000 and $38,000 in 1996, 1995 and 1994,
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.
51
<PAGE>
NOTE 11 - 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
--------- -------- --------- ---------- ----------
Year ended (In thousands)
December 31, 1996:
Drilling $ 28,819 $ 1,616 $ 24,500 $ 9,910 $ 2,944
Oil and
natural gas 43,013 18,797 110,207 25,644 10,807
--------- -------- --------- ---------- ----------
71,832 $20,413 134,707 35,554 13,751
Other 238 ======== 3,286 989 328
--------- --------- ---------- ----------
Total $ 72,070 $137,993 $ 36,543 $ 14,079
========= ========= ========== ==========
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
========= ========= ========== ==========
(1) Operating profit is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not include non-
operating revenues, general corporate expenses, interest expense,
income taxes or 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.
52
<PAGE>
NOTE 12 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1996 and 1995 is as
follows:
Three Months Ended
------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- --------- ---------
(In thousands except per share amounts)
Year ended December 31, 1996:
Revenues $ 15,871 $ 17,107 $ 17,286 $ 21,806
========= ========= ========= =========
Gross profit(1) $ 3,851 $ 4,376 $ 4,683 $ 7,503
========= ========= ========= =========
Income before
income taxes $ 1,952 $ 2,529 $ 3,096 $ 5,790
========= ========= ========= =========
Net Income $ 1,219 $ 1,589 $ 1,899 $ 3,626
========= ========= ========= =========
Earnings Per Common Share:
Primary $ .06 $ .07 $ .08 $ .15
========= ========= ========= =========
Fully diluted $ .06 $ .07 $ .08 $ .15
========= ========= ========= =========
53
<PAGE>
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(2) $ 102 $ 916(3) $ 1,876(4)
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:
(Both primary and fully diluted)
Continuing
operations $ .05(2) $ - $ .04(3) $ .09(4)
Discontinued
operations - - - (.01)
Gain on sale of
discontinued
operations - - - .02
--------- --------- --------- ---------
Net income $ .05(2) $ - $ .04(3) $ .10(4)
========= ========= ========= =========
(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.
54
<PAGE>
NOTE 13 - 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)
1996:
Capitalized costs:
Proved properties $ 195,528 $ 480 $ 196,008
Unproved properties 4,602 - 4,602
--------- -------- ---------
200,130 480 200,610
Less accumulated depreciation,
depletion, amortization
and impairment 102,463 389 102,852
--------- -------- ---------
Net capitalized costs $ 97,667 $ 91 $ 97,758
========= ======== =========
Cost incurred:
Unproved properties $ 1,640 $ - $ 1,640
Producing properties 2,338 - 2,338
Exploration 1,501 - 2,501
Development 20,150 15 20,165
--------- -------- ---------
Total costs incurred $ 25,629 $ 15 $ 25,644
========= ======== =========
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
========= ======== =========
55
<PAGE>
USA Canada Total
--------- -------- ---------
(In thousands)
1994:
Capitalized costs:
Proved properties $ 154,688 $ 455 $ 155,143
Unproved properties 2,250 - 2,250
--------- -------- ---------
156,938 455 157,393
Less accumulated depreciation,
depletion, amortization
and impairment 81,583 368 81,951
--------- -------- ---------
Net capitalized costs $ 75,355 $ 87 $ 75,442
========= ======== =========
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
========= ======== =========
56
<PAGE>
The results of operations for producing activities are provided below.
Due to the Company's utilization of net operating loss carryforwards,
income taxes were not significant and have not been included for the years
1995 and 1994.
USA Canada Total
--------- -------- ---------
(In thousands)
1996:
Revenues $ 40,432 $ 60 $ 40,492
Production costs 11,195 14 11,209
Depreciation, depletion
and amortization 10,723 11 10,734
--------- -------- ---------
18,514 35 18,549
Income tax expense 6,986 15 7,001
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 11,528 $ 20 $ 11,548
========= ======== =========
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
========= ======== =========
57
<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)
1996:
Proved developed and
undeveloped reserves:
Beginning of year 5,428 107,950 - 778 5,428 108,728
Revision of previous (387) (3,822) - 26 (387) (3,796)
estimates
Extensions, discoveries
and other additions 718 34,625 - - 718 34,625
Purchases of minerals
in place 67 3,036 - - 67 3,036
Sales of minerals
in place (43) (407) - - (43) (407)
Production (579) (12,974) - (51) (579) (13,025)
------ -------- ------- -------- -------- --------
End of Year 5,204 128,408 - 753 5,204 129,161
====== ======== ======= ======== ======== ========
Proved developed reserves:
Beginning of year 4,697 94,975 - 350 4,697 95,325
End of year 4,509 107,536 - 326 4,509 107,862
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
58
<PAGE>
USA Canada Total
--------------------------------------------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------- -------- ------- --------
(In thousands)
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
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made
in connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's
reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog-
ical and engineering data, appear with reasonable certainty to be recov-
erable in the future from known oil and natural gas reservoirs under exist-
ing economic and operating conditions. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods. Proved undeveloped reserves are
those reserves which are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expendi-
ture is required.
Estimates of oil and natural gas reserves require extensive judgments
of reservoir engineering data as previously explained. Assigning monetary
values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. Indeed the uncertainties inherent in the
disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves. The information set forth herein is therefore
subjective and, since judgments are involved, may not be comparable to
estimates submitted by other oil and natural gas producers. In addition,
since prices and costs do not remain static and no price or cost escala-
tions or de-escalations have been considered, the results are not neces-
sarily indicative of the estimated fair market value of estimated proved
reserves nor of estimated future cash flows.
59
<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)
1996:
Future cash flows $626,945 $ 2,735 $629,680
Future production and
development costs 171,749 339 172,088
Future income tax expenses 125,540 1,422 126,962
--------- -------- ---------
Future net cash flows 329,656 974 330,630
10% annual discount for
estimated timing of cash flows 129,610 368 129,978
--------- -------- ---------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $200,046 $ 606 $200,652
========= ======== =========
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
========= ======== =========
60
<PAGE>
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1996:
Sales and transfers of oil and
natural gas produced,
net of production costs $(29,237) $ (46) $(29,283)
Net changes in prices and
production costs 92,541 738 93,279
Revisions in quantity estimates
and changes in production timing (13,390) 58 (13,332)
Extensions, discoveries and improved
recovery, less related costs 69,942 - 69,942
Purchases of minerals in place 5,821 - 5,821
Sales of minerals in place (514) - (514)
Accretion of discount 12,101 71 12,172
Net change in income taxes (44,039) (470) (44,509)
Other - net 3,998 (60) 3,938
--------- -------- ---------
Net change 97,223 291 97,514
Beginning of year 102,823 315 103,138
--------- -------- ---------
End of year $200,046 $ 606 $200,652
========= ======== =========
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
========= ======== =========
61
<PAGE>
USA Canada Total
--------- -------- ---------
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
========= ======== =========
The Company's SMOG and changes therein were determined in accordance
with Statement of Financial Accounting Standards No. 69. Certain infor-
mation concerning the assumptions used in computing SMOG and their inherent
limitations are discussed below. Management believes such information is
essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those
reserves nor their present worth. Assigning monetary values to the reserve
quantity estimation process does not reduce the subjective and ever-
changing nature of such reserve estimates. Additional subjectivity occurs
when determining present values because the rate of producing the reserves
must be estimated. In addition to errors inherent in predicting the
future, variations from the expected production rate could result from
factors outside of management's control, such as unintentional delays in
development, environmental concerns or changes in prices or regulatory
controls. Also, the reserve valuation assumes that all reserves will be
disposed of by production. However, other factors such as the sale of
reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided
by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of
existing economic conditions.
62
<PAGE>
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.
In early 1997, the natural gas industry has experienced a downturn in
natural gas prices. The Company's reserves were determined at December
31,1996 using a natural gas price of approximately $3.63 per Mcf for
natural gas not subject to long-term contracts. During February 1997, the
natural gas prices received by the Company fell to approximately $2.75 per
Mcf for natural gas not subject to long-term contracts. This decrease in
natural gas prices would have a significant effect on the SMOG value of the
Company's reserves at December 31, 1996.
63
<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, 1996 and 1995 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, 1996. 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, 1996 and 1995, and the con-
solidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation
to the basic financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
February 18, 1997
64
<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 infor-
mation concerning each executive officer of the Company. Unless otherwise
indicated, each has served in the positions set forth for more than five
years. Executive officers are elected for a term of one year. There are
no family relationships between any of the persons named.
NAME AGE POSITION
-----------------------------------------------------------
King P. Kirchner 69 Chairman of the Board, Chief Executive
Officer and Director
John G. Nikkel 62 President, Chief Operating Officer and
Director
Earle Lamborn 62 Senior Vice President, Drilling and
Director
Philip M. Keeley 55 Senior Vice President, Exploration and
Production
Larry D. Pinkston 42 Vice President, Treasurer and Chief
Financial Officer
Mark E. Schell 39 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.
65
<PAGE>
Mr. Nikkel joined the Company in 1983 as its President and a director.
From 1976 until January 1982 when he co-founded Nike Exploration Company,
Mr. Nikkel was an officer and director of Cotton Petroleum Corporation,
serving as the President of that Company from 1979 until his departure.
Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production
Company for 18 years, last serving as Division Geologist for Amoco's Denver
Division. Mr. Nikkel presently serves as President and a director of Nike
Exploration Company. Mr. Nikkel received a Bachelor of Science degree in
Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 40
years, joining the Company's predecessor in 1952 prior to it becoming a
publicly-held corporation. He was elected Vice President, Drilling in 1973
and to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice
President, Exploration and Production. Prior to that time, Mr. Keeley co-
founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and
serves as Executive Vice President and a director of that company. From
1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation,
serving first as Manager of Land and from 1979 as Vice President and a
director. Before joining Cotton, Mr. Keeley was employed for four years by
Apexco, Inc. as Manager of Land and prior thereto he was employed by
Texaco, Inc. for nine years. He received a Bachelor of Arts degree in
Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as
Corporate Budget Director and Assistant Controller prior to being appointed
as Controller in February 1985. He has been Treasurer since December 1986
and was elected to the position of Vice President and Chief Financial
Officer in May 1989. He holds a Bachelor of Science Degree in Accounting
from East Central University of Oklahoma and is a Certified Public
Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and
General Counsel. From 1979 until joining the Company, Mr. Schell was
Counsel, Vice President and a member of the Board of Directors of C & S
Exploration, Inc. He received a Bachelor of Science degree in Political
Science from Arizona State University and his Juris Doctorate degree from
the University of Tulsa Law School. He is a member of the Oklahoma and
American Bar Association as well as being a member of the American
Corporate Counsel Association and the American Society of Corporate
Secretaries.
The balance of the information required in this Item 10 is incorpo-
rated by reference from the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1997
annual meeting of stockholders.
66
<PAGE>
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 1997 annual meeting of
stockholders.
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 1997 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 1997 annual meeting of
stockholders.
67
<PAGE>
PART IV
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, 1996 and 1995
Consolidated Statements of Operations for the years ended December
31, 1996, 1995 and 1994
Consolidated Statements of Changes in Shareholders' Equity for the
years ended December 31, 1996, 1995 and 1994
Consolidated Statements of Cash Flows for the years ended December
31, 1996, 1995 and 1994
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,
1996, 1995 and 1994:
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).
68
<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).
69
<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 Company of Shawnee (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the
quarter ended March 31, 1994, which is incorporated herein by
reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement
dated as of December 12, 1994, by and between Unit Corporation
and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank
IV, Oklahoma, N.A. and American National Bank and Trust
Company of Shawnee (filed as an Exhibit in Form 8-K dated
December 15, 1994, which is incorporated herein by reference).
10.1.20 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).
10.1.21 First Amendment to the Loan Agreement effective as of
September 4, 1996, by and between Unit Corporation and Bank of
Oklahoma, N.A., The First National Bank of Boston, Bank IV
Oklahoma, N.A. and American National Bank and Trust Company of
Shawnee (filed as an Exhibit to the Company's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1996, which is incorporated herein by
reference).
10.1.22 Second Amendment to the Loan Agreement effective as of
December 16, 1996 by and between Unit Corporation and Bank of
Oklahoma,N.A., The First National Bank of Boston, Boatman's
National Bank of Oklahoma and American National Bank and Trust
Company of Shawnee (filed herewith).
70
<PAGE>
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership
(filed as Exhibit I to Unit Drilling and Exploration Company's
Registration Statement on Form S-1 as S.E.C. File No. 2-66347,
which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership
(filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's
Registration Statement Form S-1 as S.E.C. File No. 2-92582,
which is incorporated herein by reference).
10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited
Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil
and Gas Program's Registration Statement of Form S-1 as S.E.C.
File No. 2-89678, which is incorporated herein by reference).
10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 3.1 to Unit 1985
Employee Oil and Gas Limited Partnership's Registration
Statement on Form S-1 as S.E.C. File No. 2-95068, which is
incorporated herein by reference).
10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 10.11 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1990, which is incorporated herein by reference).
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1991, which is incorporated herein by reference).
71
<PAGE>
10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as
Exhibit 10.16 to the Company's Registration Statement on Form
S-4 as S.E.C. File No. 33-7848, which is incorporated herein
by reference).
10.2.22* The Company's Stock Option Plan (filed as an Exhibit to the
Company's Registration Statement on Form S-8 as S.E.C. File
No's. 33-19652, 33-44103 and 33-64323 which is incorporated
herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan
(filed as an Exhibit to Form S-8 as S.E.C. File No. 33-49724,
which is incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed as an Exhibit
to Form S-8 as S.E.C. File No. 33-53542, which is incorporated
herein by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to 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 as an Exhibit to the
Company's Annual Report under cover of Form 10-K for the year
ended December 31, 1995, which is incorporated herein by
reference).
72
<PAGE>
10.2.30* Separation Benefit Plan of Unit Corporation and Participating
Subsidiaries (filed herewith).
10.2.31 Unit 1997 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 as an Exhibit to 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 as an Exhibit to 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
to Form 8-K dated December 15, 1994, which is incorporated
herein by reference).
21 Subsidiaries of the Registrant (filed herewith).
23 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 on Form 8-K were filed during the quarter ended
December 31, 1996.
73
<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, 1996 $ 116 $ - $ 12 $ 104
======== ======== ======== ========
Year ended
December 31, 1995 $ 289 $ 55 $ 228 $ 116
======== ======== ======== ========
Year ended
December 31, 1994 $ 411 $ - $ 122 $ 289
======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance at Balance at
beginning end of
Description of period Additions Deductions period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1996 $ 3,530 $ - $ - $ 3,530
======== ======== ======== ========
Year ended
December 31, 1995 $ 6,423 $ - $ 2,893 $ 3,530
======== ======== ======== ========
Year ended
December 31, 1994 $ 8,218 $ - $ 1,795 $ 6,423
======== ======== ======== ========
74
<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 17, 1997 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 17th day of March, 1997.
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 LAMBORNDirector
/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
------------------------------- Director
JOHN H. WILLIAMS
75
<PAGE>
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
--------- -------------------------------------------- -----
10.1.22 Second Amendment to the Loan Agreement effective as
of December 16, 1996 by and between Unit Corporation
and Bank of Oklahoma, N.A., The First National Bank
of Boston, Boatman's National Bank of Oklahoma and
American National Bank and Trust Company of Shawnee.
10.2.30 Separation Benefit Plan of Unit Corporation and
Participating Subsidiaries.
10.2.31 Unit 1997 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
27 Financial Data Schedule.
76
<PAGE>
EXHIBIT 10.1.22
<PAGE>
SECOND AMENDMENT TO
LOAN AGREEMENT
Dated as of
December 16, 1996
between
UNIT CORPORATION
UNIT DRILLING AND EXPLORATION COMPANY
MOUNTAIN FRONT PIPELINE COMPANY, INC.
UNIT DRILLING COMPANY
UNIT PETROLEUM COMPANY
PETROLEUM SUPPLY COMPANY
"Borrowers"
and
BANK OF OKLAHOMA, NATIONAL ASSOCIATION
THE FIRST NATIONAL BANK OF BOSTON
BOATMAN'S NATIONAL BANK OF OKLAHOMA
AMERICAN NATIONAL BANK AND TRUST
COMPANY OF SHAWNEE
"Banks"
and
BANK OF OKLAHOMA, NATIONAL ASSOCIATION
"Agent"
<PAGE>
SECOND AMENDMENT TO LOAN AGREEMENT
THIS SECOND AMENDMENT TO LOAN AGREEMENT, dated as of December
16, 1996 ("Second Amendment"), is entered into among UNIT CORPORA-
TION, a Delaware corporation ("Unit"), UNIT DRILLING AND EXPLORA-
TION COMPANY, a Delaware corporation, MOUNTAIN FRONT PIPELINE
COMPANY, INC., an Oklahoma corporation, UNIT DRILLING COMPANY, an
Oklahoma corporation, UNIT PETROLEUM COMPANY, an Oklahoma corpora-
tion and PETROLEUM SUPPLY COMPANY, an Oklahoma corporation, each
with its principal place of business at 1000 Galleria Tower 1, 7130
South Lewis, Tulsa, Oklahoma 74136 (collectively the "Borrowers")
and BANK OF OKLAHOMA, NATIONAL ASSOCIATION, a national banking
association, with principal offices at Bank of Oklahoma Tower, 7
East 2nd Street, Tulsa, Oklahoma 74172 ("BOK"); THE FIRST NATIONAL
BANK OF BOSTON, a national banking association, with principal
offices at 100 Federal Street, Boston, Massachusetts 02110 ("Bank
of Boston"); BOATMAN'S NATIONAL BANK OF OKLAHOMA, with principal
offices at 515 South Boulder, Tulsa, Oklahoma, 74119 ("Boatman's");
and AMERICAN NATIONAL BANK AND TRUST COMPANY OF SHAWNEE, a national
banking association, with principal offices at 201 N. Broadway, Shawnee,
Oklahoma 74801 ("ANB") (BOK, Bank of Boston, Boatman's and ANB each
being sometimes referred to herein, individually, as a "Bank", and
collectively as the "Banks"); and BOK as Agent for the Banks (in
such capacity, herein referred to as the "Agent").
WITNESSETH:
WHEREAS, the Borrowers, BOK, Bank of Boston, BANK IV
Oklahoma, N.A., ANB and Agent are parties to that certain Loan
Agreement dated as of August 3, 1995, as amended by that certain
First Amendment to Loan Agreement dated as of September 4, 1996
(the Loan Agreement, as amended, referred to herein as the "Prior
Loan Agreement"), pursuant to which BOK, Bank of Boston, BANK IV
Oklahoma, N.A. and ANB extended to the Borrowers a $75,000,000
revolving line of credit (the "Line Commitment") that converts to
a forty-eight (48) month term payment (the "Term Commitment"); and
WHEREAS, the Banks have increased the Borrowing Base.
NOW, THEREFORE, in consideration of the mutual agreements and
covenants herein made, and other good and valuable consideration,
the receipt and sufficiency of which are hereby acknowledged, the
Borrowers and the Banks agree as follows:
1. Amended Definitions. The following defined term in the
Prior Loan Agreement is hereby amended, as follows:
1.47 "Pro Rata Share" shall mean for each of the
Banks the percentage determined from time to time by
dividing the principal amount outstanding under such
Bank's respective Note by the aggregate principal
amount outstanding under all of the Banks' Notes.
BOK's Pro Rata Share in 45.19%, Boatman's Pro Rata
<PAGE>
Share is 38.46%, Bank of Boston's Pro Rata Share is
13.46% and ANB's Pro Rata Share is 2.89%.
All references to "BANK IV" are hereby amended to refer to
"Boatman's".
2. Notes. The form of the Notes referenced in Section 2.2
of the Prior Loan Agreement and attached thereto as Exhibits A-1,
A-2, A-3 and A-4 are hereby replaced with the form of the Notes
attached hereto as Exhibits A-1, A-2, A-3 and A-4.
3. Ratifications, Representations and Warranties. The terms
and provisions set forth in this Second Amendment shall modify and
supersede all inconsistent terms and provisions set forth in the
Prior Loan Agreement and except as expressly modified and supersed-
ed by this Second Amendment, the terms and provisions of the Prior
Loan Agreement are ratified and confirmed and shall continue in
full force and effect. The Borrowers and the Banks agree that the
Prior Loan Agreement as amended hereby shall continue to be legal,
valid, binding and enforceable in accordance with its terms.
4. Reference to Agreement. Each of the Loan Documents, in-
cluding the Prior Loan Agreement and any and all other agreements,
documents, or instruments now or hereafter executed and delivered
pursuant to the terms hereof or pursuant to the terms of the Prior
Loan Agreement as amended hereby, are hereby amended so that any
reference in such Loan Documents to the Prior Loan Agreement shall
mean a reference to the Prior Loan Agreement as amended hereby.
5. Costs. Borrowers agree to pay to the Agent for the
benefit of the Banks on demand all recording fees and filing costs
and all reasonable attorneys fees and legal expenses incurred or
accrued by the Banks in connection with the preparation, negotiation,
execution, closing, administration of the Loan Aggreement and the filing
and recording of the Security Instruments or any amendment, waiver,
consent of modification to and of the Loan Documents. In any action to
enforce or construe the provisions of this Agreement or any of the Loan
Documents, the prevailing party shall be entitled to recover its reasonable
attorneys' fees and all costs and expenses related thereto.
-2-
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Second
Amendment to be duly executed as of the day and year first above
written.
"Borrowers"
UNIT CORPORATION, a Delaware corporation
UNIT DRILLING AND EXPLORATION
COMPANY, a Delaware corporation
MOUNTAIN FRONT PIPELINE COMPANY,
INC., an Oklahoma corporation
UNIT PETROLEUM COMPANY, an Oklahoma
corporation
UNIT DRILLING COMPANY, an Oklahoma
corporation
PETROLEUM SUPPLY COMPANY, an Oklahoma
corporation
By__/s/ John G. Nikkel------------------
John G. Nikkel, President of UNIT
CORPORATION, UNIT DRILLING AND
EXPLORATION COMPANY, MOUNTAIN
FRONT PIPELINE COMPANY, INC., UNIT
PETROLEUM COMPANY, UNIT DRILLING
COMPANY, PETROLEUM SUPPLY COMPANY
"Banks"
BANK OF OKLAHOMA, NATIONAL
ASSOCIATION
By__/s/_Pam Schloeder___________________
Pam Schloeder, Vice President
P. O. Box 2300
Tulsa, Oklahoma 74192
-3-
<PAGE>
"Agent"
BANK OF OKLAHOMA, NATIONAL
ASSOCIATION
By__/s/_Pam Schloeder--------------
Pam Schloeder, Vice President
P. O. Box 2300
Tulsa, Oklahoma 74192
THE FIRST NATIONAL BANK OF BOSTON
By__/s/_Frank T. Smith, Jr.---------
Frank T. Smith Jr., Director
P.O. Box 2016
100 Federal Street
Energy & Utility Division 01-08-02
Boston, Massachusetts 02110
-4-
<PAGE>
BOATMAN'S NATIONAL BANK OF OKLAHOMA
By_/s/_Glenn A. Elrod____________
Glenn A. Elrod
Senior Vice President
P. O. Box 2360
Tulsa, Oklahoma 74101-2360
-5-
<PAGE>
AMERICAN NATIONAL BANK AND TRUST
COMPANY OF SHAWNEE
By__/s/_Tony M. McMurry_____________
Tony M. McMurry
Executive Vice President
P. O. Box 1089
Shawnee, Oklahoma 74801-1089
Exhibits to the Second Amendment to Loan Agreement
will be furnished to the SEC upon Request.
-6-
<PAGE>
EXHIBIT 10.2.30
<PAGE>
SEPARATION BENEFIT PLAN
OF UNIT CORPORATION AND
PARTICIPATING SUBSIDIARIES
<PAGE>
SEPARATION BENEFIT PLAN
OF UNIT CORPORATION AND
PARTICIPATING SUBSIDIARIES
INDEX
Page
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Article One - Scope. . . . . . . . . . . . . . . . . . . . . . . . . .1
1.1 Name. . . . . . . . . . . . . . . . . . . . . . . . . .1
1.2 Plan Year . . . . . . . . . . . . . . . . . . . . . . .1
Article Two - Definitions. . . . . . . . . . . . . . . . . . . . . . .1
2.1 Administration Committee. . . . . . . . . . . . . . . .1
2.2 Base Salary . . . . . . . . . . . . . . . . . . . . . .1
2.3 Beneficiary . . . . . . . . . . . . . . . . . . . . . .1
2.4 Board of Directors. . . . . . . . . . . . . . . . . . .2
2.5 Bonus . . . . . . . . . . . . . . . . . . . . . . . . .2
2.6 Change in Control . . . . . . . . . . . . . . . . . . .2
2.7 Code. . . . . . . . . . . . . . . . . . . . . . . . . .3
2.8 Company . . . . . . . . . . . . . . . . . . . . . . . .3
2.9 Comparable Position . . . . . . . . . . . . . . . . . .3
2.10 Completed Year of Service . . . . . . . . . . . . . . .3
2.11 Discharge for Cause . . . . . . . . . . . . . . . . . .3
2.12 Eligible Employee . . . . . . . . . . . . . . . . . . .4
2.13 Employee. . . . . . . . . . . . . . . . . . . . . . . .4
2.14 Employing Company . . . . . . . . . . . . . . . . . . .5
2.15 ERISA . . . . . . . . . . . . . . . . . . . . . . . . .5
2.16 Plan. . . . . . . . . . . . . . . . . . . . . . . . . .5
2.17 Separation Benefit. . . . . . . . . . . . . . . . . . .5
2.18 Separation Period . . . . . . . . . . . . . . . . . . .5
2.19 Termination of Employment . . . . . . . . . . . . . . .5
2.20 Years of Service. . . . . . . . . . . . . . . . . . . .6
Article Three - Benefits. . . . . . . . . . . . . . . . . . . . . . .6
3.1 Eligibility . . . . . . . . . . . . . . . . . . . . . .6
3.2 Separation Benefit. . . . . . . . . . . . . . . . . . .6
3.3 Separation Benefit Amount . . . . . . . . . . . . . . .6
3.4 Separation Benefit Limitation . . . . . . . . . . . . .8
3.5 Withholding Tax . . . . . . . . . . . . . . . . . . . .8
3.6 Reemployment of an Eligible Employee. . . . . . . . . .9
<PAGE>
3.7 Integration with Disability Benefits. . . . . . . . . . . .9
3.8 Plan Benefit Offset . . . . . . . . . . . . . . . . . . . .9
3.9 Recoupment. . . . . . . . . . . . . . . . . . . . . . . . .9
3.10 Completion of Twenty Years of Service . . . . . . . . . . .9
3.11 Change in Control . . . . . . . . . . . . . . . . . . . . 10
Article Four - Method of Payment . . . . . . . . . . . . . . . . . . . . 10
4.1 Separation Benefit Payment. . . . . . . . . . . . . . . . 10
4.2 Forfeiture of Separation Benefit Payments By Competition. 10
4.3 Death Subsequent to Termination of Employment . . . . . . 11
Article Five - Waiver and Release of Claims. . . . . . . . . . . . . . . 11
Article Six - Funding. . . . . . . . . . . . . . . . . . . . . . . . . . 11
Article Seven - Operation. . . . . . . . . . . . . . . . . . . . . . . . 12
7.1 Employing Company Participation . . . . . . . . . . . . . 12
7.2 Status of Subsidiaries. . . . . . . . . . . . . . . . . . 12
7.3 Termination by an Employing Company . . . . . . . . . . . 12
Article Eight - Administration . . . . . . . . . . . . . . . . . . . . . 13
8.1 Named Fiduciary . . . . . . . . . . . . . . . . . . . . . 13
8.2 Fiduciary Responsibilities. . . . . . . . . . . . . . . . 13
8.3 Specific Fiduciary Responsibilities . . . . . . . . . . . 13
8.4 Allocations and Delegations of Responsibility . . . . . . 13
8.5 Advisors. . . . . . . . . . . . . . . . . . . . . . . . . 14
8.6 Plan Determination. . . . . . . . . . . . . . . . . . . . 14
8.7 Claims Review Procedure . . . . . . . . . . . . . . . . . 14
8.8 Modification and Termination. . . . . . . . . . . . . . . 16
8.9 Indemnification . . . . . . . . . . . . . . . . . . . . . 16
8.10 Successful Defense . . . . . . . . . . . . . . . . . . . 17
8.11 Unsuccessful Defense. . . . . . . . . . . . . . . . . . . 17
8.12 Advance Payments. . . . . . . . . . . . . . . . . . . . . 17
8.13 Repayment of Advance Payments . . . . . . . . . . . . . . 18
8.14 Right of Indemnification. . . . . . . . . . . . . . . . . 18
Article Nine - Effective Date. . . . . . . . . . . . . . . . . . . . . . 18
Article Ten - Miscellaneous. . . . . . . . . . . . . . . . . . . . . . . 18
10.1 Assignment. . . . . . . . . . . . . . . . . . . . . . . . 18
10.2 Governing Law . . . . . . . . . . . . . . . . . . . . . . 18
10.3 Employing Company Records . . . . . . . . . . . . . . . . 19
10.4 Employment Non-Contractual. . . . . . . . . . . . . . . . 19
<PAGE>
10.5 Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . 19
10.6 Binding Effect. . . . . . . . . . . . . . . . . . . . . . 19
10.7 Entire Agreement. . . . . . . . . . . . . . . . . . . . . 19
Attachment A - Separation Agreement. . . . . . . . . . . . . . . . . . . 20
<PAGE>
SEPARATION BENEFIT PLAN
OF UNIT CORPORATION AND
PARTICIPATING SUBSIDIARIES
Introduction
The purpose of this Plan is to provide financial assistance to Eligible
Employees whose employment has terminated under certain conditions, in
consideration of the waiver and release by such employees of any claims
arising or alleged to arise from their employment or the termination of
employment. No employee is entitled to any payment under this Plan except in
exchange for and upon the Employing Company's receipt of a written waiver and
release given in accordance with the provisions of this Plan.
ARTICLE ONE
Scope
1.1 Name
This Plan shall be known as the Separation Benefit Plan of Unit
Corporation and Participating Subsidiaries.
1.2 Plan Year
The Plan Year is the calendar year. The initial Plan Year is the period
January 1, 1997 through December 31, 1997.
ARTICLE TWO
Definitions
2.1 "Administration Committee" means the Committee established and appointed
by the Board of Directors or by a committee of the Board of Directors.
2.2 "Base Salary" means the regular basic cash remuneration before deductions
for taxes and other items withheld, and without regard to any salary
reduction pursuant to any plans maintained by an Employing Company under
Section 401(k) or 125 of the Code, payable to an Employee for services
rendered to an Employing Company, but not including pay for Bonuses,
incentive compensation, special pay, awards or commissions.
2.3 "Beneficiary" means the person designated by an Eligible Employee in a
written instrument filed with an Employing Company to receive benefits
under this Plan.
1
<PAGE>
2.4 "Board of Directors" means the board of directors of the Company.
2.5 "Bonus" means any annual incentive compensation paid to an Employee over
and above Base Salary earned and paid in cash or otherwise.
2.6 "Change in Control" of the Company shall be deemed to have occurred as of
the first day that any one or more of the following conditions shall have
been satisfied:
(i) On the close of business on the tenth day following the time the
Company learns of the acquisition by any individual entity or group
(a "Person"), including any "person" within the meaning of Section
13(d)(3) or 14(d)(2) of the Exchange Act, of beneficial ownership
within the meaning of Rule 13d-3 promulgated under the Exchange Act,
of 15% or more of either (i) the then outstanding shares of Common
Stock of the Company (the "Outstanding Company Common Stock") or
(ii) the combined voting power of the then outstanding securities of
the Company entitled to vote generally in the election of Directors
(the "Outstanding Company Voting Securities"); excluding, however,
the following: (A) any acquisition directly from the Company
(excluding any acquisition resulting from the exercise of an
exercise, conversion or exchange privilege unless the security being
so exercised, converted or exchanged was acquired directly from the
Company); (B) any acquisition by the Company; (C) any acquisition by
an employee benefit plan (or related trust) sponsored or maintained
by the Company or any corporation controlled by the Company; and (D)
any acquisition by any corporation pursuant to a transaction with
complies with clauses (i), (ii) and (iii) of subsection (iii) of
this definition;
(ii) individuals who, as of the date hereof, constitute the Board of
Directors (the "Incumbent Board") cease for any reason to constitute
at least a majority of such Board; provided that any individual who
becomes a Director of the Company subsequent to the date hereof
whose election, or nomination for election by the Company's
stockholders, was approved by the vote of at least a majority of the
Directors then comprising the Incumbent Board shall be deemed a
member of the Incumbent Board; and provided further, that any
individual who was initially elected as a Director of the Company as
a result of an actual or threatened election contest, as such terms
are used in Rule 14a-11 of Regulation 14A promulgated under the
Exchange act, or any other actual or threatened solicitation of
proxies or consents by or on behalf of any Person other than the
Board shall not be deemed a member of the Incumbent Board;
(iii) approval by the stockholders of the company of a reorganization,
merger or consolidation or sale or other disposition of all or
substantially all of the assets of the Company (a "Corporate
Transaction"); excluding, however, a Corporate Transaction pursuant
2
<PAGE>
to which (i) all or substantially all of the individuals or entities
who are the beneficial owners, respectively, of the Outstanding
Company Common Stock and the Outstanding Company Voting Securities
immediately prior to such Corporate Transaction will beneficially
own, directly or indirectly, more than 70% of, respectively, the
outstanding shares of common stock, and the combined voting power of
the outstanding securities of such corporation entitled to vote
generally in the election of Directors, as the case may be, of the
corporation resulting from such Corporate Transaction (including,
without limitation, a corporation which as a result of such
transaction owns the Company or all or substantially all of the
Company's assets either directly or indirectly) in substantially the
same proportions relative to each other as their ownership,
immediately prior to such Corporate Transaction, of the Outstanding
Company Common stock and the Outstanding Company Voting Securities,
as the case may be, (ii) no Person (other than: the Company; the
corporation resulting from such Corporate Transaction; and any
Person which beneficially owned, immediately prior to such Corporate
Transaction, directly or indirectly, 25% or more of the Outstanding
Company Common Stock or the Outstanding Voting Securities, as the
case may be) will beneficially own, directly or indirectly, 25% or
more of, respectively, the outstanding shares of common stock of the
corporation resulting from such Corporate Transaction or the
combined voting power of the outstanding securities of such
corporation entitled to vote generally in the election of Directors
and (iii) individuals who were members of the Incumbent Board will
constitute a majority of the members of the Board of Directors of
the corporation resulting from such Corporate Transaction; or
(iv) approval by the stockholders of the Company of a plan of complete
liquidation or dissolution of the Company.
2.7 "Code" means the Internal Revenue Code of 1986, as amended from time to
time.
2.8 "Company" means Unit Corporation, the sponsor of this Plan.
2.9 "Comparable Position" means a job with an Employing Company or successor
company at the same or higher Base Salary as an Employee's current job
and at a work location within reasonable commuting distance from an
Employee's home, as determined by such Employee's Employing Company.
2.10 "Completed Year of Service" means the period of time beginning with an
Employee's date of hire or the anniversary of such date of hire and
ending twelve months th ereafter.
2.11 "Discharge for Cause" means termination of the Employee's employment by
the Employing Company due to:
3
<PAGE>
(i) the willful failure of the Employee to perform the Employee's
prescribed duties to the Employing Company (other than any such
failure resulting from the Employee's incapacity due to physical or
mental illness); or
(ii) the willful commission by the Employee of a wrongful act that caused
or was reasonably likely to cause damage to the Employing Company;
or
(iii) an act of gross negligence, fraud, unfair competition, dishonesty or
misrepresentation in the performance of the Employee's duties on
behalf of the Employing Company; or
(iv) the conviction of or the entry of a plea of nolo contendere by the
Employee to any felony or the conviction of or the entry of a plea
of nolo contendere to any offense involving dishonesty, breach of
trust or moral turpitude; or
(v) a breach of an Employee's fiduciary duty involving personal profit;
or
(vi) similar actions.
2.12 "Eligible Employee" means an Employee who is determined to be eligible to
participate in this Plan and receive benefits under Article 3.
2.13 "Employee" means a person who is
(a) a regular full-time salaried employee principally employed in the
continental United States, Alaska, or Hawaii,
(b) employed by an Employing Company for work on a regular full-time
salaried schedule of at least 40 hours per week for an indefinite
period,
(c) not an employee whose compensation is determined on an hourly basis
or who hold positions that are generally characterized as "hourly"
positions, regardless of whether the position of any specific
employee is characterized as hourly or salaried,
(d) not classified as a temporary employee,
(e) not a Union represented employee unless the employee's participation
in this Plan has been bargained,
(f) not retained by an Employing Company under written contract on a
consulting or other independent contractor basis,
4
<PAGE>
(g) not a leased employee who is treated as an employee of an Employing
Company pursuant to Section 414(n) of the Internal Revenue Code, and
(h) not a member of the Board of Directors.
2.14 "Employing Company" means
(i) the Company, or
(ii) any subsidiary of the Company electing to participate in this Plan
under the provisions of Section 7.1.
2.15 "ERISA" means the Employee Retirement Income Security Act of 1974, as
from time to time amended, and all regulations and rulings issued
thereunder by governmental administrative bodies.
2.16 "Plan" means the Separation Benefit Plan of Unit Corporation and
Participating Subsidiaries Plan, as set forth herein and as hereafter
amended from time to time.
2.17 "Separation Benefit" means the benefit provided for under this Plan as
determined under Article 3.
2.18 "Separation Period" means the period of time over which an Employee
receives Separation Benefits under the Plan in semimonthly or other
installment payments.
2.19 "Termination of Employment" means an Employee's separation from the
service of an Employing Company determined by the Employing Company,
provided that a Termination of Employment does not include any separation
from service resulting from:
(i) Discharge for Cause,
(ii) court decree or government action or recommendation having an effect
on an Employing Company operations or manpower involving rationing
or price control or any other similar type cause beyond the control
of an Employing Company,
(iii) an offer to the Employee of a position with an Employing Company, or
affiliate,
(iv) termination pursuant to which an Employee accepts any benefits under
an incentive retirement plan or other severance or separation plan,
or
(v) termination of an Employee who has a written employment contract
which contains severance provisions.
<PAGE>
Temporary work cessations due to strikes, lockouts or similar reasons
shall not be considered a Termination of Employment. An Employee's
separation from service in connection with the divestiture of any
business of an Employing Company shall not constitute a Termination of
Employment if the Employee is offered a Comparable Position by the
purchaser or successor of such business, an affiliate thereof, or an
affiliate of an Employing Company. A separation from service by an
Employee who is offered a Comparable Position arranged for or secured by
an Employing Company does not constitute a Termination of Employment.
A Termination or Employment shall be effective on the date specified by
the Employing Company (the "Termination Date").
2.20 "Years of Service" means the sum of the number of continuous Completed
Years of Service as an Employee of an Employing Company during the period
of employment beginning with the Employee's most recent hire date and
ending with the Employee's most recent termination date.
ARTICLE THREE
Benefits
3.1 Eligibility
Each Employee who has at least one active Year of Service with an
Employing Company immediately preceding the date of his or her
Termination of Employment, who complies with all administrative
requirements of this Plan, including the provisions of Article Five,
and who works through his/her Termination Date, is eligible to
participate in this Plan and, subject to all the terms of the Plan,
receive benefits as provided in this Article Three. An Employee is
ineligible to participate in this Plan if such Employee fails to satisfy
any of the requirements of this Plan including, but not limited to,
failure to establish that his or her termination meet the requirements
for a Termination of Employment.
3.2 Separation Benefit
A Separation Benefit shall be provided for Eligible Employees under the
provisions of this Article 3.
3.3 Separation Benefit Amount
The Separation Benefit payable to an Eligible Employee under the Plan
shall be based, in part, on his/her Years of Service with the Company, or
Employing Company. The formula for determining an Employee's Separation
Benefit payment shall be calculated by dividing the Employee's annual
6
<PAGE>
Base Salary in effect immediately prior to the date of Termination of
Employment by 52 to calculate the weekly separation benefit (the "Weekly
Separation Benefit"). The amount of the Separation Benefit payable to
the Eligible Employee shall then be determined in accordance with the
following applicable provision:
3.3.1 Involuntary separation - In the event the Termination of Employment is
the result of an Employing Company terminating the employment of the
Eligible Employee, the Separation Benefit shall be determined according
to the following schedule:
Involuntary Separation
Schedule of Separation Benefits
Number of Weekly Number of Weekly
Years of Separation Benefit Years of Separation Benefit
Service Payments: Service Payments:
1 4 14 56
2 8 15 60
3 12 16 64
4 16 17 68
5 20 18 72
6 24 19 76
7 28 20 80
8 32 21 84
9 36 22 88
10 40 23 92
11 44 24 96
12 48 25 100
13 52 26 or more 104
3.3.2 Voluntary separation - In the event the Termination of Employment is the
result of the Eligible Employee's own action (such as by way of example
and not limitation, quitting, resignation or retirement) the Separation
Benefit shall be determined according to the following Schedule:
7
<PAGE>
Voluntary Separation
Schedule of Separation Benefits
Number of Weekly
Years of Separation Benefit
Service Payments
1-19 0
20 80
21 84
22 88
23 92
24 96
25 100
26 or more 104
Under certain exceptional circumstances the Administration Committee may,
in its sole and absolute discretion, choose to treat a voluntary
separation as an involuntary separation and allow an Eligible Employee to
receive Separation Benefits in accordance with the schedule set forth in
Section 3.3.1.
3.4 Separation Benefit Limitation
Notwithstanding anything in the Plan to the contrary, the Separation
Benefit payable to any Eligible Employee under this Plan shall never
exceed the lesser of (i) 104 Weekly Separation Benefit payments; or (ii)
the amount permitted under ERISA to maintain this Plan as a welfare
benefit plan. The benefits payable under this Plan shall be inclusive of
and offset by any other severance or termination payments made by an
Employing Company, including, but not limited to, any amounts paid
pursuant to federal, state, local or foreign government worker
notification (e.g., Worker Adjustment and Retraining Notification Act) or
office closing requirements.
3.5 Withholding Tax
The Employing Company shall deduct from the amount of any Separation
Benefits payable under the Plan, any amount required to be withheld by
the Employing Company by reason of any law or regulation, for the payment
of taxes or otherwise to any federal, state, local or foreign government.
In determining the amount of any applicable tax, the Employing Company
shall be entitled to rely on the number of personal exemptions on the
official form(s) filed by the Employee with the Employing Company for
purposes of income tax withholding on regular wages.
8
<PAGE>
3.6 Reemployment of an Eligible Employee
Entitlement to the unpaid balance of any Separation Benefit amount due an
Eligible Employee under this Plan shall be revoked immediately upon
reemployment of the person as an Employee of an Employing Company. Such
unpaid balance shall not be payable in any future period.
However, if the person's re-employment is subsequently terminated and he
or she then becomes entitled to a Separation Benefit under this Plan,
Years of Service for the period of re-employment shall be added to that
portion of his or her prior service represented by the unpaid balance or
the revoked entitlement for the prior Separation Benefit.
3.7 Integration with Disability Benefits
The Separation Benefit payable to an Eligible Employee with respect to
any Separation Period shall be reduced (but not below zero) by the amount
of any disability benefit payable from any disability plan or program
sponsored or contributed to by an employing Company. The amount of any
such reduction shall not be paid to the Eligible Employee in
any future period.
3.8 Plan Benefit Offset
The amount of any severance or separation type payment that an Employing
Company is or was obligated to pay to an Eligible Employee under any law,
decree, court award, contract, program or other arrangement because of
the Eligible Employee's separation from service from an Employing Company
shall reduce the amount of Separation Benefit otherwise payable under
this Plan.
3.9 Recoupment
An Employing Company may deduct from the Separation Benefit any amount
owing to an Employing Company from
(a) the Eligible Employee, or
(b) the executor or administrator of the Eligible Employee's estate.
3.10 Completion of Twenty Years of Service
Any Eligible Employee who shall complete Twenty Years of Service prior to
the termination of this Plan shall be vested in his/her Separation
Benefit notwithstanding the subsequent termination of this Plan prior to
such Employee's Termination of Employment. Any Separation Benefit deemed
9
<PAGE>
to have vested pursuant to this section shall be payable upon such
Employee's Termination of Employment with the Employing Company and
shall be paid in accordance with the greater of (1) the Plan provisions
in effect immediately prior to the termination of this Plan, and (2) the
Plan provisions in effect on the date the Employee completed Twenty Years
of Service.
3.11 Change in Control
Unless otherwise provided in writing by the Board of Directors prior to a
Change in Control of the Company, all Eligible Employees shall be vested
in his/her Separation Benefit as of the date of the Change in Control
based on such Eligible Employee's then Years of Service as determined by
reference to the schedule set forth in Section 3.3.1 of this Plan. Any
Separation Benefit deemed to have vested pursuant to this section shall
be payable upon the Eligible Employee's Termination of Employment with
the Employing Company and shall be paid in accordance with the Plan
provisions in effect immediately prior to the Change in Control.
ARTICLE FOUR
Method of Payment
4.1 Separation Benefit Payment
Separation Benefit payments shall, unless otherwise determined by the
Administration Committee, be paid in the same manner as wages were paid
to the Employee.
4.2 Forfeiture of Separation Benefit Payments By Competition
Any Eligible Employee who receives Separation Benefits under Section
3.3.2 of this Plan agrees that, in consideration of the benefits
provided herein, Employee will not without the consent of the Employing
Company enter into competition with the Employing Company. For purposes
of this paragraph, Employee shall be deemed to be in competition if
Employee directly or indirectly, whether as consultant, agent, officer,
director, employee or otherwise, enters into an association with another
business enterprise which then is one of the competitors of the Employing
Company respecting one or more of the Employing Company's business
activities. The parties agree that one of the essential considerations
for benefits provided Employee hereunder is to protect and preserve the
good will of the Employing Company and its respective enterprises, and
that said good will will be substantially diminished in value if Employee
were to enter into competition with the Employing Company during the
Separation Period.
In the event Employee is deemed to be in competition contrary to the
provisions of this Section, thereupon Employee shall forfeit all rights
10
<PAGE>
to any further payments of benefits under this Plan and shall be
obligated to repay the Employing Company all benefit payments previously
received under this Plan.
In the event of a Change in Control, Employee's obligations under this
Section shall expire and be canceled, and Employee shall be entitled to
the benefits provided under this Plan in accordance with the terms of
this Plan, notwithstanding whether Employee thereafter engages in
competition described in this Section.
4.3 Death Subsequent to Termination of Employment
If the death of an Eligible Employee occurs subsequent to the date of
Termination of Employment and before receipt of the full Separation
Benefit to which he or she was entitled, the computed lump sum value of
the unpaid balance of the Separation Benefit amount shall be paid to such
Eligible Employee's Beneficiary. If there is no designated living
Beneficiary, the computed lump sum value shall be paid to the executor or
administrator of the Eligible Employee's estate.
ARTICLE FIVE
Waiver and Release of Claims
It is a condition of this Plan that no Separation Benefit shall be paid to or
for any Employee except upon due execution and delivery to the Employing Company
by that Employee of a Separation Agreement, in substantially the form attached
to this Plan as Attachment A (except as may be modified from time to time), by
which the Employee waives and releases the Company, its subsidiaries and their
officers, directors, agents, employees, and affiliates from all claims arising
or alleged to arise out of his or her employment or the termination of
employment. Said waiver and release as provided in the Separation Agreement
being given in exchange for and in consideration of payment of the Separation
Benefit, to which the Employee would not otherwise be entitled.
In connection therewith, the following procedures shall be followed (except as
modified from time to time): the Employee shall be advised in writing, by
receiving the written text of the Separation Agreement so stating, to consult a
lawyer before signing the Separation Agreement; the Employee shall be given
twenty-one days to consider the Separation Agreement before signing; after
signing, the Employee shall have seven days in which to revoke the Separation
Agreement; and the Separation Agreement shall not take effect until that seven
day period shall have passed.
ARTICLE SIX
Funding
This Plan is an unfunded employee welfare benefit plan under ERISA established
by the Company. Benefits payable to Eligible Employees shall be paid out of the
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<PAGE>
general assets of the Employing Company. The Employing Company shall not be
required to establish any special or separate fund or to make any other
segregation of assets to assure the payment of any Separation Benefits under the
Plan.
ARTICLE SEVEN
Operation
7.1 Employing Company Participation
Any subsidiary of the Company may participate as an Employing Company in
the Plan upon the following conditions:
(a) Such subsidiary shall make, execute and deliver such instruments as
the Company shall deem necessary or desirable;
(b) Such subsidiary may withdraw from participation as an Employing
Company upon notice to the Company in which event such subsidiary
may continue the provisions or this Plan as its own plan, and may
thereafter, with respect thereto, exercise all of the rights and
powers theretofore reserved to the Company; and
(c) Any modification or amendment of the Plan made or adopted by the
Company shall be deemed to have been accepted by each Employing
Company.
7.2 Status of Subsidiaries
The authority of each subsidiary to act independently and in accordance
with its own best judgment shall not be prejudiced or diminished by its
participation in this Plan and at the same time the several Employing
Company may act collectively in respect of general administration of this
Plan in order to secure administrative economies and maximum uniformity.
7.3 Termination by an Employing Company
Any Employing Company other than the Company may withdraw from
participation in the Plan at any time by delivering to the Administration
Committee written notification to that effect signed by such Employing
Company's chief executive officer or his delegate. Withdrawal by any
Employing Company pursuant to this paragraph or complete discontinuance
of Separation Benefits under the Plan by any Employing Company other
than the Company, shall constitute termination of the Plan with respect
to such Employing Company, but such actions shall not affect any
Separation Benefit that has become payable to an Eligible Employee, and
such benefit shall continue to be paid in accordance with the Plan
provisions in effect on the Termination of Employment.
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<PAGE>
ARTICLE EIGHT
Administration
8.1 Named Fiduciary
This Plan shall be administered by the Company acting through the
Administration Committee or such other person as may be designated by the
Company from time to time. The Administration Committee shall be the
"Administrator" of the Plan and shall be, in its capacity as
Administrator, a "Named Fiduciary," as such terms are defined or used in
ERISA.
8.2 Fiduciary Responsibilities
The named fiduciary shall fulfill the duties and requirements of such a
fiduciary under ERISA and is the Plan's agent for service of legal
process. The named fiduciary may designate other persons to carry out
such fiduciary responsibilities and may cancel such a designation. A
person may serve in more than one fiduciary or administrative capacity
with respect to this Plan. The named fiduciary shall periodically review
the performance of the fiduciary responsibilities by each designated
person.
8.3 Specific Fiduciary Responsibilities
The Administration Committee shall be responsible for the general
administration and interpretation of the Plan and the proper execution of
its provisions and shall have full discretion to carry out its duties.
In addition to any powers of the Administration Committee specified
elsewhere in this Plan, the Administration Committee shall have all
discretionary powers necessary to discharge its duties under this Plan,
including, but not limited to, the following discretionary powers and
duties:
8.3.1 To interpret or construe the terms of the Plan, including
eligibility to participate, and resolve ambiguities,
inconsistencies and omissions;
8.3.2 To make and enforce such rules and regulations and prescribe the
use of such forms as it deems necessary or appropriate for the
efficient administration of the Plan; and
8.3.3 To decide all questions concerning the Plan and the eligibility of
any person to participate in the Plan.
8.4 Allocations and Delegations of Responsibility
The Board of Directors and the Administration Committee respectively
shall have the authority to delegate, from time to time, all or any part
13
<PAGE>
of its responsibilities under this Plan to such person or persons as it
may deem advisable and in the same manner to revoke any such delegation
of responsibility. Any action of the delegate in the exercise of such
delegated responsibilities shall have the same force and effect for all
purposes hereunder as if such action had been taken by the Board of
Directors or the Administration Committee. The Company, the Board of
Directors and the Administration Committee shall not be liable for any
acts or omissions of any such delegate. The delegate shall report
periodically to the Board of Directors or the Administration Committee,
as applicable, concerning the discharge of the delegated
responsibilities.
The Board of Directors and the Administration Committee respectively
shall have the authority to allocate, from time to time, all or any part
of its responsibilities under this Plan to one or more of its members as
it may deem advisable, and in the same manner to remove such allocation
of responsibilities. Any action of the member to whom responsibilities
are allocated in the exercise of such allocated responsibilities shall
have the same force and effect for all purposes hereunder as if such
action had been taken by the Board of Directors or the Administration
Committee. The Company, the Board of Directors and the Administration
Committee shall not be liable for any acts or omissions of such member.
The member to whom responsibilities have been allocated shall report
periodically to the Board of Directors or the Administration Committee,
as applicable, concerning the discharge of the allocated
responsibilities.
8.5 Advisors
The named fiduciary or any person designated by the named fiduciary to
carry out fiduciary responsibilities may employ one or more persons to
render advice with respect to any responsibility imposed by this Plan.
8.6 Plan Determination
The determination of the Administration Committee as to any question
involving the general administration and interpretation or construction
of the Plan shall be within its sole discretion and shall be final,
conclusive and binding on all persons, except as otherwise
provided herein or by law.
8.7 Claims Review Procedure
Consistent with the requirements of ERISA and the regulations thereunder
as promulgated by the Secretary of Labor from time to time, the following
claims review procedure shall be followed with respect to the denial of
Separation Benefits to any Employee:
8.7.1 Within thirty (30) days from the date of an Employee's
Termination of Employment, the Employing Company shall furnish
such Employee with an agreement and release offering Separation
14
<PAGE>
Benefits under the Plan or notice of such Employee's
ineligibility for or denial of Separation Benefits, either in
whole or in part. Such notice from the Employing Company will
be in writing and sent to the Employee or the legal
representatives of his estate stating the reasons for such
ineligibility or denial and, if applicable, a description of
additional information that might cause a reconsideration by
the Administration Committee or its delegate of the decision
and an explanation for the Plan's claims review procedure. In
the event such notice is not furnished within thirty (30) days,
any claim for Separation Benefits shall be deemed denied and
the Employee shall be permitted to proceed to Section 8.7.2
below.
8.7.2 Each Employee may submit a claim for benefits to the
Administration Committee (or to such other person as may be
designated by the Administration Committee) in writing in such
form as is permitted by the Administration Committee. An
Employee shall have no right to seek review of a denial of
benefits, or to bring any action in any court to enforce a
claim for benefits prior to his filing a claim for benefits and
exhausting his rights to review under this section.
When claim for benefits has been filed properly, such claim for
benefits shall be evaluated and the Employee shall be notified
of the approval or the denial within ninety (90) days after the
receipt of such claim unless special circumstances require
an extension of time for processing the claim. If such an
extension of time for processing is required, written notice of
the extension shall be furnished to the Employee prior to the
termination of the initial ninety (90) day period which shall
specify the special circumstances requiring an extension and
the date by which a final decision shall be reached (which date
shall not be later than one hundred and eighty (180) days after
the date on which the claim was filed). The Employee shall
be given a written notice in which the Employee shall be
advised as to whether the claim is granted or denied, in whole
or in part. If a claim is denied by the Administrative
Committee, in whole or in part, the Employee shall be given
written notice which shall contain (1) the specific reasons for
the denial, (2) references to pertinent Plan provisions upon
which the denial is based, (3) a description of any additional
material or information necessary to perfect the claim and an
explanation of why such material or information is necessary,
and (4) the Employee's rights to seek review of the denial.
8.7.3 If a claim is denied, in whole or in part, the Employee shall
have the right to request that the Administration Committee
review the denial, provided that the Employee files a written
request for review with the Administration Committee within
sixty (60) days after the date on which the Employee received
written notification of the denial. The Employee (or his duly
authorized representative) may review pertinent documents and
submit issues and comments in writing to the Administration
15
<PAGE>
Committee. Within sixty (60) days after a request for review
is received, the review shall be made and the Employee shall be
advised in writing of the decision on review, unless special
circumstances require an extension of time for processing the
review, in which case the Employee shall be given a written
notification within such initial sixty (60) day period
specifying the reasons for the extension and when such review
shall be completed (provided that such review shall be
completed within one hundred and twenty (120) days after the
date on which the request for review was filed). The decision
on review shall be forwarded to the Employee in writing and
shall include specific reasons for the decision and references
to Plan provisions upon which the decision is based. A
decision on review shall be final and binding on all persons.
8.7.4 If an Employee fails to file a request for review in accordance
with the procedures herein outlined, such Employee shall have
no rights to review and shall have no right to bring action in
any court and the denial of the claim shall become final and
binding on all persons for all purposes.
8.7.5 The determination whether to grant or to deny any claims for
benefits under this Plan shall be made by the Administration
Committee, in its sole and absolute discretion, and all such
determinations shall be conclusive and binding on all
persons to the maximum extent permitted by law.
8.8 Modification and Termination
The Company by action of its Board of Directors may at any time, without
notice or consent of any person, terminate or modify this Plan in whole
or in part, and such termination or modification shall apply to existing
as well as to future employees, but such actions shall not affect any
Separation Benefit that has become payable to an Eligible Employee, and
such benefit shall continue to be paid in accordance with the Plan
provisions in effect on the date of the Termination of Employment.
8.9 Indemnification
To the extent permitted by law, the Company shall indemnify and hold
harmless the members of the Board of Directors, the Administration
Committee members, and any employee to whom any fiduciary responsibility
with respect to this Plan is allocated or delegated to, and against any
and all liabilities, costs and expenses incurred by any such person as a
result of any act, or omission to act, in connection with the performance
of his/her duties, responsibilities and obligations under this Plan,
ERISA and other applicable law, other than such liabilities, costs and
expenses as may result from the gross negligence or willful misconduct of
any such person. The foregoing right of indemnification shall be in
addition to any other right to which any such person may be entitled as a
matter of law or otherwise. The Company may obtain, pay for and keep
current a policy or policies of insurance, insuring the members of the
16
<PAGE>
Board of Directors, the Administration Committee members and any other
employees who have any fiduciary responsibility with respect to this Plan
from and against any and all liabilities, costs and expenses incurred by
any such person as a result of any act, or omission, in connection with
the performance of his/her duties, responsibilities and obligations under
this Plan and under ERISA.
8.10 Successful Defense
A person who has been wholly successful, on the merits or otherwise, in
the defense of a civil or criminal action or proceeding or claim or
demand of the character described in Section 8.9 above shall be entitled
to indemnification as authorized in such Section 8.9.
8.11 Unsuccessful Defense
Except as provided in Section 8.10 above, any indemnification under
Section 8.9 above, unless ordered by a court of competent jurisdiction,
shall be made by the Company only if authorized in the specific case:
8.11.1 By the Board of Directors acting by a quorum consisting of
directors who are not parties to such action, proceeding, claim
or demand, upon a finding that the member of the Administration
Committee has met the standard of conduct set forth in Section
8.9 above; or
8.11.2 If a quorum under Section 8.11.1 above is not obtainable with
due diligence:
8.11.2.1 By the Board of Directors upon the opinion in writing of
independent legal counsel (who may be counsel to any Employing
Company) that indemnification is proper in the circumstances
because the standard of conduct set forth in Section 8.9 above
has been met by such member of the Administration Committee; or
8.11.2.2 By the shareholders of the Company upon a finding that the
member of the Administration Committee has met the standard of
conduct set forth in such Section 8.9 above.
8.12 Advance Payments
Expenses incurred in defending a civil or criminal action or proceeding
or claim or demand may be paid by the Company or Employing Company, as
applicable, in advance of the final disposition of such action or
proceeding, claim or demand, if authorized in the manner specified in
Section 8.11 above, except that, in view of the obligation of repayment
set forth in Section 8.13 below, there need be no finding or opinion that
the required standard of conduct has been met.
17
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8.13 Repayment of Advance Payments
All expenses incurred, in defending a civil or criminal action or
proceeding, claim or demand, which are advanced by the Company or
Employing Company, as applicable, under Section 8.12 above shall be
repaid in case the person receiving such advance is ultimately found,
under the procedures set forth in this Article Eight, not to be entitled
to the extent the expenses so advanced by the Company exceed the
indemnification to which he or she is entitled.
8.14 Right of Indemnification
Notwithstanding the failure of the Company or Employing Company, as
applicable, to provide indemnification in the manner set forth in Section
8.11 and 8.12 above, and despite any contrary resolution of the Board of
Directors or of the shareholders in the specific case, if the member of
the Administration Committee has met the standard of conduct set forth in
Section 8.9 above, the person made or threatened to be made a party
to the action or proceeding or against whom the claim or demand has been
made, shall have the legal right to indemnification from the Company or
Employing Company, as applicable, as a matter of contract by virtue of
this Plan, it being the intention that each such person shall have the
right to enforce such right of indemnification against the Company or
Employing Company, as applicable, in any court of competent jurisdiction.
ARTICLE NINE
Effective Date
This Plan shall be effective on and after January 1, 1997.
ARTICLE TEN
Miscellaneous
10.1 Assignment
An Employee's right to benefits under this Plan shall not be assigned,
transferred, pledged, encumbered in any way or subject to attachment or
garnishment, and any attempted assignment, transfer, pledge, encumbrance,
attachment, garnishment or other disposition of such benefits shall be
null and void and without effect.
10.2 Governing Law
To the extent not governed by federal law, this Plan and all action taken
under it shall be governed by the laws of the State of Oklahoma.
18
<PAGE>
10.3 Employing Company Records
The records of the Employing Company with regard to any person's Eligible
Employee status, Beneficiary status, employment history, Years of Service
and all other relevant matters shall be conclusive for purposes of
administration of the Plan.
10.4 Employment Non-Contractual
This Plan is not intended to and does not create a contract of
employment, express or implied, and an Employing Company may terminate
the employment of any employee with or without cause as freely and with
the same effect as if this Plan did not exist. Nothing contained in the
Plan shall be deemed to qualify, limit or alter in any manner the
Employing Company's sole and complete authority and discretion to
establish, regulate, determined or modify at all time, the terms and
conditions of employment, including, but not limited to, levels of
employment, hours of work, the extent of hiring and employment
termination, when and where work shall be done, marketing of its
products, or any other matter related to the conduct of its business or
the manner in which its business is to be maintained or carried on, in
the same manner and to the same extent as if this Plan were not in
existence.
10.5 Taxes
Neither an Employing Company nor any fiduciary of this Plan shall be
liable for any taxes incurred by an Eligible Employee or Beneficiary for
Separation Benefit payments made pursuant to this Plan.
10.6 Binding Effect
This Plan shall be binding on the Company, any Employing Company and
their successors and assigns, and the Employee, Employee's heirs,
executors, administrators and legal representatives. As used in this
Plan, the term "successor" shall include any person, firm, corporation or
other business entity which at any time, whether by merger, purchase or
otherwise, acquires all or substantially all of the assets or business of
the Company or any Employing Company.
10.7 Entire Agreement
This Plan constitutes the entire understanding between the parties hereto
and may be modified only in accordance with the terms of this Plan.
19
<PAGE>
To receive a Separation Benefit, an eligible employee must sign the
following Separation Agreement provided by the Company:
SEPARATION AGREEMENT
[Name of Employing Company] ("Unit") and --------------------------------
("Employee") hereby agree as follows:
Employee's employment will end on __________________________, 19___.
Unit will pay to Employee a Separation Benefit of $_________________ in
accordance with and subject to the terms of the Separation Benefit Plan
of Unit Corporation and Participating Subsidiaries (the "Plan").
Employee knows that state and federal laws, including the Age
Discrimination in Employment Act, prohibit employment discrimination
based on age, sex, race, color, national origin, religion, handicap,
disability, or veteran status, and that these laws are enforced through
the United States Equal Employment Opportunity Commission ("EEOC"),
United States Department of Labor, and State Human Rights Agencies.
EMPLOYEE HAS BEEN ADVISED TO CONSULT AN ATTORNEY PRIOR TO
SIGNING THIS AGREEMENT.
EMPLOYEE HAS TWENTY-ONE DAYS AFTER RECEIVING THIS AGREEMENT
TO CONSIDER WHETHER TO SIGN IT.
AFTER SIGNING THIS AGREEMENT, EMPLOYEE HAS ANOTHER SEVEN
DAYS IN WHICH TO REVOKE IT, AND IT DOES NOT TAKE EFFECT UNTIL
THOSE SEVEN DAYS HAVE ENDED.
In exchange for the Separation Benefit described above, to which
Employee is not otherwise entitled, Employee forever releases and
discharges Unit Corporation, and its subsidiaries, their officers,
directors, agents, employees, and affiliates from all claims,
liabilities, and lawsuits arising out of Employee's employment or the
termination of that employment and agrees not to assert any such claim,
liability, or lawsuit. This includes any claim under the Age
Discrimination in Employment Act or under any other federal, state,
or local statute or regulation relating to employment discrimination. It
also includes any claim under any other statute or regulation or common
law rule relating to Employee's employment or the termination of that
employment. This Agreement does not have any effect with respect to acts
or events occurring after the date upon which Employee signs it. This
Agreement does not limit any benefits to which Employee is entitled under
any retirement plans, if any.
20
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As further consideration for the payment of the Separation Benefit
described above, Employee agrees that if Employee's Separation Benefit is
received pursuant to Section 3.3.2 "Voluntary Separation" of the Plan,
Employee will not without the consent of Unit enter into competition with
Unit. For purposes of this paragraph, Employee shall be deemed to be in
competition if Employee directly or indirectly, whether as consultant,
agent, officer, director, employee or otherwise, enters into an
association with another business enterprise which then is one of the
competitors of Unit respecting one or more of Unit's business activities.
The parties agree that one of the essential considerations for benefits
provided Employee hereunder is to protect and preserve the good will of
Unit and its respective enterprises, and that said good will will be
substantially diminished in value if Employee were to enter into
competition with Unit during the period of time over which Employee is
receiving payments or benefits under this Plan.
In the event Employee is deemed to be in competition contrary to the
provisions hereof, thereupon Employee shall forfeit all rights to any
further payments of benefits under the Plan and shall be obligated to
repay Unit all benefit payments previously received under the Plan.
In the event of a Change in Control (as defined in the Plan), Employee's
obligations under this Paragraph shall expire and be canceled, and
Employee shall be entitled to the benefits provided under the Plan in
accordance with the terms of the Plan, notwithstanding whether Employee
thereafter engages in competition described in this Paragraph.
Employee has carefully read and fully understands all the provisions
of this Agreement. This is the entire Agreement between the parties and
is legally binding and enforceable. Employee has not relied upon any
representation or statement, written or oral, not set forth in this
Agreement.
This Agreement shall be governed and interpreted under federal law
and the laws of Oklahoma.
Employee knowingly and voluntarily signs this Agreement.
Date Delivered to Employee: [Name of Employing Company]
______________________________ By: _______________________________
Date signed by Employee: Title: ______________________________
______________________________ Date: ______________________________
21
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Employee Signature: Seven-Day Revocation Period Ends:
______________________________ ____________________________________
______________________________
(Print Employee's Name)
22
<PAGE>
EXHIBIT 10.2.31
<PAGE>
CONFIDENTIAL
For Private Placement Purposes Only Copy No. ____
UNIT 1997 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
1000 Kensington Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
(918) 493-7700
A PRIVATE OFFERING
OF
UNITS OF LIMITED PARTNERSHIP INTEREST
_____________________________________
THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURITIES
ACT OF 1933, AS AMENDED, OR UNDER APPLICABLE STATE SECURITIES ACTS IN
RELIANCE ON EXEMPTIONS PROVIDED BY SUCH ACTS. THESE SECURITIES MAY NOT
BE SOLD OR TRANSFERRED IN THE ABSENCE OF AN EFFECTIVE REGISTRATION UNDER
SUCH ACTS OR AN OPINION OF COUNSEL ACCEPTABLE TO THE GENERAL PARTNER
THAT SUCH REGISTRATION IS NOT REQUIRED. FURTHER, THE RESALE OF A UNIT MAY
RESULT IN SUBSTANTIAL TAX LIABILITY TO THE INVESTOR. SEE "FEDERAL INCOME
TAX 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 14, 1997
500 Preformation
Units of Limited Partnership Interest
in the
UNIT 1997 EMPLOYEE
OIL AND GAS LIMITED PARTNERSHIP
(i)
<PAGE>
_____________________________________
$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 1997 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP, a proposed
Oklahoma limited partnership (the "Partnership"), are being offered privately
only to certain employees of Unit Corporation ("UNIT") and its subsidiaries and
the directors of UNIT at a price of $1,000 per Unit. Subscriptions shall be for
not less than 2 Units ($2,000). The Partnership is being formed for the purpose
of conducting oil and gas drilling and development operations. Purchasers of
the Units will become Limited Partners in the Partnership. Unit Petroleum
Company ("UPC" or the "General Partner") will serve as General Partner of the
Partnership. UPC's address is 1000 Kensington Tower I, 7130 South Lewis Avenue,
Tulsa, Oklahoma 74136, telephone (918) 493-7700.
THE RIGHTS AND OBLIGATIONS OF THE GENERAL PARTNER
AND THE LIMITED PARTNERS ARE GOVERNED BY THE
AGREEMENT OF LIMITED PARTNERSHIP (THE "AGREEMENT"),
A COPY OF WHICH ACCOMPANIES THIS MEMORANDUM AND IS
INCORPORATED HEREIN BY REFERENCE
AN INVESTMENT IN THE UNITS IS SPECULATIVE AND INVOLVES
A HIGH DEGREE OF RISK. SEE "RISK FACTORS". CERTAIN
SIGNIFICANT RISKS INCLUDE:
. Drilling to establish productive oil and natural gas properties is
inherently speculative.
. Participants will rely solely on the management capability and expertise
of the General Partner.
. Limited Partners must assume the risks of an illiquid investment.
. Investment in the Units is suitable only for investors having sufficient
financial resources and who desire a long term investment.
. Conflicts of interest exist and additional conflicts of interest may arise
between the General Partner and the Limited Partners, and there are no
pre-determined procedures for resolving any such conflicts.
. Significant tax considerations to be considered by an investor include:
. possible audit of income tax returns of the Partnership and/or the
Limited Partners and resulting reduction or elimination of tax
benefits; and
. Limited Partners will not benefit from Partnership losses unless they
have passive income from other activities.
(ii)
<PAGE>
. 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 Amended and Restated Stock Option Plan and related
prospectuses covering shares of Common Stock issuable upon exercise
of outstanding options.
5. UNIT'S Non Employee Directors' Stock Option Plan.
6. The Credit Agreement and the notes payable of UNIT.
7. All periodic reports on Forms 10-K, 10-Q and 8-K and all proxy
materials filed by or on behalf of UNIT with the Securities and
Exchange Commission pursuant to the Securities Exchange Act of 1934,
as amended, during calendar year 1995, the annual report to
shareholders and all quarterly reports to shareholders submitted by
UNIT to its shareholders during calendar year 1996.
8. The agreements of limited partnership for the prior oil and gas
drilling programs and prior employee programs of Unit Petroleum
Company, UNIT and Unit Drilling and Exploration Company ("UDEC").
9. All periodic reports filed with the Securities and Exchange
Commission and all reports and information provided to limited
partners in all limited partnerships of which Unit Petroleum Company,
UNIT or UDEC now serves or has served in the past as a general
partner.
10. The agreement of limited partnership for the Unit 1986 Energy Income
Limited Partnership.
(v)
<PAGE>
SUMMARY OF CONTENTS
Page
SUMMARY OF PROGRAM . . . . . . . . . . . . . . . . . . . . . . . . . .1
Terms of the Offering . . . . . . . . . . . . . . . . . . . . . .1
Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . .2
Additional Financing. . . . . . . . . . . . . . . . . . . . . . .4
Proposed Activities . . . . . . . . . . . . . . . . . . . . . . .5
Application of Proceeds . . . . . . . . . . . . . . . . . . . . .5
Participation in Costs and Revenues . . . . . . . . . . . . . . .6
Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . .7
Federal Income Tax Aspects. . . . . . . . . . . . . . . . . . . .7
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7
Investment Risks. . . . . . . . . . . . . . . . . . . . . . . . .7
Tax Related Risks . . . . . . . . . . . . . . . . . . . . . . . 14
Operational Risks . . . . . . . . . . . . . . . . . . . . . . . 16
TERMS OF THE OFFERING. . . . . . . . . . . . . . . . . . . . . . . . 18
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Limited Partnership Interests . . . . . . . . . . . . . . . . . 19
Subscription Rights . . . . . . . . . . . . . . . . . . . . . . 19
Payment for Units; Delinquent Installment . . . . . . . . . . . 20
Right of Presentment. . . . . . . . . . . . . . . . . . . . . . 21
Rollup or Consolidation of Partnership. . . . . . . . . . . . . 23
ADDITIONAL FINANCING . . . . . . . . . . . . . . . . . . . . . . . . 24
Additional Assessments. . . . . . . . . . . . . . . . . . . . . 24
Prior Programs. . . . . . . . . . . . . . . . . . . . . . . . . 25
Partnership Borrowings. . . . . . . . . . . . . . . . . . . . . 25
PLAN OF DISTRIBUTION . . . . . . . . . . . . . . . . . . . . . . . . 26
Suitability of Investors. . . . . . . . . . . . . . . . . . . . 26
RELATIONSHIP OF THE PARTNERSHIP, THE GENERAL PARTNER
AND AFFILIATES . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
PROPOSED ACTIVITIES. . . . . . . . . . . . . . . . . . . . . . . . . 27
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Partnership Objectives. . . . . . . . . . . . . . . . . . . . . 30
Areas of Interest . . . . . . . . . . . . . . . . . . . . . . . 31
Transfer of Properties. . . . . . . . . . . . . . . . . . . . . 31
Record Title to Partnership Properties. . . . . . . . . . . . . 32
Marketing of Reserves . . . . . . . . . . . . . . . . . . . . . 32
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . 32
(vi)
<PAGE>
APPLICATION OF PROCEEDS. . . . . . . . . . . . . . . . . . . . . . . 33
PARTICIPATION IN COSTS AND REVENUES. . . . . . . . . . . . . . . . . 33
COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Supervision of Operations . . . . . . . . . . . . . . . . . . . 35
Purchase of Equipment and Provision of Services . . . . . . . . 36
Prior Programs. . . . . . . . . . . . . . . . . . . . . . . . . 36
MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
The General Partner . . . . . . . . . . . . . . . . . . . . . . 38
Officers, Directors and Key Employees . . . . . . . . . . . . . 38
Prior Employee Programs . . . . . . . . . . . . . . . . . . . . 41
Ownership of Common Stock . . . . . . . . . . . . . . . . . . . 42
Interest of Management in Certain Transactions. . . . . . . . . 44
CONFLICTS OF INTEREST. . . . . . . . . . . . . . . . . . . . . . . . 45
Acquisition of Properties and Drilling Operations . . . . . . . 45
Participation in UNIT's Drilling or Income Programs . . . . . . 47
Transfer of Properties. . . . . . . . . . . . . . . . . . . . . 47
Partnership Assets. . . . . . . . . . . . . . . . . . . . . . . 48
Transactions with the General Partner or Affiliates . . . . . . 48
Right of Presentment Price Determination. . . . . . . . . . . . 49
Receipt of Compensation Regardless of Profitability . . . . . . 49
Legal Counsel . . . . . . . . . . . . . . . . . . . . . . . . . 49
FIDUCIARY RESPONSIBILITY . . . . . . . . . . . . . . . . . . . . . . 49
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Liability and Indemnification . . . . . . . . . . . . . . . . . 50
PRIOR ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . 51
Prior Employee Programs . . . . . . . . . . . . . . . . . . . . 54
Results of the Prior Oil and Gas Programs . . . . . . . . . . . 55
FEDERAL INCOME TAX ASPECTS . . . . . . . . . . . . . . . . . . . . . 64
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
Summary of Certain Matters. . . . . . . . . . . . . . . . . . . 65
Partnership Classification. . . . . . . . . . . . . . . . . . . 65
Taxation of Limited Partners. . . . . . . . . . . . . . . . . . 66
IRS Tax Shelter Registration. . . . . . . . . . . . . . . . . . 73
Partnership Tax Returns and Tax Information . . . . . . . . . . 73
Laws Subject to Change. . . . . . . . . . . . . . . . . . . . . 74
State and Local Taxes . . . . . . . . . . . . . . . . . . . . . 74
COMPETITION, MARKETS AND REGULATION. . . . . . . . . . . . . . . . . 74
Marketing of Production . . . . . . . . . . . . . . . . . . . . 74
Regulation of Partnership Operations. . . . . . . . . . . . . . 75
Natural Gas Price Regulation. . . . . . . . . . . . . . . . . . 76
State Regulation of Oil and Gas Production. . . . . . . . . . . 81
(vii)
<PAGE>
Legislative and Regulatory Production and Pricing Proposals . . 81
Production and Environmental Regulation . . . . . . . . . . . . 83
SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT . . . . . . . . . . . . 84
Partnership Distributions . . . . . . . . . . . . . . . . . . . 84
Deposit and Use of Funds. . . . . . . . . . . . . . . . . . . . 85
Power and Authority . . . . . . . . . . . . . . . . . . . . . . 85
Rollup or Consolidation of the Partnership. . . . . . . . . . . 86
Limited Liability . . . . . . . . . . . . . . . . . . . . . . . 86
Records, Reports and Returns. . . . . . . . . . . . . . . . . . 87
Transferability of Interests. . . . . . . . . . . . . . . . . . 87
Amendments. . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Voting Rights . . . . . . . . . . . . . . . . . . . . . . . . . 90
Exculpation and Indemnification of the General Partner. . . . . 91
Termination . . . . . . . . . . . . . . . . . . . . . . . . . . 91
Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
COUNSEL. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . 97
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 1997 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,
1997 (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, 1997 and the remaining
three of such Installments being due on June 15, 1997, September 15, 1997
and December 15, 1997, respectively, or (ii) through equal deductions
from 1997 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 1997. 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 Partnership
will be formed. No Units will be offered for sale after the Effective
Date (see "GLOSSARY") except upon compliance with the provisions of
Article XIII of the Agreement. The General Partner may, at its option,
purchase Units as a Limited Partner, including any amount that may be
necessary to meet the minimum number of Units required for formation of
the Partnership. The Partnership will terminate on December 31, 2027,
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."
1
<PAGE>
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 1997 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, 1998 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 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
2
<PAGE>
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, 1998 to present their Units to the General Partner for
purchase, Limited Partners will not be able to liquidate
their investments.
. The Partnership could be formed with as little as $50,000
in Capital Contributions (excluding the Capital
Contributions of the General Partner). As the total
amount of Capital Contributions to the Partnership will
determine the number and diversification of Partnership
Properties, the ability of the Partnership to pursue its
investment objectives may be restricted in the event that
the Partnership receives only the minimum amount of
Capital Contributions.
. The drilling and completion operations to be undertaken by
the Partnership for the development of oil and natural gas
reserves involve the possibility of a total loss of an
investment in the Partnership.
. The General Partner will have the exclusive management and
control of all aspects of the business of the Partnership.
The Limited Partners will have no opportunity to
participate in the management and control of any aspect of
the Partnership's activities. Accordingly, the Limited
Partners will be entirely dependent upon the management
skills and expertise of the General Partner.
. Conflicts of interest exist and additional conflicts of
interest may arise between the General Partner and the
Limited Partners, and there are no pre-determined
procedures for resolving any such conflicts. Accordingly
the General Partner could cause the Partnership to take
actions to the benefit of the General Partner but not to
the benefit of the Limited Partners.
. Certain provisions in the Agreement modify what would
otherwise be the applicable Oklahoma law as to the
fiduciary standards for a general partner in a limited
partnership. The fiduciary standards in the Agreement
could be less advantageous to the Limited Partners and
more advantageous to the General Partner than
3
<PAGE>
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.
. Certain allocations of income, gain, loss and deduction of
the Partnership among the Partners may be challenged by
the Internal Revenue Service (the "Service"). A
successful challenge would result 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,
4
<PAGE>
the General Partner may make one or more calls for Additional Assessments
from the Limited Partners if additional funds are required to pay the
Limited Partners' share of Drilling Costs, Special Production and
Marketing Costs or Leasehold Acquisition Costs. The maximum amount of
total Additional Assessments which may be called for by the General
Partner is $100 per Unit. See "ADDITIONAL FINANCING -- Additional
Assessments".
Partnership Borrowings. After the General Partner's Minimum Capital
Contribution has been expended, the General Partner may cause the
Partnership to borrow funds required to pay Drilling Costs, Special
Production and Marketing Costs or Leasehold Acquisition Costs of
Productive properties. Additionally, the General Partner may, but is not
required to, advance funds to the Partnership to pay such costs. See
"ADDITIONAL FINANCING -- Partnership Borrowings".
Proposed Activities
General. The Partnership is being formed for the purposes of
acquiring producing oil and gas properties and conducting oil and gas
drilling and development operations. The Partnership will, with certain
limited exceptions, participate on a proportionate basis with UPC in each
producing oil and gas lease acquired and in each oil and gas well
commenced by UPC for its own account or by UNIT during the period from
January 1, 1997, if the Partnership is formed prior to such date or from
the date of the formation of the Partnership if subsequent to January 1,
1997, until December 31, 1997, 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 1997. 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 1997. 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 1997.
Application of Proceeds
The offering proceeds will be used to pay the Leasehold Acquisition
Costs incurred by the Partnership to acquire those producing oil and gas
leases in which the Partnership participates and the Leasehold
Acquisition Costs, exploration, drilling and development costs incurred
by the Partnership pursuant to drilling activities in which the Partner-
ship 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:
5
<PAGE>
$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
(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 Partner's General Limited
Minimum Capital Contribtuion Partner's Partners'
Percentage(1) Percentage(1)
REVENUES General Limited
Partner's Partners'
- ------------------ Percentage(1) Percentage(1)
1) See "GLOSSARY."
6
<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 and as to
certain other matters discussed herein. 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 would 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, 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
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originally anticipated to be expended in connection with the operations
and, in such event, would have only limited means for providing needed
additional funds (see "ADDITIONAL FINANCING"). Also, if a well is
operated by a company which does not or cannot pay the costs and expenses
of drilling or operating a Partnership Well, the Partnership's interest
in such well may become subject to liens and claims of creditors who
supplied services or materials in connection with such operations even
though the Partnership may have previously paid its share of such costs
and expenses to the operator. If the operator is unable or unwilling to
pay the amount due, the Partnership might have to pay its share of the
amounts owing to such creditors in order to preserve its interest in the
well which would mean that it would, in effect, be paying for certain of
such costs and expenses twice.
Dependence Upon General Partner
The Limited Partners will acquire interests in the Partnership, not
in the General Partner or UNIT. They will not participate in either
increases or decreases in the General Partner's or UNIT's net worth or
the value of its common stock. Nevertheless, because the General Partner
is primarily responsible for the proper conduct of the Partnership's
business and affairs and is obligated to provide certain funds that will
be required in connection with its operations, a significant financial
reversal for the General Partner or UNIT could have an adverse effect on
the Partnership and the Limited Partners' interests therein.
Under the Partnership Agreement, UPC is designated as the General
Partner of the Partnership and is given the exclusive authority to manage
and operate the Partnership's business. See "SUMMARY OF THE LIMITED
PARTNERSHIP AGREEMENT -- Power and Authority". Accordingly, Limited
Partners must rely solely on the General Partner to make all decisions on
behalf of the Partnership, as the Limited Partners will have no role in
the management of the business of the Partnership.
The Partnership's success will depend, in part, upon the management
provided by the General Partner, the ability of the General Partner to
select and acquire oil and gas properties on which Partnership Wells
capable of producing oil and natural gas in commercial quantities may be
drilled, to fund the acquisition of revenue producing properties, and to
market oil and natural gas produced from Partnership Wells.
Conflicts of Interest
UNIT and its subsidiaries have engaged in oil and gas exploration and
development and in the acquisition of producing properties for their own
account and as the sponsors of drilling and income programs formed with
third party investors. It is anticipated that UNIT and its subsidiaries
will continue to engage in such activities. However, with certain
exceptions, it is likely that the Partnership will participate as a
working interest owner in all producing oil and gas leases acquired and
in all oil and gas wells commenced by the General Partner or UNIT for its
own account during the period from January 1, 1997, if the Partnership is
formed prior to such date, or from the date of the formation of the
Partnership, if subsequent to January 1, 1997, through December 31, 1997
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
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UNIT in 1997. 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 1997. 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 1997 and will have no rights in
production from wells commenced in years other than 1997. Likewise, if
additional interests are acquired in wells participated in by the
Partnership after 1997, the Partnership will generally not be entitled to
participate in the acquisition of such additional interests. See
"CONFLICTS OF INTEREST - Acquisition of Properties and Drilling
Operations."
The Partnership may enter into contracts for the drilling of some or
all of the Partnership Wells with affiliates of the General Partner.
Likewise the Partnership may sell or market some or all of its natural
gas production to an affiliate of the General Partner. These contracts
may not necessarily be negotiated on an arm's - length basis. The
General Partner is subject to a conflict of interest in selecting an
affiliate of the General Partner to drill the Partnership Wells and/or
market the natural gas therefrom. The compensation under these contracts
will be determined at the time of entering into each such contract, and
the costs to be paid thereunder or the sale price to be received will be
one which is competitive with the costs charged or the prices paid by
unaffiliated parties in the same geographic region. The General Partner
will make the determination of what are competitive rates or prices in
the area. No provision has been made for an independent review of the
fairness and reasonableness of such compensation. See "CONFLICTS OF
INTERESTS - Transactions with the General Partner or Affiliates".
Prohibition on Transferability; Lack of Liquidity
Except for certain transfers (i) to the General Partner, (ii) to or
for the benefit of the transferor Limited Partner or members of his or
her immediate family sharing the same residence, and (iii) by reason of
death or operation of law, a Limited Partner may not transfer or assign
Units. The General Partner has agreed, however, that it will, if
requested at any time after December 31, 1998, 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."
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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
1998. In addition, to the extent that the Partnership uses its revenues
to repay borrowings or to finance its activities (see "ADDITIONAL
FINANCING"), the funds available for cash distributions by the
Partnership will be reduced or may be unavailable. It is possible that
the amount of tax payable by a Limited Partner on his or her distributive
share of the income of a Partnership will exceed his or her 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
(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
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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 con-
sultants of UNIT or any of its subsidiaries. Such transfer or com-
bination may be effected without the vote, approval or consent of the
Limited Partners. In such event, the Limited Partners will receive
interests in the transferee or resulting entity which will mean that they
will most likely participate in the results of a larger number of
properties but will have proportionately smaller allocable interests
therein. Any such transaction is required to be effected in a manner
which UNIT and the General Partner believe is fair and equitable to the
Limited Partners but there can be no assurance that such transaction will
in fact be in the best interests of the Limited Partners. Limited
Partners have no dissenters' or appraisal rights under the terms of the
Agreement or the Act. Such a transaction would result in the termination
and dissolution of the Partnership. While there can be no assurance that
the Partnership will participate in such a transaction, the General
Partner currently anticipates that the Partnership will, at the
appropriate time, be involved in such a transaction. See "TERMS OF
OFFERING", and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT."
Partnership Borrowings
The General Partner has the authority to cause the Partnership to
borrow funds to pay certain costs of the Partnership. While the use of
financing to preserve the Partnership's equity in oil and gas properties
will be intended to increase the Partnership's profits, such financing
could have the effect of increasing the Partnership's losses if the
Partnership is unsuccessful. In addition, the Partnership may have to
mortgage its oil and gas properties and other assets in order to obtain
additional financing. If the Partnership defaults on such indebtedness,
the lender may foreclose and the Partnership could lose its investment in
such oil and gas properties and other assets. See "ADDITIONAL FINANCING
- -- Partnership Borrowings."
Limited Liability
Under the Act a Limited Partner's liability for the obligations of the
Partnership is limited to such Limited Partner's Capital Contribution and
such Limited Partner's share of Partnership assets. In addition, if a
Limited Partner receives a return of any part of his or her Capital
Contribution, such Limited Partner is generally liable to the Partnership
for a period of one year thereafter (or six years in the event such
return is in violation of the Agreement) for the amount of the returned
contribution. A Limited Partner will not otherwise be liable for the
obligations of the Partnership unless, in addition to the exercise of his
or her rights and powers as a Limited Partner, such Limited Partner
participates in the control of the business of the Partnership.
The Agreement provides that by a vote of a majority in interest, the
Limited Partners may effect certain changes in the Partnership such as
termination and dissolution of the Partnership and amendment of the
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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 Partnership'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
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 1997. 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
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director or employee who fails to pay such Installment, at a price equal
to the amount of the prior Installments paid by such person. The General
Partner may also bring legal proceedings to collect any unpaid
Installments not waived by it or Additional Assessments. In addition, as
indicated under "TERMS OF THE OFFERING - Payment for Units; Delinquent
Installment," if an employee's employment with or position as a director
of the General Partner, UNIT or any affiliate thereof is terminated
other than by reason of Normal Retirement (see "GLOSSARY"), death or
disability prior to the time the full amount of the subscription price
for his or her Units has been paid, all unpaid Installments not waived by
the General Partner as described above will become due and payable upon
such termination.
Partnership Funds
Except for Capital Contributions, Partnership funds are expected to
be commingled with funds of the General Partner or UNIT. Thus,
Partnership funds could become subject to the claims of creditors of the
General Partner or UNIT. The General Partner believes that its assets
and net worth are such that the risk of loss to the Partnership by virtue
of such fact is minimal but there can be no assurance that the
Partnership will not suffer losses of its funds to creditors of the
General Partner or UNIT.
Compliance With Federal and State Securities Laws
This offering has not been registered under the Securities Act of
1933, as amended, in reliance upon exemptive provisions of said act.
Further, these interests are being sold pursuant to exemptions from
registration in the various states in which they are being offered and
may be subject to additional restrictions in such jurisdictions on
transfer. There is no assurance that the offering presently qualifies or
will continue to qualify under such exemptive provisions due to, among
other things, the adequacy of disclosure and the manner of distribution
of the offering, the existence of similar offerings conducted by the
General Partner or UNIT or its affiliates in the past or in the future,
a failure or delay in providing notices or other required filings, the
conduct of other oil and gas activities by the General Partner or UNIT
and its affiliates or the change of any securities laws or regulations.
If and to the extent suits for rescission are brought and successfully
concluded for failure to register this offering or other offerings under
the Securities Act of 1933, as amended, or state securities acts, or for
acts or omissions constituting certain prohibited practices under any of
said acts, both the capital and assets of the General Partner and the
Partnership could be adversely affected, thus jeopardizing the ability of
the Partnership to operate successfully. Further, the time and capital
of the General Partner could be expended in defending an action by
investors or by state or federal authorities even where the Partnership
and the General Partner are ultimately exonerated.
Title To Properties
The Partnership Agreement empowers the General Partner, UNIT or any
of their affiliates, to hold title to the Partnership Properties for the
benefit of the Partnership. As such it is possible that the Partnership
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Properties could be subject to the claims of creditors of the General
Partner. The General Partner is of the opinion that the likelihood of
the occurrence of such claims is remote. However, the Partnership
Property could be subject to claims and litigation in the event that the
General Partner failed to pay its debts or became subject to the claims
of creditors.
Use of Partnership Funds to Exculpate and Indemnify the General Partner
The Agreement contains certain provisions which are intended to limit
the liability of the General Partner and its affiliates for certain acts
or omissions within the scope of the authority conferred upon them by the
Agreement. In addition, under the Agreement, the General Partner will be
indemnified by the Partnership against losses, judgments, liabilities,
expenses and amounts paid in settlement sustained by it in connection
with the Partnership so long as the losses, judgments, liabilities,
expenses or amounts were not the result of gross negligence or willful
misconduct on the part of the General Partner. See "SUMMARY OF THE
LIMITED PARTNERSHIP AGREEMENT -- Exculpation and Indemnification of the
General Partner."
The Partnership Agreement May Limit the Fiduciary Obligation of the
General Partner to the Partnership and the Limited Partners
The Agreement contains certain provisions which modify what would
otherwise be the applicable Oklahoma law relating to the fiduciary
standards of the General Partner to the Limited Partners. The fiduciary
standards in the Agreement could be less advantageous to the Limited
Partners and more advantageous to the General Partner than the
corresponding fiduciary standards otherwise applicable under Oklahoma law
(although there are very few legal precedents clarifying exactly what
fiduciary standards would otherwise be applicable under Oklahoma law).
The purchase of Units may be deemed as consent to the fiduciary standards
set forth in the Agreement. See "FIDUCIARY RESPONSIBILITY." As a result
of these provisions in the Agreement, the Limited Partners may find it
more difficult to hold the General Partner responsible for acting in the
best interest of the Partnership and the Limited Partners than if the
fiduciary standards of the otherwise applicable Oklahoma law governed the
situation.
TAX 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 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
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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 January 1, 1997 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. 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 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,
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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, 1997 or the time the Partnership is formed through December 31, 1997
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 1997.
All drilling to establish productive oil and natural gas properties
is inherently speculative. The techniques presently available to
identify the existence and location of pools of oil and natural gas are
indirect, and, therefore, a considerable amount of personal judgment is
involved in the selection of any prospect for drilling. The economics of
oil and natural gas drilling and production are affected or may be
affected in the future by a number of factors which are beyond the
control of the General Partner, including (i) the general demand in the
economy for energy fuels, (ii) the worldwide supply of oil and natural
gas, (iii) the price of, as well as governmental policies with respect
to, oil imports, (iv) potential competition from competing alternative
fuels, (v) governmental regulation of prices for oil and natural gas,
(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.
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Operating and Environmental Hazards
Operating hazards such as fires, explosions, blowouts, unusual
formations, formations with abnormal pressures and other unforeseen
conditions are sometimes encountered in drilling wells. On occasion,
substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce the funds available for
exploration and development or result in loss of Partnership Properties.
The Partnership will attempt to maintain customary insurance coverage,
but the Partnership may be subject to liability for pollution and other
damages or may lose substantial portions of its properties due to hazards
against which it cannot insure or against which it may elect not to
insure due to unreasonably high or prohibitive premium costs or for other
reasons. The activities of the Partnership may expose it to potential
liability for pollution or other damages under laws and regulations
relating to environmental matters (see "Government Regulation and
Environmental Risks" below).
Competition
The oil and gas industry is highly competitive. The Partnership will
be involved in intense competition for the acquisition of quality
undeveloped leases and producing oil and gas properties. There can be no
assurance that a sufficient number of suitable oil and gas properties
will be available for acquisition or development by the Partnership. The
Partnership will be competing with numerous major and independent
companies which possess financial resources and staffs larger than those
available to it. The Partnership, therefore, may be unable in certain
instances to acquire desirable leases or supplies or may encounter delays
in commencing or completing Partnership operations.
Markets for Oil and Natural Gas Production
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
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markets has been vigorous and there remains great uncertainty about
prices that purchasers will pay. In recent years, significant court
decisions and regulatory changes have affected the natural gas markets.
As a result of such court decisions, regulatory changes and unsettled
market conditions, natural gas regulations may be modified in the future
and may be subject to further judicial review or invalidation. The
combination of these factors, among others, makes it particularly
difficult to estimate accurately future prices of natural gas, and any
assumptions concerning future prices may prove incorrect. Natural gas
surpluses could result in the Partnership's inability to market natural
gas profitably, causing Partnership Wells to curtail production and/or
receive lower prices for its natural gas, situations which would
adversely affect the Partnership's ability to make cash distributions to
its participants. See "COMPETITION, MARKETS AND REGULATION."
In the event that the Partnership discovers or acquires natural gas
reserves, there may be delays in commencing or continuing production due
to the need for gathering and pipeline facilities, contract negotiation
with the available market, pipeline capacities, seasonal takes by the gas
purchaser or a surplus of available gas reserves in a particular area.
Government Regulation and Environmental Risks
The oil and gas business is subject to pervasive government regulation
under which, among other things, rates of production from producing
properties may be fixed and the prices for gas produced from such
producing properties may be impacted. It is possible that these
regulations pertaining to rates of production could become more pervasive
and stringent in the future. The activities of the Partnership may
expose it to potential liability under laws and regulations relating to
environmental matters which could adversely affect the Partnership.
Compliance with these laws and regulations may increase Partnership
costs, delay or prevent the drilling of wells, delay or prevent the
acquisition of otherwise desirable producing oil and gas properties,
require the Partnership to cease operations in certain areas, and cause
delays in the production of oil and gas. See "COMPETITION, MARKETING AND
REGULATION."
Leasehold Defects
In certain instances, the Partnership may not be able to obtain a
title opinion or report with respect to a producing property that is
acquired. Consequently, the Partnership's title to any such property may
be uncertain. Furthermore, even if certain technical defects do appear
in title opinions or reports with respect to a particular property, the
General Partner, in its sole discretion, may determine that it is in the
best interest of the Partnership to acquire such property without taking
any curative action.
TERMS OF THE OFFERING
General
. 500 Maximum Units; 50 Minimum Units
. $1,000 Units; Minimum subscription: $2,000
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. 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.
The offering of Units will be closed on January 31, 1997 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 sala-
ries for 1997 (excluding bonuses) have been set at $22,680 or more and to
Directors of UNIT. Only employees and Directors who are U.S. citizens
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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 1997. Each Director of UNIT may subscribe for
a maximum of 150 Units (maximum investment of $150,000). At January 1,
1997 there were approximately 125 Directors and employees eligible to
purchase Units.
Eligible employees and Directors may acquire Units through a
corporation or other entity in which all of the beneficial interests are
owned by them or permitted assignees (see "SUMMARY OF THE LIMITED
PARTNERSHIP AGREEMENT - Transferability of Interests"); provided that
such employees or Directors will be jointly and severally liable with
such entity for payment of the Capital Subscription.
If all eligible employees and Directors subscribed for the maximum
number of Units, the Units would be oversubscribed. In that event, Units
would be allocated among the respective subscribers in the proportion
that each subscription amount bears to total subscriptions obtained.
No employee is obligated to purchase Units in order to remain in the
employ of UNIT, and the purchase of Units by any employee will not
obligate UNIT to continue the employment of such employee. Units may be
subscribed for by the spouse or a trust for the minor children of
eligible employees and Directors.
Payment for Units; Delinquent Installment
The Capital Subscriptions of the Limited Partners will be payable
either (i) in four equal Installments, the first of such Installments
being due on March 15, 1997 and the remaining three of such Installments
being due on June 15, 1997, September 15, 1997 and December 15, 1997,
respectively, or (ii) by employees so electing in the space provided on
the Subscription Agreement, through equal deductions from 1997 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
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Bank of Oklahoma, N.A., Tulsa, Oklahoma; provided, however, that if the
General Partner determines that the total Aggregate Subscription is not
required to fund the Partnership's business and operations, then the
General Partner may, at its sole option, elect to release the Limited
Partners from their obligation to pay one or more Installments. If the
General Partner elects to waive the payment of an Installment, it will
notify all Limited Partners promptly in writing of its decision and will,
to the extent required, amend the certificate of limited partnership and
any other relevant Partnership documents accordingly. It is currently
anticipated that the total Aggregate Subscription will be required,
however, to fund the Partnership's business and operations.
In the event a Limited Partner fails to pay any Installment when due
and the General Partner has not released the Limited Partners from their
obligation to pay such Installment, then the General Partner, at its sole
option and discretion, may elect to purchase the Units of such defaulting
Limited Partner at a price equal to the total amount of the Capital
Contributions actually paid into the Partnership by such defaulting
Limited Partner, less the amount of any Partnership distributions that
may have been received by him or her. Such option may be exercised by
the General Partner by written notice to the Limited Partner at any time
after the date that the unpaid Installment was due and will be deemed
exercised when the amount of the purchase price is first tendered to the
defaulting Limited Partner. The General Partner may, in its discretion,
accept payments of delinquent Installments not waived by it but will not
be required to do so.
In the event that the General Partner elects to purchase the Units of
a defaulting Limited Partner, it must pay into the Partnership the amount
of the delinquent Installment (excluding any interest that may have
accrued thereon) and pay each additional Installment, if any, payable
with respect to such Units as it becomes due. By virtue of such
purchase, the General Partner will be allocated all Partnership Revenues,
be charged with all Partnership costs and expenses attributable to such
Units and will enjoy the same rights and obligations as other Limited
Partners, except the General Partner will have unlimited liability.
Right of Presentment
After December 31, 1998, 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
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<PAGE>
(3) The lower of cost or fair market value of all Partnership
Properties to which proved reserves have not been attributed but
which have not been condemned, as determined by an independent
petroleum engineering firm or the General Partner, as the case
may be; plus
(4) Cash on hand; plus
(5) Prepaid expenses and accounts receivable (less a reasonable
reserve for doubtful accounts); plus
(6) The estimated market value of all other Partnership assets not
included in (1) through (5) above, determined by the General
Partner; MINUS
(7) An amount equal to all debts, obligations and other liabilities
of the Partnership.
The price to be paid for each Limited Partner's interest of the net asset
value will be his or her proportionate share of such net asset value less
75% of the amount of any distributions received by him or her which are
attributable to the sales of the Partnership production since the date as
of which the Partnership's proved reserves are estimated.
The value of the proved reserves attributable to Partnership
Properties will be determined as follows:
(i) First, the future net revenues from the production and sale of
the proved reserves will be estimated as of the end of the
calendar year in which presentment is made based on an
independent engineering firm's report and its 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
22
<PAGE>
history and will not be as reliable as later estimates based on longer
production history. As a result of all the foregoing, reserve estimates
and estimates of future net revenues from production may vary from year
to year.
This right of presentment may be exercised by written notice from a
Limited Partner to the General Partner. The sale will be effective as of
the close of business on the last day of the calendar year in which such
notice is given or, at the General Partner's election, at 7:00 A.M. on
the following day. Within 120 days after the end of the calendar year,
the General Partner will furnish each Limited Partner who gave such
notice during the calendar year a statement showing the cash purchase
price which would be paid for the Limited Partner's interest as of
December 31 of the preceding year, which statement will include a summary
of estimated reserves and future net revenues and sufficient material to
reveal how the purchase price was determined. The Limited Partner must,
within 30 days after receipt of such statement, reaffirm his or her
election to sell to the General Partner.
As noted above, the General Partner will not be obligated to purchase
in any one calendar year more than 20% of the Units in the Partnership
then outstanding. Moreover, the General Partner will not be obligated to
purchase any Units pursuant to such right if such purchase, when added to
the total of all other sales, exchanges, transfers or assignments of
Units within the preceding 12 months, would result in the Partnership
being considered to have terminated within the meaning of Section 708 of
the Code or would cause the Partnership to lose its status as a
partnership for federal income tax purposes. If more than the number of
Units which may be purchased are tendered in any one year, the Limited
Partners from whom the Units are to be purchased will be determined by
lot. Any Units presented but not purchased with respect to one year will
have priority for such purchase the following year.
The General Partner does not intend to establish a cash reserve to
fund its obligation to purchase Units, but will use funds provided by its
operations or borrowed funds (if available), using its assets (including
such Units purchased or to be purchased from Limited Partners) as
collateral to fund such obligations. However, there is no assurance that
the General Partner will have sufficient financial resources to discharge
its obligations.
Rollup or Consolidation of Partnership
The Agreement provides that two years or more after the Partnership
has completed substantially all of its property acquisition, drilling and
development operations, the General Partner may, without the vote,
consent or approval of the Limited Partners, cause all or substantially
all of the oil and gas properties and other assets of the Partnership to
be sold, assigned or transferred to, or the Partnership merged or
consolidated with, another partnership or a corporation, trust or other
entity for the purpose of combining the assets of two or more of the oil
and gas partnerships formed for investment or participation by employees,
directors and/or consultants of UNIT or any of its subsidiaries;
provided, however, that the valuation of the oil and gas properties and
other assets of all such participating partnerships for purposes of such
transfer or combination shall be made on a consistent basis and in a
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manner which the General Partner and UNIT believe is fair and equitable
to the Limited Partners. As a consequence of any such transfer or
combination, the Partnership shall be dissolved and terminated and the
Limited Partners shall receive partnership interests, stock or other
equity interests in the transferee or resulting entity. Any such action
will cause the Limited Partners' attributable interest in the Partnership
Properties to be diluted but it will also provide them with attributable
interests in the properties and other assets of the other partnerships
participating in the consolidation. It also may reduce somewhat the
amount of their attributable shares of the direct and indirect costs of
administering the Partnership. See "RISK FACTORS - Investment Risks -
Roll-Up or Consolidation of Partnership."
ADDITIONAL FINANCING
The General Partner will use its best efforts, consistent with
Partnership objectives, to acquire Productive properties and complete the
Partnership's drilling and development operations before the Aggregate
Subscription has been fully expended or committed. However, funds in
addition to the Aggregate Subscription may be required to pay costs and
expenses which are chargeable to the Limited Partners. In those
instances described below, the General Partner may call for Additional
Assessments or may apply Partnership Revenue allocable to the Limited
Partners in payment and satisfaction of such costs or the General Partner
may, but shall not be required to, fund the deficiency with Partnership
borrowings to be repaid with Partnership Revenue.
Additional Assessments
When the Aggregate Subscription has been fully expended or committed,
the General Partner may make one or more calls for any portion or all of
the maximum Additional Assessments of $100 per Unit. However, no
Additional Assessments may be required before the General Partner's
Minimum Capital Contribution has been fully expended. Such assessments
may be used to pay the Limited Partners' share of the Drilling Costs,
Special Production and Marketing Costs or Leasehold Acquisition Costs of
Productive properties which are chargeable to the Limited Partners. The
amount of the Additional Assessment so called shall be due and payable on
or before such date as the General Partner may set in such call, which in
no event will be earlier than thirty (30) days after the date of mailing
of the call. The notice of the call for Additional Assessments will
specify the amount of the assessment being required, the intended use of
such funds, the date on which the contributions are payable and describe
the consequences of nonpayment. Although the Limited Partners who do not
respond will participate in production, if any, obtained from operations
conducted with the proceeds from the aggregate Additional Assessments
paid into the Partnership, the amount of the unpaid Additional Assessment
shall bear interest at the annual rate equal to two (2) percentage points
in excess of the prime rate of interest of Bank of Oklahoma, N.A., Tulsa,
Oklahoma, or successor bank, as announced and in effect from time to
time, until paid. The Partnership will have a lien on the defaulting
Limited Partner's interest in the Partnership and the General Partner may
retain Partnership Revenue otherwise available for distribution to the
defaulting Limited Partner until an amount equal to the unpaid Additional
Assessment and interest is received. Furthermore, the General Partner
may satisfy such lien by proceeding with legal action to enforce the lien
and the defaulting Limited Partner shall pay all expenses of collection,
including interest, court costs and a reasonable attorney's fee.
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Prior Programs
In the prior employee programs conducted by UNIT or the General
Partner in each of the years 1984 through 1996, Additional Assessments
could be called for as provided herein. At September 30, 1996, there had
been no calls for Additional Assessments in such programs. There can be
no assurance, however, that Additional Assessments will not be required
to pay Partnership costs.
Partnership Borrowings
At any time after the General Partner's Minimum Capital Contribution
has been fully expended, the General Partner may cause the Partnership to
borrow funds for the purpose of paying Drilling Costs, Special Production
and Marketing Costs or Leasehold Acquisition Costs of Productive
properties, which borrowings may be secured by interests in the
Partnership Properties and will be repaid, including interest accruing
thereon, out of Partnership Revenue. The General Partner may, but is not
required to, advance funds to the Partnership for the same purposes for
which Partnership borrowings are authorized. With respect to any such
advances, the General Partner will receive interest in an amount equal to
the lesser of the interest which would be charged to the Partnership by
unrelated banks on comparable loans for the same purpose or the General
Partner's interest cost with respect to such loan, where it borrows the
same. No financing charges will be levied by the General Partner in
connection with any such loan. If Partnership borrowings secured by
interests in the Partnership Wells and repayable out of Partnership
Revenue cannot be arranged on a basis which, in the opinion of the
General Partner, is fair and reasonable, and the entire sum required to
pay such costs is not available from Partnership Revenue, the General
Partner may dispose of some or all of the Partnership Properties upon
which such operations were to be conducted by sale, farm-out or
abandonment.
If the Partnership requires funds to conduct Partnership operations
during the period between any of the Installments due from the Limited
Partners, then, notwithstanding the foregoing, the General Partner shall
advance funds to the Partnership in an amount equal to the funds then
required to conduct such operations but in no event more than the total
amount of the Aggregate Subscription remaining unpaid. With respect to
any such advances, the General Partner shall receive no interest thereon
and no financing charges will be levied by the General Partner in
connection therewith. The General Partner shall be repaid out of the
Installments thereafter paid into the capital of the Partnership when
due.
The Partnership may attempt to finance any expenses in excess of the
Partners' Capital Subscriptions by the foregoing means and any other
means which the General Partner deems in the best interests of the
Partnership, but the Partnership's inability to meet such costs could
result in the deferral of drilling operations or in the inability to
participate in future drilling or in non-consent penalties pursuant to
which co-owners of particular working interests recover several times the
amount which would have been funded by the Partnership in accordance with
its ownership interest before the Partnership would participate in
revenues.
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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 partici-
pation 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.
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
26
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Agreement. Persons offering interests shall sufficiently inquire of a
prospective investor to be reasonably assured that such investor meets
such acceptable standards. Suitability standards may also be imposed by
the regulatory authorities of the various states in which interests may
be offered.
RELATIONSHIP OF THE PARTNERSHIP,
THE GENERAL PARTNER AND AFFILIATES
The following diagram depicts the primary relationships among the
Partnership, the General Partner and certain of its affiliates.
UNIT CORPORATION
----------------
(
(-----------------(-------------------(
( (
Unit Petroleum Company Unit Drilling Company
---------------------- ---------------------
(
( General Partner
( ---------------
(
Unit 1997 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 1997. 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 1997 and (ii) serving as a co-
general partner in any drilling or income programs, or both, formed by
the General Partner or UNIT during 1997.
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
27
<PAGE>
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, 1997, or the time of the formation of the Partnership if
subsequent to January 1, 1997, until December 31, 1997, except for wells,
if any:
(i) drilled outside the 48 contiguous United States;
(ii) drilled as part of secondary or tertiary recovery operations
which were in existence prior to formation of the Partnership;
(iii) drilled by third parties under farm-out or similar arrangements
with UNIT or the General Partner or whereby UNIT or the General
Partner may be entitled to an overriding royalty, reversionary
or other similar interest in the production from such wells but
is not obligated to pay any of the Drilling Costs thereof;
(iv) acquired by UNIT or the General Partner through the acquisition
by UNIT or the General Partner of, or merger of UNIT or the
General Partner with, other companies (However, this exception
may, at the discretion of Unit or the General Partner, be
waived); or
(v) with respect to which the General Partner does not believe that
the potential economic return therefrom justifies the costs of
participation by the Partnership.
Instances referred to in (v) could occur when UNIT or one of its
subsidiaries agrees to participate in the ownership of a prospect for its
own account in order to obtain the contract to drill the well thereon.
There may be situations where the potential economic return of the well
alone would not be sufficient to warrant participation by UNIT but when
considered in light of the revenues expected to be realized as a result
of the drilling contract, such participation is desirable from UNIT's
standpoint. However, in such a situation, the Partnership would not be
entitled to any of the revenues generated by the drilling contract so its
participation in the well would not be desirable.
For these purposes, the drilling of a well will be deemed to have
commenced on the "spud date," i.e., the date that the drilling rig is set
up and actual drilling operations are commenced. Any clearing or other
site preparation operations will not be considered part of the drilling
operations for these purposes.
Participation in Drilling or Income Programs. Except for certain
limited exceptions it is anticipated that the Partnership will
participate with UPC or UNIT as a co-general partner of any drilling or
income programs, or both, formed by UPC or UNIT and its affiliates during
1997. 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.
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UNIT or its affiliates formed drilling programs for outside
investors from 1979 through 1984. In 1987, the Unit 1986 Energy Income
Limited Partnership (the "1986 Energy Program") was formed primarily to
acquire interests in producing oil and gas properties. See "PRIOR
ACTIVITIES". All of the programs were formed as limited partnerships and
interests in all of the programs other than the Unit 1979 Oil and Gas
Program and the 1986 Energy Program were offered in registered public
offerings. The 1979 Program and 1986 Energy Program were offered
privately to a limited number of sophisticated investors.
No drilling or income programs for third party investors were formed
in 1996. Although it does not currently contemplate doing so, UNIT may
form such drilling or income programs during 1997. 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 1997 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 1997 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 propor-
tionate 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 1997
nor can it predict what producing properties, if any, will be acquired by
it during 1997. 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 Develop-
ment Wells. Exploratory Wells include both the high-risk "wildcat" wells
which are located in areas substantially removed from existing production
and "controlled" Exploratory Wells which are located in areas where
production has been established and where objective horizons have
produced from similar geological features in the vicinity. Based on
UNIT's historical profile of its drilling operations, it is presently
anticipated that the portion of the Aggregate Subscription expended for
Partnership drilling operations (see "APPLICATION OF PROCEEDS") will be
spent approximately 7% on Exploratory Wells and 93% on Development Wells.
However, these percentages may vary significantly.
Certain of the Partnership's Development Wells may be drilled on
prospects on which initial drilling operations were conducted by the
General Partner or UNIT prior to the formation of the Partnership.
Further, certain of the Partnership Wells will be drilled on prospects on
which the General Partner, UNIT or possibly future employee programs may
conduct additional drilling operations in years subsequent to 1997. In
either instance, the Partnership will have an interest only in those
wells begun in 1997 and will have no rights in production from wells
commenced in years other than 1997 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
1997, UNIT, UPC or possibly future employee programs will acquire
additional interests in wells participated in by the Partnership. In
such event the Partnership will generally not be entitled to share in the
acquisition of such additional interests. With respect to the
acquisition of producing properties, UNIT will endeavor to diversify its
investments by acquiring properties located in differing geographic
locations and by balancing its investments between properties having high
rates of production in early years and properties with more consistent
production over a longer term. See "CONFLICTS OF INTERESTS - Acquisition
of Properties and Drilling Operations."
Partnership Objectives
The Partnership is being formed to provide eligible employees and
directors the opportunity to participate in the oil and gas exploration
and producing property acquisition activities of UNIT during 1997. 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
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<PAGE>
objective of providing the Limited Partners with essentially the same
economic returns that UNIT realizes from the wells drilled or acquired
during 1997.
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 ac-
quired. Neither UNIT nor its affiliates will retain any overrides or
other burdens on the working interests conveyed to the Partnership, and
the respective working interests of UPC or UNIT and the Partnership in a
property will bear their proportionate shares of costs and revenues.
The Partnership's direct interest in a property will only encompass
the area included within the spacing unit on which a Partnership Well is
to be drilled or on which a producing Partnership Well is located, and,
in the case of a Partnership Well to be drilled, it will acquire that
interest only when the drilling of the well is ready to commence. If the
size of a spacing unit is ever reduced, or any subsequent well in which
the Partnership has no interest is drilled thereon, the Partnership will
have no interest in any additional wells drilled on properties which were
part of the original spacing unit unless such additional wells are
commenced during 1997. If additional interests in Partnership Wells are
acquired in years subsequent to 1997 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 1997. 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
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<PAGE>
thereto. If any such program is to be offered publicly, those provisions
will have to be consistent with the provisions contained in the
Guidelines for the Registration of Oil and Gas Programs adopted by the
North American Securities Administrators Association, Inc.
Record Title to Partnership Properties
Record title to the Partnership Properties will be held by the
General Partner. However, the General Partner will hold the Partnership
Properties as a nominee for the Partnership under a form of General
Partners agreement to be entered into between the nominee and the
Partnership. Under the form of nominee agreement, the General Partner
will disclaim any beneficial interest in the Partnership Properties held
as 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 discre-
tion and control over the management, business and affairs of the
Partnership and will make all decisions affecting the Partnership
Properties. To the extent that Partnership funds are reasonably
available, the General Partner will cause the Partnership to (1) test and
investigate the Partnership Properties by appropriate geological and
geophysical means, (2) conduct drilling and development operations on
such Partnership Properties as it deems appropriate in view of such
testing and investigation, (3) attempt completion of wells so drilled if
in its opinion conditions warrant the attempt and (4) properly equip and
complete productive Partnership Wells. The General Partner will also
cause the Partnership's productive wells to be operated in accordance
with sound and economical oil and gas recovery practices.
The General Partner will operate certain drilling and productive
wells on behalf of the Partnership in accordance with the terms of the
Agreement (see "COMPENSATION"). In those cases, execution of separate
operating agreements will not be necessary unless third party owners are
involved, e.g., fractional undivided interest Partnership Properties and
Partnership Properties that are pooled or unitized with other properties
owned by third parties. In such cases, and in all cases where
Partnership Properties are operated by third parties, the General Partner
will, where appropriate, make or cause to be made and enter into
operating agreements, pooling agreements, unitization agreements, etc.,
in the form in general use in the area where the affected property is
located. The General Partner is also authorized to execute production
sales contracts on behalf of the Partnership.
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<PAGE>
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.
Until Capital Contributions are invested in the Partnership's
operations, they will be temporarily deposited, with or without interest,
in one or more bank accounts of the Partnership or invested in short-term
United States government securities, money market funds, bank
certificates of deposit or commercial paper rated as "A1" or "P1" as the
General Partner deems advisable. Partnership funds other than Capital
Contributions may be commingled with the funds of the General Partner or
UNIT.
PARTICIPATION IN COSTS AND REVENUES
All costs of organizing the Partnership and offering Units therein
will be paid by the General Partner. All costs incurred in the offering
and syndication of any drilling or income program formed by UPC or UNIT
and its affiliates during 1997 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
33
<PAGE>
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, 1997 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, 1997 based on the
relative contributions of the Partners previously made and expected to be
made in the future during the remainder of the Partnership's property
acquisition and drilling phases. See "GLOSSARY - General Partner's
Minimum Capital Contribution", "General Partner's Percentage" and
" Limited Partners' Percentage." If the General Partner's estimate of
future Leasehold Acquisition Costs and Drilling Costs proves to be lower
than the actual amount of such costs and expenses, the excess amounts
will be charged to the Partners on the basis of their respective
Percentages and the Limited Partners' share will be paid out of their
share of Partnership Revenues, Additional Assessments required of them or
the proceeds of Partnership borrowings. See "ADDITIONAL FINANCING." If
the General Partner's estimate of such costs and expenses proves to be
higher than the actual costs and expenses, the General Partner will
continue to bear Partnership costs and expenses that would otherwise have
been chargeable to the Limited Partners until the total Partnership costs
and expenses charged to it (including, without limitation, offering and
organizational costs, Operating Expenses, general and administrative
overhead costs and reimbursements and Special Production and Marketing
Costs as well as Leasehold Acquisition Costs and Drilling Costs) since
the formation of the Partnership equals the General Partner's Minimum
Capital Contribution. In addition to actual contributions of cash or
properties, any Partner will be deemed to have contributed amounts of
Partnership Revenues allocated to it which are used to pay its share of
Partnership costs and expenses.
The following table presents a summary of the allocation of
Partnership costs, expenses and revenues between the General Partner and
the Limited Partners:
COSTS AND EXPENSES General Partner Limited 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%
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. 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 Partner's Limited Partners'
Partner's Minimum Capital Percentage Percentage
Contribution
REVENUES General Partner's Limited Partners'
Percentage Percentage
COMPENSATION
Supervision of Operations
It is anticipated that the General Partner will operate most, if not
all, Partnership Properties during the drilling of Partnership Wells and
most, if not all, productive Partnership Wells. For the General
Partner's services performed as operator, the Partnership will compensate
the General Partner its pro rata portion of the compensation due to the
General Partner under the operating agreements, if any, in effect with
respect to such wells or, if none is in effect for such wells, at rates
no higher than those normally charged in the same or a comparable
geographic area by non-affiliated persons or companies dealing at arm's
length.
That portion of the General Partner's general and administrative
overhead expense that is attributable to its conduct of the actual and
necessary business, affairs and operations of the Partnership will be
reimbursed by the Partnership out of Partnership Revenue. The General
Partner's general and administrative overhead expenses are determined in
accordance with industry practices. The costs and expenses to be
allocated include all customary and routine legal, accounting, geologi-
cal, engineering, travel, office rent, telephone, secretarial, salaries,
data processing, word processing and other incidental reasonable expenses
necessary to the conduct of the Partnership's business and generated by
the General Partner or allocated to it by UNIT, but will not include
filing fees, commissions, professional fees, printing costs and other
expenses incurred in forming the Partnership or offering interests
therein. The amount of such costs and expenses to be reimbursed with
respect to any particular period will be determined by allocating to the
Partnership that portion of the General Partner's total general and
administrative overhead expense incurred during such period which is
equal to the ratio of the Partnership's total expenditures compared to
the total expenditures by the General Partner for its own account. The
portion of such general and administrative overhead expense reimbursement
35
<PAGE>
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 equipment
and such services will be acquired or provided at prices or rates no
higher than those normally charged in the same or comparable geographic
area by non-affiliated persons or companies dealing at arms' length.
Production purchased by any affiliate of UNIT will be for prices which
are not less than the highest posted price (in the case of crude oil) or
prevailing price (in the case of natural gas) in the same field or area.
UNIT or one of its affiliates may provide other goods or services to
the Partnership in which event the compensation received therefor 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, 1996, is set forth below.
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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 $1,679,644 $2,231,417 $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.......... -- 205,924 697,411 829,503
1984 Employee(*) -- 3,924 5,000 13,452
1985 Employee(*) -- 10,316 -- 54,892
1986 Employee(*) -- 23,505 -- 59,446
1986 Energy
Income Fund(**) -- 142,208 676,226 64,945
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. -- 217,970 -- 144,722
1992 Employee. -- 51,416 -- 14,861
1993 Employee. -- 27,456 -- 68,504
Consolidated
Program(*) -- 43,525 -- --
1994 Employee. -- 24,369 -- 40,507
1995 Employee. -- 9,123 -- 33,586
1996 Employee. -- 1,852 -- 78,578
_____________
(*) 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 - 1996 Employee Programs and no management
fee is payable by the Partnership to UNIT or any of its affiliates.
(2) Paid only to UDEC.
(3) In the case of compensation for supervision and operation of
productive wells and reimbursement of UNIT's general and administrative
overhead expense, the general partners generally were charged with and
paid a percentage of such amounts equal to the percentage of partnership
revenues being allocated to them.
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<PAGE>
(4)Although the partnership agreement for each of the 1985-1996
Employee Programs provides that the General Partner is entitled to
reimbursement for the general administrative and overhead expenses
attributable to each of such programs, the General Partner has to date
elected not to seek such reimbursement. However, there can be no
assurance that the General Partner will continue to forego such
reimbursement in the future.
(5) Includes a special allocation of gross revenues totaling
$500,000.
MANAGEMENT
The General Partner
UNIT was formed in 1986 in connection with a major reorganization and
recapitalization whereby UNIT acquired all of the assets and liabilities
of all of the limited partnerships formed by UNIT's predecessor, UDEC,
during the period of 1980 through 1983 in exchange for shares of UNIT's
common stock and UDEC was merged with a wholly owned subsidiary of UNIT
whereby UDEC was the surviving corporation and thereby became a wholly
owned subsidiary of UNIT. UPC was incorporated in the State of Oklahoma
on February 9, 1984 as Sunshine Development Corporation ("SDC"). On
October 8, 1985 pursuant to the terms of a Stock Purchase Agreement," UDEC
purchased all of the issued and outstanding stock of SDC whereby SDC became a
wholly owned subsidiary of UDEC. On February 1, 1988, pursuant to the terms of
an "Amended and Restated Certificate of Incorporation", SDC was renamed Unit
Petroleum Company.
UPC's as well as UNIT's, principal office is at 1000 Kensington Tower
I, 7130 South Lewis Avenue, Tulsa, Oklahoma 74136 and its telephone
number is (918) 493-7700. UNIT through its various subsidiaries is
engaged in the onshore contract drilling of oil and gas wells and in the
exploration for and production of oil and gas. Unless the context
otherwise requires, references in this Memorandum to UNIT include its
predecessor as well as all or any of its subsidiaries.
Officers, Directors and Key Employees
The Partnership will have no directors or officers. The directors
of the General Partner are elected annually and serve until their succes-
sors are elected and qualified. Directors of UNIT are elected at the
Annual Meeting of Shareholders for a staggered term of three years each,
or until their successors are duly elected and qualified. The executive
officers of the General Partner are elected by and serve at the pleasure
of its Board of Directors. The names, ages and respective positions of
the directors and executive officers of UNIT are as follows:
Name Age Position
King P. Kirchner 69 Chairman of the Board
and Chief Executive Officer
John G. Nikkel 61 President, Chief Operating
Officer and Director
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<PAGE>
O. Earle Lamborn 61 Senior Vice
President, Drilling and
Director
Philip M. Keeley 55 Senior Vice
President, Exploration and
Production
Larry D. Pinkston 42 Vice President, Treasurer
and Chief Financial
Officer
Mark E. Schell 39 Secretary and General
Counsel
William B. Morgan 52 Director
Don Cook 71 Director
John S. Zink 68 Director
John H. Williams 78 Director
Don Bodard 76 Director
The names, ages and respective positions of the directors and
executive officers of UPC are as follows:
Name Age Position
John G. Nikkel 61 Chairman of the Board
and President
Philip M. Keeley 55 Vice President and
Director
Mark E. Schell 39 Secretary, General
Counsel and Director
Larry D. Pinkston 42 Treasurer
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.
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<PAGE>
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.
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-
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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'
Capital
Name Formed Subscriptions
- -------------------------------------------------- ---------- -------------
Unit 1984 Employee Oil and Gas Program April 1984 $348,000
Unit 1985 Employee Oil and Gas Limited Partnership January 1985 $378,000
Unit 1986 Employee Oil and Gas Limited Partnership January 1986 $307,000
Unit 1987 Employee Oil and Gas Limited Partnership March 1987 $209,000
Unit 1988 Employee Oil and Gas Limited Partnership April 29, 1988 $177,000
Unit 1989 Employee Oil and Gas Limited Partnership December 30,
1988 $157,000
Unit 1990 Employee Oil and Gas Limited Partnership January 19,
1990 $253,000
Unit 1991 Employee Oil and Gas Limited Partnership January 7,
1991 $263,000
Unit 1992 Employee Oil and Gas Limited Partnership January 23,
1992 $240,000
Unit 1993 Employee Oil and Gas Limited Partnership January 21,
1993 $245,000
Unit 1994 Employee Oil and Gas Limited partnership January 19,
1994 $284,000
Unit 1995 Employee Oil and Gas Limited Partnership March 7,
1995 $454,000
Unit 1996 Employee Oil and Gas Limited Partnership February 5,
1996 $437,000
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 1996 Employee
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Programs. The capital subscriptions of the following limited partners to
the 1994, 1995 and 1996 Employee Programs were as shown below:
Amount of Capital
Subscription
Position with ------------------------------------
Subscriber UNIT 1994 1995 1996
- ---------------- ------------- -------- -------- --------
King P. Kirchner Chairman of the Board and $50,000(1) $50,000(1) $50,000(1)
Chief Executive Officer
John G. Nikkel President, Chief Operating $92,840(2) $93,270(2) $107,120(2)
Officer and Director
Philip M. Keeley Senior Vice President, $27,160(2) $25,730(2) $32,880
Exploration and Production
Don Bodard Director $50,000 $200,000 $150,000(3)
__________________
(1) Mr. Kirchner invested $50,000 indirectly in each of the 1994
Employee Program, the 1995 Employee Program, and the 1996 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 1994, 1995 and
1996 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
1994, 1995 and 1996 Employee Programs by Messrs. Nikkel and Keeley are
set forth below:
Nike
Employee Mr. Nikkel Mr. Keeley Exploration
Program Directly Directly Company
-------- ---------- ---------- -----------
1994 $50,000 $10,000 $60,000
1995 $54,000 $10,000 $55,000
1996 $50,000 $10,000 $80,000
(3)Mr. Bodard invested $150,000 indirectly in the 1996 Employee
Program through the Don Bodard 1995 Revocable Trust as permitted by the
limited partnership agreement of that Employee Program.
Ownership of Common Stock
UNIT's Common Stock is listed on the New York Stock Exchange as
reported on the Composite Tape. On January 1, 1997 there were 24,041,650
shares outstanding.
As of January 1, 1997, 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:
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<PAGE>
Name and Address % of
of Beneficial Owner Shares(1) Outstanding(1)
------------------- ------ -----------
King P. Kirchner
1000 Kensington Center 1,266,758(2) 5.46%
7130 South Lewis Avenue
Tulsa, Oklahoma 74136
Don Bodard
313 Masonic Building 1,485,428(3) 6.17%
Shawnee, Oklahoma 74801
Scottish Amicable Life
Assurance Society
7 Hanover Square 1,755,000(4) 7.29%
New York, New York 10004
Dimensional Fund Advisors Inc.
1299 Ocean Avenue, 11th Floor 1,334,300(5) 5.54%
Santa Monica, California 90401
(1) The number of shares includes the shares presently issued and
outstanding plus the number of shares which any owner has the right to
acquire within 60 days after December 10, 1996, 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 5,932 shares held under Unit's
401(k) Thrift Plan as of December 31, 1995.
(3)Includes options to purchase 5,000 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. 4 to Schedule 13G,
dated February 7, 1996, 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.
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<PAGE>
As of January 1, 1997, 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:
Amount of
Beneficial % of
Name Ownership (1) Outstanding(1)
John Williams.................... 13,500(2) *
Don Cook......................... 18,138(2) *
Philip M. Keeley............... 225,271(3) *
O. Earle Lamborn............. 298,546(3) 1.2%
John G. Nikkel.................. 377,005(3) 1.5%
Larry D. Pinkston............. 124,616(3) *
Mark E. Schell................. 55,552(3) *
John S. Zink..................... 53,500(2) *
William B. Morgan........... 22,500(2) *
All Officers and Directors
as a Group (consisting
of 11 persons including
Mr. Kirchner).............. 3,940,814(4)(5) 16.16%
_______________
*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 January 1, 1997, pursuant to the exercise of
currently exercisable stock options. For purposes of calculating the
percent of the shares outstanding held by each owner, the total number of
shares excludes the shares which all other persons have the right to
acquire within 60 days after January 1, 1997 pursuant to the exercise of
currently exercisable 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, 12,500; William B. Morgan, 12,500; John H. Williams, 12,500; John
S. Zink, 12,500; Don Bodard, 5,000; and all non-Employee Directors as a
group, 55,000.
(3)Includes shares of common stock held under UNIT's 401(k) thrift
plan as of December 31, 1995 for the account of: Earle Lamborn, 7,831;
John G. Nikkel, 26,252; Philip M. Keeley, 32,781; Larry D. Pinkston,
11,375; and Mark E. Schell, 7,489.
(4)Includes options to purchase 334,500 shares of common stock.
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.
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<PAGE>
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, 1997, or from the formation of the Partnership if
subsequent to January 1, 1997, through December 31, 1997 except for
wells:
(i) drilled outside the 48 contiguous United States;
(ii) drilled as part of secondary or tertiary recovery operations
which were in existence prior to formation of the
Partnership;
(iii) drilled by third parties under farm-out or similar
arrangements with UNIT or the General Partner or whereby UNIT
or the General Partner may be entitled to an overriding
royalty, reversionary or other similar interest in the
production from such wells but is not obligated to pay any of
the Drilling Costs thereof;
(iv) acquired by UNIT or the General Partner through the
acquisition by UNIT or the General Partner of, or merger of
UNIT or the General Partner with, other companies; or
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<PAGE>
(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 1997. In the latter case, the Partnership
would have no right to participate in the drilling of such development or
offset wells.
Sometimes UNIT will agree to participate in drilling operations on
a prospect which it may not believe are fully warranted from an economic
standpoint if it believes that such participation is necessary for, or
will significantly increase its chances of, obtaining a contract to drill
the well with one of its drilling rigs and the revenues from the contract
make the economics of the entire arrangement desirable from UNIT's
standpoint. In such an instance, the Partnership would not be entitled
to any of the drilling contract revenues so the General Partner will not
cause the Partnership to participate in such a well. However, an
analysis of the economic potential of any proposed well is a very inexact
science and wells which have a very high potential commonly prove to be
dry or only marginally profitable and occasionally a well with apparently
very little promise may prove to be very profitable. Thus, there can be
no assurance that the General Partner will always make the most
profitable decision from the Partnership's standpoint in determining in
which of such potential wells the Partnership should or should not
participate.
Because the Partnership will acquire an interest only in those
properties comprising the spacing unit on which each Partnership Well is
located, it will not be entitled to participate in other wells drilled by
the General Partner, UNIT or any of its affiliates in the same prospect
area unless the drilling of those wells commences during the period from
January 1, 1997, or from the formation of the Partnership if subsequent
to January 1, 1997, through December 31, 1997. 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, 1997, or from the formation of the Partnership if
subsequent to January 1, 1997, through December 31, 1997. Likewise the
Partnership would have no interest in any increased density wells drilled
on the original spacing unit unless such wells were drilled during 1997.
In addition, if additional interests are acquired in wells participated
in by the Partnership after 1997, 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
46
<PAGE>
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 1997, it is
anticipated that the Partnership will serve as a co-general partner with
UNIT in any such drilling or income programs, or both. As the other co-
general partner of any such drilling or income program, UNIT would have
exclusive management and control over the business, operations and
affairs of the drilling or income program. Conflicts of interest may
arise between the limited partners and the general partners of such
drilling or income program and it is possible that UNIT may elect to
resolve those conflicts in favor of the limited partners. Further, if
any such drilling or income program is offered publicly, the program
agreement will be required to contain a number of provisions concerning
the conduct of program operations and handling conflicts of interests
required by the Guidelines for the Registration of Oil and Gas Programs
adopted by the North American Securities Administrators Association, Inc.
Such provisions may significantly reduce the flexibility of UNIT in
managing such programs or may affect the profitability of the program
operations or the transactions between the general partners and the
program.
Transfer of Properties
The General Partner or its affiliates are authorized to transfer
interests in oil and gas properties to the Partnership, in which case the
General Partner or its affiliate will receive an amount equal to the
Leasehold Acquisition Costs attributable to the interests being acquired
by the Partnership in the spacing unit on which the Partnership Well is
located or is to be drilled. The amount of the Leasehold Acquisition
Costs attributable to the fractional undivided interest in a property
transferred to the Partnership by the General Partner or any affiliate
shall not be reduced or offset by the amount of any gain or profit the
General Partner or its affiliate might have realized by any prior sale or
transfer of a fractional undivided interest in the property to an
unaffiliated third party for a price in excess of the portion of the
Leasehold Acquisition Costs of the property that is attributable to the
transferred interest. The Partnership will not be reimbursed for or
refunded any Leasehold Acquisition Costs if the size of a spacing unit on
which a Partnership Well is located or drilled is reduced even though the
Partnership will have no interest in any subsequent wells drilled on the
area encompassed by the original spacing unit unless they are commenced
during 1997.
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
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<PAGE>
(3) the Partnership's interest in revenues will not be less than
the proportionate interest therein of the General Partner or
its affiliates when it acquired the properties.
With respect to the General Partner or its affiliates' remaining
interest, it may retain such interest for its own account or it may sell,
transfer, farm-out or otherwise convey all or a portion of such remaining
interest to non-affiliated industry members, which may occur either
before or after the transfer of the interests in the same properties to
the Partnership. The General Partner or its affiliates may realize a
profit on the interests or may be carried to some extent with respect to
its cost obligations in connection with any drilling on such properties
and any such profit or interests will be strictly for the account of the
General Partner or its affiliates and the Partnership will have no claim
with respect thereto. The General Partner or its affiliates may not
retain any overrides or other burdens on the property conveyed to the
Partnership (other than overriding royalty interests granted to
geologists and other persons employed or retained by the General Partner
or its affiliates) and may not enter into any farm-out arrangements with
respect to its retained interest except to non-affiliated third parties
or other programs managed by the General Partner or its affiliates.
Partnership Assets
The General Partner will not take any action with respect to assets
or property of the Partnership which does not benefit primarily the
Partnership as a whole. The General Partner will not utilize the funds
of the Partnership as compensating balances for the benefit of the
General Partner or its affiliates. All benefits from marketing
arrangements or other relationships affecting property of the Partnership
will be fairly and equitably apportioned according to the respective
interests of the Partnership and the General Partner.
The Partnership Agreement provides that when the Partnership is
terminated, there will be an accounting with respect to its assets,
liabilities and accounts. The Partnership's physical property and its
oil and gas properties may be sold for cash. Except in the case of an
election by the General Partner to terminate the Partnership before the
tenth anniversary of the Effective Date, Partnership Properties may be
sold to the General Partner or any of its affiliates for their fair
market value as determined in good faith by the General Partner.
Transactions with the General Partner or Affiliates
UNIT provides through its subsidiary Unit Drilling Company contract
drilling services in the ordinary course of its business. UNIT also owns
a 34% of GED Gas Services L.L.C. which is engaged in the business of
marketing natural gas and a 40% interest in Superior Pipeline Company,
L.L.C. which is engaged in the business of buying and building gas
gathering systems. It is anticipated that the Partnership will obtain
services, equipment and supplies from 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.
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<PAGE>
For its services as a drilling contractor, Unit Drilling Company
will charge the Partnership on either a daywork (a specified per day rate
for each day a drilling rig is on the drill site), a footage (a specified
rate per foot drilled) or a turnkey (specified amount for drilling the
well) basis. The rate charged by Unit Drilling Company for such services
will be the same as those offered to unaffiliated third parties in the
same or similar geographic areas.
Right of Presentment Price Determination
Under the terms of the Partnership Agreement, a Limited Partner can,
subject to certain conditions, require the General Partner to purchase
his or her Units at a price determined by the application of a stated
formula to the estimated future net revenues attributable to the
Partnership's estimated proved reserves. See "TERMS OF THE OFFERING -
Right of Presentment." It is anticipated that if an independent
engineering firm makes an evaluation of the proved reserves of the
Partnership, the result of that evaluation will be used in determining
the price to be paid to a Limited Partner exercising his or her right of
presentment. However, if no such independent evaluation is made, the
right of presentment purchase price will be determined by using the
proved reserves and future net revenue estimates of the technical staff
of the General Partner.
Receipt of Compensation Regardless of Profitability
The General Partner is entitled to receive its fees and other
compensation and reimbursements from the Partnership regardless of
whether the Partnership operates at a profit or loss. See "PARTICIPATION
IN COSTS AND REVENUES" and "COMPENSATION." Such fees, compensation and
reimbursements will decrease the Limited Partners' share of any profits
generated by operations of the Partnership or increase losses if such
operations should prove unprofitable.
Legal Counsel
Conner & Winters, 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
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<PAGE>
Partnership's books and records upon reasonable prior notice. The nature
of the fiduciary duties of general partners is an evolving area of law
and prospective investors who have questions concerning the duties of the
General Partner should consult with their counsel.
Regardless of the fiduciary obligations of the General Partner, the
General Partner, UNIT or its affiliates, subject to any restrictions or
requirements set forth in the Agreement, may:
. engage independently of the Partnership in all aspects of the
oil and gas business, either for their own accounts or for the
accounts of others;
. sell interests in oil and gas properties held by them to,
purchase oil and gas production from, and engage in other
transactions with, the Partnership;
. serve as general partner of other oil and gas drilling or
income partnerships, including those which may be in
competition with the Partnership; and
. engage in other activities that may involve conflicts of
interest.
See "CONFLICTS OF INTEREST." Thus, unlike the strict duty of a fiduciary
who must act solely in the best interests of his beneficiary, the
Agreement permits the General Partner to consider, among other things,
the interests of other partnerships sponsored by the General Partner,
UNIT or its affiliates in resolving investment and other conflicts of
interest. The foregoing provisions permit the General Partner to conduct
its own operations and to act as the general partner of more than one
similar partnership or investment program and for the Partnership to
benefit from its experience resulting therefrom, but relieves the General
Partner of the strict fiduciary duty of a general partner acting as such
for only one investment program at a time. These provisions are
primarily intended to reconcile the applicable duties under Oklahoma law
with the fact that the General Partner will manage and administer its own
oil and gas operations and a number of other oil and gas investment
programs with which possible conflicts of interests may arise and resolve
such conflicts in a manner consistent with the expectation of the
investors in all such programs, the General Partner's fiduciary duties
and customary business practices and statutes applicable thereto.
Liability and Indemnification
The Agreement provides that the General Partner will perform its
duties in an efficient and businesslike manner with due caution and in
accordance with established practices of the oil and gas industry. The
Agreement further provides that the General Partner and its affiliates
will not be liable to the Partnership or the Partners, and will be
indemnified by the Partnership, for any expense (including attorney
fees), loss or damage incurred by reason of any act or omission performed
or omitted in good faith in a manner reasonably believed by the General
Partner or its affiliates to be within the scope of authority and in the
best interest of the Partnership or the Partners unless the General
Partner or its affiliates is guilty of gross negligence or willful
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<PAGE>
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 following
table depicts the drilling results achieved as of September 30, 1996 by
UNIT during each year since 1975. Because of the unpredictability of oil
and gas exploration in general, such results should not be considered
indicative of the results that may be achieved by the Partnership.
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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
----- --- --- --- ----- --- --- ---
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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
----- --- --- --- ----- --- --- ---
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
----- --- --- --- ----- --- --- ---
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1992 Exploratory......... 0 0 0 0 0 0 0 0
Development......... 18 1 11 6 5.81 1.00 3.33 1.48
----- --- --- --- ----- --- --- ---
Total 18 1 11 6 5.81 1.00 3.33 1.48
----- --- --- --- ----- --- --- ---
1993 Exploratory......... 1 0 0 1 .10 0 0 .10
Development......... 16 9 6 1 12.48 8.98 3.32 .18
----- --- --- --- ----- --- --- ---
Total 17 9 6 2 12.58 8.98 3.32 .28
----- --- --- --- ----- --- --- ---
1994 Exploratory......... 3 0 1 2 1.71 0 .95 .76
Development......... 57 5 40 12 25.79 4.75 14.14 6.90
----- --- --- --- ----- --- --- ---
Total 60 5 41 14 27.50 4.75 15.09 7.66
----- --- --- --- ----- --- --- ---
1995 Exploratory......... 0 0 0 0 0 0 0 0
Development......... 45 15 24 6 14.94 4.67 8.04 2.23
----- --- --- --- ----- --- --- ---
Total 45 15 24 6 14.94 4.67 8.04 2.23
----- --- --- --- ----- --- --- ---
Period of January 1, 1996
to September 30, 1996
Exploratory......... 0 0 0 0 0 0 0 0
Development......... 53 7 38 8 24.83 5.41 15.28 4.14
----- --- --- --- ----- --- --- ---
Total 53 7 38 8 24.83 5.41 15.28 4.14
----- --- --- --- ----- --- --- ---
________________
(1) Except as indicated, the figures used in this table relate to
wells drilled and completed during each of the 12 month periods ended
July 31 or December 31, as the case may be. Oil wells and gas wells
shown include both producing wells and wells capable of production.
(2) "Gross Wells" refers to the total number of wells in which
there was participation by UNIT.
(3) "Net Wells" refers to the aggregate leasehold working interest
of UNIT in such wells. For example, a 50% leasehold working interest in
a well drilled represents 1.0 Gross Well, but a .50 Net Well.
Prior Employee Programs
During the period of 1979 to 1983, persons who were designated key
employees of UNIT by its board of directors participated in the Unit Key
Employee Exploration Funds (the "Funds"). These Funds were formed as
general partnerships for the purpose of participating in 10% of all of
the exploration and development operations conducted by UNIT during a
specified period. Except for the Fund formed in 1983, each of the prior
Funds served as one of the general partners in at least one of the prior
54
<PAGE>
drilling programs sponsored by UNIT and was allocated 10% of the expenses
and revenues allocable to the general partners as a group. In each of
these Funds the costs charged to it in connection with its operations
were financed with the proceeds of bank borrowings and out of the Funds'
share of revenues.
The 1983 Fund served as the sole capital limited partner in the Unit
1983-A Oil and Gas Program and as such made no contribution to the
capital of that program and shared in 10% of the costs and revenues
otherwise allocable to the General Partner after the distributions to the
General Partner from the program equaled the amount of its contributions
thereto plus UNIT's interest costs with respect to the unrecovered amount
of its contributions.
Because of the differences in structure, format and plan of
operations between the prior Funds and the Partnership and because of the
uncertainties which are inherent in oil and gas operations generally, the
results achieved by the prior Funds should not be considered indicative
of the results the Partnership may achieve.
For each year from 1984 through 1996, 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 1992-1996 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.
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
55
<PAGE>
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, 1996, and
the economic results at September 30, 1996 of prior oil and gas programs
and the 1984-1996 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, 1995 and 1996 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.
DRILLING RESULTS
As of September 30, 1996
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
----- --- --- --- ----- --- --- ---
56
<PAGE>
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.
57
<PAGE>
EMPLOYEE PROGRAMS
As of September 30, 1996
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
----- --- --- --- ----- --- --- ---
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 0 0 0 0 0 0 0 0
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 .13 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
----- --- --- --- ----- --- --- ---
58
<PAGE>
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 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 45 15 24 6 .74 .23 .40 .11
----- --- --- --- ----- --- --- ---
Total......... 45 15 24 6 .74 .23 .40 .11
----- --- --- --- ----- --- --- ---
1996(2) Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 53 7 38 8 1.24 .27 .76 .21
----- --- --- --- ----- --- --- ---
Total......... 53 7 38 8 1.24 .27 .76 .21
----- --- --- --- ----- --- --- ---
_______________
(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.
59
<PAGE>
GENERAL PARTNERS' PAYOUT TABLE(1)
As of September 30, 1996
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, 1996
- --------------------------- ------------ --------- ------------------
1979....................... $7,723,334 $9,476,167 $68,244
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....................... 2,168,974 1,523,089 474
1984 Employee(*)........... 1,542 1,745 -
1985 Employee(*)........... 2,820 1,808 -
1986 Energy Income Fund(**) 1,210,384 1,267,368 32,212
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.............. 1,692,123 1,551,388 65,912
1992 Employee.............. 169,488 187,663 10,490
1993 Employee.............. 378,765 383,289 26,107
Consolidated Program....... 2,396 5,409 492
1994 Employee.............. 994,948 632,477 83,539
1995 Employee.............. 354,847 142,826 30,984
1996 Employee.............. 268,188 27,225 23,612
__________
(*) 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, 1996
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, 1996
- --------------------------- ------------ --------- ------------------
1979....................... $13,323,493 $17,162,312 $83,538
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....................... 2,725,124 1,585,001 601
1984 Employee(*)........... 120,942 171,540 -
1985 Employee(*)........... 277,901 178,984 -
1986 Energy Income Fund(**) 2,380,746 3,019,688 48,158
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.............. 444,274 414,233 17,558
1992 Employee.............. 436,641 485,967 27,339
1993 Employee.............. 349,787 355,410 24,217
Consolidated Program....... 241,515 536,706 49,255
1994 Employee.............. 401,950 262,404 34,646
1995 Employee.............. 548,642 228,322 49,300
1996 Employee.............. 341,330 34,649 30,052
__________
(*) 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.
61
<PAGE>
GENERAL PARTNERS' NET CASH TABLE(1)
As of September 30, 1996
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 1996 Distributed 1996
- ------------------ ------------ --------- --------- ----------- ------------
1979.............. $2,849,294 $4,602,127 $22,554 3,676,393 17,000
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.............. 934,603 288,718 (6,932) 597,941 19,200
1984 Employee(*).. 874 1,077 - 1,000 -
1985 Employee(*).. 2,300 1,288 - 1,035 -
1986 Energy Income
Fund(**).......... 232,323 289,307 18,505 325,002 20,800
1986 Employee(*).. 2,698 5,108 4,486 -
1987 Employee(*).. 357,368 548,372 - 465,800 -
1988 Employee(*).. 770,272 1,161,840 - 942,800 -
1989 Employee(*).. 1,010,133 752,569 - 607,900 -
1990 Employee(*).. 466,272 338,281 - 266,600 -
1991 Employee..... 1,050,468 909,733 36,218 771,500 38,400
1992 Employee..... 98,813 116,988 7,112 87,800 7,300
1993 Employee..... 290,390 294,914 20,289 220,800 22,600
Consolidated Program 253 3,266 323 2,864 380
1994 Employee..... 806,841 444,370 62,011 259,500 54,500
1995 Employee..... 313,737 101,716 21,880 37,900 31,900
1996 Employee..... 261,888 20,924 18,683 - -
(*) 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.
62
<PAGE>
LIMITED PARTNERS' NET CASH TABLE(1)
As of September 30, 1996
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 1996 Distributed 1996
- ---------- ----------- ----------- ---------- -------- ---------- ----------
1979...... $ 3,000,000 $ 6,208,504 $9,997,323 $ 27,698 $5,908,401 $ -
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 2,036,455 896,332 (6,808) 558,221 19,215 (6)
1984
Employee(*) 174,000 86,664 137,262 - 125,280 -
1985
Employee(*) 283,500 227,670 128,753 - 182,644 -
1986
Energy
Income
Fund(**) 1,000,000 1,080,807 1,719,749 27,620 1,506,900 29,200 (7)
1986
Employee(*) 229,750 267,008 508,122 - 460,007 -
1987
Employee(*) 209,000 207,060 335,044 - 324,845 -
1988
Employee(*) 177,000 214,712 326,858 - 281,630 -
1989
Employee(*) 157,000 157,306 153,044 - 147,737 -
1990
Employee(*) 253,000 254,483 142,479 - 180,895 -
1991
Employee.. 253,000 273,889 243,848 9,666 211,978 9,205 (8)
1992
Employee.. 240,000 254,902 304,228 18,644 252,968 16,800 (9)
1993
Employee.. 245,000 268,348 273,971 18,848 220,255 20,580 (10)
Consolidated
Program.... - 25,391 320,582 32,229 278,032 37,599 (11)
1994 Employee 284,000 324,908 185,362 25,836 96,560 15,904 (12)
1995 Employee 454,000 484,290 163,970 35,009 76,726 51,302 (13)
1996 Employee 327,750 333,311 26,631 23,778 - -
__________
(*) Effective December 31, 1993, this program was merged with and into
the Consolidated Program.
63
<PAGE>
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
(1) Amounts reflect the accrual method of accounting.
(2) Does not include expenditures of $237,600, $920,453,
$2,252,900, $1,480,248, $2,079,268, $985,371 and $241,076 which were
obtained from bank borrowings and used to pay the limited partners' share
of sales commissions of $237,600, $722,453, $1,940,400, $1,183,248,
$1,656,468, $827,046 and $190,476 and organization costs of $--0--,
$198,000, $312,500, $297,000, $422,800, $158,325 and $50,600 for the
1979, 1980, 1981, 1981-II, 1982-A, 1982-B and 1983-A Programs,
respectively.
(3) Includes original subscriptions of limited partners totaling
$10,000,000 and additional assessments totaling $2,000,000.
(4) Includes original subscriptions of limited partners totaling
$25,000,000 and additional assessments totaling $4,255,000.
(5)In November 1996 the 1979 Program made a distribution totaling
$15,840 to that program's limited partners.
(6)In November 1996, the 1984 Program made a distribution of
$13,545 to that program's limited partners.
(7)In November 1996 the 1986 Program made a distribution of
$25,000 to that program's limited partners.
(8)In November 1996, the 1991 Employee Program made a distribution
of $8,942 to that program's limited partners.
(9)In November 1996, the 1992 Employee Program made a distribution
of $16,320 to that program's limited partners.
(10)In November 1996, the 1993 Employee Program made a distribution
of $18,620 to that program's limited partners.
(11)In November 1996, the Consolidated Program made a distribution
of $36,263 to that program's limited partners.
(12)In November 1996, the 1994 Employee Program made a distribution
of $24,708 to that program's limited partners.
(13)In November 1996, the 1995 Employee Program made a distribution
of $32,688 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
64
<PAGE>
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 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 on or after January 1, 1997, and the
organization and operation of the Partnership will be in accordance
with the Agreement and the Act; and
65
<PAGE>
(ii) 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.
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
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, 1997. 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
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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 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.
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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 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
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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.
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, 1997 (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
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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.
Depletion. The Partnership will be the owner of economic interests
in its oil and gas properties (except for certain production payments).
The Limited Partners will be entitled to a deduction for depletion with
respect to the Partnership's production and sale of oil and gas from
these properties. With respect to each oil and gas property or the
Partnership, a Limited Partner's deduction for each year will be 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.
Ownership Of Partnership Properties. The General Partner has
indicated that it, as nominee for the Partnership (the "Nominee"), will
acquire and hold title to Partnership Properties on behalf of the
Partnership. The Nominee and the Partnership will enter into an agency
agreement before the Nominee acquires any oil and gas properties on
behalf of the Partnership. That agency agreement will reflect that the
Nominee's acquisition of Partnership Properties is on behalf of the
Partnership. The Nominee will deliver assignments of all oil and gas
interest acquired on behalf of the Partnership to the Partnership,
however, for various cost and procedural reasons, such assignments will
not be recorded in the real estate records in the counties in which the
Partnership Properties are located. That is, while the Partnership will
be the owner of the Partnership Properties, there will be no public
record of that ownership. It is possible that the Service could assert
that the Nominee should be treated for federal income tax purposes as the
owner of the Partnership Properties, notwithstanding the assignment of
those Properties to the Partnership. If the Service were to argue
successfully that the Nominee should be treated as the tax owner of the
Partnership Properties, there would be significant adverse federal income
tax consequences to the Limited Partners, such as the unavailability of
depletion deductions in respect of income from Partnership Properties.
The Service is concerned that taxpayers not be able to shift the tax
consequences of transactions between parties based on the parties'
declaration that one party is the agent of another; the Service generally
requires that taxpayers respect the form of their transactions and
ownership of property. Based on this concern, the Service may challenge
the Partnership's treatment of Partnership Properties, and tax attributes
thereof, which are held of record by the Nominee.
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In Commissioner of Internal Revenue v. Bollinger, 485 U.S. 340
(1988), the United States Supreme Court reviewed a principal-agent
relationship and held for the taxpayer in concluding that the principal
should be treated as the tax owner of property held in the name of the
agent. In that case the Supreme Court noted that "It seems to us that
the genuineness of the agency relationship is adequately assured, and tax-
avoiding manipulation adequately avoided, when the fact that the
corporation is acting as agent for its shareholders with respect to a
particular asset is set forth in a written agreement at the time the
asset is acquired, the corporation functions as agent and not principal
with respect to the asset for all purposes, and the corporation is held
out as the agent and not principal in all dealings with third parties
relating to the asset." While the Partnership and the Nominee will have
in place an agreement defining their relationship before any Partnership
Properties are acquired by the Nominee and the Nominee will function as
agent with respect to those Partnership Properties on behalf of the
Partnership, the Nominee will not hold itself out to all third parties as
the agent of the Partnership in dealings relating to the Partnership
Properties. Unlike the relationship between the principal and the agent
in Bollinger, the Nominee will, however, assign title to Partnership
Properties to the Partnership, but will not record those assignments.
Accordingly, the facts related to the relationship between the Nominee
and the Partnership are not the same as the facts in Bollinger and it is
not clear that the failure of the Nominee to hold itself out to third
parties as the agent of the Partnership in dealings relating to
Partnership Properties should result in the treatment of the Nominee as
the tax owner of the Partnership Properties. For the foregoing reasons,
Counsel have not expressed an opinion on this issue, but Counsel believe
that substantial arguments may be made that the Partnership should be
treated as the tax owner of Partnership Properties acquired by the
Nominee on the Partnership's behalf.
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
assumed by the purchaser 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
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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
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 January 1, 1997 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 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.
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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.
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 programs
and there is a high degree of competition among such companies and
individuals in the offering of their programs.
Marketing of Production
The availability of a ready market for any oil and gas produced from
Partnership Wells will depend upon numerous factors beyond the control of
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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.
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
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Partnership intends to conduct activities have statutory provisions
regulating the production and sale of oil and gas. Such statutes, and
the regulations promulgated in connection therewith, generally are
intended to prevent waste of oil and gas and to protect correlative
rights and the opportunities to produce oil and gas as between owners of
a common reservoir. Certain state regulatory authorities also regulate
the amount of oil and gas produced by assigning allowable rates of
production to each well or proration unit. Pertinent state and federal
statutes and regulations also extend to the prevention and clean-up of
pollution. These laws and regulations are subject to change and no
predictions can be made as to what changes may be made or the effect of
such changes on the Partnership's operations.
Under the laws and administrative regulations of the State of
Oklahoma regarding forced pooling, owners of oil and gas leases or
unleased mineral interests may be required to elect to participate in the
drilling of a well with other fractional undivided interest owners within
an established spacing unit or to sell or farm out their interest
therein. The terms of any such sale or farm-out are generally those
determined by the Oklahoma Corporation Commission to be equal to the most
favorable terms then available in the area in arm's length transactions
although there can be no assurance that this will be the case. In
addition, if properties become the subject of a forced pooling order,
drilling operations may have to be undertaken at a time or with other
parties which the General Partner feels may not be in the best interest
of the Partnership. In such event, the Partnership may have to farm out
or assign its interest in such properties. In addition, if a property
which might otherwise be acquired by the Partnership becomes subject to
such an order, it may become unavailable to the Partnership. Finally, as
a result of forced pooling proceedings involving a Partnership Property,
the Partnership may acquire a larger than anticipated interest in such
property, thereby increasing its share of the costs of operations to be
conducted.
Natural Gas Price Regulation
Partnership Revenues are likely to be dependent on the sale and
transportation of natural gas that may be subject to regulation by the
Federal Energy Regulatory Commission ("FERC"). Historically the sale of
natural gas has been regulated by the FERC under the Natural Gas Act of
1938 ("NGA") and/or the Natural Gas Policy Act of 1978 ("NGPA"). Under
the NGPA, natural gas is divided into numerous, complex categories based
on, among other things, when, where and how deep the gas well was drilled
and whether the gas was committed to interstate or intrastate commerce on
the day before the date of enactment of the statute. These categories
determine whether the natural gas remains subject to non-price regulation
under the NGA and/or to maximum price restrictions under the NGPA. In
addition to setting ceiling prices for natural gas, FERC approval is
required for both the commencement and abandonment of sales of certain
categories of gas in interstate commerce for resale and for the
transportation of natural gas in interstate commerce. FERC has general
investigatory and other powers, including limited authority to set aside
or modify terms of gas purchase contracts subject to its jurisdiction.
Price and non-price regulation of natural gas produced from most wells
drilled after 1978 has terminated. That gas may be sold without prior
regulatory approval and at whatever price the market will bear.
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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 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."
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Pipeline Service Obligations and Revisions to Regulations Governing Self-
Implementing Transportation; and Regulation of Natural Gas Pipelines
After Wellhead Decontrol, Order No. 636, 57 Fed. Reg. 13,267 (Apr. 16,
1992), III FERC Stats. & Regs. Preambles Paragraph 30,939, at 30,406.
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. 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.
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.
Order 636 is still in the judicial review stage. On October 29,
1996, the United States Court of Appeals for the District of Columbia
Circuit denied petitions for rehearing of its earlier decision, United
Distribution Companies v. FERC, 88 F. 3d 1105, 1191 (D.C. Cir. 1996), in
which the D.C. Circuit upheld most of Order 636 ("In its broad contours
and in most of its specifics we uphold Order No. 636"). However, the
Court remanded to the FERC for further explanation the provisions
pertaining to (1) restriction of entitlement to receive no-service to
those customers who received bundled firm-sales service on May 18, 1992;
(2) the twenty-year term-matching cap for the right-of-first refusal
mechanism; (3) two aspects of the straight fixed variable (SFV) rate
design mitigation measures; and (4) why, in light of Order 500 and the
general cost-spreading principles of Order 636, pipelines can pass
through all their gas supply realignment (GSR) transition costs to
customers and why interruptible-transportation customers should bear 10%
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of GSR costs. In addition, many of the individual pipeline
restructurings arising from Order 636 are the subject of pending appeals,
either before the FERC or in the courts.
In essence, the goal of Order 636 is to make a pipeline's position
as gas merchant indistinguishable from that of a non-pipeline supplier.
It, therefore, pushes the point of sale of gas by pipelines upstream,
perhaps all the way to the wellhead. Order 636 also requires pipelines
to give firm transportation customers flexibility with respect to receipt
and delivery points (except that a firm shipper's choice of delivery
point cannot be downstream of the existing primary delivery point) and to
allow "no-notice" service (which means that gas is available not only
simultaneously but also without prior nomination, with the only
limitation being the customer's daily contract demand) if the pipeline
offered no-notice city-gate sales service on May 18, 1992. Thus, this
separation of pipelines' sales and transportation allows non-pipeline
sellers to acquire firm downstream transportation rights and thus to
offer buyers what is effectively a bundled city-gate sales service and it
permits each customer to assemble a package of services that serves its
individual requirements. But it also makes more difficult the
coordination of gas supply and transportation.
The results of these changes could increase the marketability of
natural gas and place the burden of obtaining supplies of natural gas for
local distribution systems directly on distributors who would no longer
be able to rely on the aggregation of supplies by the interstate
pipelines. Such distributors may return to longer term contracts with
suppliers who can assure a secure supply of natural gas. A return to
longer term contracts and the attendant decrease in gas available for the
spot market could improve gas prices. The primary beneficiaries of these
changes should be gas marketers and the producers who are able to
demonstrate the availability of an assured long-term supply of natural
gas to local distribution purchasers and to large end users. However,
due to the still evolutionary nature of Order 636 and its implementation,
it is not possible at this time to project the impact Order 636 will have
on the Partnership's ability to sell gas directly into gas markets
previously served by the gas pipelines.
As a corollary to Order 636, FERC issued Order 547, which is a
blanket certificate of public convenience and necessity pursuant to
Section 7 of the NGA that authorizes any person who is not an interstate
pipeline or an affiliate thereof to make sales for resale at negotiated
rates in interstate commerce of any category of gas that is subject to
the Commission's NGA jurisdiction. (There are certain requirements which
must be met before an affiliated marketer of an interstate pipeline can
avail itself of this certification.) Regulations Governing Blanket
Marketer Sales Certificates, Order No. 547, 57 Fed. Reg. 57,952 (Dec. 8,
1992) (to be codified at 18 C.F.R. Sections 284.401 - .402). The blanket
certificates 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.
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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 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 systems, either to
unregulated affiliates or to third persons, a practice which could result
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in separate, and higher, rates for gathering a producer's natural gas.
In proceedings during mid and late 1994 allowing various interstate
natural gas companies' spindowns or spinoffs of gathering facilities, the
FERC held that, except in limited circumstances of abuse, it generally
lacks jurisdiction over a pipeline's gathering affiliates, which neither
transport natural gas in interstate commerce nor sell gas in interstate
commerce for resale. However, pipelines spinning down gathering systems
have to include two Order No. 497 standards of conduct in their tariffs:
nondiscriminatory access to transportation for all sources of supply and
no tying of pipeline transportation service to any service by the
pipeline's gathering affiliate. In addition, if unable to reach a
mutually acceptable gathering contract with a present user of the
gathering facilities, the FERC required that the pipeline must offer a
two-year "default contract" to existing users of the gathering
facilities. However, on appeal, while the United States Court of Appeals
for the District of Columbia upheld the FERC's allowing the spinning down
of gathering facilities to a non-regulated affiliate, in Conoco Inc. v.
FERC, 90 F.3d 536, 552-53 (D.C. Cir. 1996) the D.C. Circuit remanded the
FERC's default contract mechanism. On October 31, 1996, four producers,
Amoco Energy Trading Corp. (together with its parent, Amoco Production
Co.), Anadarko Production Corp., Conoco Inc. and Marathon Oil Co.,
petitioned the Supreme Court of the United States to review the D.C.
Circuit's upholding the FERC's determination not to regulate the
gathering systems spun down to affiliates except in circumstances of
affiliate abuse. 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
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industry. The various proposals involve, among other things, 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 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.
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The effect of these regulations could be to decrease allowable
production on Partnership Properties and thereby to decrease Partnership
Revenues. However, by decreasing the amount of natural gas available in
the market, such regulations could also have the effect of increasing
prices of natural gas, although there can be no assurance that any such
increase will occur. There can also be no assurance that the proposed
regulations described above will be adopted or that they will be adopted
upon the terms set forth above. Additionally, such proposals, if
adopted, are likely to be challenged in the courts and there can be no
assurance as to the outcome of any such challenge.
Production and Environmental Regulation
Certain states in which the Partnership may drill and own productive
properties control production from wells through regulations establishing
the spacing of wells, limiting the number of days in a given month during
which a well can produce and otherwise limiting the rate of allowable
production.
In addition, the federal government and various state governments
have adopted laws and regulations regarding protection of the
environment. These laws and regulations may require the acquisition of
a permit before or after drilling commences, impose requirements that
increase the cost of operations, prohibit drilling activities on certain
lands lying within wilderness areas or other environmentally sensitive
areas and impose substantial liabilities for pollution resulting from
drilling operations, particularly operations in offshore waters or on
submerged lands.
A past, present, or future release or threatened release of a
hazardous substance into the air, water, or ground by the Partnership or
as a result of disposal practices may subject the Partnership to
liability under the Comprehensive Environmental Response, Compensation
and Liability Act, as amended ("CERCLA"), the Resource Conservation
Recovery Act ("RCRA"), the Clean Water Act, and/or similar state laws,
and any regulations promulgated pursuant thereto. Under CERCLA and
similar laws, the Partnership may be fully liable for the cleanup costs
of a release of hazardous substances even though it contributed to only
part of the release. While liability under CERCLA and similar laws may
be limited under certain circumstances, typically the limits are so high
that the maximum liability would likely have a significant adverse effect
on the Partnership. In certain circumstances, the Partnership may have
liability for releases of hazardous substances by previous owners of
Partnership Properties. Additionally, the discharge or substantial
threat of a discharge of oil by the Partnership into United States waters
or onto an adjoining shoreline may subject the Partnership to liability
under the Oil Pollution Act of 1990 and similar state laws. While
liability under the Oil Pollution Act of 1990 is limited under certain
circumstances, the maximum liability under those limits would still
likely have a significant adverse effect on the Partnership. The
Partnership's operations generally will be covered by the insurance
carried by the General Partner or UNIT, if any. However, there can be no
assurance that such insurance coverage will always be in force or that,
if in force, it will adequately cover any losses or liability the
Partnership may incur.
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Violation of environmental legislation and regulations may result in
the imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the removal, remediation and
abatement of the conditions, or suspension of the activities, giving rise
to the violation. The General Partner believes that the Partnership will
comply with all orders and regulations applicable to its operations.
However, in view of the many uncertainties with respect to the current
controls, including their duration and possible modification, the General
Partner cannot predict the overall effect of such controls on such
operations. Similarly, the General Partner cannot predict what future
environmental laws may be enacted or regulations may be promulgated and
what, if any, impact they would have on operations or Partnership
Revenue.
SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT
The business and affairs of the Partnership and the respective
rights and obligations of the Partners will be governed by the Agreement.
The following is a summary of certain pertinent provisions of the
Agreement which have not been as fully discussed elsewhere in this
Memorandum but does not purport to be a complete description of all
relevant terms and provisions of the Agreement and is qualified in its
entirety by express reference to the Agreement. Each prospective
subscriber should carefully review the entire Agreement.
Partnership Distributions
The General Partner will make quarterly determinations of the
Partnership's cash position. If it determines that excess cash is
available for distribution, it will be distributed to the Partners in the
same proportions that Partnership Revenue has been allocated to them
after giving effect to previous distributions and to portions of such
revenues theretofore used or expected to be thereafter used to pay costs
incurred in conducting Partnership operations or to repay Partnership
borrowings. It is expected that no cash distributions will be made
earlier than the first quarter of 1998. Distributions of cash determined
by the General Partner to be available therefor will be made to the
Limited Partners quarterly and to the General Partner at any time. All
Partnership funds distributed to the Limited Partners shall be
distributed to the persons who were record holders of Units on the day on
which the distribution is made. Thus, regardless of when an assignment
of Units is made, any distribution with respect to the Units which are
assigned will be made entirely to the assignee without regard to the
period of time prior to the date of such assignment that the assignee
holds the Units.
The Partnership will terminate automatically on December 31, 2027
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
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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 Partnership,
will be deposited, with or without interest, in one or more bank accounts
of the Partnership in a bank or banks to be selected by the General
Partner or invested in short-term United States government securities,
money market funds, bank certificates of deposit or commercial paper
rated as "A1" or "P1" as the General Partner, in its sole discretion,
deems advisable. Any interest or other income generated by such deposits
or investments will be for the Partnership's account. Except for Capital
Contributions, Partnership funds from any of the various sources
mentioned above may be commingled with funds of the General Partner and
may be used, expended and distributed as authorized by the terms and
provisions of the Agreement. The General Partner will be entitled to
prompt reimbursement of expenses it incurs on behalf of the Partnership.
Power and Authority
In managing the business and affairs of the Partnership, the General
Partner is authorized to take such action as it considers appropriate and
in the best interests of the Partnership (see Section 10.1 of the
Agreement). The General Partner is authorized to engage legal counsel
and otherwise to act with respect to Service audits, assessments and
administrative and judicial proceedings as it deems in the best interests
of the Partnership and pursuant to the provisions of the Code.
The General Partner is granted a broad power of attorney authorizing
it to execute certain documents required in connection with the
organization, qualification, continuance, modification and termination of
the Partnership on behalf of the Limited Partners (see Sections 1.5 and
1.6 of the Agreement). Certain actions, such as an assignment for the
benefit of its creditors or a sale of substantially all of the
Partnership Properties, except in connection with the termination, roll-
up or consolidation of the Partnership, cannot be taken by the General
Partner without the consent of a majority in interest of the Limited
Partners and the receipt of an opinion of 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 authorizing either the
General Partner or a third party operator to conduct such operations.
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The Partnership Agreement further provides that the Partnership will take
such action in connection with operations pursuant to such operating
agreements as the General Partner, in its sole discretion, deems
appropriate and in the best interests of the Partnership, and the
decision of the General Partner with respect thereto will be binding upon
the Partnership.
Rollup or Consolidation of the Partnership
Two years or more after the Partnership has completed substantially
all of its property acquisition, drilling and development operations, the
General Partner may, without the vote, consent or approval of the Limited
Partners, cause all or substantially all of the oil and gas properties
and other assets of the Partnership to be sold, assigned or transferred
to, or the Partnership merged or consolidated with, another partnership
or a corporation, trust or other entity for the purpose of combining the
assets of two or more of the oil and gas partnerships formed for
investment or participation by employees, directors and/or consultants of
UNIT or any of its subsidiaries; provided, however, that the valuation of
the oil and gas properties and other assets of all such participating
partnerships for purposes of such transfer or combination shall be made
on a consistent basis and in a manner which the General Partner and UNIT
believe is fair and equitable to the Limited Partners. As a consequence
of any such transfer or combination, the Partnership will be dissolved
and terminated and the Limited Partners shall receive partnership
interests, stock or other equity interests in the transferee or resulting
entity. See "RISK FACTORS - Investment Risks - Roll-Up or Consolidation
of the Partnership."
Limited Liability
Under the Act, a limited partner is not generally liable for
partnership obligations unless he takes part in the control of the
business. The Agreement provides that the Limited Partners cannot bind
or commit the Partnership or take part in the control of its business or
management of its affairs, and that the Limited Partners will not be
personally liable for any debts or losses of the Partnership. However,
the amounts contributed to the Partnership by the Limited Partners and
the Limited Partners' interests in Partnership assets, including amounts
of undistributed Partnership Revenue allocable to the Limited Partners,
will be subject to the claims of creditors of the Partnership. A Limited
Partner (or his or her estate) will be obligated to contribute cash to
the Partnership, even if the Limited Partner is unable to do so because
of death, disability or any other reason, for:
(1) any unpaid contribution which the Limited Partner agreed
to make to the Partnership; and
(2) any return, in whole or in part, of the Limited Partner's
contribution to the extent necessary to discharge Partnership
liabilities to all creditors who extended credit or whose claims
arose before such return.
Liability of a Limited Partner is limited by the Act to one year for
any return of his or her contribution not in violation of the Partnership
Agreement or such Act and six years on any return of his or her
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contribution in violation of the Partnership Agreement or such Act. A
partner is deemed to have received a return of his or her contribution to
the extent that a distribution to him or her reduces his or her share of
the fair value of the net assets of the Partnership below the value of
his or her contribution which has not been distributed to him or her.
How this provision applies to a partnership whose primary assets are
producing oil and gas properties or other depleting assets is not
entirely clear. The Agreement provides that for the purposes of this
provision, the value of a Limited Partner's contribution which has not
been distributed to him or her at any point in time will be the Limited
Partner's Percentage of the stated capital of the Partnership allocated
to the Limited Partners as reflected in its financial statements as of
such point in time.
Maintenance of limited liability of the Limited Partners in other
jurisdictions in which the Partnership may operate may require compliance
with certain legal requirements of those jurisdictions. In such
jurisdictions, the General Partner shall cause the Partnership to operate
in such a manner as it, on the advice of responsible 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 termination of
the Partnership, any distribution of Partnership Properties to the
Limited Partners would result in their having unlimited liability with
respect to such properties.
Although the Partnership will, with certain limited exceptions,
serve as a co-general partner of any drilling or income programs formed
by UNIT or UPC in 1997 (see "PROPOSED ACTIVITIES"), the general liability
of the Partnership will not flow through to the Limited Partners.
Records, Reports and Returns
The General Partner will maintain adequate books, records, accounts
and files for the Partnership and keep the Limited Partners informed by
means of written interim reports rendered within 60 days after each
quarter of the Partnership's fiscal year. The reports will set forth the
source and disposition of Partnership Revenues during the quarter.
Engineering reports on the Partnership Properties will be prepared
by the General Partner for each year for which the General Partner
prepares such a report in connection with its own activities. Such
report will include an estimate of the total oil and gas proven reserves
of the Partnership, the dollar value thereof and the value of the Limited
Partners' interest in such reserve value. The report shall also contain
an estimate of the life of the Partnership Properties and the present
worth of the reserves. Each Limited Partner will receive a summary
statement of such report which will reflect the value of the Limited
Partners' interest in such reserves.
The General Partner will timely file the Partnership's income tax
returns and by March 15 of each year or as soon thereafter as 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
87
<PAGE>
Restrictions. A Limited Partner may not transfer or assign Units
except for certain transfers:
. to the General Partner;
. to or for the benefit of himself or herself, his or her spouse,
or other members of the transferor Limited Partner's immediate
family sharing the same residence;
. to any corporation or other entity whose beneficial owners are
all Limited Partners or permitted assignees;
. by the General Partner to any person who at the time of such
transfer is an employee of the General Partner, UNIT or its
subsidiaries; and
. by reason of death or operation of law.
Further, no sale or exchange of any Units may be made if the sale of
such interest would, in the opinion of counsel for the Partnership,
result in a termination of the Partnership for purposes of Section 708 of
the Code, violate any applicable securities laws or cause the Partnership
to be treated as an association taxable as a corporation for federal
income tax purposes; provided, however, that this condition may be waived
by the General Partner, in its sole discretion. Moreover, in no event
shall all or any portion of a Limited Partner's Units be assigned to a
minor or an incompetent, except by will, intestate succession, in trust,
or pursuant to the Uniform Gifts to Minors Act.
As the offer and sale of the Units are not being registered under
the Securities Act of 1933, as amended, they may be sold, transferred,
assigned or otherwise disposed of by a Limited Partner only if, in the
opinion of counsel for the Partnership, such transfer or assignment would
not violate, or cause the offering of the Units to be violative of, such
act or applicable state securities laws, including investor suitability
standards thereunder. Because of the structure and anticipated operation
of the Partnership, Rule 144 under the Securities Act of 1933 will not be
available to Limited Partners in connection with any such sales.
Assignees. An assignee of a Limited Partner does not automatically
become a Substituted Limited Partner, but has the right to receive the
same share of Partnership Revenue and distributions thereof to which the
assignor Limited Partner would have been entitled. A Limited Partner who
assigns his or her Partnership interest ceases to be a Limited Partner,
except that until a Substituted Limited Partner is admitted in his or her
place, the assignor retains the statutory rights of an assignor of a
Limited Partner's interest under the partnership laws of the State of
Oklahoma. The assignee of a Partnership interest who does not become a
Substituted Limited Partner and desires to make a further assignment of
such interest is subject to all of the restrictions on transferability of
Partnership interests described herein and in the Partnership Agreement.
In the event of the death, incapacity or bankruptcy of a Limited
Partner, his or her legal representatives will have all the rights of a
Limited Partner only for the purpose of settling or liquidating his or
her estate and such power as the decedent, incompetent or bankrupt
88
<PAGE>
Limited Partner possessed to assign all or any part of his or her
interest in the Partnership and to join with such assignee in satisfying
conditions precedent to such assignee's becoming a Substituted Limited
Partner.
A purported sale, assignment or transfer of a Limited Partner's
interest will be recognized by the Partnership when it has received
written notice of such sale or assignment in form satisfactory to the
General Partner, signed by both parties, containing the purchaser's or
assignee's acceptance of the terms of the Agreement and a representation
by the parties that the sale or assignment was lawful. Such sale or
assignment will be recognized as of the date of such notice, except that
if such date is more than 30 days prior to the time of filing, such sale
or assignment will be recognized as of the time the notice was filed with
the Partnership. Distributions of Partnership Revenue will be made only
to those persons who were record owners of Units on the day any such
distribution is made (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 jurisdiction
to the effect that the exercise of such right will not be deemed to
evidence that the Limited Partners are taking part in the management of
the Partnership's business and affairs and will not result in a loss of
any Limited Partner's limited liability or cause the Partnership to be
classified as an association taxable as a corporation for federal income
tax purposes (see Section 12.1 of the Agreement). Any transferee of the
General Partner's interest may become a substitute General Partner by
assuming and agreeing to perform all of the duties and obligations of a
General Partner under the Agreement. In such event, the transferring
General Partner, upon making a proper accounting to the substitute
General Partner, will be relieved of any further duties or obligations
with respect to any future Partnership operations.
89
<PAGE>
Amendments
The Agreement may be amended upon the approval by a majority in
interest of the Limited Partners, except that amendments changing the
Partners' participation in costs and revenues, increasing or decreasing
the General Partner's compensation or otherwise materially and adversely
affecting the interests of either the Limited Partners or the General
Partner must be approved by all Limited Partners if their interests would
be adversely affected thereby or by the General Partner if its interest
would be adversely affected thereby. The Limited Partners have no right
to propose amendments to the Agreement.
Voting Rights
Under the Agreement, the Limited Partners will have very limited
rights to vote on any Partnership matters. Except for certain special
amendments referred to under "Amendments" above, matters submitted to the
Limited Partners for determination will be determined by the affirmative
vote of Limited Partners holding a majority of the outstanding Units.
Units held by the General Partner may be voted by it.
Generally, Limited Partners owning more than 50% of the outstanding
Units of the Partnership may, without the necessity of concurrence by the
General Partner, vote to:
. Approve the execution or delivery of any assignment for the
benefit of the Partnership's creditors;
. Approve the sale or disposal of all or substantially all of the
Partnership's assets, except pursuant to (i) a rollup or
consolidation of the Partnership (see "Rollup or Consolidation
of the Partnership" above) or (ii) termination (see
"Termination" below);
. Approve the General Partner's sale, assignment, transfer or
disposal of its interest in the Partnership, unless such sale,
assignment or transfer is pursuant to (i) a merger or other
corporate reorganization, or liquidation or sale of
substantially all of its assets, and the purchaser agrees to
assume the duties and obligations of the General Partner, or
(ii) any sale to UNIT or its affiliates;
. Terminate and dissolve the Partnership; or
. Approve any amendments to the Agreement which may be proposed
by the General Partner;
provided, however, any approvals, consents or elections of the Limited
Partners will not become effective unless prior to the exercise thereof
the General Partner is furnished with an opinion of counsel for the
Partnership, or an order or judgment of any court of competent
jurisdiction, that the exercise of such rights:
. Will not be deemed to evidence that the Limited Partners are
taking part in the control or management of the Partnership's
business affairs;
90
<PAGE>
. 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, 2027.
In addition, upon the dissolution (other than pursuant to a merger, or
other corporate reorganization or sale), bankruptcy, legal disability or
withdrawal of the General Partner, the Partnership shall immediately be
dissolved and terminated. The Act provides, however, that the Limited
Partners may elect to reform and reconstitute themselves as a limited
partnership within 90 days after such dissolution under the provisions in
the Partnership Agreement or under any other terms. The Partnership may
terminate sooner if a majority in interest of the Limited Partners or the
General Partner elects to dissolve and terminate the Partnership as of an
earlier date. Such right to accelerate termination of the Partnership by
the Limited Partners will not be available unless prior to any exercise
thereof the Limited Partners proposing such termination obtain and
furnish to the General Partner an opinion, order or judgment in the form
referred to above under "Transferability of Interests - Assignments by
the General Partner." The withdrawal, expulsion, dissolution, death,
legal disability, bankruptcy or insolvency of any Limited Partner will
not effect a dissolution or termination of the Partnership. In the event
of an election to terminate the Partnership prior to expiration of its
stated terms, 90 days' prior written notice must be given to all Partners
specifying the termination date which must be the last day of a calendar
month following such 90 day period unless an earlier date is approved by
Limited Partners holding a majority of the outstanding Units.
When the Partnership is terminated, there will be an accounting with
respect to its assets, liabilities and accounts. The Partnership's
physical property and its oil and gas properties may be sold for cash.
Except in the case of an election by the General Partner to terminate the
Partnership before the tenth anniversary of the Effective Date,
Partnership Properties may be sold to the General Partner or any of its
affiliates for their fair market value as determined in good faith by the
General Partner.
91
<PAGE>
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 properties of the
Partnership, if any, will be distributed to the Partners as set forth
under "Partnership Distributions" above (see Section 16.4 of the
Agreement). Such distribution will result in the Limited Partners'
having unlimited liability with respect to any Partnership Properties
distributed to them.
Insurance
The General Partner will use its best efforts to obtain such
insurance as it deems prudent to serve as protection against liability
for loss and damage. Such insurance may include, but is not limited to,
public liability, automotive liability, workers' compensation and
employer's liability insurance and blowout and control of well insurance.
COUNSEL
Conner & Winters, 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,
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
92
<PAGE>
with power to vote, by such other person; (3) any person directly or
indirectly controlling, controlled by, or under common control with
such other person; (4) any officer, director, trustee or partner of
such other person; and (5) if such other person is an officer,
director, trustee or partner, any company for which such person acts
in any such capacity.
(c) The "Aggregate Subscription" is the sum of the Capital
Subscriptions of all Limited Partners.
(d)"Agreement" and "Partnership Agreement" refers to the
Agreement of Limited Partnership attached as Exhibit A to this
Private Offering Memorandum.
(e) The "Capital Contribution" of a Limited Partner is the
amount of the Capital Subscription actually paid in by him or her,
or by any predecessor in interest, to the capital of the Partnership
including any payments made by deductions from salary. The "Capital
Contribution" of the General Partner includes the amounts
contributed to the Partnership or paid by the General Partner or by
any Limited Partner whose Units are purchased by the General Partner
pursuant to Section 4.2 of the Agreement because of a default by
such Limited Partner in the payment of an Installment or pursuant to
Article XV of the Agreement, including payments made by deductions
from the salary of such Limited Partner.
(f) The "Capital Subscription" of a Limited Partner or his or
her assignee (including the General Partner where Units are trans-
ferred pursuant to Section 4.2 of the Agreement) is the amount
specified in the Subscription Agreement executed by such Limited
Partner for payment by him or her to the capital of the Partnership
in accordance with the provisions of the Agreement, reduced by the
amounts thereof from which the Limited Partners have been released
by the General Partner of their obligation to pay.
(g) A "Development Well" means a well intended to be drilled
within the proved areas of a known oil or gas reservoir to the depth
of a stratigraphic horizon known to be productive.
(h) "Director" refers to the duly elected directors of UNIT as
well as all honorary directors and consultants to the Board of
Directors of UNIT.
(i) "Drilling Costs" are those costs incurred in drilling,
testing, completing and equipping a well to the point that it proves
to be dry and is abandoned or is ready to commence commercial
production of oil or gas therefrom.
(j) "Effective Date" refers to the date on which the 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).
93
<PAGE>
(k) An "Exploratory Well" means a well drilled to find
production in an unproven area, to find a new reservoir in a field
previously found to be productive or to extend greatly the limits of
a known reservoir.
(l) A "farm-out" is an agreement whereby the owner of an oil
and gas property agrees to assign such property, usually retaining
some interest therein such as an overriding royalty, a production
payment, a net profits interest or a carried working interest,
subject in most cases, however, to the drilling of one or more wells
or other performance by the prospective assignee as a condition of
the assignment.
(m) The "General Partner's Minimum Capital Contribution" is
that amount equal to the total of (i) all Partnership costs and
expenses charged to its account from the time of the formation of
the Partnership through December 31, 1997, 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, 1997, if any, minus (iii) the amount, if any, of the
unexpended Aggregate Subscription at December 31, 1997.
(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, 1997, June 15, 1997, September 15,
1997 and December 15, 1997, respectively, or (ii) if an employee so
elects, through equal deductions from 1997 salary commencing
immediately after formation of the Partnership.
(p) "Leasehold Acquisition Costs" with respect to properties,
if any, acquired by the Partnership from non-affiliated parties mean
the actual costs to the Partnership of and in acquiring the
properties, and, with respect to properties acquired by the
Partnership from the General Partner, UNIT or its affiliates are,
without duplication, the sum of:
(1) the prices paid by the General Partner, UNIT or its
affiliates in acquiring an oil and gas property, including
purchase option fees and charges, bonuses and penalties,
if any;
(2) title insurance or examination costs, broker's
commissions, filing fees, recording costs, transfer taxes,
if any, and like charges incurred in connection with the
acquisition of such property;
(3) a pro rata portion of the actual, necessary and reasonable
expenses of the General Partner, UNIT or its affiliates
for seismic and geophysical services;
94
<PAGE>
(4) rentals, shut-in royalties and ad valorem taxes paid by
the General Partner, UNIT or its affiliates with respect
to such property to the date of its transfer to the
Partnership;
(5) interest and points actually incurred on funds used by the
General Partner, UNIT or its affiliates to acquire or
maintain such property; and
(6) such portion of the General Partner's, UNIT or its
affiliates' reasonable, necessary and actual expenses for
geological, engineering, drafting, accounting, legal and
other like services allocated to the acquisition,
operations and maintenance of the property in accordance
with generally accepted industry practices, except for
expenses in connection with the past drilling of wells
which are not producers of sufficient quantities of oil or
gas to make commercially reasonable their continued
operations, and provided that the costs and expenses
enumerated in (4), (5) and (6) above with respect to any
particular property shall have been incurred not more than
thirty-six (36) months prior to the acquisition of such
property by the Partnership.
In the event a fractional undivided interest in a property is sold
or transferred by the General Partner, UNIT or any affiliate to an
unaffiliated third party for an amount in excess of that portion of
the original cost of the property attributable to the transferred
interest, the amount of such excess shall not reduce or be offset
against the amount of the Leasehold Acquisition Costs attributable
to any interest in the same property which is transferred to the
Partnership.
(q) "Limited Partners" are those persons who acquire Units in
the Partnership upon its formation and those transferees of Units
who are accepted as Substituted Limited Partners. The General
Partner may also be a Limited Partner if it subscribes for Units or
if it subsequently acquires Units by (i) the exercise by a Limited
Partner of his or her right of presentment; (ii) a purchase by the
General Partner of the Units of a Limited Partner who defaults in
the payment of an Installment; or (iii) any other assignment or
transfer.
(r) The "Limited Partners' Percentage" is that percentage
determined by dividing the amount of the Aggregate Subscription by
the total of (i) the General Partner's Minimum Capital Contribution
plus (ii) the Aggregate Subscription.
(s) "Normal Retirement" means retirement under the terms of a
pension or similar retirement plan adopted by the General Partner,
UNIT or any subsidiary with whom a Limited Partner is employed as in
effect at the time of retirement.
(t) "Oil and gas properties" are oil and gas leasehold working
interests, fee interests, mineral interests, royalty interests,
overriding royalty interests, production payments, options or rights
95
<PAGE>
to lease or acquire such interests, geophysical exploration permits
and any tangible or intangible properties or other rights incident
thereto, whether real, personal or mixed.
(u) "Operating Expenses" are expenditures made and costs
incurred in producing and marketing oil or gas from completed wells,
including, in addition to labor, fuel, repairs, hauling, material,
supplies, utility charges and other costs incident to or necessary
for the maintenance or operation of such wells or the marketing of
production therefrom, ad valorem, severance and other such taxes
(other than windfall profit taxes), insurance and casualty loss
expense and compensation to well operators or others for services
rendered in conducting such operations.
(v) The General Partner and the Limited Partners are sometimes
collectively referred to as the "Partners."
(w) "Partnership Agreement" and "Agreement" refer to the
Agreement of Limited Partnership attached as Exhibit A to this
Private Offering Memorandum.
(x) The "Partnership Properties" are oil and gas properties or
interests therein acquired by the Partnership or properties acquired
by any partnership or joint venture in which the Partnership is a
partner or joint venturer, whether acquired by purchase, option
exercise or otherwise.
(y) "Partnership Revenue" refers to the Partnership's gross
revenues from all sources, including interest income, proceeds from
sales of production, the Partnership's share of revenues from
partnerships or joint ventures of which it is a member, sales or
other dispositions of Partnership Properties or other Partnership
assets, provided that contributions to Partnership capital by the
Partners and the proceeds of any Partnership borrowings are
specifically excluded and dry-hole and bottom-hole contributions
shall be treated as reductions of the costs giving rise to the right
to receive such contributions.
(z) "Partnership Wells" are any and all of the oil and gas
wells in which the Partnership has an interest, either directly or
indirectly through any other partnership or joint venture.
(aa) "Productive properties" are oil and gas properties that
have been tested by drilling and determined to be capable of
producing oil or gas in commercial quantities.
(bb) A "spacing unit" is a drilling and spacing, production or
similar unit established by any regulatory body with jurisdiction,
or in the absence of such a regulatory body or action thereby, the
acreage attributable to wells drilled under the normal spacing
pattern in such area or if no such spacing unit is designated, in
keeping with generally accepted industry practices, or the largest
of such units in the event of multiple objective formations.
(cc) "Special Production and Marketing Costs" are costs and
expenses that are not normally and customarily incurred in connec-
tion with drilling, producing and marketing operations, including
96
<PAGE>
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 November
30, 1996 is unaudited and includes all adjustments which UNIT considers
necessary for a fair presentation of the financial position of Unit
Petroleum Company at November 30, 1996.
97
<PAGE>
Unit Petroleum Company and Subsidiary
Consolidated Balance Sheet
(In Thousands)
November 30,
1996
------------
(Unaudited)
Assets
Current Assets:
Cash and cash equivalents $ 187
Accounts receivable 8,625
Materials and supplies, at lower of
cost or market 2,281
Other 157
----------
11,250
----------
Property and Equipment:
Oil and natural gas properties, on the
full cost method 198,790
Other 323
----------
199,113
Less accumulated depreciation, depletion,
amortization and impairment (101,771)
----------
Net property and equipment 97,342
----------
Other Assets 1
----------
Total Assets $ 108,593
==========
Liabilities and Shareholder Equity
Current Liabilities:
Accounts payable $ 4,767
Amount Payable to Parent 13,517
Contract advances 1,562
Accrued liabilities 789
----------
Total current liabilities 20,635
----------
Long-Term Portion of Natural Gas Purchaser Prepayment 2,362
----------
Shareholder Equity:
Common stock, $1.00 per value,
500 shares authorized and outstanding 1
Capital in excess of par value 31,486
Retained earnings 54,109
----------
Total Shareholder Equity 85,596
----------
Total Liabilities and Shareholder Equity $ 108,593
==========
98
<PAGE>
Exhibits to the 1997 Employee Oil and Gas Limited Partnership
will be provided to the SEC upon request.
<PAGE>
EXHIBIT 21
<PAGE>
EXHIBIT 21
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 23
<PAGE>
EXHIBIT 23
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) of our report dated February 18, 1997, on our audits
of the consolidated financial statements and financial statement schedule
of Unit Corporation as of December 31, 1996 and 1995, and for the years
ended December 31, 1996, 1995 and 1994, which report is included in this
Annual Report on Form 10-K.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
March 17, 1997
<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, 1996 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-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 547
<SECURITIES> 0
<RECEIVABLES> 15,946
<ALLOWANCES> 104
<INVENTORY> 2,302
<CURRENT-ASSETS> 20,155
<PP&E> 293,917
<DEPRECIATION> 176,211
<TOTAL-ASSETS> 137,993
<CURRENT-LIABILITIES> 12,709
<BONDS> 0
0
0
<COMMON> 4,831
<OTHER-SE> 73,379
<TOTAL-LIABILITY-AND-EQUITY> 137,993
<SALES> 0
<TOTAL-REVENUES> 72,070
<CGS> 0
<TOTAL-COSTS> 51,419
<OTHER-EXPENSES> 4,122
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 3,162
<INCOME-PRETAX> 13,367
<INCOME-TAX> 5,034
<INCOME-CONTINUING> 8,333
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 8,333
<EPS-PRIMARY> .37
<EPS-DILUTED> .36
</TABLE>
