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F O R M 1 0 - K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
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. X
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 15, 1995 - $44,446,596
Number of Shares of Common Stock
Outstanding on March 15, 1995 - 20,933,190
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 3, 1995 are incorporated by
reference in Part III.
Exhibit Index - See Page 66
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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. . . . . . . . . . . . . . . . . . . . . . . . 15
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . 16
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . 16
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . 17
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations. . . . . . . . . . . . . . . . . . . 17
Item 8. Financial Statements and Supplementary Data. . . . . . . . . . . 25
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . 55
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . 55
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . 56
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . 57
Item 13. Certain Relationships and Related Transactions . . . . . . . . . 57
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . 58
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
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UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1994
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, the development,
acquisition and production of oil and natural gas properties and the
marketing of natural gas. 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 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. As used herein, the term "Company" refers to Unit Corpo-
ration 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 a
major portion of the Company's operations as conducted through its wholly
owned subsidiaries, Unit Petroleum Company and Roundup Resources, Inc.
As of December 31, 1994, the Company had 4,308 Mbbls and 93,360 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, 1994,
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the Company had an interest in a total of 1,764 wells in the United States
of which it served as the operator of 418. The Company also had an
interest in 61 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,
Wells drilled: 1994 1993 1992
- -------------- Gross Net Gross Net Gross Net
Exploratory: ------ ------ ------ ------ ------ ------
Oil.............. - - - - - -
Natural gas...... 1 .98 1 1.00 - -
Dry.............. 2 .80 1 0.10 - -
------ ------ ------ ------ ------ ------
Total 3 1.78 2 1.10 - -
====== ====== ====== ====== ====== ======
Development:
Oil.............. 5 5.00 12 11.98 2 2.00
Natural gas...... 40 13.46 25 11.12 15 5.38
Dry.............. 12 7.26 8 4.29 6 1.48
------ ------ ------ ------ ------ ------
Total 57 25.72 45 27.39 23 8.86
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
- ------------------------------------------------------------
Oil - USA........ 675 177.68 337 162.09 329 130.70
Oil - Canada..... - - - - - -
Gas - USA........ 1,089 179.99 709 141.76 715 132.03
Gas - Canada..... 61 1.53 61 1.53 56 1.40
------ ------ ------ ------ ------ ------
Total 1,825 359.20 1,107 305.38 1,100 264.13
====== ====== ====== ====== ====== ======
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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
------- ------- ------- -------
1994
----
USA 340,241 100,732 21,514 11,540
Canada 31,360 784 - -
------- ------- ------- -------
Total 371,601 101,516 21,514 11,540
======= ======= ======= =======
1993
----
USA 246,115 86,013 28,738 18,021
Canada 31,360 784 - -
------- ------- ------- -------
Total 277,475 86,797 28,738 18,021
======= ======= ======= =======
1992
----
USA 228,363 86,144 36,169 18,736
Canada 31,360 784 - -
------- ------- ------- -------
Total 259,723 86,928 36,169 18,736
======= ======= ======= =======
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Price and Production Data. The average sales price, oil and natural
gas production volumes and average production cost per equivalent barrel (6
thousand cubic feet (Mcf) of natural gas = 1 barrel (Bbl) of oil) of
production, experienced by the Company, for the periods indicated were as
follows:
Year Ended December 31,
1994 1993 1992
-------- -------- --------
Average sales price per barrel
of oil produced:
USA $ 15.13 $ 16.73 $ 19.52
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 1.86 $ 2.07 $ 2.15
Canada $ 1.27 $ 0.96 $ 0.93
Oil production (Mbbls):
USA 406 397 375
Canada - - -
-------- -------- --------
Total 406 397 375
======== ======== ========
Natural gas production (MMcf):
USA 9,606 7,435 6,730
Canada 53 70 80
-------- -------- --------
Total 9,659 7,505 6,810
======== ======== ========
Average production expense per
equivalent barrel:
USA $ 3.49 $ 3.93 $ 4.11
Canada $ 2.19 $ 1.28 $ 0.76
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,
1994 1993 1992
------- ------- -------
Oil (Mbbls):
USA 4,308 3,304 3,308
Canada - - -
------- ------- -------
Total 4,308 3,304 3,308
======= ======= =======
Natural gas (Mmcf):
USA 92,566 71,379 63,761
Canada 794 861 931
------- ------- -------
Total 93,360 72,240 64,692
======= ======= =======
Further information relating to oil and natural gas operations is
presented in Notes 1, 2, 4, 9, 10 and 12 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
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LAND CONTRACT DRILLING OPERATIONS
Unit Drilling Company, a wholly owned subsidiary of the Company,
engages in the land drilling of oil and natural gas wells for a wide range
of customers. A land drilling rig consists, in part, of engines, drawworks
or hoists, derrick or mast, pumps to circulate the drilling fluid, blowout
preventers and drill pipe. An active maintenance and replacement program
during the life of a drilling rig permits upgrading of components on an
individual basis. Over the life of a typical rig, due to the normal wear
and tear of operating up to 24 hours a day, several of the major
components, such as engines, mud pumps and drill pipe, are replaced or
rebuilt on a periodic basis as required, while other components, such as
the substructure, mast and drawworks, can be utilized for extended periods
of time with proper maintenance. The Company also owns additional
equipment used in the operation of its rigs, including large air compres-
sors, trucks and other support equipment.
The Company owns and operates 25 drilling rigs with drilling capa-
bilities primarily in the 6,000 to 20,000 foot depth range. Historically,
all of these drilling rigs were located in the Anadarko and Arkoma Basins
of Oklahoma, Kansas, Arkansas and Texas. In 1994, the Company moved two
20,000 feet depth range rigs to the South Texas basin region thereby
expanding the Company's market area for its contract drilling services. A
third rig was moved under contract to the South Texas basin early in 1995.
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 drill pipe or
other equipment. However, as certain grades of drill pipe start to reach
the end of their useful life there is no assurance that sufficient supplies
of such equipment will be readily available. In addition, given the
general decline experienced in the land contract drilling industry over the
past number of years, the Company's ability to utilize its full complement
of drilling rigs, should economic conditions improve rapidly in the future,
will be restricted due to a lack of equipment and qualified labor not only
within the Company but in the industry as a whole.
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The following table sets forth for each of the periods indicated
certain data concerning the Company's contract drilling operations:
Year Ended December 31,
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Number of rigs owned at end of period 25 25 26 26 27
Average number of rigs utilized(1) 9.5 8.0 5.5 9.1 12.6
Number of wells drilled 95 84 56 92 106
Total footage drilled (feet in 1000's) 1027 788 527 736 991
- -------------------
(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 15, 1995, 6 of the Company's 25 drilling rigs were oper-
ating under contract.
The following table sets forth, as of March 15, 1995, the type and
approximate depth capability of the Company's drilling rigs:
Depth
Capability
Type (feet)
---- ----------
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
Gardner Denver 800. . . . . . . . . . . . 15,000
Brewster N-55 . . . . . . . . . . . . . . 12,000
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
National 75 . . . . . . . . . . . . . . . 15,000
Brewster N-75 . . . . . . . . . . . . . . 15,000
BDW 1350-M. . . . . . . . . . . . . . . . 20,000
SU-15 North Texas Machine . . . . . . . . 12,000
SU-15 North Texas Machine . . . . . . . . 12,000
National 110-E. . . . . . . . . . . . . . 20,000
Continental Emsco C-1-E . . . . . . . . . 20,000
Gardner Denver 1500-E . . . . . . . . . . 25,000
For the past several years, the Company's contract drilling services
have encountered significant competition due to depressed levels of
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activity in contract drilling as oil and natural gas prices remained below
economic levels needed to encourage domestic exploration. While drilling
operations of the Company showed continued improvement in 1994, this
competition will, for the foreseeable future, continue to adversely affect
the Company's drilling operations.
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. During the year ended December 31, 1994 turnkey revenue
represented approximately 19% of the Company's contract drilling revenues.
To date, the Company has not experienced significant losses in performing
turnkey contracts.
Customers. During the last 3 years, approximately 8 customers have
regularly used the Company for drilling operations. During the fiscal year
ended December 31, 1994, 10 contract drilling customers accounted for
approximately 10% of the Company's revenues. In addition, approximately 2%
of the Company's revenues for the year ended December 31, 1994, were
generated by drilling on oil and natural gas properties of which the
Company was the operator (including properties owned by limited partner-
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ships for which the Company acted as general partner). Such drilling was
pursuant to contracts containing terms and conditions comparable to those
contained in the Company's customary drilling contracts with non-affiliated
operators.
Further information relating to contract drilling operations is
presented in Notes 1 and 10 of Notes to Consolidated Financial Statements
set forth in Item 8 hereof.
NATURAL GAS MARKETING, GATHERING AND PROCESSING
The Company, through its wholly owned subsidiary, Mountain Front
Pipeline Company ("Mountain Front"), is engaged in marketing natural gas
from wells located primarily in Oklahoma and Texas and to a lesser extent
in Arkansas, Kansas, Louisiana, Mississippi and New Mexico. Natural gas
purchased from 5 customers during 1994 accounted for 32% of the Company's
marketing activity. The Company owns 8 natural gas gathering systems. The
Company also owns an interest in 2 natural gas processing plants located in
Oklahoma and Mississippi and 44 natural gas compressors.
Revenues and expenses from the Company's natural gas marketing,
gathering and processing activities for the periods indicated were as
follows:
Year Ended December 31,
1994 1993 1992
------- ------- -------
(In thousands)
Natural gas marketing and
gathering revenue $43,725 $31,624 $21,341
Natural gas processing revenue $ 82 $ 181 $ 514
Other revenue $ 364 $ 299 $ 115
Natural gas marketing
and processing expense $43,897 $32,325 $22,627
Mountain Front, while achieving substantial growth in revenues in
recent years, has not, in the opinion of management, achieved the size
necessary to reach desired levels of profitability. Consequently, the
Company is currently negotiating to effect a business combination between
Mountain Front's marketing operations and a third party. The combination,
if completed, would leave the Company with a minority interest in the
resulting larger entity. Such a combination would not adversely affect the
operations of the Company's drilling and oil and natural gas exploration
segments or the profitability of the Company as a whole, although it would
result in a significant reduction in the Company's total revenues and
associated costs.
Further information related to natural gas marketing, gathering and
processing is presented in Note 10 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
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MARKETING OF OIL AND NATURAL GAS PRODUCTION
The Company's revenue and profitability are substantially dependent
upon prevailing prices for natural gas and crude oil. These prices vary
based on factors beyond the control of the Company, including the extent of
domestic production and importation of crude oil and natural gas, the
proximity and capacity of oil and natural gas pipelines, the marketing of
competitive fuels, general fluctuations in the supply and demand for oil
and natural gas, the effect of federal and state regulation of production,
refining, transportation and sales, the use and allocation of oil and
natural gas and their substitute fuels and general national and worldwide
economic conditions. In addition, natural gas spot prices received by the
Company are influenced by weather conditions impacting the continental
United States.
The Company's oil and condensate production is sold at or near the
Company's wells under short-term 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 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 slightly
increased in the United States, imports of foreign oil continue to in-
crease. 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. 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, a surplus of drilling rigs currently exists.
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 and the Company's natural
gas marketing operations, likewise encounter strong competition from major
oil companies, independent operators, marketers, pipelines and others.
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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 and the marketing of natural gas than the
Company.
OIL AND NATURAL GAS PROGRAMS
The Company currently serves as a general partner to 5 oil and gas
limited partnerships and 6 employee oil and gas limited partnerships. The
employee partnerships acquire an interest ranging from 5% to 15% of the
Company's interest in most oil and natural gas drilling activities and pur-
chases 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. Prior to
December 31, 1993, the Company was the general partner of seven additional
employee limited partnerships. However, pursuant to the terms of an
agreement and plan of merger these seven limited partnerships were
consolidated into one new employee limited partnership effective December
31, 1993.
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 February 28, 1995, the Company had approximately 205 employees
in its land contract drilling operations, 46 employees in its oil and natu-
ral gas operations, 9 employees in natural gas marketing and processing and
23 in its general corporate area. None of the Company's employees are
represented by a union or labor organization nor have the Company's
operations ever been interrupted by a strike or work stoppage. The Company
considers relations with its employees to be satisfactory.
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OPERATING AND OTHER RISKS
The Company's land contract drilling, oil and natural gas operations
and natural gas processing facilities are subject to a variety of oil field
hazards such as fire, explosion, blowouts, cratering and oil spills or
certain other types of possible surface and subsurface pollution, any of
which can cause personal injury and loss of life and severely damage or
destroy equipment, suspend drilling operations and cause substantial damage
to surrounding areas or property of others. As protection against some,
but not all, of these operating hazards, the Company maintains broad
insurance coverage, including all-risk physical damage, employer's
liability and comprehensive general liability. In all states in which the
Company operates except Oklahoma, the Company maintains worker's
compensation insurance for losses exceeding $50,000. In Oklahoma, starting
in August 1991, the Company elected to become self insured. In
consideration therewith, the Company purchased an excess liability
reinsurance policy. The Company believes that to the extent reasonably
practicable such insurance coverages are adequate. The Company's insurance
policies do not, however, provide protection against revenue losses
incurred by reason of business interruptions caused by the destruction or
damage of major items of equipment nor certain types of hazards such as
specific types of environmental pollution claims. In view of the
difficulties which may be encountered in renewing such insurance at
reasonable rates, no assurance can be given that the Company will be able
to maintain the amount of insurance coverage which it considers adequate at
reasonable rates. Moreover, loss of or serious damage to any of the
Company's equipment, although adequately covered by insurance, could have
an adverse effect upon the Company's earning capacity.
The Company's oil and natural gas operations are also subject to all
of the risks and hazards typically associated with the search for and
production of oil and natural gas. These include the necessity of 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
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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.
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
12
<PAGE>
firm shippers can release unwanted capacity to those desiring capacity
(which program replaces previous "capacity brokering" and "buy-sell"
programs); existing bundled firm sales entitlement are converted to
unbundled firm sales entitlement and to unbundled firm transportation
rights on the effective date of a particular pipeline's blanket sales
certificate; and pipeline transportation rights must be developed under the
Straight Fixed Variable (SFV) method of cost classification, allocation and
rate design unless the FERC permits the pipeline to use some other method.
The FERC will not permit a pipeline to change the new resulting rates until
the FERC accepts the pipeline's formal restructuring plans.
In essence, the goal of Order 636 is to make a pipeline's position as
natural gas merchant indistinguishable from that of a non-pipeline
supplier. It, therefore, pushes the point or sale of natural gas by
pipelines upstream, perhaps all the way to the wellhead. Order 636 also
requires pipelines to give firm transportation customers flexibility with
respect to receipt and delivery points (except that a firm shipper's choice
of delivery point cannot be downstream of the existing primary delivery
point) and to allow "no-notice" service (which means that natural gas is
available not only simultaneously but also without prior nomination, with
the only limitation being the customer's daily contract demand) if the
pipeline offered no-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. However, due to the still evolutionary nature of Order 636
and its implementation, it is not possible to project the overall potential
impact on transportation rates for natural gas or market prices of natural
gas.
The future interpretation and application by FERC of these rules and
its broad authority, or of the state and local regulations by the relevant
agencies, could affect the terms and availability of transportation
services for transportation of natural gas to customers and the prices at
which natural gas can be sold by the Company.
Additional proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by
the FERC and Congress will continue. Sales of petroleum liquids by the
Company are not currently regulated and are made at market prices; however,
the FERC is considering a proposal that could increase transportation rates
for petroleum liquids. A number of legislative proposals have also been
introduced in Congress and the state legislatures of various states, that,
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.
Item 3. Legal Proceeding
- -------------------------
The Company is a party to a settlement agreement dated January 31,
1991 with a natural gas purchaser which superseded a settlement agreement
entered into during March of 1988. Under the agreements the purchaser made
certain prepayments to the Company for natural gas to be delivered to the
purchaser in the future. As of December 31, 1994, this prepayment balance
for natural gas yet to be delivered was $3.7 million. The Company has
learned that the Oklahoma Tax Commission (the "Commission"), based on four
assessments, one in 1988, one in 1992 and two in 1994, is seeking to hold
the purchaser liable for certain taxes, interests and penalties that the
Commission contends are due and owing with respect to the prepayment
amounts made by the purchaser under the agreements on the grounds that the
prepayments are solely attributable to the settlement of past claims for
take-or-pay obligations. To date, the Company is not a party to the
Commission's proceedings, but may in the future, seek to intervene in these
proceedings. The purchaser has denied the claims made by the Commission
and is contesting the assessments. The purchaser and the Commission have
settled the 1988 assessment for approximately $51,000 and the remaining
three assessments have been consolidated and set for a hearing before an
administrative law judge on or before May 10, 1995. The purchaser has
notified the Company of the proceedings and has indicated its intention to
assert claims against the Company to recover the amount it paid in
settlement of the 1988 assessment (including its attorney fees) as well as
any amounts it might have to pay by virtue of the remaining assessments.
The Company is aware that the purchaser has made such claims against other
companies which also received prepayments from the purchaser, although the
type of agreements and the facts involved in those cases are not known by
the Company. At this time, the Company is unable to determine what the
outcome of the remaining Commission's proceedings will be, the amount of
taxes, if any, plus interest and penalties that may ultimately be assessed
against the purchaser and the claims, if any, that the purchaser might seek
to assert against the Company in the event an unfavorable result is
incurred by the purchaser. The Company has advised the purchaser that it
believes the responsibility for the payment of the taxes, interest and
15
<PAGE>
penalty sought by the Commission, should it be ultimately determined that
any such amounts are in fact owed, is the responsibility of the purchaser
and not the Company.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
should result in judgments which would have a material adverse effect on
the Company.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted to the security holders during the fourth
quarter of the Company's calendar year ended December 31, 1994.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 21, 1995, the Company had 3,512 holders of record of
its common stock. The Company has not paid any cash dividends on shares of
its common stock since its organization and currently intends to continue
its policy of retaining earnings, if any, from the Company's operations.
The Company is prohibited, by certain loan agreement provisions, from
declaring and paying dividends (other than stock dividends) during any
fiscal year in excess of 25 percent of its consolidated net income of the
preceding fiscal year. The table below reflects the high and low sales
prices per share of the Company's common stock as reported by the New York
Stock Exchange, Inc. for the period indicated:
1994 1993
QUARTER High Low High Low
------- ------ ------ ------ ------
First $3 1/2 $2 5/8 $3 1/4 $1 5/8
Second $3 1/4 $2 3/4 $4 3/8 $2 3/4
Third $3 1/2 $2 5/8 $4 3/4 $3 1/4
Fourth $3 7/8 $2 5/8 $4 3/4 $2 5/8
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Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
1994 1993 1992 1991 1990
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $87,958 $70,941 $55,827 $69,652 $61,904
======= ======= ======= ======= =======
Income Before
Income Taxes $ 4,814 $ 3,892 $ 1,102(1)$ 4,436 $ 830
======= ======= ======= ======= =======
Net Income $ 4,794 $ 3,871 $ 1,087(1)$ 4,341 $ 830
======= ======= ======= ======= =======
Net Income Per
Common Share $.23 $.19 $.05(1) $.21 $.04
==== ==== ==== ==== ====
Total Assets $112,421 $95,762 $88,710 $92,086 $86,286
======== ======= ======= ======= =======
Long-Term Debt $ 37,824 $25,919 $22,298 $23,153 $19,929
======== ======= ======= ======= =======
Long-Term Portion
of Natural Gas
Purchaser Prepayments $ 2,149 $ 4,417 $ 5,924 $ 7,626 $ 9,481
======== ======= ======= ======= =======
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
======== ======= ======= ======= =======
___________
(1) Includes a $1.5 million provision for litigation
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1994, 1993 and 1992 activity.
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------------------------------------------------------------------------
Results of Operations
- ---------------------
Financial Condition and Liquidity
On December 12, 1994, the Company amended its credit agreement (as
amended the "Agreement"), in part to provide funds for the December 15,
1994 closing of a producing oil and natural gas property acquisition from
two subsidiaries of Patrick Petroleum Company (collectively "Patrick").
The acquisition consisted of producing properties, located in Alabama,
Louisiana, Mississippi, New Mexico, Oklahoma and Texas and related accounts
receivable and certain related assumed liabilities for a net cost of $13.2
million. The Agreement provides for a total commitment of $50 million,
consisting of a revolving credit facility through January 1, 1997 and a
term loan thereafter, maturing on January 1, 2001. Borrowings under the
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<PAGE>
revolving credit facility are limited to a borrowing base which is subject
to a semi-annual redetermination. The latest borrowing base determination
indicated $42 million of the commitment is available to the Company.
Certain covenants of the Agreement were also amended. The Company must
maintain consolidated net worth of at least $45 million, a modified current
ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the
Agreement, to consolidated tangible net worth not greater than 1 to 1 and a
ratio of total liabilities, as defined in the Agreement, to consolidated
tangible net worth not greater than 1.25 to 1. In addition, working
capital provided by operations, as defined in the Agreement, cannot be less
than $13 million in any year. At December 31, 1994, borrowings under the
Agreement totalled $37.3 million. At February 21, 1995, borrowings under
the Agreement totalled $37.0 million with $2.7 million available for future
borrowings. The interest rate on the bank debt was 8.5 and 9 percent at
December 31, 1994 and February 21, 1995, respectively. A commitment fee of
1/2 of 1 percent is charged for any unused portion of the borrowing base.
Shareholders' equity at December 31, 1994 was $52.6 million, making
the Company's ratio of long-term debt-to-equity .72 to 1. The Company's
primary source of liquidity and capital resources in the near- and long-term
will consist of cash flow from operating activities and available
borrowings under the Company's Agreement. Net cash provided by operating
activities in 1994 was $13.2 million as compared to $9.9 million in 1993.
The Company's capital expenditures during 1994 were $27 million. The
majority of the capital expenditures, $25.1 million, were made in the
Company's oil and natural gas operations with $11.5 million and $13.1
million used for exploration and development drilling and producing
property acquisitions, respectively. Capital expenditures made by the
Company's contract drilling operations were approximately $1.1 million in
1994 and principally consisted of improvements to large rig components
which benefit current and future years. The Company's rigs are composed of
large components some of which, on a rotational basis, are required to be
overhauled to assure proper performance. Such capital expenditures will
continue in future years. Additional expenditures may be required in 1995
for drill pipe as certain grades of the Company's drill pipe are reaching
the end of their useful life.
Late in December 1994, Unit agreed to acquire producing oil and
natural gas properties for a purchase price of $2,125,000. This
acquisition has an effective date of January 1, 1995 and includes ten
natural gas wells located in Lipscomb County, Texas.
During the first half of 1995, the Company plans to pay down a portion
of its long-term debt while continuing its developmental drilling on a
limited basis. The Company's capital expenditures are discretionary and
directed toward increasing reserves and future growth. Current operations
should not be adversely affected by any inability to obtain funds outside
of the Company's current loan agreement. The decision to acquire or drill
on oil and natural gas properties at any given time depends on market
conditions, potential return on investment, future drilling potential and
the availability of opportunities to obtain financing given the
circumstances involved, thus providing the Company with a large degree of
18
<PAGE>
flexibility in incurring such costs. Depending, in part, on commodity
pricing, the Company plans to spend approximately $16 million on its
capital expenditure program in 1995.
The Company has 2.873 million warrants outstanding. The warrants
entitle the holders to purchase one share of common stock at a price of
$4.375 per share. The warrants, subject to certain restrictions, are
callable by the Company, in whole or in part, at $.50 per warrant. A
Second Amendment to the Warrant Agreement between the Company and the
Warrant Agent, dated May 9, 1994, extended the term of the warrants to
August 30, 1996.
The Company continued to receive monthly payments on behalf of itself
and other parties (collectively the "Committed Interest") from a natural
gas purchaser pursuant to a settlement agreement (the "Settlement
Agreement"). As a result of the Settlement Agreement, the December 31,
1994 prepayment balance of $3.7 million paid by the purchaser for natural
gas not taken (the "Prepayment Balance") is subject to recoupment in
volumes of natural gas through a period ending on the earlier of recoupment
or December 31, 1997 (the "Recoupment Period"). Additionally, the purchaser
is obligated to make monthly payments on behalf of the Committed Interest
based on their share of the natural gas deliverability of the wells subject
to the Settlement Agreement, up to a maximum of $211,000 or a minimum of
$110,000 per month for the year 1995. Both the maximum and minimum monthly
payments decline annually through the Recoupment Period. If natural gas is
taken during a month, the value of such natural gas is credited toward the
monthly amount the purchaser is required to pay. In the event the
purchaser takes volumes of natural gas valued in excess of its monthly
payment obligations, the value taken in excess is applied to reduce any
then outstanding Prepayment Balance. The Company currently believes that
sufficient natural gas deliverability is available to enable the Committed
Interest to receive substantially all of the maximum monthly payments
during 1995. At the end of the Recoupment Period, the Settlement Agreement
and the natural gas purchase contracts which are subject to the Settlement
Agreement will terminate. If the Prepayment Balance is not fully recouped
in natural gas by December 31, 1997 then the unrecouped portion is subject
to cash repayment, limited to a maximum of $3 million, payable in equal
annual installments over a five year period. Under the Settlement
Agreement, the purchaser is entitled to make a monthly determination of the
volumes to be purchased from the wells subject to the Settlement Agreement.
During 1993, the Company, in accordance with the terms of the Settlement
Agreement, elected to deliver natural gas at approximately 80 percent of
the deliverability of the wells subject to the Settlement Agreement.
During 1994 natural gas delivered was again reduced to approximately 75
percent of the deliverability of the wells subject to the Settlement
Agreement. However, because these month-to-month determinations, up to
certain maximum levels, are made by the purchaser, the Company is unable to
predict with certainty future natural gas sales from these wells. In
addition, future revenues to be received by the Company would be impacted
by the failure of the purchaser to meet its obligations, financially or
otherwise, under the terms of the Settlement Agreement or by the ability of
the wells to maintain certain projected deliverability requirements. In
the event the wells are unable to maintain such deliverability, the monthly
19
<PAGE>
payments to be received by the Company under the Settlement Agreement would
be decreased. The price per Mcf under the Settlement Agreement is
substantially higher than current spot market prices. The impact of the
higher price received under the Settlement Agreement increased pre-tax
income by approximately $1.8, $1.9 and $2.8 million in 1994, 1993 and 1992,
respectively.
Oil prices received by the Company in 1994 ranged from an average of
$12.53 in February to $17.78 in July and averaged $15.73 in December. The
Company's average price for oil received in 1994 was $15.13. Average
natural gas prices received by the Company have gradually declined since
the first quarter of 1994, and December's average price of $1.52 per Mcf
was 32 percent less than the average natural gas price of $2.24 received by
the Company in March 1994. Oil prices received early in the first quarter
of 1995 were 3 percent higher than average prices received by the Company
at December 31, 1994 while spot prices for natural gas dropped 17 percent
from the December 31, 1994 price. Oil prices within the industry remain
largely dependent upon world market developments for crude oil. Prices for
natural gas are influenced by weather conditions and supply imbalances,
particularly in the domestic market, and by world wide oil price levels.
The large drop in spot market natural gas prices had a significant adverse
effect on the value of the Company's reserves at year end 1994 and could
cause the Company to reduce the carrying value of its oil and natural gas
properties in 1995 (see Note 12 of Notes to Consolidated Financial
Statements). Likewise, declines in natural gas or oil prices could
adversely effect the semi-annual borrowing base determination under the
Company's current credit agreement since this determination is, for the
most part, calculated on the value of the Company's oil and natural gas
reserves.
The Company's ability to utilize its full complement of drilling rigs,
should economic conditions improve in the future, will be restricted due to
the lack of qualified labor and certain supporting equipment not only
within the Company but in the industry as a whole. The Company's ability
to utilize its drilling rigs at any given time is dependent on a number of
factors, including but not limited to, the price of both oil and natural
gas, the availability of labor and the Company's ability to supply the type
of equipment required. The Company's management expects that these factors
will continue to influence the Company's rig utilization during 1995.
In the third quarter of 1994, the Company's Board of Directors
authorized the Company to purchase up to 1,000,000 shares of the Company's
outstanding common stock on the open market. At December 31, 1994 25,100
shares had been repurchased at prices ranging from $2 5/8 to $3 3/8 per
share.
The Company's wholly owned natural gas marketing subsidiary, Mountain
Front Pipeline Company, while achieving substantial growth in revenues in
recent years, has not achieved the size necessary to reach desired levels
of profitability. Consequently, the Company is currently negotiating to
effect a business combination between Mountain Front Pipeline Company's
marketing operations and a third party. The combination, if completed,
would leave the Company with a minority interest in the resulting larger
20
<PAGE>
entity. Such a combination would not adversely affect the operations of
the Company's drilling and oil and natural gas exploration segments or the
profitability of the Company as a whole, although it would result in a
significant reduction in the Company's total revenues and associated costs.
Effects of Inflation
The effects of inflation on the Company's current operations have been
minimal due to low inflation rates. However, the impact of inflation on
the Company in the future will depend on the relative increase, if any, the
Company may realize in its rig rates and the selling price of its oil and
natural gas. If industry activity increases substantially, shortages in
support equipment such as drill pipe, third party services and qualified
labor would occur resulting in corresponding increases in material and
labor costs. These market conditions may limit the Company's ability to
realize improvements in operating profits.
Results of Operations
1994 versus 1993
- ----------------
Net income for 1994 was $4,794,000, compared with $3,871,000 in 1993.
The increase in net income was achieved through improved operating results
in the Company's contract drilling and natural gas marketing operations and
also from a net gain of $742,000 recognized in conjunction with the sale of
one of the Company's gas gathering systems. Total revenues were
$87,958,000 in 1994 and $70,941,000 in 1993.
Oil and natural gas revenues increased 8 percent due to a 29 percent
increase in natural gas production and a 2 percent increase in oil
production between 1994 and 1993. Average natural gas and oil prices
received by the Company both decreased 10 percent and partially offset the
increases in production. Average natural gas prices received by the
Company declined due to a 14 percent reduction in average spot market
prices received by the Company coupled with a 14 percent reduction in
volumes produced from certain wells included under a settlement agreement
which contains provisions for prices which are higher than current spot
market prices. Approximately 92 percent of the Company's natural gas
production was sold under spot market prices in 1994 as compared with 88
percent in 1993.
In 1994, revenues from contract drilling operations increased by 16
percent as average rig utilization increased from 8 rigs in 1993 to 9.5
rigs in 1994. Daywork revenues represented 58 percent of total drilling
revenues in 1994 as opposed to 47 percent in 1993. Turnkey and footage
contracts typically provide for higher revenues since a greater portion of
the expense of drilling the well is born by the drilling contractor.
In July 1994, the Company moved one of its rigs under a multi-well
contract to the South Texas Basin creating a new operating region for the
Company to market its drilling services. In November, the Company moved a
21
<PAGE>
second rig under contract into the region and a third rig was moved under
contract in February 1995.
The Company's marketing and natural gas processing revenues increased
38 percent as the marketing operation moved 53 percent higher volumes in
1994 while experiencing a 15 percent decrease in prices.
Operating margins (revenues less operating costs) were either slightly
improved or unchanged for all segments on the Company's operations when
comparing 1994 with 1993. Operating margins for the Company's oil and
natural gas operations were unchanged due primarily to increased production
offset by the decrease in average prices received for natural gas. Total
operating costs from oil and natural gas operations increased 9 percent as
the Company increased production from reserves added primarily through
development drilling in 1993 and 1994.
Operating margins for contract drilling improved from 10 percent in
1993 to 12 percent in 1994. Increased rig utilization helped provide
greater revenue in relation to fixed costs. Total operating costs for
contract drilling were up 12 percent in 1994 versus 1993 due to the
increased utilization.
Natural gas marketing and processing operating margins improved from a
negative 1 percent in 1993 to a positive 1 percent in 1994. Increased
volumes marketed in 1994 helped to improve the Company's ability to cover
its fixed overhead. Total natural gas marketing and processing expense
increased 36 percent due to increased volumes marketed between the
comparative periods.
Contract drilling depreciation increased 19 percent in response to
increased rig utilization. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 18 percent as the
Company increased its equivalent barrels of production by 22 percent. The
Company's average DD&A rate per equivalent barrel dropped from $4.13 in
1993 to $4.08 in 1994.
General and administrative expense increased 8 percent as certain
employee and reporting costs increased between the comparative years. This
increase is expected to continue in 1995 as the Company continues to expand
its area of operation. Interest expense increased 25 percent as the
average interest rate on the Company's outstanding bank debt increased from
6 percent in 1993 to 7.15 percent in 1994. Outstanding bank debt was $12.4
million higher at December 31, 1994 when compared with December 31, 1993
due to the financing of the December 15, 1994 Patrick acquisition
previously discussed.
1993 versus 1992
- ----------------
Net income for 1993 was $3,871,000, compared with $1,087,000 in 1992.
The increase in 1993 resulted primarily from improved operating results
associated with the contract drilling segment. Additionally net income for
22
<PAGE>
1992 was negatively impacted by a $1.5 million provision for certain
litigation.
Total revenues were $70,941,000 in 1993 and $55,827,000 in 1992. Oil
and natural gas revenues increased 3 percent due to a 10 percent increase
in natural gas production and a 6 percent increase in oil production
between 1993 and 1992. Average natural gas and oil prices received by the
Company decreased 4 and 14 percent, respectively, and partially offset the
increases in production. Although spot market natural gas prices
increased, the Company's natural gas price was negatively impacted by a 26
percent reduction in volumes produced from certain wells included under a
settlement agreement which contains provisions for prices which are higher
than current spot market prices. Approximately 88 percent of the Company's
natural gas production was sold under spot market prices in 1993 as
compared with 83 percent in 1992.
Higher spot market natural gas prices had a positive effect on the
Company's contract drilling operations. Revenues from contract drilling
operations increased 51 percent as utilization went from 21 percent in 1992
to 31 percent in 1993. Rising spot market natural gas prices encouraged
domestic operators to increase their focus on drilling new wells as opposed
to acquiring producing properties as in previous years. To a lesser
extent, the increase in drilling revenues resulted from higher rates per
day for daywork drilling and a greater portion of the Company's contract
drilling being performed under turnkey and footage contracts. Turnkey and
footage contracts typically provide for higher revenues since a greater
portion of the expense of drilling the well is born by the drilling
contractor. Daywork revenues represented 47 percent of total drilling
revenues in 1993 as opposed to 51 percent in 1992.
The Company's marketing and natural gas processing revenues increased
46 percent as the marketing operations began moving higher volumes in 1993
after experiencing reduced volumes in 1992 which were associated with the
change in focus of its marketing activity toward an end user market. The
Company had previously marketed its natural gas primarily to broker and
commodity markets.
Increased revenues were complemented by improved operating margins
(revenues less operating costs) in 1993 versus 1992 from both contract
drilling and natural gas marketing and processing. Operating margins for
the Company's oil and natural gas operations declined from 68 percent to 66
percent due primarily to the decrease in average prices received for oil
and natural gas. Total operating costs from oil and natural gas operations
increased 7 percent as the Company increased production from reserves added
primarily through developmental drilling in 1993 and from producing
property acquisitions in 1992.
Operating margins for contract drilling showed significant improvement
as they moved from a negative 2 percent in 1992 to a positive 10 percent in
1993. This increase was a result of a reduction in fixed overhead expense
made by the Company during the last six months of 1992, reduced worker's
compensation expense and increased rig utilization and dayrates which
provided greater revenue to cover fixed costs. Total operating costs for
23
<PAGE>
contract drilling were up 34 percent in 1993 versus 1992 due to the
increased utilization.
Natural gas marketing and processing operating margins improved from a
negative 3 percent in 1992 to a negative 1 percent in 1993. Increased
volumes marketed in 1993 helped to improve the Company's ability to cover
its fixed overhead. Total natural gas marketing and processing expense
increased 43 percent due to the increased volumes marketed between the
comparative periods.
Contract drilling depreciation increased 33 percent in response to
increased rig utilization and a $160,000 write down in value of components
previously utilized on one of the Company's rigs which was retired at
December 31, 1993. Depreciation, depletion and amortization ("DD&A") of
oil and natural gas properties decreased 2 percent as the Company's average
DD&A rate per equivalent barrel dropped from $4.67 per equivalent barrel in
1992 to $4.13 per equivalent barrel in 1993. The effect of the decreased
rate was partially offset by increased production volumes between the
comparative periods.
General and administrative expense increased 6 percent, primarily due
to increased payroll, employee benefits and office related expenses.
Interest expense decreased 19 percent as interest rates remained stable and
the Company's average debt outstanding for the year of 1993 remained below
the average debt outstanding in 1992.
24
<PAGE>
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
ASSETS 1994 1993
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 2,749 $ 3,756
Short-term investments - 41
Accounts receivable (less allowance for
doubtful accounts of $289 and $411) 16,369 14,099
Materials and supplies 1,498 1,424
Prepaid expenses and other 1,222 736
--------- ---------
Total current assets 21,838 20,056
--------- ---------
Property and Equipment:
Drilling equipment 75,746 75,528
Oil and natural gas properties, on the full
cost method 157,393 132,704
Transportation equipment 3,341 2,851
Other 7,925 8,541
--------- ---------
244,405 219,624
Less accumulated depreciation, depletion,
amortization and impairment 153,862 144,099
--------- ---------
Net property and equipment 90,543 75,525
--------- ---------
Other Assets 40 181
--------- ---------
Total Assets $112,421 $ 95,762
========= =========
The accompanying notes are an integral part of the
consolidated financial statements
25
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY 1994 1993
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term debt $ 496 $ 481
Current portion of natural gas
purchaser prepayments (Note 4) 1,580 1,170
Accounts payable 14,593 14,008
Accrued liabilities 3,014 1,983
Contract advances 158 10
---------- ----------
Total current liabilities 19,841 17,652
---------- ----------
Natural Gas Purchaser Prepayments (Note 4) 2,149 4,417
---------- ----------
Long-Term Debt 37,824 25,919
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value, 5,000,000
shares authorized, none issued - -
Common stock, $.20 par value, 40,000,000
shares authorized, 20,910,190 and
20,861,505 shares issued, respectively 4,182 4,172
Capital in excess of par value 50,086 49,977
Accumulated deficit (1,581) (6,375)
Treasury stock, at cost (25,100 shares) (80) -
---------- ----------
Total shareholders' equity 52,607 47,774
---------- ----------
Total Liabilities and Shareholders' Equity $ 112,421 $ 95,762
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
26
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
1994 1993 1992
-------- -------- --------
(In thousands except per share amounts)
Revenues:
Contract drilling $16,952 $14,676 $ 9,732
Oil and natural gas 26,001 24,073 23,464
Natural gas marketing
and processing 44,171 32,104 21,970
Other 834 88 661
-------- -------- --------
Total revenues 87,958 70,941 55,827
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 14,909 13,269 9,901
Depreciation and impairment 2,030 1,713 1,284
Oil and natural gas:
Operating costs 8,799 8,098 7,538
Depreciation, depletion
and amortization 8,281 7,018 7,128
Natural gas marketing
and processing 43,897 32,325 22,627
General and administrative 3,574 3,302 3,114
Interest 1,654 1,324 1,633
Provision for litigation - - 1,500
-------- -------- --------
Total expenses 83,144 67,049 54,725
-------- -------- --------
Income Before Income Taxes 4,814 3,892 1,102
Income Tax Expense 20 21 15
-------- -------- --------
Net Income $ 4,794 $ 3,871 $ 1,087
======== ======== ========
Net Income Per Common Share $ .23 $ .19 $ .05
======== ======== ========
Weighted Average Shares Outstanding 20,900 20,860 20,781
(Both Primary and Fully Diluted) ======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
27
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1992, 1993 and 1994
Capital
In Excess Treasury
Common Of Par Accumulated
Stock Value Deficit Stock Total
-------- -------- --------- -------- --------
(In thousands)
Balances,
January 1, 1992 $ 4,143 $49,733 $(11,333) $ - $42,543
Net income - - 1,087 - 1,087
Activity in employee
compensation plans
(67,755 shares) 14 108 - - 122
-------- -------- --------- -------- --------
Balances,
December 31, 1992 4,157 49,841 (10,246) - 43,752
Net income - - 3,871 - 3,871
Activity in employee
compensation plans
(78,706 shares) 15 136 - - 151
-------- -------- --------- -------- --------
Balances,
December 31, 1993 4,172 49,977 (6,375) - 47,774
Net income - - 4,794 - 4,794
Activity in employee
compensation plans
(48,685 shares) 10 109 - - 119
Purchase of treasury
stock (25,100
shares) - - - (80) (80)
-------- -------- --------- -------- --------
Balances,
December 31, 1994 $ 4,182 $50,086 $ (1,581) $ (80) $52,607
======== ======== ========= ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
28
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1994 1993 1992
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 4,794 $ 3,871 $ 1,087
Adjustments to reconcile net income
to net cash provided by
operating activities:
Depreciation, depletion,
amortization and impairment 10,774 9,256 8,772
Gain on disposition of assets (813) (49) (463)
Employee stock compensation plans 119 151 122
Bad debt expense - - 200
Provision for litigation - - 1,500
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (939) (1,257) 2,493
Materials and supplies (74) (99) 121
Prepaid expenses and other (486) 83 191
Accounts payable 735 634 (747)
Accrued liabilities 760 (947) (151)
Contract advances 148 8 (876)
Natural gas purchaser prepayments (1,858) (1,743) (2,319)
-------- -------- --------
Net cash provided
by operating activities 13,160 9,908 9,930
-------- -------- --------
The accompanying notes are an integral part of the
consolidated financial statements
29
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
1994 1993 1992
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions) $(28,227) $(11,946) $(10,768)
Proceeds from disposition of assets 2,038 709 1,146
Decrease in short-term investments 41 664 170
(Acquisition) disposition
of other assets 141 (45) 60
--------- --------- ---------
Net cash used in
investing activities (26,007) (10,618) (9,392)
Cash Flows From Financing Activities:
Borrowings under line of credit 63,700 43,400 23,900
Payments under line of credit (51,300) (40,600) (24,700)
Proceeds from notes payable
and other long-term debt - 911 710
Payments on notes payable and
other long-term debt (480) (367) (80)
Acquisition of treasury stock (80) - -
--------- --------- ---------
Net cash provided by
(used in) financing
activities 11,840 3,344 (170)
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents (1,007) 2,634 368
Cash and Cash Equivalents,
Beginning of Year 3,756 1,122 754
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 2,749 $ 3,756 $ 1,122
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 1,548 $ 1,326 $ 1,673
Income taxes $ 2 $ 2 $ 63
The accompanying notes are an integral part of the
consolidated financial statements
30
<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.
Drilling Contracts
The Company accounts for "footage" and "turnkey" drilling contracts,
in which the Company assumes the risks associated with drilling the well,
under the completed-contract method and for "daywork" drilling contracts
under the percentage-of-completion method. The entire amount of the loss,
if any, is recorded when the loss is determinable.
The costs of uncompleted drilling contracts include expenses incurred
to date on "footage" or "turnkey" drilling contracts which are still in
process.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and
all investments with original maturities at date of purchase of three
months or less which are readily convertible into known amounts of cash.
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated
useful lives, including a minimum provision of 20 percent of the active
rate when the equipment is idle. At December 31, 1993, one of the
Company's rigs was retired and certain components of the rig were written
down by $160,000 to their estimated market value. The Company uses the
composite method of depreciation for drill pipe and collars and calculates
the depreciation by footage actually drilled compared to total estimated
remaining footage. Depreciation of other property and equipment is comput-
ed using the straight-line method over the estimated useful lives of the
assets ranging from 3 to 15 years.
When property and equipment components are disposed of, the cost and
the related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For dispo-
31
<PAGE>
sitions of drill pipe and drill collars, an average cost for the
appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and
development activities on the full cost method of accounting prescribed by
the Securities and Exchange Commission ("SEC"). Accordingly, all produc-
tive and non-productive costs incurred in connection with the acquisition,
exploration and development of oil and natural gas reserves are capitalized
and amortized on a composite units-of-production method based on proved oil
and natural gas reserves. The Company's determination of its oil and
natural gas reserves are reviewed annually by independent petroleum
engineers. The average composite rates used for depreciation, depletion and
amortization ("DD&A") were $4.08, $4.13 and $4.67 per equivalent barrel in
1994, 1993 and 1992, respectively. The Company's calculation of DD&A
includes estimated future expenditures to be incurred in developing proved
reserves and estimated dismantlement and abandonment costs, net of
estimated salvage values. In the event the unamortized cost of oil and
natural gas properties being amortized exceeds the full cost ceiling, as
defined by the SEC, the excess is charged to expense in the period during
which such excess occurs.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties
in which the Company has an interest or on properties in which a part-
nership, of which the Company is a general partner, has an interest.
Accordingly, in 1994 the Company recorded $14,000 of contract drilling
profits as a reduction of the carrying value of its oil and natural gas
properties rather than including these profits in current operations. No
contract drilling profits were realized on such interests in 1993 and 1992.
Limited Partnerships
The Company, through its wholly owned subsidiary, Unit Petroleum
Company, is a general partner in eleven oil and natural gas limited part-
nerships sold privately and publicly. Certain of the Company's officers
and directors own interests in some of these partnerships. Their interests
were acquired generally on the same basis as other outside investors.
Prior to December 31, 1993, the Company also was general partner of seven
additional employee limited partnerships. However, pursuant to the terms
of an agreement and plan of merger, these seven limited partnerships were
consolidated into one new employee limited partnership effective December
31, 1993.
The Company shares in partnership revenues and costs in accordance
with formulas prescribed in each limited partnership agreement. The
32
<PAGE>
partnerships also reimburse the Company for certain administrative costs
incurred on behalf of the partnerships.
Income Taxes
Income taxes are accounted for in accordance with Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes". SFAS No. 109 requires the measurement of deferred tax assets for
deductible temporary differences and operating loss carryforwards, and of
deferred tax liabilities for taxable temporary differences. Measurement of
current and deferred tax liabilities and assets is based on provisions of
enacted tax law; the effects of future changes in tax laws or rates are not
included in the measurement. Deferred tax assets primarily result from net
operating loss carryforwards, and deferred tax liabilities result from the
recognition of depreciation, depletion and amortization in different
periods for financial reporting and tax purposes. Valuation allowances are
established where necessary to reduce deferred tax assets to the amount
expected to be realized. Income tax expense is the tax payable for the
year and the change during that year in deferred tax assets and
liabilities.
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales.
This method allows for recognition of revenue which may be more or less
than the Company's share of pro-rata production from certain wells. Based
upon the Company's 1994 average spot market natural gas price of $1.65 per
Mcf, the Company estimates its balancing position to be approximately $5.5
million on under-produced properties and approximately $3.1 million on
over-produced properties.
The Company's policy is to expense its pro-rata share of lease oper-
ating costs from all wells as incurred. Such expenses relating to the
Company's balancing position on wells on which the Company has imbalances
are not material.
Financial Instruments and Concentrations of Credit Risk
At December 31, 1994, the Company had natural gas price swaps, related
to its marketing of natural gas, which qualify as hedges of the Company's
future purchase and sales commitments. Gains or losses on these swaps are
recognized in the consolidated statement of operations and included in
operating cash flows in the same period as the associated sale of natural
gas occurs. At December 31, 1994, the Company had price swap agreements
for 380,000 Mcf totaling $525,000 related to purchase commitments and
358,000 Mcf totaling $694,000 related to sales commitments for the period
of January through March of 1995.
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
credit risk is considered by management to be limited due to the large
33
<PAGE>
number of customers comprising the Company's customer base. The Company
had one customer in its natural gas marketing operation at December 31,
1993, with an accounts receivable balance of $4.1 million which was
subsequently paid in January 1994. In addition, at December 31, 1994 and
1993, the Company had a concentration of cash of $2.3 and $3.4 million,
respectively, with one bank.
RECLASSIFICATIONS
Certain reclassifications have been made in the 1992 and 1993
consolidated financial statements to conform them to classifications used
in 1994.
NOTE 2 - PRODUCING PROPERTY ACQUISITION
- ---------------------------------------
On December 15, 1994, Unit Petroleum Company, a wholly owned
subsidiary of Unit Corporation, acquired interests in approximately 700 oil
and natural gas wells located primarily in Oklahoma, Texas, New Mexico and
Louisiana. Financing for the transaction was provided under the Company's
bank credit agreement. The acquisition is summarized as follows:
Current assets net of current liabilities $ 976,000
Producing oil and natural gas properties 12,261,000
-----------
Net assets acquired $13,237,000
===========
Unaudited summary pro forma results of operations for the Company,
reflecting the above described acquisition as if it had occurred at the
beginning of the years ended December 31, 1994 and December 31, 1993, are
as follows, respectively; revenues, $94,373,000 and $79,807,000; net
income, $5,068,000 and $7,259,000; and net income per common share, $.24
and $.35. The pro forma results of operations are not necessarily
indicative of the actual results of operations that would have occurred had
the purchase actually been made at the beginning of the respective periods
nor of the results which may occur in the future.
NOTE 3 - WARRANTS
- -----------------
In 1987, the Company issued 2.873 million units, consisting of three
shares of the Company's common stock and one warrant, at a price of $10.375
per unit. Each warrant entitles the holder to purchase one share of the
Company's common stock at a price of $4.375 anytime prior to the warrant's
expiration on August 30, 1996. The warrants, subject to certain
restrictions, are callable by the Company, in whole or in part, at $.50 per
warrant. As of December 31, 1994 no warrants have been exercised.
34
<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, the Company has a prepayment balance of $3.7 million at
December 31, 1994 representing proceeds received from the purchaser as
prepayment for natural gas. This amount is net of natural gas recouped and
net of certain amounts disbursed to other owners (such owners, collectively
with the Company are referred to as the "Committed Interest") for their
proportionate share of the prepayments. The December 31, 1994 prepayment
balance is subject to recoupment in volumes of natural gas for a period
ending the earlier of recoupment or December 31, 1997 (the "Recoupment
Period"). Additionally, the purchaser is obligated to make monthly
payments on behalf of the Committed Interest in an amount calculated as a
percentage of the Committed Interest's share of the deliverability of the
wells subject to the settlement agreement, up to a maximum of $211,000 or a
minimum of $110,000 per month for the year 1995. Both the maximum and
minimum monthly payments decline annually through the Recoupment Period.
At December 31, 1997, the Committed Interest's prepayment balance, if any,
that has not been fully recouped in natural gas is subject to a cash
repayment limited to a maximum of $3 million to be made in equal payments
over a five year period. The prepayment amounts subject to recoupment from
future production by the purchaser are being recorded as liabilities and
are reflected in revenues as recoupment occurs. The portion of the prepay-
ments that are estimated to be recouped in the next twelve months has been
included in current liabilities. At the end of the Recoupment Period, the
terms of the settlement agreement and the natural gas purchase contracts
which are subject to the settlement agreement will terminate.
NOTE 5 - LONG-TERM DEBT
- ------------------------
Long-term debt consisted of the following as of December 31, 1994 and
1993:
1994 1993
--------- ---------
Revolving credit and term loan, (In thousands)
with interest at December 31,
1994 and 1993 of 8.5%
and 6%, respectively $ 37,300 $ 24,900
Other 1,020 1,500
--------- ---------
38,320 26,400
Less current portion 496 481
--------- ---------
Total long-term debt $ 37,824 $ 25,919
========= =========
35
<PAGE>
At December 31, 1994, the Company's credit agreement ("Agreement")
provided for a total loan commitment of $50 million consisting of a revolv-
ing credit facility through January 1, 1997 and a term loan thereafter,
maturing on January 1, 2001. Borrowings under the Agreement are limited to
a semi-annual borrowing base computation which as of December 31, 1994 is
$42 million.
The principal of the revolving credit facility is due in 48 equal
monthly payments commencing February 1, 1997 and continuing on the first
day of each month thereafter through maturity. The outstanding principal
amount of the revolving credit facility which is less than or equal to the
loan value of the mineral interest then in effect shall bear interest at
the Chase Manhattan Bank, N.A. prime rate ("Prime Rate") and that portion
of the outstanding balance exceeding such loan value shall bear interest at
the Prime Rate plus 1 and 1/2 percent through January 1, 1997. Subsequent to
January 1, 1997 and continuing through January 1, 2001, the portion of the
outstanding amount under the Agreement which is less than or equal to the
loan value of the mineral interests then in effect shall bear interest at
the Prime Rate plus 1/4 of 1 percent and any portion of the outstanding
principal balance exceeding such loan value shall bear interest equal to
the Prime Rate plus 1 and 1/2 percent. The Agreement also provides for a
commitment fee of 1/2 of 1 percent of the unused portion of the borrowing
base. Virtually all of the Company's drilling rigs are collateral for such
indebtedness and the balance of the Company's assets are subject to a
negative pledge.
The Agreement includes prohibitions against (i) the payment of divi-
dends (other than stock dividends) during any fiscal year in excess of 25
percent of the consolidated net income of the Company during the preceding
fiscal year, (ii) the incurrence by the Company or any of its subsidiaries
of additional debt with certain very limited exceptions and (iii) the
creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any property of the Company or any of its
subsidiaries, except in favor of its banks. The Agreement also requires
that the Company maintain consolidated net worth of at least $45 million, a
modified current ratio of not less than 1 to 1, a ratio of long-term debt,
as defined in the Agreement, to consolidated tangible net worth not greater
than 1 to 1 and a ratio of total liabilities, as defined in the Agreement,
to consolidated tangible net worth not greater than 1.25 to 1. In
addition, working capital provided by operations, as defined in the
Agreement, cannot be less than $13 million in any year.
Estimated annual principal payments under the terms of all long-term
debt from 1995 through 1999 are $496,000, $200,000, $200,000, $8,671,000
and $9,325,000.
36
<PAGE>
NOTE 6 - INCOME TAXES
- ---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income, to the Company's effective income
tax expense is as follows:
1994 1993 1992
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 1,637 $ 1,323 $ 375
Tax benefit of net operating
loss carryforward (1,652) (1,308) (396)
Alternative minimum tax - - 2
State income tax 6 1 7
Other 29 5 27
-------- -------- --------
Income tax expense $ 20 $ 21 $ 15
======== ======== ========
Deferred tax assets and liabilities are comprised of the following at
December 31, 1994 and 1993:
1994 1993
-------- --------
Deferred tax assets: (In thousands)
Allowance for losses $ 521 $ 580
Gas purchaser prepayments - 149
Net operating loss carryforwards 18,190 18,118
Statutory depletion carryforward 2,500 2,500
Investment tax credit carryforward 3,530 3,530
-------- --------
Gross deferred tax assets 24,741 24,877
-------- --------
Deferred tax liabilities:
Depreciation, depletion and amortization 18,318 16,659
-------- --------
Gross deferred tax liabilities 18,318 16,659
-------- --------
Net deferred tax asset 6,423 8,218
Valuation allowance 6,423 8,218
-------- --------
$ - $ -
======== ========
The net deferred tax asset valuation allowance reflects that the tax
carryforwards above may not be utilized before the expiration dates as
itemized below due in part to the effects of anticipated future exploratory
and development drilling costs.
At December 31, 1994, the Company has net operating loss carryforwards
for regular tax purposes of approximately $47,868,000 and net operating
loss carryforwards for alternative minimum tax purposes of approximately
37
<PAGE>
$38,260,000 which expire in various amounts from 1999 to 2007. The Company
has investment tax credit carryforwards of approximately $3,530,000 which
expire from 1995 to 2000. In addition, a statutory depletion carryforward
of approximately $6,579,000 is available to reduce future taxable income,
subject to statutory limitations. Statutory depletion may be carried
forward indefinitely.
In 1987, the Company completed an equity offering which constituted an
ownership change as that term is used in the Internal Revenue Code. As a
result of the ownership change, the amount of taxable income in future
years which may be offset by the Company's net operating loss carryovers
prior to the ownership change is limited. Tax losses of $45,950,000 at
December 31, 1994 are not subject to these limitations. The remaining tax
net operating loss carryforward will become available for utilization by
the Company at a rate of $3,500,000 per year. Similar limitations apply to
investment tax credits.
NOTE 7 - BENEFIT AND COMPENSATION PLANS
- ---------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common
stock were authorized for issuance under the Plan. Under the terms of the
Plan, bonuses may be granted to employees in either cash or stock or a
combination thereof, and are payable in a lump sum or in annual in-
stallments subject to certain restrictions. The Company issued 38,354 and
50,788 shares under the Plan in 1993 and 1992, respectively. No shares
were issued under the Plan in 1994.
The Company has a Stock Option Plan which provides for the granting of
options for up to 1,000,000 shares of common stock to officers and
employees. The plan permits the issuance of qualified or nonqualified
stock options. Stock options granted in 1986 became exercisable at the
rate of 20 percent per year through 1990. Options granted subsequent to
1986 become exercisable at the rate of 20 percent per year one year after
being granted.
38
<PAGE>
Activity pertaining to the Stock Option Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES -----------------------------
--------- PER SHARE AGGREGATE
Outstanding at -----------------------------
January 1, 1992 752,000 $1.50 to 3.375 $1,476,995
Granted 10,000 1.875 18,750
Cancelled (10,000) 2.37 to 2.875 (26,225)
--------- -------------- ----------
Outstanding at
December 31, 1992 752,000 1.50 to 3.375 1,469,520
Granted 89,000 2.75 244,750
Exercised (12,000) 1.50 to 2.37 (19,740)
--------- -------------- -----------
Outstanding at
December 31, 1993 829,000 1.50 to 3.375 1,694,530
Granted 102,500 3.00 307,500
Exercised (16,000) 1.50 to 2.37 (24,870)
--------- -------------- -----------
Outstanding at
December 31, 1994 915,500 $1.50 to 3.375 $ 1,977,160
========= ============== ===========
Options for 676,400, 610,500 and 556,400 shares were exercisable at
prices ranging from $1.50 to $3.375 at December 31, 1994, 1993 and 1992,
respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued or delivered upon exercise of the
stock options. On the first business day following each annual meeting of
stockholders of the Company, each person who is then a member of the Board
of Directors of the Company and who is not then an employee of the Company
or any of its subsidiaries will be granted an option to purchase 2,500
shares of common stock. The option price for each stock option is the fair
market value of the common stock on the date the stock options are granted.
No stock options may be exercised during the first six months of its term
except in case of death and no stock options are exercisable after ten
years from the date of grant.
39
<PAGE>
Activity pertaining to the Directors' Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES --------------------------
------- PER SHARE AGGREGATE
1992: -------------- ---------
Granted 10,000 $ 1.75 $ 17,500
------- -------------- ---------
Outstanding at
December 31, 1992 10,000 1.75 17,500
Granted 10,000 3.75 37,500
------- -------------- ---------
Outstanding at
December 31, 1993 20,000 1.75 to 3.75 55,000
Granted 10,000 2.875 28,750
------- -------------- ---------
Outstanding at
December 31, 1994 30,000(1) $1.75 to 3.75 $ 83,750
======= ============== =========
- -------------
(1) All 30,000 options were exercisable at December 31, 1994.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in
full or on a partial basis. The Company made discretionary contributions
under the plan of 32,685, 28,352 and 16,967 shares of common stock and
recognized expense of $130,000, $162,000 and $33,000 in 1994, 1993 and
1992, respectively.
Effective March 1, 1993, the Company adopted a salary deferral plan
("Deferral Plan"). The Deferral Plan allows participants to defer the
recognition of salary for income tax purposes until actual distribution of
benefits which occurs at either termination of employment, death or certain
defined unforeseeable emergency hardships. Funds set aside in a trust to
satisfy the Company's obligation under the Deferral Plan at December 31,
1994 and 1993 totaled $108,000 and $41,000, respectively. The Company
recognizes payroll expense and records a deferred liability at the time of
deferral.
NOTE 8 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through
1994, with a subsidiary of the Company serving as General Partner. The
Partnerships were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as co-general
partner with the Company in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with the Company in most drilling operations and most producing property
40
<PAGE>
acquisitions commenced by the Company for its own account during the period
from the formation of the Partnership through December 31 of each year.
Pursuant to the terms of an agreement and plan of merger, seven limited
partnerships, in which the Company was general partner, were consolidated
into one new employee limited partnership effective December 31, 1993.
Amounts received in the following years ended December 31 from both
public and private Partnerships for which the Company is a general partner
are as follows:
1994 1993 1992
-------- -------- --------
(In thousands)
Contract drilling $ 53 $ 60 $ 38
Well supervision and other fees $ 226 $ 278 $ 277
General and administrative
expense reimbursement $ 209 $ 231 $ 294
A subsidiary of the Company paid the Partnerships, for which the
Company or a subsidiary is the general partner, $38,000, $65,000 and
$58,000 during the years ended December 31, 1994, 1993 and 1992,
respectively, for purchases of natural gas production.
During 1993 and 1992, the Company received legal services from a law
firm of which one of the Company's directors was a partner. Total payments
to the law firm during 1993 and 1992 were $164,000 and $130,000,
respectively. The Company did not receive such services from the law firm
in 1994.
During 1994, a bank owned by one of the Company's Directors became a
participant in the Company's loan agreement. The bank's total pro rata
share of the Company's line of credit is not to exceed $1.5 million.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
- --------------------------------------
The Company is currently negotiating a new operating lease agreement
to remain in its current office space until February 1, 2000. Future
minimum rental payments under the proposed terms of the lease would be
approximately $205,000, $224,000, $244,000, $246,000 and $246,000 in 1995,
1996, 1997, 1998 and 1999, respectively. Total rent expense incurred by
the Company was $210,000, $208,000 and $205,000 in 1994, 1993 and 1992,
respectively.
The Company had letters of credit totaling $835,600 outstanding at
December 31, 1994.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership agreements along with the employee oil and gas
limited partnerships require, upon the election of a limited partner, that
the Company repurchase the limited partner's interest at amounts to be
determined by appraisal in the future. Such repurchases in any one year
are limited to 20 percent of the units outstanding. The Company made
41
<PAGE>
repurchases of $38,000, $56,000 and $70,000 in 1994, 1993 and 1992,
respectively, for such limited partner's interest.
The Company is a party to a settlement agreement dated January 31,
1991 with a natural gas purchaser which superseded a settlement agreement
entered into during March of 1988. Under the agreements the purchaser made
certain prepayments to the Company for natural gas to be delivered to the
purchaser in the future. As of December 31, 1994, this prepayment balance
for natural gas yet to be delivered was $3.7 million. The Company has
learned that the Oklahoma Tax Commission (the "Commission"), based on four
assessments, one in 1988, one in 1992 and two in 1994, is seeking to hold
the purchaser liable for certain taxes, interests and penalties that the
Commission contends are due and owing with respect to the prepayment
amounts made by the purchaser under the agreements on the grounds that the
prepayments are solely attributable to the settlement of past claims for
take-or-pay obligations. To date, the Company is not a party to the
Commission's proceedings, but may in the future, seek to intervene in these
proceedings. The purchaser has denied the claims made by the Commission
and is contesting the assessments. The purchaser and the Commission have
settled the 1988 assessment for approximately $51,000 and the remaining
three assessments have been consolidated and set for a hearing before an
administrative law judge on or before May 10, 1995. The purchaser has
notified the Company of the proceedings and has indicated its intention to
assert claims against the Company to recover the amount it paid in
settlement of the 1988 assessment (including its attorney fees) as well as
any amounts it might have to pay by virtue of the remaining assessments.
The Company is aware that the purchaser has made such claims against other
companies which also received prepayments from the purchaser, although the
type of agreements and the facts involved in those cases are not known by
the Company. At this time, the Company is unable to determine what the
outcome of the remaining Commission's proceedings will be, the amount of
taxes, if any, plus interest and penalties that may ultimately be assessed
against the purchaser and the claims, if any, that the purchaser might seek
to assert against the Company in the event an unfavorable result is
incurred by the purchaser. The Company has advised the purchaser that it
believes the responsibility for the payment of the taxes, interest and
penalty sought by the Commission, should it be ultimately determined that
any such amounts are in fact owed, is the responsibility of the purchaser
and not the Company.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
should result in judgements which would have a material adverse effect on
the Company.
42
<PAGE>
NOTE 10 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
The Company operates in the United States in three industry segments
which are contract drilling, oil and natural gas exploration and production
and natural gas marketing and processing. The Company also has natural gas
production in Canada which is not significant. Selected financial
information by industry segment is as follows:
<TABLE>
<CAPTION>
Depreciation,
Depletion,
Operating Amortization
Operating Profit Total Capital and Impairment
Revenues (Loss)(1) Assets(2) Expenditures Expense
---------- -------- --------- ---------- ----------
(In thousands)
<S> <C> <C> <C> <C> <C>
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
Natural gas marketing
and processing 44,171 274 10,619 56 331
---------- -------- --------- ---------- ----------
87,124 $ 9,208 108,472 26,281 10,642
Other 834 ======== 3,949 708 132
---------- --------- ---------- ----------
Total $ 87,958 $112,421 $ 26,989 $ 10,774
========== ========= ========== ==========
Year ended December 31, 1993:
Drilling $ 14,676 $ (306) $ 15,738 $ 936 $ 1,713
Oil and natural gas 24,073 8,957 64,845 11,422 7,018
Natural gas marketing
and processing 32,104 (221) 10,099 1,049 418
---------- -------- --------- ---------- ----------
70,853 $ 8,430 90,682 13,407 9,149
Other 88 ======== 5,080 323 107
---------- --------- ---------- ----------
Total $ 70,941 $ 95,762 $ 13,730 $ 9,256
========== ========= ========== ==========
Year ended December 31, 1992:
Drilling $ 9,732 $(1,453) $ 16,382 $ 266 $ 1,284
Oil and natural gas 23,464 8,798 61,694 7,951 7,128
Natural gas marketing
and processing 21,970 (657) 7,628 541 250
---------- -------- --------- ---------- ----------
55,166 $ 6,688 85,704 8,758 8,662
Other 661 ======== 3,006 137 110
---------- --------- ---------- ----------
Total $ 55,827 $ 88,710 $ 8,895 $ 8,772
========== ========= ========== ==========
</TABLE>
- ---------------------
(1) Operating profit is total operating revenues, less operating expenses,
depreciation, depletion, amortization and impairment and does not include
non-operating revenues, general corporate expenses, interest expense,
income taxes or provision for litigation.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements and
furniture and equipment.
43
<PAGE>
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1994 and 1993 is as
follows:
Three Months Ended
-------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- ----------- ----------
(In thousands except per share amounts)
Year ended December 31, 1994:
Revenues $ 23,005 $ 19,926 $ 21,166 (2) $ 23,861
========= ========= ========= =========
Gross Profit(1) $ 2,396 $ 2,726 $ 2,090 $ 1,996
========= ========= ========= =========
Income before
income taxes $ 1,215 $ 1,430 $ 1,595 (2) $ 574
========= ========= ========= =========
Net income $ 1,211 $ 1,425 $ 1,590 (2) $ 568
========= ========= ========= =========
Net income per
common share $ .06 $ .07 $ .07 (2) $ .03
========= ========= ========= =========
Year ended December 31, 1993:
Revenues $ 15,574 $ 17,881 $ 16,935 $ 20,551
========= ========= ========= =========
Gross Profit(1) $ 2,357 $ 1,982 $ 1,920 $ 2,171
========= ========= ========= =========
Income before
income taxes $ 1,163 $ 884 $ 890 $ 955
========= ========= ========= =========
Net income $ 1,156 $ 878 $ 886 $ 951
========= ========= ========= =========
Net income per
common share $ 0.06 $ 0.04 $ 0.04 $ 0.05
========= ========= ========= =========
- -------------
(1) Gross Profit excludes other revenues, general and administrative
expense and interest expense.
(2) Includes $742,000 net gain on sale of natural gas gathering system.
44
<PAGE>
NOTE 12 - OIL AND NATURAL GAS INFORMATION (UNAUDITED)
- -----------------------------------------------------
The capitalized costs at year end and costs incurred during the year
were as follows:
USA Canada Total
--------- -------- --------
(In thousands)
1994:
Capitalized costs:
Proved properties $ 154,688 $ 455 $155,143
Unproved properties 2,250 - 2,250
--------- -------- --------
156,938 455 157,393
Less accumulated depreciation,
depletion, amortization
and impairment 81,583 368 81,951
--------- -------- --------
Net capitalized costs $ 75,355 $ 87 $ 75,422
========= ======== ========
Cost incurred:
Unproved properties $ 460 $ - $ 460
Producing properties 13,108 - 13,108
Exploration 1,825 - 1,825
Development 9,716 1 9,717
--------- -------- --------
Total costs incurred $ 25,109 $ 1 $ 25,110
========= ======== ========
1993:
Capitalized costs:
Proved properties $ 129,612 $ 454 $130,066
Unproved properties 2,638 - 2,638
--------- -------- --------
132,250 454 132,704
Less accumulated depreciation,
depletion, amortization
and impairment 73,419 314 73,733
--------- -------- --------
Net capitalized costs $ 58,831 $ 140 $ 58,971
========= ======== ========
Cost incurred:
Unproved properties $ 732 $ - $ 732
Producing properties 1,241 - 1,241
Exploration 1,359 - 1,359
Development 8,084 6 8,090
--------- -------- --------
Total costs incurred $ 11,416 $ 6 $ 11,422
========= ======== ========
45
<PAGE>
USA Canada Total
--------- -------- --------
1992: (In thousands)
Capitalized costs:
Proved properties $ 117,721 $ 448 $ 118,169
Unproved properties 3,680 - 3,680
--------- -------- --------
121,401 448 121,849
Less accumulated depreciation,
depletion, amortization
and impairment 66,544 233 66,777
--------- -------- --------
Net capitalized costs $ 54,857 $ 215 $ 55,072
========= ======== ========
Cost incurred:
Unproved properties $ 504 $ - $ 504
Producing properties 3,629 - 3,629
Exploration 900 - 900
Development 2,918 - 2,918
--------- -------- --------
Total costs incurred $ 7,951 $ - $ 7,951
========= ======== ========
The results of operations before income taxes for producing activities
are provided below. Due to the Company's utilization of net operating loss
carryforwards, income taxes are not significant and have not been included.
USA Canada Total
--------- -------- --------
(In thousands)
1994:
Revenues $ 23,964 $ 67 $24,031
Production costs 7,011 19 7,030
Depreciation, depletion
and amortization 8,165 53 8,218
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing
costs) $ 8,788 $ (5) $ 8,783
======== ======== ========
46
<PAGE>
USA Canada Total
--------- -------- --------
(In thousands)
1993:
Revenues $ 22,040 $ 67 $22,107
Production costs 6,439 15 6,454
Depreciation, depletion
and amortization 6,875 81 6,956
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing costs) $ 8,726 $ (29) $ 8,697
======== ======== ========
1992:
Revenues $21,816 $ 75 $21,891
Production costs 6,159 10 6,169
Depreciation, depletion
and amortization 6,961 94 7,055
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing costs) $ 8,696 $ (29) $ 8,667
======== ======== ========
47
<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
------- -------- ------ ----- ------- --------
1994: (In thousands)
Proved developed and
undeveloped reserves:
Beginning of year 3,304 71,379 - 861 3,304 72,240
Revision of previous
estimates (97) (571) - (14) (97) (585)
Extensions, discoveries
and other additions 601 17,426 - - 601 17,426
Purchases of minerals
in place 910 14,075 - - 910 14,075
Sales of minerals in place (4) (137) - - (4) (137)
Production (406) (9,606) - (53) (406) (9,659)
------- -------- ----- ----- ------- --------
End of Year 4,308 92,566 - 794 4,308 93,360
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year
End of year
1993:
Proved developed and
undeveloped reserves:
Beginning of year 3,308 63,761 - 931 3,308 64,692
Revision of previous
estimates (132) 4,662 - - (132) 4,662
Extensions, discoveries
and other additions 549 9,169 - - 549 9,169
Purchases of minerals
in place 18 1,369 - - 18 1,369
Sales of minerals in place (42) (147) - - (42) (147)
Production (397) (7,435) - (70) (397) (7,505)
------- -------- ----- ----- ------- --------
End of Year 3,304 71,379 - 861 3,304 72,240
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,245 58,809 - 468 3,245 59,277
End of year 3,187 65,395 - 426 3,187 65,821
48
<PAGE>
USA Canada Total
----------------- ------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------ ------ ------- --------
1992:
Proved developed and
undeveloped reserves:
Beginning of year 2,943 52,853 - 964 2,943 53,817
Revision of previous
estimates 235 7,679 - 47 235 7,726
Extensions, discoveries
and other additions 190 1,655 - - 190 1,655
Purchases of minerals
in place 316 8,327 - - 316 8,327
Sales of minerals in place (1) (23) - - (1) (23)
Production (375) (6,730) - (80) (375) (6,810)
------- -------- ----- ----- ------- --------
End of Year 3,308 63,761 - 931 3,308 64,692
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 2,778 44,936 - 499 2,278 45,435
End of year 3,245 58,809 - 468 3,245 59,277
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made
in connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's
reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog-
ical and engineering data, appear with reasonable certainty to be recov-
erable in the future from known oil and natural gas reservoirs under exist-
ing economic and operating conditions. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods. Proved undeveloped reserves are
those reserves which are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expendi-
ture is required.
Estimates of oil and natural gas reserves require extensive judgments
of reservoir engineering data as explained above. Assigning monetary
values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. Indeed the uncertainties inherent in the
disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves. The information set forth herein is therefore
subjective and, since judgments are involved, may not be comparable to
estimates submitted by other oil and natural gas producers. In addition,
since prices and costs do not remain static and no price or cost escala-
tions or de-escalations have been considered, the results are not neces-
sarily indicative of the estimated fair market value of estimated proved
reserves nor of estimated future cash flows.
49
<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
--------- -------- --------
1994: (In thousands)
Future cash flows $234,171 $ 1,255 $235,426
Future production and
development costs 105,876 311 106,187
Future income tax expenses 20,161 524 20,685
--------- -------- --------
Future net cash flows 108,134 420 108,554
10% annual discount for
estimated timing of cash flows 30,116 170 30,286
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 78,018 $ 250 $ 78,268
========= ======== =========
1993:
Future cash flows $214,800 $ 861 $215,661
Future production and
development costs 90,177 229 90,406
Future income tax expenses 17,097 244 17,341
--------- -------- --------
Future net cash flows 107,526 388 107,914
10% annual discount for
estimated timing of cash flows 34,374 157 34,531
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 73,152 $ 231 $ 73,383
======== ======== ========
1992
Future cash flows $208,964 $ 931 $209,895
Future production and
development costs 86,417 361 86,778
Future income tax expenses 19,634 194 19,828
--------- -------- --------
Future net cash flows 102,913 376 103,289
10% annual discount for
estimated timing of cash flows 32,653 120 32,773
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 70,260 $ 256 $ 70,516
======== ======== ========
50
<PAGE>
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1994:
Sales and transfers of oil and
natural gas produced,
net of production costs $(16,953) $ (48) $(17,001)
Net changes in prices and
production costs (14,941) 206 (14,735)
Revisions in quantity estimates
and changes in production timing (482) (5) (487)
Extensions, discoveries and improved
recovery, less related costs 17,050 - 17,050
Purchases of minerals in place 13,426 - 13,426
Sales of minerals in place (138) - (138)
Accretion of discount 7,915 35 7,950
Net change in income taxes (457) (177) (634)
Other - net (554) 8 (546)
--------- -------- ---------
Net change 4,866 19 4,885
Beginning of year 73,152 231 73,383
--------- -------- ---------
End of year $ 78,018 $ 250 $ 78,268
========= ======== =========
1993:
Sales and transfers of oil and
natural gas produced,
net of production costs $(15,359) $ (52) $(15,411)
Net changes in prices and
production costs (4,997) 73 (4,924)
Revisions in quantity estimates
and changes in production timing 483 (70) 413
Extensions, discoveries and improved
recovery, less related costs 12,886 - 12,886
Purchases of minerals in place 1,440 - 1,440
Sales of minerals in place (284) - (284)
Accretion of discount 7,619 36 7,655
Net change in income taxes (74) (8) (82)
Other - net 1,178 (4) 1,174
--------- -------- --------
Net change 2,892 (25) 2,867
Beginning of year 70,260 256 70,516
--------- -------- --------
End of year $ 73,152 $ 231 $ 73,383
========= ======== =========
51
<PAGE>
USA Canada Total
--------- -------- --------
(In Thousands)
1992:
Sales and transfers of oil
and natural gas produced,
net of production costs $(14,693) $ (65) $(14,758)
Net changes in prices and
production costs (1,081) (117) (1,198)
Revisions in quantity estimates
and changes in production timing 4,113 2 4,115
Extensions, discoveries and improved
recovery, less related costs 3,677 - 3,677
Purchases of minerals in place 9,488 - 9,488
Sales of minerals in place (47) - (47)
Accretion of discount 6,602 49 6,651
Net change in income taxes (2,870) 95 (2,775)
Other - net 2,104 5 2,109
--------- -------- ---------
Net change 7,293 (31) 7,262
Beginning of year 62,967 287 63,254
--------- -------- ---------
End of year $ 70,260 $ 256 $ 70,516
========= ======== =========
The Company's SMOG and changes therein were determined in accordance
with Statement of Financial Accounting Standards No. 69. Certain infor-
mation concerning the assumptions used in computing SMOG and their inherent
limitations are discussed below. Management believes such information is
essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those
reserves nor their present worth. Assigning monetary values to the reserve
quantity estimation process does not reduce the subjective and ever-changing
nature of such reserve estimates. Additional subjectivity occurs
when determining present values because the rate of producing the reserves
must be estimated. In addition to errors inherent in predicting the
future, variations from the expected production rate could result from
factors outside of management's control, such as unintentional delays in
development, environmental concerns or changes in prices or regulatory
controls. Also, the reserve valuation assumes that all reserves will be
disposed of by production. However, other factors such as the sale of
reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided
by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of
existing economic conditions.
52
<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.
Subsequent to December 31, 1994, the natural gas industry experienced
a significant downturn in natural gas prices. The Company's reserves were
determined at December 31, 1994 using a natural gas price of approximately
$1.70 per Mcf for natural gas not subject to long-term contracts. At
February 21, 1995, the natural gas prices received by the Company fell to
approximately $1.41 per Mcf for natural gas not subject to long-term
contracts. This decrease in natural gas prices would have had a
significant effect on the SMOG value of the Company's reserves at December
31, 1994 and would have resulted in a provision to reduce the carrying
value of oil and natural gas properties of approximately $3.5 million.
REPORT OF INDEPENDENT ACCOUNTANTS
53
<PAGE>
The Shareholders and Board of Directors
Unit Corporation
We have audited the accompanying consolidated balance sheets of Unit
Corporation and subsidiaries as of December 31, 1994 and 1993 and the
related consolidated statements of operations, changes in shareholders'
equity and cash flows and the related financial statement schedule for each
of the three years in the period ended December 31, 1994. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Unit
Corporation and subsidiaries as of December 31, 1994 and 1993, and the con-
solidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation
to the basic financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
February 22, 1995
54
<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 67 Chairman of the Board, Chief Executive
Officer and Director
John G. Nikkel 60 President, Chief Operating Officer and
Director
Earle Lamborn 60 Senior Vice President, Drilling and
Director
Philip M. Keeley 53 Senior Vice President, Exploration and
Production
Larry D. Pinkston 40 Vice President, Treasurer and Chief
Financial Officer
Mark E. Schell 37 General Counsel and Secretary
________
Mr. Kirchner, a co-founder of the Company, has been the Chairman of
the Board and a director since 1963 and was President until November 1983.
Mr. Kirchner is a Registered Professional Engineer within the State of
Oklahoma, having received degrees in Mechanical Engineering from Oklahoma
State University and in Petroleum Engineering from the University of
Oklahoma.
Mr. Nikkel joined the Company in 1983 as its President and a director.
From 1976 until January 1982 when he co-founded Nike Exploration Company,
Mr. Nikkel was an officer and director of Cotton Petroleum Corporation,
serving as the President of that Company from 1979 until his departure.
Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production
Company for 18 years, last serving as Division Geologist for Amoco's Denver
Division. Mr. Nikkel presently serves as President and a director of Nike
55
<PAGE>
Exploration Company. Mr. Nikkel received a Bachelor of Science degree in
Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 40
years, joining the Company's predecessor in 1952 prior to it becoming a
publicly-held corporation. He was elected Vice President, Drilling in 1973
and to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice
President, Exploration and Production. Prior to that time, Mr. Keeley co-
founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and
serves as Executive Vice President and a director of that company. From
1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation,
serving first as Manager of Land and from 1979 as Vice President and a
director. Before joining Cotton, Mr. Keeley was employed for four years by
Apexco, Inc. as Manager of Land and prior thereto he was employed by
Texaco, Inc. for nine years. He received a Bachelor of Arts degree in
Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as
Corporate Budget Director and Assistant Controller prior to being appointed
as Controller in February 1985. He has been Treasurer since December 1986
and was elected to the position of Vice President and Chief Financial
Officer in May 1989. He holds a Bachelor of Science Degree in Accounting
from East Central University of Oklahoma and is a Certified Public
Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and
General Counsel. From 1979 until joining the Company, Mr. Schell was
Counsel, Vice President and a member of the Board of Directors of C & S
Exploration, Inc. He received a Bachelor of Science degree in Political
Science from Arizona State University and his Juris Doctorate degree from
the University of Tulsa Law School.
The balance of the information required in this Item 10 is incorpo-
rated by reference to the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1995
annual meeting of stockholders.
Item 11. Executive Compensation
- ---------------------------------
Information required by this item is incorporated by reference to the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1995 annual meeting of
stockholders.
56
<PAGE>
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
Information required by this item is incorporated by reference to the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1995 annual meeting of
stockholders.
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Information required by this item is incorporated by reference to the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1995 annual meeting of
stockholders.
57
<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, 1994 and 1993
Consolidated Statements of Operations for the years ended December
31, 1994, 1993 and 1992
Consolidated Statements of Changes in Shareholders' Equity for the
years ended December 31, 1994, 1993 and 1992
Consolidated Statements of Cash Flows for the years ended December
31, 1994, 1993 and 1992
Notes to Consolidated Financial Statements
Report of Independent Accountants
2. Financial Statement Schedules:
------------------------------
Included in Part IV of this report for the years ended December 31,
1994, 1993 and 1992:
Schedule VIII - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under
which they are required or because the required information is included
in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers
assigned such exhibits in the Exhibit Table of Item 601 of Regulation
S-K.
3. Exhibits:
--------
2 Certificate of Ownership and Merger of the Company and Unit
Drilling Co., dated February 22, 1979 (filed as an Exhibit to
the Company's Registration Statement No. 2-63702, which is
incorporated herein by reference).
3.1.1 Certificate of Incorporation (filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated
July 21, 1988 (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December
31, 1989, which is incorporated herein by reference).
58
<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).
10.1.14 Amended and Restated Credit Agreement dated as of January 17,
1992 by and between Unit Corporation and Bank of Oklahoma
N.A., F&M Bank and Trust Company, Fourth National Bank of
Tulsa and Western National Bank of Tulsa (filed as an Exhibit
to the Company's Annual Report under cover of Form 10-K for
the year ended December 31, 1991, which is incorporated herein
by reference).
10.1.16 First Amendment to Amended and Restated Credit Agreement dated
as of May 1, 1992, by and between Unit Corporation and Bank of
Oklahoma, N.A., F&M Bank and Trust Company, Fourth National
Bank of Tulsa, and Western National Bank of Tulsa (filed as an
Exhibit to the Company's Quarterly Report under cover of Form
10-Q for the quarter ended June 30, 1992, which is
incorporated herein by reference).
59
<PAGE>
10.1.17 Second Amendment to Amended and Restated Credit Agreement,
dated March 3, 1993 and effective as of March 1, 1993, by and
between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank
and Trust Company, Fourth National Bank of Tulsa, and Western
National Bank of Tulsa (filed as an Exhibit to the Company's
Quarterly Report under cover of Form 10-Q for the quarter
ended March 31, 1993, which is incorporated herein by
reference).
10.1.18 Third Amendment to Amended and Restated Credit Agreement
effective as of March 31, 1994, by and between Unit
Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust
Company, Bank IV, Oklahoma, N.A. and American National Bank
and Trust Company of Shawnee (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the
quarter ended March 31, 1994, which is incorporated herein by
reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement
dated as of December 12, 1994, by and between Unit Corporation
and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank
IV, Oklahoma, N.A. and American National Bank and Trust
Company of Shawnee (filed as an Exhibit in Form 8-K dated
December 15, 1994, which is incorporated herein by reference).
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership
(filed as Exhibit I to Unit Drilling and Exploration Company's
Registration Statement on Form S-1 as S.E.C. File No. 2-66347,
which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership
(filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's
Registration Statement Form S-1 as S.E.C. File No. 2-92582,
which is incorporated herein by reference).
10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited
Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil
and Gas Program's Registration Statement of Form S-1 as S.E.C.
File No. 2-89678, which is incorporated herein by reference).
10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 3.1 to Unit 1985
Employee Oil and Gas Limited Partnership's Registration
Statement on Form S-1 as S.E.C. File No. 2-95068, which is
incorporated herein by reference).
10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 10.11 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
60
<PAGE>
10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1990, which is incorporated herein by reference).
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1991, which is incorporated herein by reference).
10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as
Exhibit 10.16 to the Company's Registration Statement on Form
S-4 as S.E.C. File No. 33-7848, which is incorporated herein
by reference).
10.2.22* The Company's Stock Option Plan (filed on the Company's
Registration Statement of Form S-8 as S.E.C. File No. 33-44103,
which is incorporated herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan
(filed on Form S-8 as S.E.C. File No. 33-49724, which is
incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed on Form S-8 as
S.E.C. File No. 33-53542, which is incorporated herein by
reference).
61
<PAGE>
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1993,
which is incorporated herein by reference).
10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to
the Company's Annual Report under cover of Form 10-K for the
year ended December 31, 1993, which is incorporated herein by
reference).
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed herewith).
10.3.4 Director and Officers Insurance and Company Reimbursement
Policy (filed as an Exhibit to the Company's Quarterly Report
under cover of Form 10-Q for the quarter ended March 31, 1993,
which is incorporated herein by reference).
10.5 Acquisition and Development Agreement, dated September 26,
1991, between Registrant and Municipal Energy Agency of
Nebraska (filed on Form 8-K dated September 30, 1991, which is
incorporated herein by reference).
10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco
Exploration, Inc. and Aleco Production Company (as "Seller")
and Unit Petroleum Company (a "Buyer") and Helmerich & Payne,
Inc. (a "Buyer") (filed on Form 8-K dated May 21, 1992, which
is incorporated herein by reference).
10.7 Asset Purchase Agreement, dated as of November 28, 1994,
between the Registrant and Patrick Petroleum Corp of Michigan
and American National Petroleum Company (filed as an Exhibit
in Form 8-K dated December 15, 1994, which is incorporated
herein by reference).
22.1 Subsidiaries of the Registrant (filed herewith).
24.1 Consent of Independent Accountants (filed herewith).
27 Financial Data Schedules (filed herewith).
* Indicates a management contract or compensatory plan identified
pursuant to the requirements of Item 14 of Form 10-K.
62
<PAGE>
(b) Reports on Form 8-K:
On December 28, 1994 (as amended by Form 8-K/A filed February
24, 1995), the Company filed a report on Form 8-K under Item 2
and Item 5 reporting the purchase of certain oil and natural
gas wells located in Oklahoma, Texas, New Mexico and Louisiana
from Patrick Petroleum Corp of Michigan and American National
Petroleum Company and the amending of the Company's credit
agreement.
63
<PAGE>
Schedule VIII
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance
Balance at charged to Deductions at
beginning costs & & net end of
Description of period expenses write-offs period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1994 $ 411 $ - $ 122 $ 289
======== ======== ======== ========
Year ended
December 31, 1993 $ 376 $ - $ (35) $ 411
======== ======== ======== ========
Year ended
December 31, 1992 $ 170 $ 200 $ (6) $ 376
======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance at Balance at
beginning end of
Description of period Additions Deductions period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1994 $ 8,218 $ - $ 1,795 $ 6,423
======== ======== ======== ========
Year ended
December 31, 1993 $ 12,245 $ - $ 4,027 $ 8,218
======== ======== ======== ========
Year ended
December 31, 1992 $ 12,905(1) $ - $ 660 $ 12,245
======== ======== ======== ========
___________
(1) Represents initial valuation allowance recorded at the date of
adoption of Statement of Financial Accounting Standard No. 109.
64
<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 21, 1995 By: /s/ John G. Nikkel
-------------- ---------------------------
JOHN G. NIKKEL
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on the 21st day of March, 1995.
Name Title
/s/ King P. Kirchner
- ------------------------------- Chairman of the Board and Chief
KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel
- ------------------------------- President and Chief Operating
JOHN G. NIKKEL Officer, Director
/s/ Earle Lamborn
- ------------------------------- Senior Vice President, Drilling,
EARLE LAMBORN Director
/s/ Larry D. Pinkston
- ------------------------------- Vice President, Chief Financial
LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz
- ------------------------------- Controller
STANLEY W. BELITZ
/s/ Don Bodard
- ------------------------------- Director
DON BODARD
/s/ Don Cook
- ------------------------------- Director
DON COOK
/s/ William B. Morgan
- ------------------------------- Director
WILLIAM B. MORGAN
/s/ John S. Zink
- ------------------------------- Director
JOHN S. ZINK
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
65
<PAGE>
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
------- ----------------------------------------------- -----
10.2.28 Unit 1995 Employee Oil and Gas Limited
Partnership Agreement of
Limited Partnership.
22.1 Subsidiaries of the Registrant.
24.1 Consent of Independent Accountants.
27 Financial Data Schedule
66
<PAGE>
EXHIBIT 10.2.28
<PAGE>
CONFIDENTIAL
For Private Placement Purposes Only Copy No. ____
UNIT 1995 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 6, 1995
(i)
<PAGE>
500 Preformation
Units of Limited Partnership Interest
in the
UNIT 1995 EMPLOYEE
OIL AND GAS LIMITED PARTNERSHIP
_____________________________________
$1,000 Per Unit Plus Possible
Additional Assessments of $100 Per Unit
(Minimum Investment - 2 Units)
Minimum Aggregate Subscriptions Necessary
to Form Partnership - 50 Units
_____________________________________
A maximum of 500 (minimum of 50) units of limited partnership interest
("Units") in the UNIT 1995 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.
(continued on next page)
_____________________________________
(ii)
<PAGE>
. Conflicts of interest exist and additional conflicts of
interest may arise between the General Partner and the Limited
Partners, and there are no pre-determined procedures for
resolving any such conflicts.
. Significant tax considerations to be considered by an investor
include:
. possible audit of income tax returns of the Partnership
and/or the Limited Partners and resulting reduction or
elimination of tax benefits; and
. Limited Partners will not benefit from Partnership
losses unless they have passive income from other
activities.
. There can be no assurance that the Partnership will have
adequate funds to provide cash distributions to the Limited
Partners. The amount and timing of any such distributions will
be within the complete discretion of the General Partner.
. The amount of any cash distribution which a Limited Partner may
receive from the Partnership could be insufficient to pay the
tax liability incurred by such Limited Partner with respect to
income or gain allocated to such Limited Partner by the
Partnership.
. Certain provisions in the Agreement modify what would otherwise
be the applicable Oklahoma law as to the fiduciary standards
for general partners in limited partnerships. Those standards
in the Agreement could be less advantageous to the Limited
Partners than the corresponding fiduciary standards otherwise
applicable under Oklahoma law. The purchase of Units may be
deemed as consent to the fiduciary standards set forth in the
Agreement.
_____________________________________
EXCEPT AS STATED HEREIN UNDER "ADDITIONAL INFORMATION," NO
PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM
IN CONNECTION WITH THIS OFFERING AND SUCH REPRESENTATIONS, IF ANY, MAY NOT BE
RELIED UPON. THE INFORMATION CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM IS
AS OF THE DATE HEREOF UNLESS ANOTHER DATE IS SPECIFIED.
_____________________________________
PROSPECTIVE INVESTORS ARE NOT TO CONSTRUE THE CONTENTS OF THIS
PRIVATE OFFERING MEMORANDUM AS LEGAL, BUSINESS, OR TAX ADVICE. EACH INVESTOR
SHOULD CONSULT HIS OR HER OWN ATTORNEY, BUSINESS ADVISOR AND TAX ADVISOR AS TO
LEGAL, BUSINESS, TAX AND RELATED MATTERS CONCERNING HIS OR HER INVESTMENT.
PROSPECTIVE INVESTORS ARE URGED TO REQUEST ANY ADDITIONAL INFORMATION THEY MAY
CONSIDER NECESSARY TO MAKE AN INFORMED INVESTMENT DECISION.
_____________________________________
(iii)
<PAGE>
THE SECURITIES OFFERED HEREBY HAVE NOT BEEN APPROVED OR
DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION, THE
OKLAHOMA SECURITIES COMMISSION OR BY THE SECURITIES REGULATORY AUTHORITY OF ANY
OTHER STATE, NOR HAS ANY COMMISSION OR AUTHORITY PASSED UPON OR ENDORSED THE
MERITS OF THIS OFFERING OR THE ACCURACY OR ADEQUACY OF THIS PRIVATE OFFERING
MEMORANDUM. ANY REPRESENTATION CONTRARY TO THE FOREGOING IS UNLAWFUL.
_____________________________________
THESE UNITS ARE BEING OFFERED SUBJECT TO PRIOR SALE, TO
WITHDRAWAL, CANCELLATION OR MODIFICATION OF THE OFFER WITHOUT NOTICE AND TO THE
FURTHER CONDITIONS SET FORTH HEREIN.
_____________________________________
IN CONNECTION WITH THE REGISTRATION OF THE PARTNERSHIP AS A
"TAX SHELTER" PURSUANT TO SECTION 6111 OF THE INTERNAL REVENUE CODE OF 1986, AS
AMENDED, PLEASE NOTE THAT ISSUANCE OF A REGISTRATION NUMBER DOES NOT INDICATE
THAT AN INVESTMENT IN THE PARTNERSHIP OR THE CLAIMED TAX BENEFITS THEREFROM
HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE INTERNAL REVENUE SERVICE.
_____________________________________
ADDITIONAL INFORMATION
----------------------
Each prospective investor, or his or her qualified
representative named in writing, is hereby offered the opportunity (1) to
obtain additional information necessary to verify the accuracy of the
information supplied herewith or hereafter, and (2) to ask questions and
receive answers concerning the terms and conditions of the offering. If you
desire to avail yourself of the opportunity, please contact:
Mark E. Schell, Esq.
1000 Kensington Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
(918) 493-7700
(iv)
<PAGE>
The following documents and instruments are available to
qualified offerees upon written request:
1. Amended and Restated Certificate of Incorporation and
By-Laws of UNIT.
2. Certificate of Incorporation and By-Laws of Unit
Petroleum Company.
3. UNIT's Employees' Thrift Plan.
4. UNIT's Stock Option Plan and related prospectuses
covering shares of Common Stock issuable upon exercise
of outstanding options.
5. Unit's Non Employee Directors' Stock Option Plan.
6. The Credit Agreement as Amended 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 1994, the annual report to shareholders
and all quarterly reports to shareholders submitted by
UNIT to its shareholders during calendar year 1994.
8. The agreements of limited partnership for the prior oil
and gas drilling programs and prior employee programs
of Unit Petroleum Company, UNIT and Unit Drilling and
Exploration Company ("UDEC").
9. All periodic reports filed with the Securities and
Exchange Commission and all reports and information
provided to limited partners in all limited
partnerships of which Unit Petroleum Company, UNIT or
UDEC now serves or has served in the past as a general
partner.
10. Form of nominee agreement to be entered into by the
Partnership with any party holding record title to
Partnership Properties as nominee of the Partnership.
11. The agreement of limited partnership for the Unit 1986
Energy Income Limited Partnership.
(v)
<PAGE>
SUMMARY OF CONTENTS
Page
SUMMARY OF PROGRAM........................................ 1
Terms of the Offering................................ 1
Risk Factors......................................... 2
Additional Financing................................. 5
Proposed Activities.................................. 5
Application of Proceeds.............................. 6
Participation in Costs and Revenues.................. 7
Compensation......................................... 7
Federal Income Tax Aspects........................... 7
RISK FACTORS.............................................. 8
Investment Risks..................................... 8
Tax Related Risks.................................... 15
Operational Risks................................... 17
TERMS OF THE OFFERING..................................... 19
General.............................................. 19
Limited Partnership Interests........................ 20
Subscription Rights.................................. 20
Payment for Units; Delinquent Installment............ 21
Right of Presentment................................. 22
Rollup or Consolidation of Partnership............... 24
ADDITIONAL FINANCING...................................... 25
Additional Assessments............................... 25
Prior Programs....................................... 26
Partnership Borrowings............................... 26
PLAN OF DISTRIBUTION...................................... 27
Suitability of Investors............................. 27
RELATIONSHIP OF THE PARTNERSHIP, THE GENERAL PARTNER
AND AFFILIATES............................................ 28
PROPOSED ACTIVITIES....................................... 28
General.............................................. 28
Partnership Objectives............................... 31
Areas of Interest.................................... 32
Transfer of Properties............................... 32
Record Title to Partnership Properties............... 33
Marketing of Reserves................................ 33
Conduct of Operations................................ 33
APPLICATION OF PROCEEDS................................... 34
PARTICIPATION IN COSTS AND REVENUES....................... 35
(vi)
<PAGE>
COMPENSATION.............................................. 36
Supervision of Operations............................ 36
Purchase of Equipment and Provision of Services...... 37
Prior Programs....................................... 38
MANAGEMENT................................................ 40
The General Partner.................................. 40
Officers, Directors and Key Employees................ 40
Prior Employee Programs.............................. 43
Ownership of Common Stock............................ 44
Interest of Management in Certain Transactions....... 47
CONFLICTS OF INTEREST..................................... 47
Acquisition of Properties and Drilling Operations.... 48
Participation in UNIT's Drilling or Income Programs.. 49
Transfer of Properties............................... 50
Partnership Assets................................... 51
Transactions with the General Partner or Affiliates.. 51
Right of Presentment Price Determination............. 52
Receipt of Compensation Regardless of Profitability.. 52
Legal Counsel........................................ 52
FIDUCIARY RESPONSIBILITY.................................. 52
General.............................................. 52
Liability and Indemnification........................ 53
PRIOR ACTIVITIES.......................................... 54
Prior Employee Programs.............................. 57
Results of the Prior Oil and Gas Programs............ 58
FEDERAL INCOME TAX ASPECTS................................ 66
General.............................................. 66
Summary of Certain Matters........................... 67
Partnership Classification........................... 67
Taxation of Limited Partners......................... 68
IRS Tax Shelter Registration......................... 74
Partnership Tax Returns and Tax Information.......... 74
Laws Subject to Change............................... 75
State and Local Taxes................................ 75
COMPETITION, MARKETS AND REGULATION....................... 76
Marketing of Production.............................. 76
Regulation of Partnership Operations................. 77
Natural Gas Price Regulation......................... 78
State Regulation of Oil and Gas Production........... 83
Legislative and Regulatory Production and Pricing
Proposals.......................................... 83
Production and Environmental Regulation.............. 85
SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT.............. 86
Partnership Distributions............................ 86
Deposit and Use of Funds............................. 87
Power and Authority.................................. 87
Rollup or Consolidation of the Partnership........... 88
(vii)
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Limited Liability.................................... 88
Records, Reports and Returns......................... 89
Transferability of Interests......................... 90
Amendments........................................... 92
Voting Rights........................................ 92
Exculpation and Indemnification of the
General Partner.................................... 93
Termination.......................................... 93
Insurance............................................ 94
COUNSEL................................................... 94
GLOSSARY.................................................. 95
FINANCIAL STATEMENTS...................................... 99
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 1995 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 the 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, 1995 (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, 1995
and the remaining three of such Installments being due on June 15, 1995,
September 15, 1995 and December 15, 1995, respectively, or (ii) through equal
deductions from 1995 salary commencing immediately after formation of the
Partner ship.
The purchase price of each Unit is $1,000, and the minimum permissible
purchase is two Units ($2,000) for each subscriber. Additional Assessments of
up to $100 per Unit may be required (see "ADDITIONAL FINANCING - Additional
Assessments"). Maximum purchases by employees (other than directors) will be
for an amount equal to one-half of their base salaries for calendar year 1995.
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, 2025, unless it is terminated
earlier pursuant to the provisions of the Agreement or by operation of law.
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<PAGE>
See "TERMS OF THE OFFERING - Limited Partnership Interests"; "TERMS OF THE
OFFERING - Subscription Rights"; and "SUMMARY OF THE LIMITED PARTNERSHIP
AGREEMENT - Termination."
Units will be offered only to those qualified employees of UNIT or any
of its subsidiaries at the date of formation of the Partnership whose annual
base salaries for 1995 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 1995 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 1995.
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, 1996 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 a nd 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.
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<PAGE>
Investment Risks:
. Future oil and natural gas prices are unpredictable. If oil
and natural gas prices go down, the Partnership's
distributions, if any, to the Limited Partners will be
adversely affected.
. The General Partner is authorized under the Agreement to cause,
in its sole discretion, the sale or transfer of the
Partnership's assets to, or the merger or consolidation of the
Partnership with, another partnership, corporation or other
business entity. Such action could have a material impact on
the nature of the investment of all Limited Partners.
. Except for certain transfers to the General Partner and other
restricted transfers, the Agreement prohibits a Limited Partner
from transferring Units. Thus, except for the limited right of
the Limited Partners after December 31, 1996 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.
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<PAGE>
. Certain provisions in the Agreement modify what would otherwise
be the applicable Oklahoma law as to the fiduciary standards
for a general partner in a limited partnership. The fiduciary
standards in the Agreement could be less advantageous to the
Limited Partners and more advantageous to the General Partner
than corresponding fiduciary standards otherwise applicable
under Oklahoma law. The purchase of Units may be deemed as
consent to the fiduciary standards set forth in the Agreement.
. There can be no assurances that the Partnership will have
adequate funds to provide cash distributions to the Limited
Partners. The amount and timing of any such distributions will
be within the complete discretion of the General Partner.
. The amount of any cash distributions which Limited Partners may
receive from the Partnership could be insufficient to pay the
tax liability incurred by such Limited Partners with respect to
income or gain allocated to such Limited Partners by the
Partnership.
Tax Risks:
. Tax laws and regulations applicable to partnership investments
may change at any time and these changes may be applicable
retroactively.
. The Partnership may not qualify or may fail to continue to
qualify as a partnership for federal income tax purposes.
. Certain allocations of income, gain, loss and deduction of the
Partnership among the Partners may be challenged by the
Internal Revenue Service (the "Service") resulting in a Limited
Partner having to report additional taxable income or being
denied a deduction.
Operational Risks:
. The search for oil and gas is highly speculative and the
drilling activities conducted by the Partnership may result in
a well that may be dry or productive wells that do not produce
sufficient oil and gas to produce a profit or result in a
return of the Limited Partners' investment.
. Certain hazards may be encountered in drilling wells which
could lead to substantial liabilities to third parties or
governmental entities. In addition, governmental regulations
or new laws relating to environmental matters could increase
Partnership costs, delay or prevent drilling a well, require
the Partnership to cease operations in certain areas or expose
the Partnership to significant liabilities for violations of
such laws and regulations.
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<PAGE>
Additional Financing
Additional Assessments. After the Aggregate Subscription received from
the Limited Partners has been fully expended or committed and the General
Partner's Minimum Capital Contribution has been fully expended, the General
Partner may make one or more calls for Additional Assessments from the Limited
Partners if additional funds are required to pay the Limited Partners' share of
Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition
Costs. The maximum amount of total Additional Assessments which may be called
for by the General Partner is $100 per Unit. See "ADDITIONAL FINANCING --
Additional Assessments".
Partnership Borrowings. After the General Partner's Minimum Capital
Contribution has been expended, the General Partner may cause the Partnership
to borrow funds required to pay Drilling Costs, Special Production and
Marketing Costs or Lease hold 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, 1995, if the Partnership
is formed prior to such date or from the date of the formation of the
Partnership if subsequent to January 1, 1995, until December 31, 1995, 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 1995. 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
1995. 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 h as 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 1995.
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<PAGE>
Application of Proceeds
The offering proceeds will be used to pay the Leasehold Acquisition
Costs incurred by the Partnership to acquire those producing oil and gas leases
in which the Partnership participates and the Leasehold Acquisition Costs,
exploration, drilling and development costs incurred by the Partnership
pursuant to drilling activities in which the Partnership participates. The
General Partner estimates (based on historical operating experience) that such
costs may be expended as shown below based on the assumption of a maximum
number of subscriptions in the first column and a minimum number of
subscriptions in the second column:
$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."
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Participation in Costs and Revenues
Partnership costs, expenses and revenues will be allocated among the
Partners in the following percentages:
General Limited
COSTS AND EXPENSES Partner Partners
------- --------
Organizational and offering costs
of the Partnership and any drilling
or income programs in which the
Partnership participates as a
co-general partner 100% 0%
All other Partnership costs and
expenses
Prior to time Limited Partner
Capital Contributions are
entirely expended 1% 99%
After expenditure of Limited
Partner Capital Contributions
and until expenditure of
General Partner's Minimum
Capital Contribution 100% 0%
After expenditure of General General Part- Limited Partners'
Partner's Minimum Capital ner's Per- Percentage(1)
Contribution centage(1)
REVENUES General Part- Limited Partners'
ner's Per- Percentage(1)
centage(1)
____________________
1) See "GLOSSARY."
Compensation
The General Partner will not receive any management fees in connection
with the operation of the Partnership. The Partnership will reimburse the
General Partner for that portion of its general and administrative overhead
expense attributable to its conduct of Partnership business and affairs. See
"COMPENSATION."
Federal Income Tax Aspects
The General Partner has received an opinion from the law firm of Conner
& Winters, A Professional Corporation, to the effect that, for federal income
tax purposes, the Partnership will be classified as a partnership and not as an
association taxable as a corporation. Such opinion is based on certain
premises as stated therein and is not binding on the Service or the courts.
-7-
<PAGE>
The General Partner will not apply for a ruling from the Service with respect
to such matter and the Partnership may not meet all the conditions which must
be met before a ruling will be issued. See "FEDERAL INCOME TAX ASPECTS -
Partnership Classification."
THIS MEMORANDUM CONTAINS AN EXPLANATION OF THE MORE SIGNIFICANT TERMS
AND PROVISIONS OF THE AGREEMENT OF LIMITED PARTNERSHIP WHICH IS ATTACHED AS
EXHIBIT A. THE SUMMARY OF THE AGREEMENT CONTAINED IN THIS MEMORANDUM IS
QUALIFIED IN ITS ENTIRETY BY SUCH REFERENCE AND ACCORDINGLY THE AGREEMENT
SHOULD BE CAREFULLY REVIEWED AND CONSIDERED.
RISK FACTORS
Prospective purchasers of Units should carefully study the information
contained in this Memorandum and should make their own evaluations of the
probability for the discovery of oil and natural gas through exploration.
INVESTMENT RISKS
Financial Risks of Drilling Operations
The Partnership will participate with the General Partner (including,
with certain limited exceptions, other drilling programs sponsored by it, or
UNIT) and, in some cases, other parties ("joint interest parties") in
connection with drilling operations conducted on properties in which the
Partnership has an interest. It is not anticipated that all such drilling
operations will be conducted under turnkey drilling contracts and, thus, all of
the parties participating in the drilling operations on a particular property,
including the Partnership, may be fully liable for their proportionate share of
all costs of such operations even if the actual costs significantly exceed the
original cost estimates. Further, if any joint interest party defaults in its
obligation to pay its share of the costs, the other joint interest parties may
be required to fund the deficiency until, if ever, it can be collected from the
defaulting party. As a result of forced pooling or similar proceedings (see
"COMPETITION, MARKETS AND REGULATION"), the Partnership may acquire larger
fractional interests in Partnership Properties than originally anticipated and,
thus, be required to bear a greater share of the costs of operations. As a
result of the foregoing, the Partnership could become liable for amounts
significantly in excess of the amounts originally anticipated to be expended in
connection with the operations and, in such event, would have only limited
means for providing needed additional funds (see "ADDITIONAL FINANCING").
Also, if a well is operated by a company which does not or cannot pay the costs
and expenses of drilling or operating a Partnership Well, the Partnership's
interest in such well may become subject to liens and claims of creditors who
supplied services or materials in connection with such operations even though
the Partnership may have previously paid its share of such costs and expenses
to the operator. If the operator is unable or unwilling to pay the amount
due, the Partnership might have to pay its share of the amounts owing to such
creditors in order to preserve its interest in the well which would mean that
it would, in effect, be paying for certain of such costs and expenses twice.
-8-
<PAGE>
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 an d 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 a nd in all oil and gas wells commenced
by the General Partner or UNIT for its own account during the period from
January 1, 1995, if the Partnership is formed prior to such date, or from the
date of the formation of the Partnership, if subsequent to January 1, 1995,
through December 31, 1995 and, with certain limited exceptions, will be a co-
general partner of any drilling or income programs, or both, formed by the
General Partner or UNIT in 1995. 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 1995. 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 1995
and will have no rights in production from wells commenced in years other than
1995. Likewise, if additional interests are acquired in wells participated in
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<PAGE>
by the Partnership after 1995, 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 o f 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 to the General Partner, to or for the
benefit of the transferor Limited Partner or members of his or her immediate
family sharing the same residence, and transfers 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, buy Units for
prices determined either by an independent petroleum engineering firm or the
General Partner pursuant to a formula describe d under "TERMS OF THE OFFERING
- -Right of Presentment." Similar commitments have been made and may hereafter
be made to investors in other oil and gas drilling, income and employee
programs sponsored by the General Partner or UNIT. There can be no assurance
that the General Partner will have the financial resources to honor its
repurchase commitments. See "TERMS OF THE OFFERING - Right of Presentment."
Delay of Cash Distributions
For income tax purposes a Limited Partner will have to include in his
or her income his or her distributive share of the income, gains, losses and
deductions of the Partnership whether or not cash distributions are made. No
cash distribution s are expected to be made earlier than the first quarter of
1996. In addition, to the extent that the Partnership utilizes its revenues to
repay outside borrowings or otherwise uses its own revenues to finance its
activities (see "ADDITIONAL FINANCING"), the funds available for cash
distributions by the Partnership may be reduced or unavailable. It is possible
that the amount of tax payable by a Limited Partner on his or her distributive
share of the income of a Partnership will exceed cash distributions from the
Partnership. See "FEDERAL INCOME TAX ASPECTS."
The date any distributions commence and their subsequent timing or
amount cannot be accurately predicted. The decision as to whether or not the
Partnership will make a cash distribution at any particular time will be made
solely by the General Partner.
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<PAGE>
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 t he Partnership.
Rollup or Consolidation of Partnership
Under the terms of the Agreement, at any time two years or more after
the Partnership has completed substantially all of its property acquisition,
drilling and development operations, the General Partner is authorized to cause
the Partnership to transfer its assets to, or to merge or consolidate with,
another partnership or a corporation or other entity for the purpose of
combining the oil and gas properties and other assets of the Partnership with
those of other partnerships formed for investment or participation by the
employees, directors and/or consultants of UNIT or any of its subsidiaries.
Such transfer or combination may be effected without the vote, approval or
consent of the Limited Partners. In such event, the Limited Partners will
receive interests in the transferee or resulting entity which will mean that
they will most likely participate in the results of a larger number of
properties but will have proportionately smaller allocable interests therein.
Any such transaction is required to be effected in a manner which UNIT and the
General Partner believe is fair and equitable to the Limited Partners but there
can be no assurance that such transaction will in fact be in the best interests
of the Limited Partner s. Limited Partners have no dissenters' or appraisal
rights under the terms of the Agreement or the Act. Such a
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<PAGE>
transaction will result in the termination and dissolution of the Partnership.
While there can be no assurance that the Partnership will participate in such
a transaction, the General Partner currently anticipates that the Partnership
will, at the appropriate time, be involved in such a transaction. See "TERMS
OF OFFERING", and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT."
Partnership Borrowings
The General Partner has the authority to cause the Partnership to
borrow additional funds in the future to pay certain costs of the Partnership.
While the use of additional financing to preserve the Partnership's equity in
oil and gas proper ties is 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 t he business of the
Partnership.
The Agreement provides that by a vote of a majority in interest, the
Limited Partners may effect certain changes in the Partnership such as
termination and dissolution of the Partnership and amendment of the Agreement.
The exercise of any of these and certain other rights is conditioned upon
receipt of an opinion by counsel for the Limited Partners or an order or
judgment of a court of competent jurisdiction to the effect that the exercise
of such rights will not result in the loss of t he 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 or cause the Partnership to be
classified as an association taxable as a corporation. The Partnership will be
governed by the Act. The A ct 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.
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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."
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 am end any relevant Partnership documents
accordingly. It is currently anticipated that the total Aggregate Subscription
will be required to fund the Partnership's business and operations. In the
event an Installment is not paid when due and the General Partner has not
released the Limited Partners from their obligation to pay such Installment,
then the General Partner may, at its sole option, purchase all Units of the
director or employee who fails to pay such Installment, at a price equal to
the amount of the prior Installments paid by such person. The General Partner
may also bring legal proceedings to collect any unpaid Installments not waived
by it or Additional Assessments. In addition, as indicated under "TERMS OF THE
OFFERING - Payment for Units; Delinquent Installment," if an employee's
employment with or position as a director of the General Partner, UNIT or any
affiliate thereof is terminated other than by reason of Normal 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
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offering presently qualifies or will continue to qualify under such exemptive
provisions due to, among other things, the adequacy of disclosure and the
manner of distribution of the offering, the existence of similar offerings
conducted by the General Partner or UNIT or its affiliates in the past or in
the future, a failure or delay in providing notices or other required filings,
the conduct of other oil and gas activities by the General Partner or UNIT and
its affiliates or the change of any securities laws or regulations.
If and to the extent suits for rescission are brought and successfully
concluded for failure to register this offering or other offerings under the
Securities Act of 1933, as amended, or state securities acts, or for acts or
omissions constituting certain prohibited practices under any of said acts,
both the capital and assets of the General Partner and the Partnership could be
adversely affected, thus jeopardizing the ability of the Partnership to operate
successfully. Further, the time and capital of the General Partner could be
expended in defending an action by investors or by state or federal authorities
even where the Partnership and the General Partner are ultimately exonerated.
Nominee Agreements
The Partnership Agreement empowers the General Partner, UNIT or any of
their affiliates, to hold title to the Partnership Properties as nominee for
the benefit of the Partnership. If title to the Partnership Properties is held
in the name of a nominee the nominee will act as nominee for the Partnership
pursuant to a form of Nominee Agreement to be entered into between the nominee
and the Partnership. In some jurisdictions, such interests could be subject to
the claims of creditors of such nominee. The General Partner is of the
opinion that the likelihood of the occurrence of such claims is remote, due to
the fact that executed nominee agreements will appear in the files of the
General Partner. It is possible that the nominee agreement would be
disregarded, however, in which case Partnership Property could be subject to
claims and litigation in the event that the nominee failed to pay its debts or
became subject to the claims of creditors.
The General Partner may elect to hold title to Partnership Properties
permanently in the name of a nominee for the Partnership provided such
arrangement is evidenced by a nominee agreement and the nominee conducts no
business or operations other than holding record title to interests in
properties. See "PROPOSED ACTIVITIES -- Record Title To Partnership
Properties." Based on certain representations discussed under "FEDERAL INCOME
TAX ASPECTS -- Taxation of Limited Partners -- Nominee Ownership of
Partnership Properties," Counsel is of the opinion that the Partnership will be
treated, for federal income tax purposes, as the owner of the Partnership
Properties held by the nominee for the account of the Partnership.
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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 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
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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, 1995 is 9%
(compounded daily), but, as stated, such rate may change every three months.
In addition, audits of Partnership taxable years will be conducted at
the Partnership level rather than at the Partner level. The Code also gives
certain authority to the "Tax Matters Partner" to deal with any Service audit,
assessment and administrative and judicial proceedings. The General Partner
will be the "Tax Matters Partner" for the Partnership. See "FEDERAL INCOME TAX
ASPECTS - Partnership Tax Returns and Tax Information."
Status as a Partnership
The tax benefits of oil and gas investments will be unavailable to the
Limited Partners if the Partnership is not held to be a partnership for federal
income tax purposes. The General Partner has not obtained a ruling from the
Service that t he Partnership will be treated, for federal income tax purposes,
as a partnership rather than as an association taxable as a corporation and the
Partnership probably will not meet all of the requirements set forth by the
Service necessary to obtain such ruling (see "FEDERAL INCOME TAX ASPECTS -
Partnership Classification"). Although the General Partner has received an
opinion of Conner & Winters, a Professional Corporation, based on certain
premises and representations of the General Partner as stated therein, that the
Partnership will be classified as a partnership for federal income tax
purposes, such opinion is not binding upon the Service and there is no
assurance that partnership status will not be challenged. Should the
Partnership be held to be an association taxable as a corporation, only the
Partnership, and not the Partners, would be entitled to the principal tax
benefits, including the deduction for intangible drilling and development
costs, and the Partners' after-tax investment return, if any, would be
reduced. In such event the Partnership 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 t he Partnership.
Excess distributions would be treated first as a reduction of basis and the
balance as capital gain.
Tax Treatment of Partnership Allocations
There are various provisions in the Agreement pertaining to the
allocation among Partners of items of income, gain, loss, deduction and credit.
There can be no assurance that the allocation provisions of the Agreement will
not be challenged by the Service or that such a challenge, if made, would not
be sustained by the courts. Also, under the passive activity loss rules,
allocations of losses from the Partnership to Limited Partners may not be
deductible currently. See "FEDERAL INCOME TAX ASPECTS - Partnership
Allocations, Partnership Losses and Limitations on Losses and Credits from
Passive Activities."
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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, 1995 or the
time the Partner ship is formed through December 31, 1995 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 1995.
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 consider able 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.
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
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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 t he 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 prohib-
itive 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 term s less favorable than might otherwise be
obtained. Competition for available markets has been vigorous and there
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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
. Minimum Partnership: $50,000 in subscriptions
. Maximum Partnership: $500,000 in subscriptions
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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, 1995 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 Genera l 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 t o
investors to indicate that their interest is shared by other unaffiliated
investors and no investor should place any reliance on the sale of the minimum
Aggregate Subscription as an indication of the merits of this offering. Units
acquired by the General Partner will be for investment purposes only without a
present intent for resale and there is no limit on the number of Units that may
be acquired by it.
Subscription Rights
Units are offered only to persons who are salaried employees of UNIT or
its subsidiaries at the date of formation of the Partnership and who are exempt
under the Fair Labor Standards Act and whose annual base salaries for 1995
(excluding bonuses) have been set at $22,680 or more and to Directors of UNIT.
Only employees and Directors who are U.S. citizens are eligible to participate
in the offering. In addition, employees and Directors must be able to bear the
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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 1995. Each Director of UNIT may subscribe for a maximum of 150
Units (maximum investment of $150,000). At December 21, 1994 there were
approximately 101 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 b ears 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, 1995 and the remaining three of such Installments being due on
June 15, 1995, September 15, 1995 and December 15, 1995, respectively, or (ii)
by employees so electing in the space provided on the Subscription Agreement,
through equal deductions from 1995 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 a Director of the General Partner, UNIT or any o f its
subsidiaries for any reason other than death, disability or Normal Retirement
prior to the time the full amount of all Installments not waived by the General
Partner as described below are due, then the due date for any such unpaid
Installments shall be accelerated so that the full amount of his or her unpaid
Capital Subscription will be due and payable on the effective date of such
termination.
Each Installment will be a legally binding obligation of the Limited
Partner and any past due amounts will bear interest at an annual rate equal to
two percentage points in excess of the prime rate of interest of Bank of
Oklahoma, N.A., Tulsa , Oklahoma; provided, however, that if the General
Partner determines that the total Aggregate Subscription is not required to
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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, 1996, and annually thereafter, Limited Partners will
have the right to present their Units to the General Partner for purchase. The
General Partner will not be obligated to purchase more than 20% of the then
outstanding Units in any one calendar year. The purchase price to be paid for
the Units of any Limited Partner presenting them for purchase will be based on
the net asset value of the Partnership which shall be equal to:
(1) The value of the proved reserves attributable to the
Partnership Properties, determined as set forth below; plus
(2) The estimated salvage value of tangible equipment installed on
Partnership Wells less the costs of plugging and abandoning the
wells, both discounted at the rate utilized to determine the
value of the Partnership's reserves as set forth below; plus
(3) The lower of cost or fair market value of all Partnership
Properties to which proved reserves have not been attributed
but which have not been condemned, as determined by an
independent petroleum engineering firm or the General Partner,
as the case may be; plus
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(4) Cash on hand; plus
(5) Prepaid expenses and accounts receivable (less a reasonable
reserve for doubtful accounts); plus
(6) The estimated market value of all other Partnership assets not
included in (1) through (5) above, determined by the General
Partner; MINUS
(7) An amount equal to all debts, obligations and other liabilities
of the Partnership.
The price to be paid for each Limited Partner's interest of the net asset value
will be his or her proportionate share of such net asset value less 75% of the
amount of any distributions received by him or her which are attributable to
the sales of t he 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
success or bank, as of the date such reserves are
estimated; and
(iii) Finally, the total discounted value of the future net
revenues from the production and sale of proved reserves
will be reduced by an additional 25% to take into account
the risks and uncertainties associated with the production
and sale of the reserves and other unforeseen
uncertainties.
A Limited Partner who elects to have his Units purchased by the General
Partner should be aware that estimates of future net recoverable reserves of
oil and gas and estimates of future net revenues to be received therefrom are
based on a great many factors, some of which, particularly future prices of
production, are usually variable and uncertain and are always determined by
predictions of future events. Accordingly, it is common for the actual
production and revenues received to vary from earlier estimates. Estimates
made in the first few years of production from a property will be based on
relatively little production history and will not 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.
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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 b e purchased from Limited Partners) as collateral to fund such
obligations. However, there is no assurance that the General Partner will have
sufficient financial resources to discharge its obligations.
Rollup or Consolidation of Partnership
The Agreement provides that two years or more after the Partnership has
completed substantially all of its property acquisition, drilling and
development operations, the General Partner may, without the vote, consent or
approval of the Limited Partners, cause all or substantially all of the oil
and gas properties and other assets of the Partnership to be sold, assigned or
transferred to, or the Partnership merged or consolidated with, another
partnership or a corporation, trust or other entity for the purpose of
combining the assets of two or more of the oil and gas partnerships formed for
investment or participation by employees, directors and/or consultants of UNIT
or any of its subsidiaries; provided, however, that the valuation of the oil
and gas properties and other assets of all such participating partnerships for
purposes of such transfer or combination shall be made on a consistent basis
and in a manner which the General Partner and UNIT believe is fair and
equitable to the Limited Partners. As a consequence of any such transfer or
combination, the Partnership shall be dissolved and terminated and the Limited
Partners shall receive partnership interests, stock or other equity interests
in the transferee or resulting entity. Any such action will cause the Limited
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Partners' attributable interest in the Partnership Properties to be diluted but
it will also provide them with attributable interests in the properties and
other assets of the other partnerships participating in the consolidation. It
also may reduce somewhat the amount of their attributable shares of the direct
and indirect costs of administering the Partnership. However, there may be
certain adverse tax consequences resulting from such a transaction. See "RISK
FACTORS - Investment Risks - Roll-Up or Consolidation of Partnership."
ADDITIONAL FINANCING
The General Partner will use its best efforts, consistent with
Partnership objectives, to acquire Productive properties and complete the
Partnership's drilling and development operations before the Aggregate
Subscription has been fully expend ed 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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<PAGE>
Prior Programs
In the prior employee programs conducted by UNIT or the General Partner
in each of the years 1984 through 1994, Additional Assessments could be called
for as provided herein. At September 30, 1994, 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 t hereon 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 in ability 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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<PAGE>
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 be incurring income tax
liability by virtue of that revenue and, thus, may not receive distributions
from the Partnership in amounts necessary to pay such income tax. However, the
use of such revenue to pay Partnership costs and expenses may generate
additional deductions for the Limited Partners.
PLAN OF DISTRIBUTION
Units will be offered privately only to select persons who can
demonstrate to the General Partner that they have both the economic means and
investment expertise to qualify as suitable investors. It is anticipated that
the Units will be offered and sold by the officers and directors of UPC or
UNIT, except that in states which require participation by a registered broker-
dealer in the offer and sale of securities the Units will be offered through
such broker-dealer as may be selected by the General Partner. Such broker-
dealer's activities in connection with the offering of interests in the
Partnership will be limited solely to such activities as are technically
required by state laws with respect to the offer of securities by brokers or
dealers. Such broker-dealer will not receive any fees or sales commission but
will be reimbursed for actual out-of-pocket expenses. Such expenses will be
part of the organizational costs to be paid by the General Partner.
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 (o r 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 s he 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 o f investment acumen or financial resources,
satisfy the General Partner that they meet suitability standards consistent
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with the maintenance and preservation of the exemptions provided by Sections
3(b) and/or 4(2) and by the applicable rules and regulations of the Securities
and Exchange Commission, as well as those contained herein and in the
Subscription Agreement. Persons offering interests shall sufficiently inquire
of a prospective investor to be reasonably assured that such investor meets
such acceptable standards. Suitability standards may also be imposed by the
regulatory authorities of the various states in which interests may be offered.
RELATIONSHIP OF THE PARTNERSHIP,
THE GENERAL PARTNER AND AFFILIATES
The following diagram depicts the primary relationships among the
Partnership, the General Partner and certain of its affiliates.
UNIT CORPORATION
|---------------------------|-----------------------|
| | |
|--------|---------| |--------|--------| |----------|-----------|
| Unit Petroleum | | Unit Drilling | | Mountain Front |
| | | | | |
| Company | | Company | |Pipeline Company, Inc.|
|--------|---------| |-----------------| |----------------------|
|
|-----------General Partner
|
|--------|--------------|
| Unit 1995 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 1995. 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 1995 and (ii) serving as a co-general partner in any
drilling or income programs, or both, formed by the General Partner or UNIT
during 1995.
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Acquisition of Properties and Drilling Operations. The Partnership
will participate, to the extent of 5% of UPC or UNIT's final interest in each
well, as a fractional working interest holder in any producing leases acquired
and in any drilling operations conducted by UPC or UNIT for its own account
which are acquired or commenced, respectively, from January 1, 1995, or the
time of the formation of the Partnership if subsequent to January 1, 1995,
until December 31, 1995, except for well s, 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; 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 o r UNIT and its affiliates during 1995. 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
1994. However UNIT may form such drilling or income programs during 1995. 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 1995 for outside investors is expected to 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% t o the general partners' accounts to 85% to the limited partners' accounts
and 15% to the general partners' accounts.
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<PAGE>
As co-general partners of any drilling or income programs that may be
formed by UNIT and/or UPC during 1995 and participated in by the Partnership,
UNIT and/or UPC and the Partnership will share the costs, expenses and revenues
allocable to t he general partners on a proportionate basis, 95% for the
account of UNIT and/or UPC and 5% for the account of the Partnership. The
Partnership will not receive any portion of any management fees payable to the
general partners nor any fees or payments for supervisory services which UNIT
or UPC may render to such programs as operator of program wells or other fees
and payments which UNIT or UPC may be entitled to receive from such programs
for services rendered to them or goods, materials, equipment or other property
sold to them.
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 1995 nor can it predict
what producing proper ties, if any, will be acquired by it during 1995.
Further, since the General Partner anticipates that the Partnership will
acquire a small interest (either directly or through any drilling or income
programs of which it or UNIT serves as a general partner) in approximately 30
to 70 wells (however, the exact number of wells may vary greatly depending on
the actual activity undertaken), it would be impractical to describe in any
detail all of the properties in which the Partnership can be expected to
acquire some interest.
The Partnership's drilling and development operations are expected to
include both Exploratory Wells and comparatively lower-risk Development Wells.
Exploratory Wells include both the high-risk "wildcat" wells which are located
in areas substantially removed from existing production and "controlled"
Exploratory Wells which are located in areas where production has been
established and where objective horizons have produced from similar geological
features in the vicinity. Based on UNIT 's historical profile of its drilling
operations, it is presently anticipated that the portion of the Aggregate
Subscription expended for Partnership drilling operations (see "APPLICATION OF
PROCEEDS") will be spent approximately 6% on Exploratory Wells and 94% on
Development Wells. However, these percentages may vary significantly.
Certain of the Partnership's Development Wells may be drilled on
prospects on which initial drilling operations were conducted by the General
Partner or UNIT prior to the formation of the Partnership. Further, certain of
the Partnership Well s 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 1995. In either instance, the
Partnership will have an interest only in those wells begun in 1995 and will
have no rights in production from wells commenced in years other than 1995 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 1995, 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 proper ties having high rates of production in early
years and properties with more consistent production over a longer term. See
"CONFLICTS OF INTERESTS - Acquisition of Properties and Drilling Operations."
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<PAGE>
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 1995. UNIT hopes that
participation in the Partnership will provide the participants with greater
proprietary interests in its operations and the potential for realizing a more
direct benefit in the event these operations prove to be profitable. The
Partnership has been structured to achieve the objective of providing the
Limited Partners with essentially the same economic returns that UNIT realizes
from the wells drilled or acquired during 1995.
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, 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 attempt ed. Plans to conduct drilling and
development operations or to acquire producing properties in certain of these
states may be abandoned if attractive prospects cannot be obtained upon
satisfactory terms or if the Partnership is not fully subscribed.
Transfer of Properties
In the case of wells drilled or producing properties acquired by the
Partnership and UPC or UNIT for their own accounts and not through another
drilling or income program, the Partnership will acquire from UPC or UNIT a
portion of the fractional undivided working interest in the properties or
portions thereof comprising the spacing unit on which a proposed Partnership
Well is to be drilled or on which a producing Partnership Well is located, and
UPC or UNIT will retain for its own account all or a portion of the remainder
of such working interest. Such working interests will be sold to the
Partnership for an amount equal to the Leasehold Acquisition Costs attributable
to the interest being acquired. Neither UNIT nor its affiliates will retain
any overrides or other burdens on the working interests conveyed to the
Partnership, and the respective working interests of UPC or UNIT and the
Partnership in a property will bear their proportionate shares of costs and
revenues.
The Partnership's direct interest in a property will only encompass the
area included within the spacing unit on which a Partnership Well is to be
drilled or on which a producing Partnership Well is located, and, in the case
of a Partnership Well to be drilled, it will acquire that interest only when
the drilling of the well is ready to commence. If the size of a spacing unit
is ever reduced, or any subsequent well in which the Partnership has no
interest is drilled thereon, the Partner ship 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 1995. If additional
interests in Partnership Wells are acquired in years subsequent to 1995 the
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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 1995. The Partnership will never own any
significant amounts of undeveloped properties or have an occasion to sell or
farm out any undeveloped Partnership Properties.
Transfers of properties to any drilling or income programs of which the
Partnership serves as a general partner will be governed by the provisions of
the agreement of limited partnership in effect with respect thereto. If any
such program is to be offered publicly, those provisions will have to be
consistent with the provisions contained in the Guidelines for the Registration
of Oil and Gas Programs adopted by the North American Securities Administrators
Association, Inc.
Record Title to Partnership Properties
Record title to the Partnership Properties will be held by the
Partnership or held in the name of a nominee for the Partnership under a form
of nominee agreement to be entered into between the nominee and the
Partnership. Under the form of nominee agreement, the nominee will disclaim
any beneficial interest in the Partnership Properties held as nominee for the
Partnership.
Marketing of Reserves
The General Partner has the authority to market the oil and gas
production of the Partnership. In this connection, it may execute on behalf of
the Partnership division orders, contracts for the marketing or sale of oil,
gas or other hydrocarbons or other marketing agreements. Sales of the oil and
gas production of the Partnership will be to independent third parties or to
the General Partner or its affiliates (see "CONFLICTS OF INTEREST").
Conduct of Operations
The General Partner will have full, exclusive and complete discretion
and control over the management, business and affairs of the Partnership and
will make all decisions affecting the Partnership Properties. To the extent
that Partnership funds are reasonably available, the General Partner will
cause the Partnership to (1) test and investigate the Partnership Properties by
appropriate geological and geophysical means, (2) conduct drilling and
development operations on such Partnership Properties as it deems appropriate
in view of such testing and investigation, (3) attempt completion of wells so
drilled if in its opinion conditions warrant the attempt and (4) properly equip
and complete productive Partnership Wells. The General Partner will also
cause the Partnership's productive wells to 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
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pooled or unitized with other properties owned by third parties. In such
cases, and in all cases where Partnership Properties are operated by third
parties, the General Partner will, where appropriate, make or cause to be made
and enter into operating agreements, pooling agreements, unitization
agreements, etc., in the form in general use in the area where the affected
property is located. The General Partner is also authorized to execute
production sales contracts on behalf of the Partnership.
APPLICATION OF PROCEEDS
The Aggregate Subscription will be used to pay costs and expenses
incurred in the operations of the Partnership which are chargeable to the
Limited Partners. The organizational costs of the Partnership and the offering
costs of the Units will be paid by the General Partner.
If all 500 Units offered hereby are sold, the proceeds to the
Partnership would be $500,000. If the minimum 50 Units are sold, the proceeds
to the Partnership would be $50,000. The General Partner estimates that the
gross proceeds will be expended as follows:
$500,000 Program $50,000 Program
---------------- ----------------
Percent Amount Percent Amount
Leasehold Acquisition Costs
of Properties to Be Drilled.. 5% $ 25,000 5% $ 2,500
Drilling Costs of Exploratory
Wells........................ 5% 25,000 5% 2,500
Drilling Costs of Develop-
ment Wells................... 70% 350,000 70% 35,000
Leasehold Acquisition Costs
of Productive Properties..... 20% 100,000 20% 10,000
Total..................... 100% $500,000 100% $50,000
The foregoing allocation between Drilling Costs and Leasehold
Acquisition Costs is solely an estimate and the actual percentages may vary
materially from this estimate. Funds otherwise available for drilling
Exploratory Wells will be reduced to the extent that such funds are used in
conducting development operations in which the Partnership participates. If
only the minimum Aggregate Subscription of $50,000 is received, the percentage
interest owned in each property will have to be reduced.
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.
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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 1995 in which the Partnership participates as a co-general
partner will also be paid by the General Partner. All other Partnership costs
and expenses will be charged 99% to the Limited Partners and 1% to the General
Partner until such time as the Aggregate Subscription has been fully expended.
Thereafter and until the General Partner's Minimum Capital Contribution has
been fully expended, all of such costs and expenses will be charged to the
General Partner. After the General Partner's Minimum Capital Contribution has
been fully expended, such costs and expenses will be charged to the respective
accounts of the General Partner and the Limited Partners on the basis of their
respective Percentages (see "GLOSSARY").
All Partnership Revenues will be allocated between the General Partner
and the Limited Partners on the basis of their respective Percentages.
The General Partner's Minimum Capital Contribution will be determined
as of December 31, 1995 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, 1995 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.
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The following table presents a summary of the allocation of Partnership
costs, expenses and revenues between the General Partner and the Limited
Partners:
General Limited
COSTS AND EXPENSES Partner Partners
-------- --------
. Organizational and offering costs
of the Partnership and any drilling
or income programs in which the
Partnership participates as a
co-general partner 100% 0%
. All other Partnership Costs and
Expenses:
. Prior to time Limited Partner
Capital Contributions are
entirely expended 1% 99%
. After expenditure of Limited
Partner Capital Contributions
and until expenditure of
General Partner's Minimum
Capital Contribution 100% 0%
. After expenditure of General General Part Limited Part
Partner's Minimum Capital ner's Per- ners' Per-
Contribution centage centage
REVENUES General Part Limited Part
ner's Per- ners' Per-
centage centage
COMPENSATION
Supervision of Operations
It is anticipated that the General Partner will operate most, if not
all, Partnership Properties during the drilling of Partnership Wells and most,
if not all, productive Partnership Wells. For the General Partner's services
performed as operator, the Partnership will compensate the General Partner its
pro rata portion of the compensation due to the General Partner under the
operating agreements, if any, in effect with respect to such wells or, if none
is in effect for such wells, at rates no higher than those normally charged in
the same or a comparable geographic area by non-affiliated persons or companies
dealing at arm's length.
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That portion of the General Partner's general and administrative
overhead expense that is attributable to its conduct of the actual and
necessary business, affairs and operations of the Partnership will be
reimbursed by the Partnership out of Partnership Revenue. The General
Partner's general and administrative overhead expenses are determined in
accordance with industry practices. The costs and expenses to be allocated
include all customary and routine legal, accounting, geological, engineering,
travel, office rent, telephone, secretarial, salaries, data processing, word
processing and other incidental reasonable expenses necessary to the conduct of
the Partnership's business and generated by the General Partner or allocated to
it by UNIT, but will not include filing fees, commissions, professional fees,
printing costs and other expenses incurred in forming the Partnership or
offering interests therein. The amount of such costs and expenses to be
reimbursed with respect to any particular period will be determined by
allocating to the Partnership that portion of the General Partner's total
general and administrative overhead expense incurred during such period which
is equal to the ratio of the Partnership's total expenditures compared to the
total expenditures by the General Partner for its own account. The portion of
such general and administrative overhead expense reimbursement which is charged
to the Limited Partners may not exceed an amount equal to 3% of the Aggregate
Subscription during the first 12 months of the Partnership's operations, and in
each succeeding twelve-month period, the lesser of (a) 2% of the Aggregate
Subscription and (b) 10% of the total Partnership Revenue realized in such
twelve-mo nth 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 a nd 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
has a subsidiary which owns and operates natural gas gathering systems, salt
water disposal system s and natural gas processing plants and such subsidiary
may perform services for the Partnership and may purchase a portion of the
Partnership's oil or gas production.
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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 charge d 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 predecessor, Unit Drilling and
Exploration Comp any ("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 U NIT. 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 Limit ed 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, 1994, 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 $1,431,023 $2,101,363 $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.......... -- 174,547 584,297 829,503
1984 Employee(*) -- 3,924 5,000 13,452
1985 Employee(*) -- 10,316 -- 54,892
1986 Employee(*) -- 23,505 -- 59,446
1986 Energy
Income Fund(**) -- 100,868 553,576 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. -- 121,363 -- 144,722
1992 Employee. -- 25,354 -- 14,861
1993 Employee. -- 11,213 -- 68,504
Consolidated
Program(*) -- 9,863 -- --
1994 Employee. -- 3,250 -- 29,614
_____________
(*) 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 - 1994 Employee Programs and no management fee is
payable by the Partnership to UNIT or any of its affiliates.
(2) Paid only to UDEC.
(3) In the case of compensation for supervision and operation of
productive wells and reimbursement of UNIT's general and administrative
overhead expense, the general partners generally were charged with and paid a
percentage of such amounts equal to the percentage of partnership revenues
being allocated to them.
(4) Although the partnership agreement for each of the 1985-1994
Employee Programs provides that the General Partner is entitled to
reimbursement for the general administrative and overhead expenses attributable
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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 totalling
$500,000.
MANAGEMENT
The General Partner
UNIT was formed in 1986 in connection with a major reorganization and
recapitalization whereby UNIT acquired all of the assets and liabilities of all
of the limited partnerships formed by UNIT's predecessor, UDEC, during the
period of 1980 through 1983 in exchange for shares of UNIT's common stock and
UDEC was merged with a wholly owned subsidiary of UNIT whereby UDEC was the
surviving corporation and thereby became a wholly owned subsidiary of UNIT.
UPC was incorporated in the State of Oklahoma on February 9, 1984 as Sunshine
Development Corporation ("SDC"). On October 8, 1985 pursuant to the terms of a
"Stock Purchase Agreement," UDEC purchased all of the issued and outstanding
stock of SDC whereby SDC became a wholly owned subsidiary of UDEC. On
February 1, 1988, pursuant to the terms of an "Amended and Restated Certificate
of Incorporation", SDC was renamed Unit Petroleum Company.
UPC's as well as UNIT's, principal office is at 1000 Kensington Tower
I, 7130 South Lewis Avenue, Tulsa, Oklahoma 74136 and its telephone number is
(918) 493-7700. UNIT through its various subsidiaries is engaged in the
onshore contract drilling of oil and gas wells and in the exploration for and
production of oil and gas. Unless the context otherwise requires, references
in this Memorandum to UNIT include its predecessor as well as all or any of its
subsidiaries.
Officers, Directors and Key Employees
The Partnership will have no directors or officers. The directors of
the General Partner are elected annually and serve until their successors are
elected and qualified. Directors of UNIT are elected at the Annual Meeting of
Shareholders for a staggered term of three years each, or until their
successors are duly elected and qualified. The executive officers of the
General Partner are elected by and serve at the pleasure of its Board of
Directors. The names, ages and respective posit ions of the directors and
executive officers of UNIT are as follows:
Name Age Position
---- --- --------
King P. Kirchner 67 Chairman of the Board and
Chief Executive Officer
John G. Nikkel 59 President, Chief
Operating Officer and
Director
Philip M. Keeley 53 Senior Vice President,
Exploration and Production
O. Earle Lamborn 59 Senior Vice President,
Drilling and Director
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Larry D. Pinkston 40 Vice President, Treasurer
and Chief Financial
Officer
Mark E. Schell 37 Secretary and General
Counsel
William B. Morgan 50 Director
Don Cook 69 Director
John S. Zink 66 Director
John H. Williams 76 Director
Don Bodard 74 Director
The names, ages and respective positions of the directors and executive
officers of UPC are as follows:
Name Age Position
---- --- --------
John G. Nikkel 59 Chairman of the Board
and President
Philip M. Keeley 53 Vice President and
Director
Mark E. Schell 37 Secretary, General Counsel
and Director
Larry D. Pinkston 40 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.
Mr. Lamborn has been actively involved in the oil industry for over 35
years, joining UNIT's predecessor in 1952 when it was a privately-held
corporation. He was elected Vice President-Drilling in 1973 and to his present
position as Senior V ice President and Director in 1979.
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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. 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. 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. Morgan was elected a Director of UNIT in February, 1988. He is a
partner in the law firm of Doerner, Stuart, 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 a
principal in several privately held companies engaged in the businesses of
designing and manufacturing equipment used in the petroleum industry,
construction and heating and air conditioning services and installation. He
holds a Bachelor of Science degree in Mechanical Engineering from Oklahoma
State University. He is also a director of Banks of Mid America, Tulsa and
Oklahoma City, Oklahoma and Matrix Corp.
Mr. Williams was elected a Director of UNIT in December of 1988. Prior
to his retirement in December 1978, he was Chairman of the Board and Chief
Executive Officer of The Williams Companies, Inc.
Mr. Bodard, a co-founder of UNIT, served as a Director from 1963 until
February, 1988 when he resigned. From February, 1988 until August 23, 1994,
when Mr. Bodard was again elected to be a Director of Unit, he served as a
Consultant to the Board of Directors. He is Secretary-Treasurer of Bodard &
Hale Drilling Company, an Oklahoma based drilling company, President of Bodard
Drilling Company, Inc., an Oklahoma based oil service company, and owner of
Bodard Equipment Company, a sole proprietorship, of Shawnee, Oklahoma. He is
also chairman of the Board of Ameribank.
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Prior Employee Programs
Since 1984, UNIT has formed limited partnerships for investment by
certain of its key employees and directors that participate with UNIT in its
exploration and production operations. The name, month of formation and amount
of limited partner capital subscriptions of each of these limited partnerships
(the "Employee Programs") are set forth below.
Limited Partners'
Name Formed Capital Subscriptions
---- ---------- ---------------------
Unit 1984 Employee Oil and
Gas Program April 1984 $348,000
Unit 1985 Employee Oil and
Gas Limited Partnership January 1985 $378,000
Unit 1986 Employee Oil and
Gas Limited Partnership January 1986 $307,000
Unit 1987 Employee Oil and
Gas Limited Partnership March 1987 $209,000
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
One-half of the capital subscriptions from all limited partners,
including those shown below, were required to be paid in the 1984 Employee
Program, three-fourths of the capital subscriptions from all limited partners,
including those shown below, were required to be paid in the 1985 Employee
Program, and three-fourths of the capital subscriptions from all limited
partners, including those shown below, were required to be paid in 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 1994
Employee Programs. The capital subscriptions of the following limited partners
to the 1992, 1993 and 1994 Employee Programs were as shown be low:
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Amount of Capital
Subscription
Position with --------------------------------
Subscriber UNIT 1992 1993 1994
---------- ------------- ------- ------- -------
King P. Kirchner Chairman of the Board $50,000(1) $50,000(1) $50,000(1)
and Chief Executive
Officer
John G. Nikkel President, Chief $90,840(2) $72,130(2) $98,000(2)
Operating Officer
and Director
Philip M. Keeley Senior Vice President, $29,160(2) $18,870(2) $22,000(2)
Exploration and
Production
Don Bodard Director $50,000 $50,000 $50,000
__________________
(1) Mr. Kirchner invested $50,000 indirectly in each of the 1992
Employee Program, the 1993 Employee Program, and the 1994 Employee Program,
through the King P. Kirchner Revocable Trust as permitted by the limited
partnership agreement o f those Employee Programs.
(2) Messrs. Nikkel and Keeley have invested in the 1991, 1992 and
1993 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 1992, 1993 and
1994 Employee Programs by Messrs. Nikkel and Keeley are set forth below:
Nike
Employee Mr. Nikkel Mr. Keeley Exploration
Program Directly Directly Company
-------- ---------- ---------- -----------
1992 $48,000 $12,000 $60,000
1993 $40,000 $ 6,000 $45,000
1994 $50,000 $10,000 $60,000
Ownership of Common Stock
UNIT's Common Stock is listed on the New York Stock Exchange as
reported on the Composite Tape. On December 21, 1994, there were
20,910,190 shares outstanding.
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As of December 21, 1994, the only shareholders who owned of record or
who were known by UNIT to own beneficially more than 5 % of its total
outstanding shares of Common Stock were:
Name and Address % of
of Beneficial Owner Shares(1) Outstanding(1)
------------------- --------- -----------
King P. Kirchner
1000 Kensington Centre 1,379,269(2) 6.59%
7130 South Lewis Avenue
Tulsa, Oklahoma 74136
Don Bodard
313 Masonic Building 1,680,428 8.03%
Shawnee, Oklahoma 74801
Scottish Amicable Life
Assurance Society
7 Hanover Square 1,755,000(3) 8.39%
New York, New York 10004
Dimensional Fund Advisors Inc.
1299 Ocean Avenue, 11th Floor 1,273,600(4) 6.09%
Santa Monica, California 90401
The Energy Recovery Fund
Limited Partnership
6610 Rockledge Drive 1,584,100(5) 7.57%
Bethesda, Maryland 20817
__________________
(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 21, 1994, pursuant to the exercise of currently
exercisable war rants 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 December 21, 1994, pursuant to the exercise of currently
exercisable warrants or stock options.
(2) The number of shares involves 3,443 shares held under Unit's
401(k) Thrift Plan as of December 31, 1993.
(3) 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
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and 245,000 warrants. Unit Trust holds shared voting power over 470,000 shares
of common stock and 120,000 warrants. Pension holds shared voting power with
respect to 590,000 shares of common stock and 125,000 warrants.
(4) This information is based on Amendment No. 1 to Schedule 13G,
dated February 10, 1993, filed with the Securities and Exchange Commission by
Dimensional Fund Advisors Inc. ("Dimensional"). Dimensional, a registered
investment advisor, is deemed to have beneficial ownership of 1,273,600 shares
of common stock as of December 31, 1992, all of which shares are held in
portfolios of DFA Investment Dimensions Group Inc., a registered open-end
investment company, or the DFA Group Trust and DFA Participation Group Trust,
investment vehicles for qualified employee benefit plans, all of which
Dimensional serves as investment manager. Dimensional disclaims beneficial
ownership of all such shares.
(5) This information is based on the most recent amendment, dated
September 17, 1992, to the Schedule 13D filed with the Securities and Exchange
Commission by Energy Recovery Fund Limited Partnership, Mr. Robert E. Torray
and Mr. Frank A. Benevento, II. The Energy Recovery Fund Limited Partnership
holds shared voting power and shared dispositive power with respect to
1,418,100 shares of common stock and 165,000 warrants. Mr. Torray holds 1,000
shares of common stock with sole voting power and dispositive power, and
1,418,100 shares of common stock and 165,000 warrants with shared voting power
and shared dispositive power. Mr. Benevento, II holds 1,418,000 shares of
common stock and 165,000 warrants with shared voting power.
As of December 12 , 1994, 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................ 8,500 (2) *
Don Cook..................... 13,638 (2) *
Philip M. Keeley............. 218,422 (3)(4) *
O. Earle Lamborn............. 326,773 (4) 1.55
John G. Nikkel............... 349,075 (4) 1.64
Larry D. Pinkston............ 72,234 (4) *
Mark E. Schell............... 33,530 (4) *
John S. Zink................. 18,500 (2) *
William B. Morgan............ 17,500 (2) *
All Officers and Directors
as a Group (consisting
of 11 persons including
Mr. Kirchner).............. 4,117,869 (4)(5) 19.15
_____________________
*Less than .1%
(1) The number of shares includes the shares presently issued and
outstanding plus the number of shares which any owner has the right to acquire
within 60 days after December 12, 1994, pursuant to the exercise of currently
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exercisable war rants 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 December 12 , 1994, pursuant to the exercise of currently
exercisable warrants or stock options.
(2) Includes unexercised stock options under UNIT's non-Employee
Directors' Stock Option Plan, to each of the following which may be exercised
at the discretion of the holder: Don Cook, 7,500; William B. Morgan, 7,500;
John H. Williams, 7,500; John S. Zink, 7,500; and all non-Employee Directors
as a group, 30,000.
(3) Includes warrants to purchase 2,100 shares of common stock.
(4) Includes shares of common stock held under UNIT's 401(k) thrift
plan as of December 31, 1993 for the account of: Earle Lamborn, 5,813; John G.
Nikkel, 23,221; Philip M. Keeley, 27,813; Larry D. Pinkston, 7,769; and Mark E.
Schell, 4,5 15.
(5) Includes options to purchase 581,500 shares of common stock and
warrants to purchase 2,100 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.
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.
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. 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,
1995, or from the formation of the Partnership if subsequent to January 1,
1995, through December 31, 1995 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 pa y any of the Drilling Costs thereof;
(iv) acquired by UNIT or the General Partner through the
acquisition by UNIT or the General Partner of, or
merger of UNIT or the General Partner with, other
companies; or
(v) with respect to which the General Partner does not
believe that the potential economic return therefrom
justifies the costs and participation by the
Partnership.
As a result, the Partnership may have an interest in wells located on prospects
on which producing wells have been drilled by UNIT or the General Partner in
prior years. Likewise, it is possible that the Partnership will participate in
the drilling of initial wells on prospects on which some or all of the
development or offset wells will be drilled in years subsequent to 1995. 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
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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, 1995,
or from the formation of the Partnership if subsequent to January 1, 1995,
through December 31, 1995. 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, 1995, or from the
formation of the Partnership if subsequent to January 1, 1995, through December
31, 1995. Likewise the Partnership would have no interest in any increased
density wells drilled on the original spacing unit unless such wells were
drilled during 1995. In addition, if additional interests are acquired in
wells participated in by the Partnership after 1995, the Partnership will
generally not be entitled to participate in the acquisition of such additional
interests. Management believes that the apparent conflicts of interest
arising from these situations are mitigated by the fact that the Partnership is
expected to participate in all of UNIT's drilling operations (with the
exceptions noted above) conducted during the period. Thus, there is little
opportunity for the General Partner to selectively choose Partnership drilling
locations for the purpose of proving up other properties of UNIT or its
affiliates in which the Partnership has no interest. Further, the Partnership
will benefit in many instances by its participation in the drilling of wells
located on prospects previously proved up by drilling operations conducted by
UNIT prior to formation of the Partnership.
Participation in UNIT's Drilling or Income Programs
If UNIT forms any drilling or income programs in 1995, 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
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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
1995.
A sale, transfer or conveyance to the Partnership of less than all of
the ownership of the General Partner or its affiliates in any interest or
property is prohibited unless:
(1) the interest retained by the General Partner or its affiliates
is a proportionate working interest;
(2) the obligations of the Partnership with respect to the
properties will be substantially the same proportionately as
those of the General Partner or its affiliates at the time it
acquired the properties; and
(3) the Partnership's interest in revenues will not be less than
the proportionate interest therein of the General Partner or
its affiliates when it acquired the properties.
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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 m embers, 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 through its
subsidiary Mountain Front Pipeline Company, Inc. engages in the business of
owning and operating natural gas gathering systems, salt water disposal
systems and natural gas processing plants and may engage in the business of
purchasing crude oil and natural gas. It is anticipated that the Partnership
will obtain services, equipment and supplies from some or all of such persons.
In addition, UNIT may supply other goods or services to the Partnership. The
terms of any contracts or agreements between the Partnership and UNIT or any
affiliate will be no less favorable to the Partnership than t hose of
comparable contracts or agreements entered into, and will be at prices not in
excess of (or in the case of purchases of production, less than) those charged
in the same geographical area, by non-affiliated persons or companies dealing
at arm's length.
For its services as a drilling contractor, UNIT 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
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drilled) or a turnkey (specified amount for drilling the well) basis. The rate
charged by UNIT or any affiliate 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, t he 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 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 and
the Partnership by such firm will not be disadvantageous to the Partnership.
FIDUCIARY RESPONSIBILITY
General
Under Oklahoma law, the General Partner will have a fiduciary duty to
the Limited Partners and consequently must exercise good faith, fairness and
loyalty in the handling of the Partnership's affairs. The General Partner must
provide Limited Partners (or their representatives) with timely and full
information concerning matters affecting the business of the Partnership. Each
Limited Partner may inspect the Partnership's books and records upon reasonable
prior notice. The nature of the fiduciary duties of general partners is an
evolving area of law and prospective investors who have questions concerning
the duties of the General Partner should consult with their counsel.
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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
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
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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 asset s 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 December 31, 1994 by UNIT during each year
since 1975. Because of the unpredictability of oil and gas exploration in
general, such results should not be considered indicative of the results that
may be achieved by the Partnership.
Gross Wells(2) Net Wells(3)
Year Ended -------------------- ------------------------
July 31(1) Total Oil Gas Dry Total Oil Gas Dry
----- --- --- --- ----- ----- ---- ---
1975 Exploratory........ 2 0 2 0 .01 0 .01 0
Development........ 4 0 2 2 .07 0 .03 .04
----- --- --- --- ----- ----- ---- ---
6 0 4 2 .08 0 .04 .04
----- --- --- --- ---- ----- ---- ---
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Gross Wells(2) Net Wells(3)
-------------------- ------------------------
Total Oil Gas Dry Total Oil Gas Dry
----- --- --- --- ----- ----- ---- ----
1976 Exploratory........ 1 0 0 1 .01 0 0 .01
Development........ 8 0 6 2 .29 0 .28 .01
----- --- --- --- ----- ----- ---- ----
9 0 6 3 .30 0 .28 .02
----- --- --- --- ----- ----- ---- ----
1977 Exploratory........ 9 0 3 6 1.50 0 .45 1.05
Development........ 16 0 9 7 2.00 0 .70 1.30
----- --- --- --- ----- ----- ---- ----
25 0 12 13 3.50 0 1.15 2.35
----- --- --- --- ----- ----- ---- ----
1978 Exploratory........ 8 1 1 6 1.17 .34 .15 .68
Development........ 26 0 13 13 2.64 0 .76 1.88
----- --- --- --- ----- ----- ---- ----
34 1 14 19 3.81 .34 .91 2.56
----- --- --- --- ----- ----- ---- ----
1979 Exploratory........ 10 0 5 5 1.40 0 .76 .64
Development........ 16 1 8 7 1.99 .06 .95 .98
----- --- --- --- ----- ----- ---- ----
26 1 13 12 3.39 .06 1.71 1.62
----- --- --- --- ----- ----- ---- ----
1980 Exploratory........ 1 0 1 0 1.28 0 .23 1.05
Development........ 10 0 8 2 3.13 0 .85 2.28
----- --- --- --- ----- ----- ---- ----
11 0 9 2 4.41 0 1.08 3.33
----- --- --- --- ----- ----- ---- ----
Year Ended
December 31(1)
1981 Exploratory........ 14 1 4 9 1.12 .02 .16 .94
Development........ 66 18 29 19 7.38 2.96 1.77 2.65
----- --- --- --- ----- ----- ---- ----
Total 80 19 33 28 8.50 2.98 1.93 3.59
----- --- --- --- ----- ----- ---- ----
1982 Exploratory........ 40 5 9 26 3.39 .60 .32 2.47
Development........ 100 22 51 27 11.70 4.70 2.71 4.29
----- --- --- --- ----- ----- ---- ----
Total 140 27 60 53 15.09 5.30 3.03 6.76
----- --- --- --- ----- ----- ---- ----
1983 Exploratory........ 6 2 0 4 1.31 .72 0 .59
Development........ 72 18 26 28 8.01 3.45 1.17 3.39
----- --- --- --- ----- ----- ---- ----
Total 78 20 26 32 9.32 4.17 1.17 3.98
----- --- --- --- ----- ----- ---- ----
1984 Exploratory........ 2 1 1 0 .52 .49 .03 0
Development........ 50 15 22 13 6.81 3.42 2.74 .65
----- --- --- --- ----- ----- ---- ----
Total 52 16 23 13 7.33 3.91 2.77 .65
----- --- --- --- ----- ----- ---- ----
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Gross Wells(2) Net Wells(3)
-------------------- ------------------------
Total Oil Gas Dry Total Oil Gas Dry
----- --- --- --- ----- ----- ---- ----
1985 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 38 11 16 11 8.32 2.89 2.39 3.04
----- --- --- --- ----- ----- ---- ----
Total 38 11 16 11 8.32 2.89 2.39 3.04
----- --- --- --- ----- ----- ---- ----
1986 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 21 4 6 11 3.85 .81 1.01 2.03
----- --- --- --- ----- ----- ---- ----
Total 21 4 6 11 3.85 .81 1.01 2.03
----- --- --- --- ----- ----- ---- ----
1987 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 46 23 10 13 11.91 7.95 1.76 2.34
----- --- --- --- ----- ----- ---- ----
Total 46 23 10 13 11.91 7.95 1.76 2.34
----- --- --- --- ----- ----- ---- ----
1988 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 39 20 10 9 22.56 14.77 4.05 3.74
----- --- --- --- ----- ----- ---- ----
Total 39 20 10 9 22.56 14.77 4.05 3.74
----- --- --- --- ----- ----- ---- ----
1989 Exploratory........ 3 0 1 2 1.97 0 .47 1.50
Development........ 40 12 15 13 18.83 8.81 4.13 5.89
----- --- --- --- ----- ----- ---- ----
Total 43 12 16 15 20.80 8.81 4.60 7.39
----- --- --- --- ----- ----- ---- ----
1990 Exploratory........ 5 0 2 3 1.22 0 .12 1.10
Development........ 35 11 14 10 16.53 8.38 3.52 4.63
----- --- --- --- ----- ----- ---- ----
Total 40 11 16 13 17.75 8.38 3.64 5.73
----- --- --- --- ----- ----- ---- ----
1991 Exploratory........ 4 0 0 4 .82 0 0 .82
Development........ 28 10 9 9 15.88 8.61 3.91 3.36
----- --- --- --- ----- ----- ---- ----
Total 32 10 9 13 16.70 8.61 3.91 4.18
----- --- --- --- ----- ----- ---- ----
1992 Exploratory........ 0 0 0 0 0 0 0 0
Development........ 18 1 11 6 5.81 1.00 3.33 1.48
----- --- --- --- ----- ----- ---- ----
Total 18 1 11 6 5.81 1.00 3.33 1.48
----- --- --- --- ----- ----- ---- ----
1993 Exploratory........ 1 0 0 1 .10 0 0 .10
Development........ 16 9 6 1 12.48 8.98 3.32 .18
----- --- --- --- ----- ----- ---- ----
Total 17 9 6 2 12.58 8.98 3.32 .28
----- --- --- --- ----- ----- ---- ----
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Gross Wells(2) Net Wells(3)
-------------------- ------------------------
Total Oil Gas Dry Total Oil Gas Dry
----- --- --- --- ----- ----- ---- ----
1994 Exploratory....... 3 0 1 2 1.71 0 .95 .76
Development........ 57 5 40 12 24.42 4.75 12.77 6.90
Total 60 5 41 14 26.13 4.75 13.72 7.66
________________
(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 well s 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 interest
in a well drilled represents 1.0 Gross Well, but a .50 Net
Well.
Prior Employee Programs
During the period of 1979 to 1983, persons who were designated key
employees of UNIT by its board of directors participated in the Unit Key
Employee Exploration Funds (the "Funds"). These Funds were formed as general
partnerships for the purpose of participating in 10% of all of the exploration
and development operations conducted by UNIT during a specified period. Except
for the Fund formed in 1983, each of the prior Funds served as one of the
general partners in at least one of the prior drilling programs sponsored by
UNIT and was allocated 10% of the expenses and revenues allocable to the
general partners as a group. In each of these Funds the costs charged to it in
connection with its operations were financed with the proceed s 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 equalled 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 Fund s should not be considered indicative of the results the
Partnership may achieve.
For each year from 1984 through 1994, 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
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Employee Programs, in which case the percentage participation was 15% and the
1992, 1993 and 1994 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 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 limit ed 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 w ere
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 19 82-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
December 31, 1994, and the economic results at September 30, 1994 of prior oil
and gas programs and the 1984, 1985, 1986, 1987, 1988, 1989, 1990, 1991, 1992,
1993 and 1994 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 o f 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
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and Gas Program continues in existence as do the 1991, 1992, 1993 and 1994
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 December 31, 1994
Gross Wells Net Wells
-------------------- ------------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- ----- --- --- --- ----- ----- ---- ----
1979 Exploratory Wells 6 0 2 4 2.43 0.00 0.65 1.78
Development Wells 21 16 1 4 17.28 14.14 0.03 3.11
----- --- --- --- ----- ----- ---- ----
Total.......... 27 16 3 8 19.71 14.14 0.68 4.89
----- --- --- --- ----- ----- ---- ----
1980(1) Exploratory Wells 15 2 5 8 5.65 0.50 2.14 3.01
Development Wells 32 5 15 12 12.77 1.17 5.75 5.85
----- --- --- --- ----- ----- ---- ----
Total.......... 47 7 20 20 18.42 1.67 7.89 8.86
----- --- --- --- ----- ----- ---- ----
1981(1) Exploratory Wells 11 1 4 6 4.61 0.33 0.88 3.40
Development Wells 67 14 34 19 21.77 5.03 6.61 10.13
----- --- --- --- ----- ----- ---- ----
Total.......... 78 15 38 25 26.38 5.36 7.49 13.53
----- --- --- --- ----- ----- ---- ----
1981-II(1) Exploratory Wells 13 1 5 7 5.21 0.25 1.12 3.84
Development Wells 45 3 29 13 9.07 0.69 4.78 3.60
----- --- --- --- ----- ----- ---- ----
Total.......... 58 4 34 20 14.28 0.94 5.90 7.44
----- --- --- --- ----- ----- ---- ----
1982-A(1) Exploratory Wells 11 3 1 7 3.55 0.78 0.00 2.77
Development Wells 69 23 22 24 25.22 13.09 3.59 8.54
----- --- --- --- ----- ----- ---- ----
Total.......... 80 26 23 31 28.77 13.87 3.59 11.31
----- --- --- --- ----- ----- ---- ----
1982-B(1) Exploratory Wells 4 1 1 2 2.28 0.80 0.08 1.40
Development Wells 41 16 9 16 18.60 9.47 1.01 8.12
----- --- --- --- ----- ----- ---- ----
Total.......... 45 17 10 18 20.88 10.27 1.09 9.52
----- --- --- --- ----- ----- ---- ----
1983-A(1) Exploratory Wells 1 1 0 0 1.00 1.00 0.00 0.00
Development Wells 26 14 10 2 6.60 4.39 1.27 0.94
----- --- --- --- ----- ----- ---- ----
Total.......... 27 15 10 2 7.60 5.39 1.27 0.94
----- --- --- --- ----- ----- ---- ----
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Gross Wells Net Wells
-------------------- ------------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- ----- --- --- --- ----- ----- ---- ----
1984 Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells 21 1 10 10 5.89 .38 3.08 2.43
----- --- --- --- ----- ----- ---- ----
Total.......... 21 1 10 10 5.89 .38 3.08 2.43
----- --- --- --- ----- ----- ---- ----
(1) On September 12, 1986, Unit acquired all of the assets and liabilities of
this Program and the Program has been dissolved.
EMPLOYEE PROGRAMS
-----------------
As of December 31, 1994
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
----- --- --- --- ----- ----- ---- ----
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Gross Wells Net Wells
-------------------- ------------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- ----- --- --- --- ----- ----- ---- ----
1990(1) Exploratory Wells 5 0 2 3 .122 0 .01 .11
Empl. Development Wells 34 11 14 9 1.65 .83 .35 .46
----- --- --- --- ----- ----- ---- ----
Total.......... 39 11 16 12 1.78 .83 .36 .57
----- --- --- --- ----- ----- ---- ----
1991 Exploratory Wells 4 0 0 4 .08 0 0 .08
Empl. Development Wells 28 10 9 9 1.59 .86 .39 .34
----- --- --- --- ----- ----- ---- ----
Total.......... 32 10 9 13 1.67 .86 .39 .42
----- --- --- --- ----- ----- ---- ----
1992 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 18 1 11 6 .29 .05 .17 .07
----- --- --- --- ----- ----- ---- ----
Total.......... 18 1 11 6 .29 .05 .17 .07
----- --- --- --- ----- ----- ---- ----
1993 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 16 9 6 1 .63 .45 .17 .01
----- --- --- --- ----- ----- ---- ----
Total.......... 16 9 6 1 .63 .45 .17 .01
----- --- --- --- ----- ----- ---- ----
1994 Exploratory Wells 3 0 1 2 .09 0 .05 .04
Empl. Development Wells 57 5 40 12 1.28 .25 .67 .36
----- --- --- --- ----- ----- ---- ----
Total.......... 60 5 41 14 1.37 .25 .72 .40
----- --- --- --- ----- ----- ---- ----
________________
(1) Effective December 31, 1993 this Program was merged with and into the
Consolidated Program.
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GENERAL PARTNERS' PAYOUT TABLE(1)
As of September 30, 1994
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, 1994
- --------------------------- ------------ ----------- ------------------
1979....................... $7,291,905 $8,997,700 $55,129
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....................... 2,003,894 1,359,002 19,768
1984 Employee(*)........... 1,542 1,745 -
1985 Employee(*)........... 2,820 1,808 -
1986 Energy Income Fund(**) 984,420 1,055,954 33,161
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.............. 1,440,711 1,043,100 67,658
1992 Employee.............. 136,042 111,453 11,120
1993 Employee.............. 317,565 147,141 42,230
Consolidated Program....... 598 1,684 488
1994 Employee.............. 195,307 15,486 9,622
__________
(*) 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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LIMITED PARTNERS' PAYOUT TABLE(1)
As of September 30, 1994
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, 1994
- --------------------------- ------------ --------- ------------------
1979....................... $12,848,864 $16,576,713 $ 67,522
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....................... 2,645,537 1,420,377 19,832
1984 Employee(*)........... 120,942 171,540 -
1985 Employee(*)........... 277,901 178,984 -
1986 Energy Income Fund(**) 2,142,912 2,702,134 49,822
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.............. 377,442 278,660 18,050
1992 Employee.............. 350,594 289,101 28,691
1993 Employee.............. 293,585 136,447 39,030
Consolidated Program....... 59,423 166,872 48,435
1994 Employee.............. 91,909 7,958 4,822
__________
(*) 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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GENERAL PARTNERS' NET CASH TABLE(1)
As of September 30, 1994
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 1994 Distributed 1994
---------- ---------- ------- --------- ------
1979................. $2,835,079 $4,540,874 ($6,549) 3,591,294 21,000
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................. 903,786 258,894 ( 1,075) 534,741 8,400
1984 Employee(*)..... 874 1,077 - 1,000 -
1985 Employee(*)..... 2,300 1,288 - 1,035 -
1986 Energy Income
Fund(**)........... 210,035 281,569 - 287,203 -
1986 Employee(*)..... 2,698 5,108 17,845 4,486 -
1987 Employee(*)..... 357,368 548,372 - 465,800 -
1988 Employee(*)..... 770,272 1,161,840 - 942,800 -
1989 Employee(*)..... 1,010,133 752,569 - 607,900 -
1990 Employee(*)..... 466,272 338,281 - 266,600 -
1991 Employee........ 1,051,738 654,127 38,793 505,000 49,000
1992 Employee........ 97,325 72,786 7,294 43,500 8,500
1993 Employee........ 285,003 114,579 34,539 29,500 23,000
Consolidated Program. (7) 1,079 294 - -
1994 Employee........ 191,583 11,762 6,780 - -
(*) 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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<TABLE>
LIMITED PARTNERS' NET CASH TABLE(1)
As of September 30, 1994
<CAPTION>
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 1994 Distributed 1994
- --------------- ------------- ---------- ----------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
1979........... $ 3,000,000 $6,193,798 $ 9,921,647 ($ 7,861) $5,867,601 $19,200(5)
1980........... 12,000,000(3) 14,469,265 3,729,906 - 760,000 -
1981........... 29,255,000(4) 32,700,741 11,395,621 - 5,335,065 -
1981-II........ 15,000,000 16,603,760 4,994,106 - 1,710,001 -
1982-A......... 21,140,000 21,591,442 9,434,313 - 6,342,000 -
1982-B......... 10,555,000 9,935,850 3,233,596 - 2,828,740 -
1983-A......... 2,530,000 2,993,705 1,145,026 - 227,700 -
1984........... 1,575,000 2,034,248 809,048 14,024 452,066 17,010(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 1,056,473 1,615,695 17,832 1,426,600 11,100(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.. 253,000 274,227 175,445 10,372 141,494 16,832(8)
1992 Employee.. 240,000 251,167 189,674 18,856 139,440 22,800(9)
1993 Employee.. 245,000 263,667 106,529 31,933 41,895 10,780(10)
Consolidated
Program...... - (713) 106,736 29,162 93,279 43,421(11)
1994 Employee.. 213,000 90,156 6,205 3,484 _ _
</TABLE>
- --------------------
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
(1) Amounts reflect the accrual method of accounting.
(2) Does not include expenditures of $237,600, $920,453,
$2,252,900, $1,480,248, $2,079,268, $985,371 and $241,076 which
were obtained from bank borrowings and used to pay the limited
partners' share of sales commissions of $237,600, $722 ,453,
$1,940,400, $1,183,248, $1,656,468, $827,046 and $190,476 and
organization costs of $--0--, $198,000, $312,500, $297,000,
$422,800, $158,325 and $50,600 for the 1979, 1980, 1981,
1981-II, 1982-A, 1982-B and 1983-A Programs, respectively.
(3) Includes original subscriptions of limited partners totaling
$10,000,000 and additional assessments totaling $2,000,000.
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(4) Includes original subscriptions of limited partners totaling
$25,000,000 and additional assessments totaling $4,255,000.
(5) In November 1994, the 1979 Program made a distribution of
$9,600 to that program's limited partners.
(6) In November 1994, the 1984 Program made a distribution of
$25,200 to that program's limited partners.
(7) In November 1994, the 1986 Energy Income Fund made a
distribution of $8,500 to that program's limited partners.
(8) In November 1994, the 1991 Employee Program made a distribution
of $8,942 to that program's limited partners.
(9) In November 1994, the 1992 Employee Program made a distribution
of $17,760 to that program's limited partners.
(10) In November 1994, the 1993 Employee Program made a distribution
of $34,790 to that program's limited partners.
(11) In November 1994, the Consolidated Program made a distribution
of $32,160 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 Treasury Regulations, proposed Treasury Regulations to the
extent noted, existing administrative interpretations, and existing court
decisions. No assurance can be given that legislation, Treasury Regulations,
administrative interpretations, or court decisions will not significantly
change existing law, or that any of such changes will not be applied
retroactively.
Conner & Winters, A Professional Corporation, tax counsel to the
Partnership ("Counsel"), is of the opinion that to the extent the summary of
federal income tax consequences to the Limited Partners set forth in this
"FEDERAL INCOME TAX ASPECT S" 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.
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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 Partner ship will not, in
general, be subject to income tax. It is expected the income of the
Partnership will be passive income which may be used to offset a Limited
Partner's losses from other passive activities.
Partnership Classification
The federal income tax consequences summarized herein depend on the
classification of the Partnership as a partnership and not as an association
taxable as a corporation for federal income tax purposes. In Counsel's
opinion, the Partnership will be treated as a partnership for federal income
tax purposes assuming the satisfaction at all times of the following
conditions:
(i) A duly executed Certificate of Limited
Partnership for the Partnership will be filed with the Oklahoma
Secretary of State in compliance with the Act and the organization
and operation of the Partnership will be in accordance with the
Agreement and the Act;
(ii) The General Partner will continue to serve as
such and is neither controlled by nor is it acting as agent for the
Limited Partners or any Persons affiliated with the Limited Partners;
(iii) The General Partner has and will maintain substantial
assets which can be reached by a creditor of the Partnership,
exclusive of its interests in the Partnership and notes and accounts
receivable from and payable to the Partnership. At the time of
admission of Limited Partners to the Partnership, the General Partner
will have a net worth equal to at least 10% of the total Capital
Contributions made to the Partnership, excluding any net worth
attributable to any interest of the General Partner in the
Partnership. For purposes of satisfying this net worth requirement,
assets will be valued based upon their current fair market value.
The General Partner will use its best efforts to ensure that the net
worth of the General Partner continues to meet these requirements
throughout the term of the Partnership;
(iv) The General Partner will, in the aggregate, at
all times during the existence of the Partnership, receive at least
1% of each material item of the Partnership's income, gain, loss,
deduction, or credit;
(v) In excess of 90% of the gross income of the
Partnership will be interest income, dividends, (excluding interest
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identified in Section 7704(d)(2) of the Code) and gains derived from
the exploration, development, mining, or production, processing,
refining, transportation, or the marketing of minerals or natural
resources, or gain from the sale or disposition of interests in oil
and gas properties or other items described in Section 7704(d) of the
Code; and
(vi) There are no other documents or agreements
which alter, modify, or change in any way the validity and accuracy
of the above assumptions and information.
If the Partnership were classified as a corporation for federal
income tax purposes, then (a) the taxable income of the Partnership
would be subject to the corporate federal income tax, (b) the income,
gains, losses, deductions and credits of the Partnership (including
deductions for depletion with respect to income from oil and gas
properties would not be taken into account by the Limited Partners in
computing federal income tax, and (c) distributions by the
Partnership would be treated as ordinary income (not subject to
depletion) to the extent of the current and accumulated earnings and
profits of the Partnership. As a result, the after-tax investment
return of a Limited Partner by reason of an investment in the
Partnership would likely be significantly reduced. The following
discussion assumes that the Partnership will be classified as a
partnership and not as a corporation for federal income tax purposes.
Taxation of Limited Partners
A Limited Partner must include in his or her tax return 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, 1995. Due to a lack of authority relating to the allocation of
basis in oil or gas properties consistent with the policy underlying the
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applicable Code Section, Counsel is unable to opine that the manner in which
the Partnership will allocate the basis of each Partnership Property (and
therefore any associated cost depletion deductions) to the Limited Partners
will comply with the relevant Code and Treasury Regulation requirements.
Notwithstanding this uncertainty, Counsel does not believe that any
reallocation of the basis of Partnership Properties in response to a Service
challenge of the proposed method of allocation would differ significantly from
the proposed method which is set out in the Agreement.
Partnership Losses. Subject to the "passive loss" limitation rules
described under "Limitations on Losses and Credits from Passive Activities"
below and the limitations on miscellaneous itemized deductions, each Limited
Partner may deduct his or her share of the Partnership's taxable loss, if any,
on his or her own federal income tax return only to the extent of the lesser of
the Limited Partner's tax basis in his or her Units at the end of the
Partnership's fiscal year in which the loss occurs or the amount that the
Limited Partner is "at risk" with respect to an activity of the Partnership.
Partnership losses which exceed the Limited Partner's tax basis or "at risk"
amount may be deducted in any subsequent year to the extent the Limited
Partner's tax basis and "at risk" amounts are increased above zero. A Limited
Partner's adjusted tax basis in the Partnership will initially be equal to his
or her Capital Contribution. This basis will be 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 f or 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 in come 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 Temporary 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 o pinion 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 o f 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 these 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. These losses will be allowed as deductions against income in
the following order: (i) gain recognize d on the disposition; (ii) net income
or gain for the taxable year from all passive activities; and (iii) any other
income or gain.
Under Section 469(k) of the Code, the limitations on losses and credits
from passive activities will be applied separately to a partnership which is
considered "publicly traded" under Code Section 7704. For this purpose, a
publicly traded partnership is one the interests in which are (a) traded on an
established securities market or (b) readily tradeable on a secondary market
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(or the substantial equivalent thereof). Under the Agreement, the Limited
Partners are prohibited from transfer ring 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 Partner ship 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 i s 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, 1995 (see
"PARTICIPATION IN COSTS AND REVENUES"), the Service may attempt to disallow
deductions claimed by the Limited Partners for all or a portion of the
intangible drilling and development costs specially allocated to them pursuant
to the Agreement. The law provides for a recapture of intangible drilling and
development costs, requiring the taxpayer to treat as ordinary income any gain
on the disposition of oil and gas properties (or any interest in any oil and
gas partnership) to the extent of intangible drilling and development costs
deducted with respect to such properties.
In some cases, the agreements under which the Partnership acquires an
interest in a property may require the Partnership to pay a share of the costs
attributable thereto which is disproportionately greater than the working
interest acquired. In such cases, generally, the excess portion of intangible
drilling and development costs must be capitalized as additional leasehold
costs. However, full deductibility is obtainable under certain arrangements
and in certain circumstances. The General Partner will seek to structure the
agreements for the acquisition of properties in a manner which will permit the
deduction of the full amount of the intangible drilling and development costs
paid but there can be no assurance that it will be able to do so or that the
arrangements will be recognized for federal income tax purposes. Since all of
the facts and terms of such arrangements are not currently known, it is not
practicable to predict the outcome of a challenge to the full deductibility of
such costs.
Depletion. The Partnership will be the owner of economic interests in
its oil and gas properties (except for certain production payments). The
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Limited Partners are entitled to a deduction for depletion with respect to a
Partnership's production and sale of oil and gas from these properties. With
respect to each oil and gas property, a Limited Partner's deduction for each
year is the greater of cost depletion or percentage depletion. Percentage
depletion with respect to a property is equal to 15% of the gross income
attributable to the production from such property, subject to certain
limitations. Percentage depletion is allowable even if the taxpayer has no
basis in the property and continues to be allowable after the taxpayer has
fully depleted his or her basis in the property. Cost depletion allows the
leasehold cost of each producing Partnership Property to be recovered over its
productive life based on units of production. To determine the per unit (i.e.,
barrels of oil or cubic feet of gas) allowance, the adjusted tax basis for the
property is divided by the estimated total units recoverable therefrom. The
cost depletion deduction is the per unit allowance multiplied by the number of
units sold during the year . Depletion computed under this method cannot
exceed the cost or other basis of the producing property. In the case of the
Partnership, the cost or percentage depletion allowance is computed separately
by the Partners, and not by the Partnership.
Nominee Ownership of Partnership Properties. In the event the
Partnership Properties are not held in the name of the Partnership, it is
anticipated that all of the Partnership Properties will be held in the record
name of Unit Texas Company ("UNIT Nominee"), an affiliate of the General
Partner and a wholly-owned subsidiary of Unit Petroleum Company. In Counsel's
opinion the Partnership will be treated, for federal income tax purposes, as
the owner of the Partnership Properties held by UNIT Nominee for its benefit
assuming the accuracy at the time of formation of the Partnership, and the
continuing accuracy thereafter, of the following representations of the General
Partner:
(i) A nominee/agent agreement ("Nominee Agreement")
in substantially the form of the Nominee Agreement attached as
Exhibit I to Counsel's opinion included as Exhibit B to this
Memorandum will be executed by and between UNIT Nominee, as agent,
and the Partnership before any interests in oil and gas properties
are acquired by UNIT Nominee as agent for the Partnership;
(ii) The terms and provisions of the Nominee
Agreement entered into as provided above will be adhered to by each
party thereto and, in particular, UNIT Nominee will be held out as
the agent and not the principal in all dealings with third parties
relating to the oil and gas properties which UNIT Nominee holds as
agent for the Partnership; and
(iii) The beneficial ownership of any oil and gas property
interests to be assigned to the Partnership will be assigned to the
Partnership by delivery to UNIT Nominee, as agent for the
Partnership, of an enforceable written assignment, in substantially
the form of Exhibit II to Counsel's opinion included as Exhibit B to
this Memorandum, properly executed by the assignor.
If the Service were to argue successfully that UNIT Nominee should be treated
as the tax owner of the Partnership's oil and gas properties, there would be
significant adverse federal income tax consequences to the Limited Partners,
such as the unavailability of depletion deductions in respect of income from
oil and gas properties.
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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 a re incurred and will be paid from
Partnership Revenue. Generally, the reimbursements paid to the General Partner
will be currently deductible to the extent they represent ordinary and
necessary business expenses incurred by the Partnership in the course of its
business for services rendered by the General Partner. As all of the facts
regarding the nature of the services to be rendered are not known and may vary
according to the circumstances presented, it is not practical to predict
whether all or a substantial portion of such reimbursement will be deductible,
if challenged, and there can be no assurance that any such challenge would not
ultimately be upheld.
Sales and Distributions. The Partnership's gain on a sale of an
interest in an oil and gas property will be measured by the difference between
the sale proceeds (including the amount of any indebtedness to which the
property is subject) and the adjusted basis of the property. Consequently, the
amount of tax payable by a Limited Partner on his or her share of the
Partnership's allocable share of such gain may in some cases exceed his or her
share of cash proceeds therefrom. Gain realized by the Partnership (and,
thus, the Limited Partners) on a sale of an oil and gas property will be
ordinary income to the extent of the recapture of depreciation, depletion and
intangible drilling and development costs. In that regard, the Partner ship'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 bas is 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
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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 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.
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 who m 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.
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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, 1995 is 9%, compounded daily.
The tax treatment of Partnership items will be determined at the
Partnership level, rather than in separate proceedings with the Partners.
Thus, the availability and amount of the tax deductions taken by the Limited
Partners will depend not only on the general legal principles discussed herein,
but also upon various determinations of the General Partner. These
determinations are subject to challenge by the Service on factual or other
grounds. Generally, each Partner is required to treat Partnership items on
his or her return consistently with the treatment on the Partnership return.
Where this treatment is inconsistent, a statement must be filed by the Partner
identifying the inconsistency. If the consistency requirement is not satisfied
and the identifying statement is not filed, the Service may assess a deficiency
against the Partner before audit proceedings are completed at the Partnership
level. Additionally, if a taxpayer fails to show properly on a return any
amount that is shown on an information return, the taxpayer's failure may be
treated as negligence and subject to a penalty equal to 20% of the underpayment
of tax attributable to the negligence.
The General Partner is to be designated pursuant to Treasury
Regulations as the tax matters partner ("TMP"). The TMP is responsible for
protecting the interests of the Partners in the audit process. In the
Agreement, the General Partner is designated as the TMP and, as such, is given
the right, on behalf of the Partnership, to determine whether to challenge a
final Partnership administrative adjustment proposed by the Service. If the
TMP determines not to challenge an administrative adjustment, any Partner with
at least a 1% interest in the Partnership and any requesting group of Partners
that together have at least a 5% interest in the Partnership may challenge it.
Generally, the period for assessment with respect to Partnership items
for any Partnership taxable year will not expire before three years from (a)
the date of filing the Partnership return or, if later, (b) the last date
prescribed for filing such return determined without extensions. The period
may be extended for all Partners by agreement with the TMP (or other person
authorized in writing by the Partnership).
The procedures regarding the audit of partnerships and the authority of
the TMP are complex and cannot be described completely herein. Each
prospective investor is urged to seek the advise of his or her individual tax
advisor with respect t o those audit provisions.
Laws Subject to Change
The tax aspects described above are based upon interpretations of the
Code as it has been amended to the date of this Memorandum and as Counsel
understand it. Federal income tax laws and regulations and interpretations
thereof are subject to change by Congress, and the courts and administrative
agencies. Regulations have not been issued or proposed under most of the
provisions of recent legislation. For these reasons, no assurance can be given
that the foregoing interpretations will not be challenged or if challenged,
will be sustained or that the favorable tax aspects described above will be
available in future years.
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State and Local Taxes
In addition to the federal income tax aspects described above,
prospective investors should consider with their advisors the state tax
consequences of an investment in Units.
COMPETITION, MARKETS AND REGULATION
The oil and gas industry is highly competitive in all its phases. The
Partnership will encounter strong competition from both major independent oil
companies and individuals, many of which possess substantial financial
resources, in acquiring economically desirable prospects and equipment and
labor to operate and maintain Partnership Properties. There are likewise
numerous companies and individuals engaged in the organization and conduct of
oil and gas drilling programs and there is a high degree of competition among
such companies and individuals in the offering of their programs.
Marketing of Production
The availability of a ready market for any oil and gas produced from
Partnership Wells will depend upon numerous factors beyond the control of the
Partnership, including the extent of domestic production and importation of oil
and gas, the proximity of Partnership Wells to gas pipelines and the capacity
of such gas pipelines, the marketing of other competitive fuels, fluctuation in
demand, governmental regulation of production, refining and transportation,
general national and worldwide economic conditions, and the pricing, use and
allocation of oil and gas and their substitute fuels.
The demand for gas decreased significantly in the 1980s due to economic
conditions, conservation and other factors. As a result of such reduced demand
and other factors, including the Power Plant and Industrial Fuel Use Act (the
"Fuel Use Act") which related to the use of oil and gas in the United States
in certain fuel burning installations, many pipeline companies began purchasing
gas on terms which were not as favorable to sellers as terms governing
purchases of gas prior thereto. S pot 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 a readistant 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
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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 avail able 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 administration in the United States and the potential for a
different focus for the United States energy policy, the General Partner is
unable to predict what future gas and oil prices will be.
Regulation of Partnership Operations
Production of any oil and gas found by the Partnership will be affected
by state and federal regulations. All states in which the Partnership intends
to conduct activities have statutory provisions regulating the production and
sale of oil a nd 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 a t 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 of natural
gas that may be subject to regulation by the Federal Energy Regulatory
Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and/or the
Natural Gas Policy Act of 1 978 ("NGPA"). Under the NGPA, natural gas is
divided into numerous, complex categories based on, among other things, when,
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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 an d 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 b e sold without prior regulatory approval and at
whatever price the market will bear.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Wellhead Decontrol Act") became effective. Consequently, due to this
statutory deregulation and FERC's issuance of Order No. 547 discussed below, as
of January 7, 1993 the price of virtually all gas produced by producers not
affiliated with interstate pipelines has been deregulated by FERC.
Market determined prices for deregulated categories of natural gas
fluctuate in response to market pressures which currently favor purchasers and
disfavor producers. As a result of the deregulation of 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, 1 985), 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.
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Subsequently, the FERC focused on whether the resulting regulatory
structure provided all gas sellers with the same regulatory opportunity to
compete for gas purchasers. It decided that the form of bundled pipeline
services (gas sales and transportation) was unduly discriminatory and
anticompetitive. The FERC concluded that "the pipelines' bundled, city-gate
firm sales service gives pipelines an undue advantage over other gas sellers
because of the superior quality of the 'no-notice' aspect of the
transportation embedded within the bundled, city-gate, firm sales service
compared to the firm and interruptible transportation available for the gas of
nonpipeline gas sellers." Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation; and Regulation of
Natural Gas Pipelines After Wellhead Decontrol, Order No. 636, 57 Fed. Reg.
13,267 (Apr. 16, 1992), III FERC Stats. & Regs. Preambles Paragraph 30,939, at
30,406.
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
gas suppliers and must provide access to storage on an open access contract
basis; pipelines that provided firm sales service on May 18, 1992 must offer a
"no-notice" firm transportation service under which firm shippers may receive
delivery of gas on demand up to their firm entitlements 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 pipe lines 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
t o those desiring capacity (which program replaces previous "capacity
brokering" and "buy-sell" programs); existing bundled firm sales entitlements
are converted to unbundled firm sales entitlements 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 charge the new resulting rates until the
FERC accepts the pipeline's formal restructuring plans. All restructuring
plans had to be filed by December 31, 1992, and are to receive final approval
by FERC by November 1, 1993 (i.e., before the beginning of the 1993-94 winter
heating season).
In addition, in Order 636 the FERC (1) in response to the remand of the
United States Court of Appeals for the District of Columbia in American Gas
Association v. FERC, 912 F.2d 1456 (D.C. Cir. 1990), cert. denied, 111 S. Ct.
957 (1991), amended 18 C.F.R. Section 284.221(d) to protect firm
transportation contracts for one year from abandonment, provided the shipper
matches the highest competing bid up to the maximum lawful rate, (2) concluded
that pipelines should be able to recover 100% of their prudently incurred costs
attributable to Order 636, and (3) adopted measures governing the
implementation of Order 636.
The FERC has clarified several aspects of Order 636. Pipelines Service
Obligations and Revisions to Regulations Governing Self-Implementing
Transportation Under Part 284 of the Commission's Regulations, Regulations of
Natural Gas Pipelines After Partial Wellhead Decontrol, and Order Denying
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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. In Order 636-A t he FERC upheld the primary
requirements of Order 636. In addition, the FERC (1) is requiring pipelines to
maintain their one-part volumetric rates computed at an imputed load factor to
determine transportation rates for "small customers" and is requiring
pipelines for a one year period (from the effective date of the blanket sales
certificate issued pursuant to Order 636) to sell gas to their smallest
customers that elect to continue buying gas from the pipeline at a cost-based
rate (based upon their actual price paid for gas), (2) is allowing pipelines 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 service s, (3) is allowing capacity releases on
a pipeline for any period of less than one month without prior posting on the
electronic bulletin board or bidding for the released capacity, and (4) is
requiring pipelines to recover 10% of their gas supply re alignment costs from
their Part 284 interruptible transportation service.
On November 8, 1992, FERC published Order 636-B. Regulation of Natural
Gas Pipelines After Partial Wellhead Decontrol; Order Denying Rehearing and
Clarifying Order Nos. 636 and 636-A, Order No. 636-B, 57 Fed. Reg. 57,911 (Dec.
8, 1992). Order 636-B essentially upholds without significant change Order
Nos. 636 and 636-A. FERC also stated that it will accept no further petitions
for rehearing. Thus, Order 636 constitutes final agency action.
In essence, the goal of Order 636 is to make a pipeline's position as
gas merchant indistinguishable from that of a non-pipeline supplier. It,
therefore, pushes the point of sale of gas by pipelines upstream, perhaps all
the way to the wellhead. Order 636 also requires pipelines to give firm
transportation customers flexibility with respect to receipt and delivery
points (except that a firm shipper's choice of delivery point cannot be
downstream of the existing primary delivery 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 perm its 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 s pot 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.
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As a corollary to Order 636, FERC issued Order 547, which is a blanket
certificate of public convenience and necessity pursuant to Section 7 of the
NGA that authorizes any person who is not an interstate pipeline or an
affiliate thereof to make sales for resale at negotiated rates in interstate
commerce of any category of gas that is subject to the Commission's NGA
jurisdiction. (There are certain requirements which must be met before an
affiliated marketer of an interstate pipeline can avail itself of this
certification.) Regulations Governing Blanket Marketer Sales Certificates,
Order No. 547, 57 Fed. Reg. 57,952 (Dec. 8, 1992) (to be codified at 18 C.F.R.
Sections 284.401 - .402). The blanket certificates are effective January 7,
1993, and do not require any further application by a person. The goal of
Order 457, in conjunction with Orders 636, 636-A and 636-B, is to provide all
merchants of natural gas a "level playing field" so that gas merchants who are
not interstate pipelines are on an equal footing with interstate pipeline
merchants who are afforded blanket sales certificates pursuant to Order 636.
The FERC is also modifying its traditional use of cost-of-service rate
regulation in order to prevent pipelines from exercising market power.
However, the FERC has begun to allow individual companies to depart from cost-
of-service regulation and set market-based rates if they can show they lack
significant market power or have mitigated 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 g ranted 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 establish ed 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.
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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 re versed
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 in separate, and higher, rates for gathering a producer's natural
gas. In proceedings during mid and late 1994 allowing various interstate
natural gas companies' spindowns or spinoffs of gathering facilities, the FERC
held that, except in limited circumstances of abuse, it generally lacks
jurisdiction over a pipeline's gathering affiliates, which neither transport
natural gas in interstate commerce nor sell gas in interstate commerce for
resale. However, pipelines spinning down gathering systems have to include two
Order No. 497 standards of conduct in their tariffs: nondiscriminatory access
to transportation for all sources of supply and no tying of pipeline
transportation service to any service by the pipeline's gathering affiliate.
In addition, if unable to reach a mutually acceptable gathering contract with a
present user of the gathering facilities, the pipeline must offer a two-year
"default contract" to existing users of the gathering facilities.
Consequently, the General Partner cannot reliably predict at this time how
regulation will ultimately impact Partnership Revenue.
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State Regulation of Oil and Gas Production
Most states in which the Partnership may conduct oil and gas activities
regulate the production and sale of oil and natural gas. Those states
generally impose requirements or restrictions for obtaining drilling permits,
the method of developing new fields, the spacing and operation of wells and
the prevention of waste of oil and gas resources. In addition, most states
regulate the rate of production and may establish maximum daily production
allowable from both oil and gas wells on a market demand or conservation
basis. Until recently there has been no limit on allowable daily production on
the basis of market demand, although at some locations production continues to
be regulated for conservation or market purposes. In 1987 the Oklahoma
Corporation Commission (the "OCC") promulgated production allowable reductions
with respect to relatively high capability gas wells (i.e., those capable of
open flowing more than 2,000,000 cubic feet per day) and the law enacted by the
Oklahoma legislature during March 1992 gives the OCC power to set statewide
(versus only field-by-field) production limits for all natural gas wells
producing in the State to prevent waste and to protect the interests of the
public against production of natural gas reserves in amounts in excess of the
reasonable market demand therefor. The General Partner cannot predict whether
the OCC, or any other state regulatory agency, may issue additional allowable
reductions which may adversely affect the Partnership's ability to produce its
gas reserves.
Legislative and Regulatory Production and Pricing Proposals
A number of legislative and regulatory proposals continually are
advanced which, if put into effect, could have an impact on the petroleum
industry. The various proposals involve, among other things, 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 "in definite 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.
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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 m ore than the greater of 1,000,000 cubic feet
per day or 40% of their total capacity, unless and until the OCC promulgates
other production limitations. Other states, including Louisiana, New Mexico
and Wyoming, are also reported to be contemplating whether to institute new
rules governing gas production in those States.
The effect of these regulations could be to decrease allowable
production on Partnership Properties and thereby to decrease Partnership
Revenues. However, by decreasing the amount of natural gas available in the
market, such regulations could also have the effect of increasing prices of
natural gas, although there can be no assurance that any such increase will
occur. There can also be no assurance that the proposed regulations described
above will be adopted or that they will be adopt ed 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.
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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 commence s, impose requirements that increase the cost of operations,
prohibit drilling activities on certain lands lying within wilderness areas or
other environmentally sensitive areas and impose substantial liabilities for
pollution resulting from drilling operations, particularly operations in
offshore waters or on submerged lands.
A past, present, or future release or threatened release of a hazardous
substance into the air, water, or ground by the Partnership or as a result of
disposal practices may subject the Partnership to liability under the
Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), the Resource Conservation Recovery Act ("RCRA"), the Clean
Water Act, and/or similar state laws, and any regulations promulgated pursuant
thereto. Under CERCLA and similar laws, the Partnership may be fully liable
for the cleanup costs of a release of hazardous substances even though it
contributed to only part of the release. While liability under CERCLA and
similar laws may be limited under certain circumstances, typically the limits
are so high that the maximum liability would likely have a significant adverse
effect on the Partnership. In certain circumstances, the Partnership may have
liability for releases of hazardous substances by previous owners of Partnership
Properties. Additionally, the discharge or substantial threat of a discharge
of oil by the Partnership into United States waters or onto an adjoining
shoreline may subject the Partnership to liability under the Oil Pollution Act
of 1990 and similar state laws. While liability under the Oil Pollution Act
of 1990 is limited under certain circumstances, the maximum liability under
those limits would still likely have a significant adverse effect on the
Partnership. The Partnership's operations generally will be covered by the
insurance carried by the General Partner or UNIT, if any. However, there can
be no assurance that such insurance coverage will always be in force or that,
if in force, it will adequately cover any losses or liability the Partnership
may incur.
Violation of environmental legislation and regulations may result in
the imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the removal, remediation and abatement
of the conditions, or suspension of the activities, giving rise to the
violation. The General Partner believes that the Partnership will comply with
all orders and regulations applicable to its operations. However, in view of
the many uncertainties with respect to the current controls, including their
duration and possible modification, the General Partner cannot predict the
overall effect of such controls on such operations. Similarly, the General
Partner cannot predict what future environmental laws may be enact ed or
regulations may be promulgated and what, if any, impact they would have on
operations or Partnership Revenue.
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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 1996.
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, 2025
unless prior thereto the General Partner or Limited Partners holding a majority
of the outstanding Units elect to terminate the Partnership as of an earlier
date. Upon termination of the Partnership, the debts, liabilities and
obligations of the Partnership will be paid and the Partnership's oil and gas
properties and any tangible equipment, materials or other personal property may
be sold for cash. The cash received will be used to make certain adjusting
payments to the Partners (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
Termination"). Any remaining cash and properties will then be distributed to
the Partners in proportion to and to the extent of any remaining balances in
the Partners' capital accounts and then in undivided percentage interests to
the Partners in the same proportions that Partnership Revenues are being shared
at the time of such termination (see "SUMMARY OF THE LIMITED PARTNERSHIP
AGREEMENT -Termination").
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Deposit and Use of Funds
Until required in the conduct of the Partnership's business,
Partnership funds, including, but not limited to, the Capital Contributions,
Partnership Revenue and proceeds of borrowings by the Partnership, will be
deposited, with or without interest, in one or more bank accounts of the
Partnership in a bank or banks to be selected by the General Partner or
invested in short-term United States government securities, money market funds,
bank certificates of deposit or commercial paper rated as "A1" or "P1" as the
General Partner, in its sole discretion, deems advisable. Any interest or
other income generated by such deposits or investments will be for the
Partnership's account. Except for Capital Contributions, Partnership funds
from any of the various sources mentioned above may be commingled with funds of
the General Partner and may be used, expended and distributed as authorized by
the terms and provisions of the Agreement. The General Partner will be
entitled to prompt reimbursement of expenses it incurs on behalf of the
Partnership.
Power and Authority
In managing the business and affairs of the Partnership, the General
Partner is authorized to take such action as it considers appropriate and in
the best interests of the Partnership (see Section 10.1 of the Agreement). The
General Partner is authorized to engage legal counsel and otherwise to act with
respect to Service audits, assessments and administrative and judicial
proceedings as it deems in the best interests of the Partnership and pursuant
to the provisions of the Code.
The General Partner is granted a broad power of attorney authorizing it
to execute certain documents required in connection with the organization,
qualification, continuance, modification and termination of the Partnership on
behalf of the Limited Partners (see Sections 1.5 and 1.6 of the Agreement).
Certain actions, such as an assignment for the benefit of its creditors or a
sale of substantially all of the Partnership Properties, except in connection
with the termination, roll-up or consolidation of the Partnership, cannot be
taken by the General Partner without the consent of a majority in interest of
the Limited Partners and the receipt of an opinion of 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. 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.
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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 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
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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 t he 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 in
1995 (see "PROPOSED ACTIVITIES"), the general liability of the Partnership will
not flow through to the Limited Partners.
Records, Reports and Returns
The General Partner will maintain adequate books, records, accounts and
files for the Partnership and keep the Limited Partners informed by means of
written interim reports rendered within 60 days after each quarter of the
Partnership's fiscal year. The reports will set forth the source and
disposition of Partnership Revenues during the quarter.
Engineering reports on the Partnership Properties will be prepared by
the General Partner for each year for which the General Partner prepares such a
report in connection with its own activities. Such report will include an
estimate of the total oil and gas proven reserves of the Partnership, the
dollar value thereof and the value of the Limited Partners' interest in such
reserve value. The report shall also contain an estimate of the life of the
Partnership Properties and the present worth of the reserves. Each Limited
Partner will receive a summary statement of such report which will reflect the
value of the Limited Partners' interest in such reserves.
The General Partner will timely file the Partnership's income tax
returns and by March 15 of each year or as soon thereafter as practicable,
furnish each person who was a Limited Partner during the prior year all
available information necessary for inclusion in his or her federal income tax
return. (See Section 8.1 of the Agreement).
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Transferability of Interests
Restrictions. A Limited Partner may not transfer or assign Units
except for certain transfers:
. to the General Partner;
. to or for the benefit of himself or herself, his or her spouse,
or other members of the transferor Limited Partner's immediate
family sharing the same residence;
. to any corporation or other entity whose beneficial owners are
all Limited Partners or permitted assignees;
. by the General Partner to any person who at the time of such
transfer is an employee of the General Partner, UNIT or its
subsidiaries; and
. by reason of death or operation of law.
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 Partner ship, 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.
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In the event of the death, incapacity or bankruptcy of a Limited
Partner, his or her legal representatives will have all the rights of a Limited
Partner only for the purpose of settling or liquidating his or her estate and
such power as the decedent, incompetent or bankrupt Limited Partner possessed
to assign all or any part of his or her interest in the Partnership and to join
with such assignee in satisfying conditions precedent to such assignee's
becoming a Substituted Limited Partner .
A purported sale, assignment or transfer of a Limited Partner's
interest will be recognized by the Partnership when it has received written
notice of such sale or assignment in form satisfactory to the General Partner,
signed by both parties, containing the purchaser's or assignee's acceptance of
the terms of the Agreement and a representation by the parties that the sale or
assignment was lawful. Such sale or assignment will be recognized as of the
date of such notice, except that if such date is more than 30 days prior to
the time of filing, such sale or assignment will be recognized as of the time
the notice was filed with the Partnership. Distributions of Partnership
Revenue will be made only to those persons who were record owners of Units on
the day any such distribution is made (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 Limit
ed 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.
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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 o r 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
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Partner is furnished with an opinion of counsel for the Partnership, or an
order or judgment of any court of competent jurisdiction, that the exercise of
such rights:
. Will not be deemed to evidence that the Limited Partners are
taking part in the control or management of the Partnership's
business affairs;
. Will not result in the loss of any Limited Partner's limited
liability under the Act; and
. Will not result in the Partnership being classified as an
association taxable as a corporation for federal income tax
purposes.
Exculpation and Indemnification of the General Partner
Pursuant to the Agreement, neither the General Partner or any affiliate
thereof will have any liability to the Partnership or to any Partners therein
for any loss suffered by the Partnership or such Partner that arises out of any
action or in action 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, 2025. 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.
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When the Partnership is terminated, there will be an accounting with
respect to its assets, liabilities and accounts. The Partnership's physical
property and its oil and gas properties may be sold for cash. Except in the
case of an election by the General Partner to terminate the Partnership before
the tenth anniversary of the Effective Date, Partnership Properties may be
sold to the General Partner or any of its affiliates for their fair market
value as determined in good faith by the General Partner.
Upon termination, all of the Partnership's debts, liabilities and
obligations, including expenses incurred in connection with the termination and
the sale or distribution of Partnership assets, will be paid. All Partnership
borrowings will b e 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.
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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 Assessment s."
(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 w hose outstanding voting securities are directly
or indirectly owned, controlled, or held with power to vote, by such
other person; (3) any person directly or indirectly controlling,
controlled by, or under common control with such other person; (4) any
officer, director, trustee or partner of such other person; and (5) if
such other person is an officer, director, trustee or partner, any
company for which such person acts in any such capacity.
(c) The "Aggregate Subscription" is the sum of the Capital
Subscriptions of all Limited Partners.
(d) "Agreement" and "Partnership Agreement" refers to the
Agreement of Limited Partnership attached as Exhibit A to this Private
Offering Memorandum.
(e) The "Capital Contribution" of a Limited Partner is the
amount of the Capital Subscription actually paid in by him or her, or
by any predecessor in interest, to the capital of the Partnership
including any payments made by deductions from salary. The "Capital
Contribution" of the General Partner includes the amounts contributed
to the Partnership or paid by the General Partner or by any Limited
Partner whose Units are purchased by the General Partner pursuant to
Section 4 .2 of the Agreement because of a default by such Limited
Partner in the payment of an Installment or pursuant to Article XV of
the Agreement, including payments made by deductions from the salary of
such Limited Partner.
(f) The "Capital Subscription" of a Limited Partner or his or
her assignee (including the General Partner where Units are transferred
pursuant to Section 4.2 of the Agreement) is the amount specified in
the Subscription Agreement executed by such Limited Partner for payment
by him or her to the capital of the Partnership in accordance with the
provisions of the Agreement, reduced by the amounts thereof from which
the Limited Partners have been released by the General Partner of their
obligation to pay.
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(g) A "Development Well" means a well intended to be drilled
within the proved areas of a known oil or gas reservoir to the depth of
a stratigraphic horizon known to be productive.
(h) "Director" refers to the duly elected directors of UNIT as
well as all honorary directors and consultants to the Board of
Directors of UNIT.
(i) "Drilling Costs" are those costs incurred in drilling,
testing, completing and equipping a well to the point that it proves to
be dry and is abandoned or is ready to commence commercial production
of oil or gas therefrom.
(j) "Effective Date" refers to the date on which the
certificate evidencing formation of the Partnership is filed with the
Secretary of State of the State of Oklahoma as required by the Act (54
Okla. Stat. 1991, Section 309).
(k) An "Exploratory Well" means a well drilled to find
production in an unproven area, to find a new reservoir in a field
previously found to be productive or to extend greatly the limits of a
known reservoir.
(l) A "farm-out" is an agreement whereby the owner of an oil
and gas property agrees to assign such property, usually retaining some
interest therein such as an overriding royalty, a production payment, a
net profits interest or a carried working interest, subject in most
cases, however, to the drilling of one or more wells or other
performance by the prospective assignee as a condition of the
assignment.
(m) The "General Partner's Minimum Capital Contribution" is
that amount equal to the total of (i) all Partnership costs and
expenses charged to its account from the time of the formation of the
Partnership through December 31, 199 5, 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,
1995, if any, minus (iii) the amount, if any, of the unexpended
Aggregate Subscription at December 31, 1995.
(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, 1995, June 15, 1995, September 15, 1995
and December 15, 1995, respectively, o r (ii) if an employee so elects,
through equal deductions from 1995 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,
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and, with respect to proper ties acquired by the Partnership from the
General Partner, UNIT or its affiliates are, without duplication, the
sum of:
(1) the prices paid by the General Partner, UNIT or its
affiliates in acquiring an oil and gas property,
including purchase option fees and charges, bonuses and
penalties, if any;
(2) title insurance or examination costs, broker's
commissions, filing fees, recording costs, transfer
taxes, if any, and like charges incurred in connection
with the acquisition of such property;
(3) a pro rata portion of the actual, necessary and
reasonable expenses of the General Partner, UNIT or its
affiliates for seismic and geophysical services;
(4) rentals, shut-in royalties and ad valorem taxes paid by
the General Partner, UNIT or its affiliates with
respect to such property to the date of its transfer to
the Partnership;
(5) interest and points actually incurred on funds used by
the General Partner, UNIT or its affiliates to acquire
or maintain such property; and
(6) such portion of the General Partner's, UNIT or its
affiliates' reasonable, necessary and actual expenses
for geological, engineering, drafting, accounting,
legal and other like services allocated to the
acquisition, operations and maintenance of the property
in accordance with generally accepted industry
practices, except for expenses in connection with the
past drilling of wells which are not producers of
sufficient quantities of oil or gas to make
commercially reasonable their continued operations, and
provided that the costs and expenses enumerated in (4),
(5) and (6) above with respect to any particular
property shall have been incurred not more than thirty-
six (36) months prior to the acquisition of such
property by the Partnership.
In the event a fractional undivided interest in a property is sold or
transferred by the General Partner, UNIT or any affiliate to an unaffiliated
third party for an amount in excess of that portion of the original cost of the
property attributable to the transferred interest, the amount of such excess
shall not reduce or be offset against the amount of the Leasehold Acquisition
Costs attributable to any interest in the same property which is transferred to
the Partnership.
(q) "Limited Partners" are those persons who acquire Units in
the Partnership upon its formation and those transferees of Units who
are accepted as Substituted Limited Partners. The General Partner may
also be a Limited Partner i f it subscribes for Units or if it
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<PAGE>
subsequently acquires Units by (i) the exercise by a Limited Partner of
his or her right of presentment; (ii) a purchase by the General Partner
of the Units of a Limited Partner who defaults in the payment of an
Installment; or (iii) any other assignment or transfer.
(r) The "Limited Partners' Percentage" is that percentage
determined by dividing the amount of the Aggregate Subscription by the
total of (i) the General Partner's Minimum Capital Contribution plus
(ii) the Aggregate Subscription.
(s) "Normal Retirement" means retirement under the terms of a
pension or similar retirement plan adopted by the General Partner, UNIT
or any subsidiary with whom a Limited Partner is employed as in effect
at the time of retirement .
(t) "Oil and gas properties" are oil and gas leasehold working
interests, fee interests, mineral interests, royalty interests,
overriding royalty interests, production payments, options or rights to
lease or acquire such interests , geophysical exploration permits and
any tangible or intangible properties or other rights incident thereto,
whether real, personal or mixed.
(u) "Operating Expenses" are expenditures made and costs
incurred in producing and marketing oil or gas from completed wells,
including, in addition to labor, fuel, repairs, hauling, material,
supplies, utility charges and other costs incident to or necessary for
the maintenance or operation of such wells or the marketing of
production therefrom, ad valorem, severance and other such taxes (other
than windfall profit taxes), insurance and casualty loss expense and
compensation to well operators or others for services rendered in
conducting such operations.
(v) The General Partner and the Limited Partners are sometimes
collectively referred to as the "Partners."
(w) "Partnership Agreement" and "Agreement" refer to the
Agreement of Limited Partnership attached as Exhibit A to this Private
Offering Memorandum.
(x) The "Partnership Properties" are oil and gas properties or
interests therein acquired by the Partnership or properties acquired by
any partnership or joint venture in which the Partnership is a partner
or joint venturer, whether acquired by purchase, option exercise or
otherwise.
(y) "Partnership Revenue" refers to the Partnership's gross
revenues from all sources, including interest income, proceeds from
sales of production, the Partnership's share of revenues from
partnerships or joint ventures of which it is a member, sales or other
dispositions of Partnership Properties or other Partnership assets,
provided that contributions to Partnership capital by the Partners and
the proceeds of any Partnership borrowings are specifically excluded
and dry-hole and bottom-hole contributions shall be treated as
reductions of the costs giving rise to the right to receive such
contributions.
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<PAGE>
(z) "Partnership Wells" are any and all of the oil and gas
wells in which the Partnership has an interest, either directly or
indirectly through any other partnership or joint venture.
(aa) "Productive properties" are oil and gas properties that
have been tested by drilling and determined to be capable of producing
oil or gas in commercial quantities.
(bb) A "spacing unit" is a drilling and spacing, production or
similar unit established by any regulatory body with jurisdiction, or
in the absence of such a regulatory body or action thereby, the acreage
attributable to wells drilled under the normal spacing pattern in such
area or if no such spacing unit is designated, in keeping with
generally accepted industry practices, or the largest of such units in
the event of multiple objective formations.
(cc) "Special Production and Marketing Costs" are costs and
expenses that are not normally and customarily incurred in connection
with drilling, producing and marketing operations, including without
limitation, costs incurred in constructing compressor plants, gasoline
plants, gas gathering systems, natural gas processing plants, pipeline
systems and salt water disposal systems and costs incurred in
installing pressure maintenance and secondary or tertiary production
projects.
(dd) "Subscription Agreement" refers to the form of Limited
Partner Subscription Agreement and Suitability Statement attached as
Attachment I to the Partnership Agreement.
(ee) A "Substituted Limited Partner" is a transferee, donee,
heir, legatee or other recipient of all or any portion of a Limited
Partner's interest in the Partnership with respect to whom all
conditions and consents required to become a Substituted Limited
Partner under Article XIII of the Partnership Agreement have been
satisfied and given.
(ff) A "Unit" is a preformation unit of limited partnership
interest of a Limited Partner in the Partnership representing a Capital
Subscription of One Thousand Dollars ($1,000).
FINANCIAL STATEMENTS
On January 1, 1988 all of the oil and natural gas properties previously
owned by Unit Drilling and Exploration Company ("UDEC") and UNIT were
transferred into Sunshine Development Company through a contribution of
capital. Included in the transfer were all interests previously owned by UDEC
in numerous General and Limited Partnerships sponsored by UDEC. Effective
February 1, 1988, Sunshine Development Company, a wholly owned subsidiary of
UDEC, pursuant to an "Amended and Restated Certificate of Incorporation" was
renamed Unit Petroleum Company and became a wholly owned subsidiary of UNIT.
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<PAGE>
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, 1994 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, 1994.
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<PAGE>
Unit Petroleum Company and Subsidiary
Consolidated Balance Sheet
(In Thousands)
November 30
1994
------------
(Unaudited)
Assets
------
Current Assets:
Cash and cash equivalents $ 107
Accounts receivable 3,915
Materials and supplies, at lower of
cost or market 1,594
Amount receivable from Parent 9,345
Other 134
----------
15,095
----------
Property and Equipment:
Oil and natural gas properties, on the
full cost method 143,666
Other 322
----------
143,988
Less accumulated depreciation, depletion,
amortization and impairment (80,255)
----------
Net property and equipment 63,733
----------
Other Assets 289
----------
Total Assets $ 79,117
==========
Liabilities and Shareholder Equity
----------------------------------
Current Liabilities:
Accounts payable $ 4,666
Current portion of natural gas purchaser prepayment 960
Contract advances 15
Accrued liabilities 70
----------
Total current liabilities 5,711
----------
Long-Term Portion of Natural Gas Purchaser Prepayment 2,857
----------
Shareholder Equity:
Common stock, $1.00 per value,
500 shares authorized and outstanding 1
Capital in excess of par value 31,486
Retained earnings 39,062
----------
Total Shareholder Equity 70,549
----------
Total Liabilities and Shareholder Equity $ 79,117
==========
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<PAGE>
EXHIBIT A
UNIT 1995 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
AGREEMENT OF LIMITED PARTNERSHIP
A-1
<PAGE>
INDEX
Page
----
ARTICLE I Formation of Limited Partnership........ A-4
ARTICLE II Definitions............................. A-6
ARTICLE III Purposes and Powers of the Partnership.. A-10
ARTICLE IV Partner Capital Contributions........... A-12
ARTICLE V Deposit and Use of Capital Contributions
and Other Partnership Funds.......... A-14
ARTICLE VI Sharing of Costs, Capital Accounts and
Allocation of Charges and Income..... A-16
ARTICLE VII Fiscal Year, Accountings and
Reports.............................. A-21
ARTICLE VIII Tax Returns and Elections............... A-22
ARTICLE IX Distributions........................... A-22
ARTICLE X Rights, Duties and Obligations of the
General Partner...................... A-23
ARTICLE XI Compensation and Reimbursements......... A-29
ARTICLE XII Rights and Obligations of Limited
Partners............................. A-30
ARTICLE XIII Transferability of Limited Partner's
Interest............................. A-31
ARTICLE XIV Assignments by the General Partner...... A-34
ARTICLE XV Limited Partners' Right of Presentment.. A-34
ARTICLE XVI Termination and Dissolution of
Partnership.......................... A-36
A-2
<PAGE>
Page
----
ARTICLE XVII Notices................................ A-39
ARTICLE XVIII Amendments............................. A-39
ARTICLE XIX General Provisions..................... A-40
ATTACHMENT I Limited Partner Subscription
Agreement and Suitability Statement.... I-1
A-3
<PAGE>
UNIT 1995 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
AGREEMENT OF LIMITED PARTNERSHIP
THIS AGREEMENT OF LIMITED PARTNERSHIP (this "Agreement") is made and
entered into by and among Unit Petroleum Company, an Oklahoma
corporation, hereinafter referred to as the "General Partner" or "UPC"
(which term shall include any successors or assigns of UPC), and each of
those persons who have executed a counterpart of the Limited Partner
Subscription Agreement and Suitability Statement attached as Attachment
I to this Agreement that have been accepted by the General Partner, said
persons being hereinafter collectively referred to as the "Limited
Partners".
WITNESSETH THAT:
ARTICLE I
Formation of Limited Partnership
1.1 The parties to this Agreement hereby form a Limited Partnership
(the "Partnership") pursuant to the Revised Uniform Limited Partnership
Act of the State of Oklahoma (the "Act"). The terms and provisions
hereof will be construed and interpreted in accordance with the terms and
provisions of the Act and if any of the terms and provisions of this
Agreement should be deemed inconsistent with those terms and provisions
of the Act which under the Act may not be altered by agreement of the
parties, the Act will be controlling, but otherwise this Agreement will
be controlling.
1.2 The Partnership will be conducted under the name of "Unit 1995
Employee Oil and Gas Limited Partnership" in Oklahoma, and under such
name or variations of such name as the General Partner deems appropriate
to comply with the laws of the other jurisdictions in which the
Partnership does business.
1.3 The principal office of the Partnership will be 1000 Kensington
Tower I, 7130 South Lewis Avenue, P.O. Box 702500, Tulsa, Oklahoma 74136,
or at such other location as may from time to time be designated by the
General Partner, and the Partnership's agent for service of process shall
be Unit Corporation ("UNIT", which term shall include all or any of its
subsidiaries or affiliates unless the context otherwise requires) at the
same address.
1.4 The Partnership will be effective on the date on which the
certificate evidencing formation of the Partnership is filed with the
Secretary of State of the State of Oklahoma. Its business and operations
will not be commenced prior to such date. The Partnership will continue
in existence until December 31, 2025, unless sooner terminated pursuant
to any provisions of this Agreement.
A-4
<PAGE>
1.5 The parties hereto will execute such certificates and other
documents, and the General Partner will file, record and publish such
certificates and documents, as may be necessary or appropriate to comply
with the requirements for the formation and operation of a limited
partnership under the Act and as the General Partner, upon advice of
counsel, deems necessary or appropriate to comply with requirements of
applicable laws governing the formation and operations of a limited
partnership (or a partnership in which special partners have a limited
liability) in all other jurisdictions where the Partnership desires to
conduct business, including, but not limited to, filings under the
Fictitious Name Act, Assumed Name Act or similar law in effect in the
counties, parishes and other governmental jurisdictions in which the
Partnership conducts business. The General Partner shall not be required
to deliver or mail a copy of the certificate of limited partnership or
any amendments thereto filed pursuant to the Act to the Limited Partners.
1.6 Each Limited Partner by his or her execution of a counterpart
of the Subscription Agreement irrevocably constitutes and appoints the
General Partner such Limited Partner's true and lawful attorney and
agent, with full power and authority in such Limited Partner's name,
place and stead, to execute, sign, acknowledge, swear to, deliver, file
and record in the appropriate public offices (i) all certificates or
other instruments (including, without limitation, counterparts of this
Agreement) and amendments thereto which the General Partner deems
appropriate to qualify or continue the Partnership as a limited part-
nership (or a partnership in which special partners have limited
liability) in the jurisdictions in which the Partnership conducts
business; (ii) all instruments and amendments thereto which the General
Partner deems appropriate to reflect any change or modification of this
Agreement, the admission of additional or substitute Partners in
accordance with the terms of this Agreement, the release or waiver of the
Limited Partners from the obligation to pay in one or more of the
installments of their Capital Subscriptions pursuant to Section 4.2 below
and the termination of the Partnership and the cancellation of the
certificate of limited partnership; (iii) all conveyances and other
instruments which the General Partner deems appropriate to evidence and
reflect any sales or transfers, including sales or transfers upon or in
connection with the dissolution and termination of the Partnership; and
(iv) all consents to transfers of Partnership interests, to the admission
of substitute or additional Partners or to the withdrawal or reduction of
any Partner's invested capital, to the extent that such actions are
authorized by the terms of this Agreement. The Power of Attorney granted
herein is irrevocable and is a power coupled with an interest and will
survive the death, disability, dissolution, bankruptcy, insolvency or
incapacity of a Limited Partner.
A-5
<PAGE>
ARTICLE II
Definitions
2.1 Whenever used in this Agreement the following terms will have
the meanings described below:
(a) The "Additional Assessments" of the Limited Partners are
those amounts, if any, which they are required to pay into the
capital of the Partnership pursuant to Section 5.3 of this
Agreement.
(b) An "affiliate" of another person is (1) any person
directly or indirectly owning, controlling or holding with power to
vote 10% or more of the outstanding voting securities of such other
person; (2) any person 10% or more of whose outstanding voting
securities are directly or indirectly owned, controlled, or held
with power to vote, by such other person; (3) any person directly or
indirectly controlling, controlled by, or under common control with
such other person; (4) any officer, director, trustee or partner of
such other person; and (5) if such other person is an officer,
director, trustee or partner, any company for which such person acts
in any such capacity.
(c) The "Aggregate Subscription" is the sum of the Capital
Subscriptions of all Limited Partners.
(d) The "Capital Contribution" of a Limited Partner is the
amount of the Capital Subscription actually paid in by him or her,
or by any predecessor in interest, to the capital of the
Partnership, including any payments made by deductions from salary.
The "Capital Contribution" of the General Partner includes the
amounts contributed to the Partnership or paid by the General
Partner or by any Limited Partner whose Units are purchased by the
General Partner including purchases pursuant to Section 4.2 of this
Agreement because of a default by such Limited Partner in the
payment of a subscription installment or pursuant to Article XV of
this Agreement, including payments made by deductions from the
salary of such Limited Partner.
(e) The "Capital Subscription" of a Limited Partner or his or
her assignee (including the General Partner where Units are trans-
ferred pursuant to Section 4.2 of this Agreement) is the amount
specified in the Subscription Agreement executed by such Limited
Partner for payment by him or her to the capital of the Partnership
in accordance with the provisions of this Agreement, reduced by the
amount thereof from which the Limited Partner has been released by
the General Partner of his or her obligation to pay pursuant to
Section 4.2 hereof.
(f) "Drilling Costs" are those costs incurred in drilling,
testing, completing and equipping a Partnership Well to the point
that it proves to be dry and is abandoned or is ready to commence
commercial production of oil or gas therefrom.
A-6
<PAGE>
(g) "Effective Date" refers to the date on which the certif-
icate evidencing formation of the Partnership is filed with the
Secretary of State of the State of Oklahoma as required by the Act
(54 Okla. Stat. 1991, Section 309).
(h) A "farm-out" is an agreement whereby the owner of an oil
and gas property agrees to assign such property, usually retaining
some interest therein such as an overriding royalty, a production
payment, a net profits interest or a carried working interest,
subject in most cases, however, to the drilling of one or more wells
or other performance by the prospective assignee as a condition of
the assignment.
(i) The "General Partner's Minimum Capital Contribution" is
that amount equal to the total of (i) all Partnership costs and
expenses charged to its account from the time of the formation of
the Partnership through December 31, 1995, 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, 1995, minus (iii) the amount, if any, of the
unexpended Aggregate Subscription at December 31, 1995.
(j) The "General Partner's Percentage" is that percentage
determined by dividing the amount of the General Partner's Minimum
Capital Contribution by the total of (i) the General Partner's
Minimum Capital Contribution plus (ii) the Aggregate Subscription.
(k) "Leasehold Acquisition Costs" with respect to properties,
if any, acquired by the Partnership from non-affiliated parties mean
the actual costs to the Partnership of and in acquiring the
properties, and, with respect to properties acquired by the
Partnership from the General Partner, UNIT or its affiliates, are,
without duplication, the sum of: (1) the prices paid by the General
Partner, UNIT or its affiliates in acquiring an oil and gas
property, including purchase option fees and charges, bonuses and
penalties, if any; (2) title insurance or examination costs,
broker's commissions, filing fees, recording costs, transfer taxes,
if any, and like charges incurred in connection with the acquisition
of such property; (3) a pro rata portion of the actual, necessary
and reasonable expenses of the General Partner, UNIT or its
affiliates for seismic and geophysical services; (4) rentals, shut-in
royalties and ad valorem taxes paid by the General Partner, UNIT
or its affiliates with respect to such property to the date of its
transfer to the Partnership; (5) interest and points actually
incurred on funds used by the General Partner, UNIT or its
affiliates to acquire or maintain such property; and (6) such
portion of the General Partner's, UNIT's or its affiliates'
reasonable, necessary and actual expenses for geological,
engineering, drafting, accounting, legal and other like services
allocated to the acquisition, operations and maintenance of the
property in accordance with generally accepted industry practices,
except for expenses in connection with the past drilling of wells
which are not producers of sufficient quantities of oil or gas to
make commercially reasonable their continued operations, and
provided that the costs and expenses enumerated in (4), (5) and (6)
A-7
<PAGE>
above with respect to any particular property shall have been
incurred not more than thirty-six (36) months prior to the
acquisition of such property by the Partnership. In the event a
fractional undivided interest in a property is sold or transferred
by the General Partner, UNIT or any affiliate to an unaffiliated
third party for an amount in excess of that portion of the original
cost of the property attributable to the transferred interest, the
amount of such excess shall not reduce or be offset against the
amount of the Leasehold Acquisition Costs attributable to any
interest in the same property which is transferred to the
Partnership.
(l) "Limited Partners" are those persons who acquire Units in
the Partnership upon its formation and those transferees of Units
who are accepted as Substituted Limited Partners. The General
Partner may also be a Limited Partner if it subscribes for Units or
if it subsequently acquires Units by (i) the exercise by a Limited
Partner of his or her right of presentment; (ii) a purchase by the
General Partner of the Units of a Limited Partner who defaults in
the payment of any subscription installment; or (iii) any other
assignment or transfer.
(m) The "Limited Partners' Percentage" is that percentage
determined by dividing the amount of the Aggregate Subscription by
the total of (i) the General Partner's Minimum Capital Contribution
plus (ii) the Aggregate Subscription.
(n) "Normal Retirement" means retirement under the provision
of a pension or similar retirement plan adopted by the General
Partner, UNIT or any subsidiary with whom a Limited Partner is
employed as in effect at the time of the employee's retirement.
(o) "Oil and gas properties" are oil and gas leasehold working
interests, fee interests, mineral interests, royalty interests,
overriding royalty interests, production payments, options or rights
to lease or acquire such interests, geophysical exploration permits
and any tangible or intangible properties or other rights incident
thereto, whether real, personal or mixed.
(p) "Operating Expenses" are expenditures made and costs
incurred in producing and marketing oil or gas from completed wells,
including, in addition to labor, fuel, repairs, hauling, material,
supplies, utility charges and other costs incident to or necessary
for the maintenance or operation of such wells or the marketing of
production therefrom, ad valorem, severance and other such taxes
(other than windfall profit taxes), insurance and casualty loss
expense and compensation to well operators or others for services
rendered in conducting such operations.
A-8
<PAGE>
(q) The General Partner and the Limited Partners are sometimes
collectively referred to as the "Partners".
(r) The "Partnership Properties" are oil and gas properties or
interests therein acquired by the Partnership or properties acquired
by any partnership or joint venture in which the Partnership is a
partner or joint venturer, whether acquired by purchase, option
exercise or otherwise.
(s) "Partnership Revenue" refers to the Partnership's gross
revenues from all sources, including interest income, proceeds from
sales of production, the Partnership's share of revenues from
partnerships or joint ventures of which it is a member, sales or
other dispositions of Partnership Properties or other Partnership
assets, provided that contributions to Partnership capital by the
Partners and the proceeds of any Partnership borrowings are
specifically excluded and dry-hole and bottom-hole contributions
shall be treated as reductions of the costs giving rise to the right
to receive such contributions.
(t) "Partnership Wells" are any and all of the oil and gas
wells in which the Partnership has an interest, either directly or
indirectly through any other partnership or joint venture.
(u) "Productive properties" are oil and gas properties that
have been tested by drilling and determined to be capable of
producing oil or gas in commercial quantities.
(v) "Special Production and Marketing Costs" are costs and
expenses that are not normally and customarily incurred in connec-
tion with drilling, producing and marketing operations, including
without limitation, costs incurred in constructing compressor
plants, gasoline plants, gas gathering systems, natural gas
processing plants, pipeline systems and salt water disposal systems
and costs incurred in installing pressure maintenance and secondary
or tertiary production projects.
(w) "Subscription Agreement" refers to the form of Limited
Partner Subscription Agreement and Suitability Statement attached as
Attachment I to this Agreement.
(x) A "Substituted Limited Partner" is a transferee, donee,
heir, legatee or other recipient of all or any portion of a Limited
Partner's interest in the Partnership with respect to whom all
conditions and consents required to become a Substituted Limited
Partner under Article XIII have been satisfied and given.
(y) A "Unit" is a preformation unit of limited partnership
interest of a Limited Partner in the Partnership representing a
Capital Subscription of One Thousand Dollars ($1,000).
A-9
<PAGE>
ARTICLE III
Purposes and Powers of the Partnership
3.1 The purposes of the Partnership will be to acquire productive
oil and gas properties and to explore for, produce, treat, transport and
market oil, gas or both, or products derived therefrom, anywhere in the
United States. It is contemplated that all or most of the Partnership's
operations will be conducted as part of the operations of the General
Partner and its affiliates, but the Partnership may engage in operations
on its own or in conjunction with unaffiliated third parties. In
accomplishing such purposes the Partnership may:
(a) acquire oil and gas properties, either alone or in
conjunction with other parties;
(b) conduct geological and geophysical investigations,
including, without limitation, seismic exploration, core drilling
and other means and methods of exploration;
(c) drill, equip, complete, rework, reequip, recomplete, plug
back, deepen, plug and abandon Partnership Wells as the General
Partner deems advisable;
(d) acquire and dispose of tangible lease and well equipment
for use or used in connection with Partnership Wells;
(e) employ or retain such personnel and obtain such legal,
accounting, geological, geophysical, engineering and other profes-
sional services and advice as the General Partner may deem advisable
in the course of the Partnership's operations under this Agreement;
(f) either pay or elect not to pay delay rentals or shut-in
royalties on Partnership Properties as appropriate in the judgment
of the General Partner, it being understood that the General Partner
will not be liable for failure to make correct or timely payments of
delay rentals or shut-in royalties if such failure was due to any
reason other than gross negligence or lack of good faith;
(g) make or give dry-hole or bottom-hole or other contribu-
tions of oil and gas properties, money or both, to encourage
drilling by others in the vicinity of or on Partnership Properties;
(h) negotiate for and accept dry-hole, bottom-hole or other
contributions of oil and gas properties, cash or both, as consid-
eration for the drilling of a Partnership Well, with oil and gas
properties so acquired, if any, to become Partnership Properties;
A-10
<PAGE>
(i) pay all ad valorem taxes levied or assessed against the
Partnership Properties, all taxes upon or measured by the production
of oil or gas or other hydrocarbons therefrom, and all other taxes
(other than income taxes) directly relating to operations conducted
under this Agreement;
(j) enter into and operate pursuant to operating agreements
with respect to Partnership Properties naming either the General
Partner, any of its affiliates or a third party as operator, or
enter into partnership agreements with third parties whereby the
Partnership may be either a general or a limited partner (including
any partnerships formed or sponsored by the General Partner or in
which the General Partner may also be a partner), which operating or
partnership agreements shall contain such terms, provisions and
conditions as the General Partner deems appropriate;
(k) execute all documents or instruments of any kind which the
General Partner deems appropriate for carrying out the purposes of
the Partnership, including, without limitation, unitization
agreements, gasoline plant contracts, recycling agreements and
agreements relating to pressure maintenance and secondary or
tertiary production projects;
(l) purchase and establish inventories of equipment and
material required or expected to be required in connection with its
operations;
(m) contract or enter into agreements with unaffiliated third
parties, the General Partner or its affiliates for the performance
of services and the purchase and sale of material, equipment,
supplies and property, both real and personal, provided, however,
that any such contracts or agreements with the General Partner or
any of its affiliates shall, except as otherwise provided herein,
provide for prices, fees, rates, charges or other compensation which
are not greater than those available from, being paid to or charged
by unaffiliated third parties dealing at arm's length in the same or
a similar geographic area for the same or comparable services,
material, equipment, supplies or property;
(n) conduct operations either alone or as a joint venturer,
co-tenant, partner or in any other manner of participation with
third persons and to enter into agreements and contracts setting
forth the terms and provisions of such participation;
(o) borrow money from banks and other lending institutions for
Partnership purposes and pledge Partnership Properties (including
production therefrom) for the repayment of such loans, it being
understood that no bank or other lending institution to which the
General Partner makes application for a loan will be required to
inquire as to the purposes for which such loan is sought, and as
between the Partnership and such bank or lending institution it will
be conclusively presumed that the proceeds of such loan are to be
and will be used for purposes authorized under the terms of this
Agreement;
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(p) hold Partnership Properties in its own name or in the name
of the General Partner, UNIT or any affiliate or any other party as
nominee for the Partnership;
(q) sell, relinquish, release, farm-out, abandon or otherwise
dispose of Partnership Properties, including undeveloped, productive
and condemned properties;
(r) produce, treat, transport and market oil and gas and
execute division orders, contracts for the marketing or sale of oil,
gas or other hydrocarbons and other marketing agreements;
(s) purchase, sell or pledge payments out of production from
Partnership Properties; and
(t) perform any and all other acts or activities customary or
incident to exploration for or development, production and marketing
of oil and gas.
ARTICLE IV
Partner Capital Contributions
4.1 The General Partner will have the unrestricted right to admit
such parties as Limited Partners as it deems advisable. By their
execution of the Subscription Agreement, the Limited Partners severally
agree, subject to the acceptance of their subscription by the General
Partner, to be bound by the terms hereof as Limited Partners.
4.2 The Capital Subscriptions of the Limited Partners will be
payable either (i) in four equal installments on March 15, 1995, June 15,
1995, September 15, 1995, and December 15, 1995, respectively, or (ii) by
employees so electing, through equal deductions from 1995 salary paid to
the employee by the General Partner, UNIT or its subsidiaries commencing
immediately after the Effective Date. Notwithstanding the foregoing, if
in the judgment of the General Partner, the entire amount of the
Aggregate Subscription is not required for purposes of conducting the
business, operations and affairs of the Partnership, the General Partner
may, at its sole option, elect to release the Limited Partners from the
obligation to pay in one or more of the installments of their Capital
Subscriptions. If Units are acquired by a corporation or other entity,
the beneficial owners of the interests therein shall be jointly and
severally liable for the payment of the Capital Subscription. If an
employee or director who has subscribed for Units (either directly or
through a corporation or other entity) ceases to be employed by or a
director of the General Partner, UNIT or any of its subsidiaries for any
reason other than death, disability or Normal Retirement prior to the
time the full amount of his or her Capital Subscription is paid, then the
due date for any unpaid amount shall be accelerated so that the full
amount of his or her unpaid Capital Subscription shall be due and payable
on the effective date of such termination. The Capital Subscriptions
shall be legally binding obligations of the Limited Partners and any past
due amounts shall bear interest at the annual rate equal to two (2)
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percentage points in excess of the prime rate of interest of Bank of
Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in
effect from time to time, until paid. Further, in the event a Limited
Partner fails to pay any installment when due, the General Partner, at
its sole option and discretion, may elect to purchase the Units of such
defaulting Limited Partner at a price equal to the total amount of the
Capital Contributions actually paid into the Partnership by such
defaulting Limited Partner, less the amount of any Partnership
distributions that may have been received by him or her. Such option may
be exercised by the General Partner by written notice to the Limited
Partner at any time after the date that the unpaid installment was due
and shall be deemed exercised when the amount of the purchase price is
first tendered to the defaulting Limited Partner. The General Partner
may, in its discretion, accept payments of delinquent installments but
shall not be required to do so. In the event that the General Partner
elects to purchase the Units of a defaulting Limited Partner, it shall
pay into the Partnership the amount of the delinquent installment
(excluding any interest that may have accrued thereon) and shall pay each
additional installment, if any, payable with respect to such Units as it
becomes due. By virtue of such purchase, the General Partner shall be
allocated all Partnership Revenues and be charged with all Partnership
costs and expenses attributable to such Units otherwise allocable or
chargeable to the defaulting Limited Partner to the extent provided in
Section 13.9.
4.3 If the Partnership requires funds to conduct Partnership
operations during the period between any of the installments due as set
forth in Section 4.2 above, then, notwithstanding the provisions of
Section 5.4 below, the General Partner shall advance funds to the
Partnership in an amount equal to the funds then required to conduct such
operations but in no event more than the total amount of the Aggregate
Subscription remaining unpaid. With respect to any such advances, the
General Partner shall receive no interest thereon and no financing
charges will be levied by the General Partner in connection therewith.
The General Partner shall be repaid out of the Capital Subscription
installments thereafter paid into the capital of the Partnership when
due.
4.4 Additional Assessments required by the General Partner pursuant
to Section 5.3 of this Agreement will be payable in cash on such date as
the General Partner may set in its written notice, but in no event will
such assessments be due earlier than thirty (30) days after the date of
mailing of the notice. Notice of the General Partner's call for
Additional Assessments shall specify the amount required, the manner in
which the additional funds will be expended, the date on which such
amounts are payable, and the consequences of non-payment. The General
Partner will not be required to accept late payments of such amounts, but
it may in its discretion do so.
4.5 The General Partner will contribute to the capital of the
Partnership amounts equal to the total of all costs paid by the Part-
nership that are charged to the General Partner's account as such costs
are incurred.
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ARTICLE V
Deposit and Use of Capital Contributions and
Other Partnership Funds
5.1 Until required in the conduct of the Partnership's business,
Partnership funds, including, but not limited to, Capital Contributions,
Partnership Revenue and proceeds of borrowings by the Partnership, will
be deposited, with or without interest, in one or more bank accounts of
the Partnership in a bank or banks selected by the General Partner or
invested in short-term United States government securities, money market
funds, bank certificates of deposit or commercial paper rated as "A1" or
"P1" as the General Partner, in its sole discretion, deems advisable.
Any interest or other income generated by such deposits or investments
will be for the Partnership's account. Except for Capital Contributions,
Partnership funds from any of the various sources mentioned above may be
commingled with other Partnership funds and with the funds of the General
Partner and may be withdrawn, expended and distributed as authorized by
the terms and provisions of this Agreement.
5.2 The Capital Contributions of the Limited Partners will be
expended for costs incurred by the Partnership that, in accordance with
the terms of this Agreement, are properly chargeable to the Limited
Partners' accounts.
5.3 After the General Partner's Minimum Capital Contribution has
been fully expended, if the Aggregate Subscription has all been fully
expended or committed and additional funds are required in order to pay
Drilling Costs, Special Production and Marketing Costs or Leasehold
Acquisition Costs of productive properties which are chargeable to the
Limited Partners, the General Partner may, but shall not be required to,
make one or more calls for Additional Assessments from Limited Partners
pursuant to Section 4.4; provided, however, that the aggregate amount of
Additional Assessments called of the Limited Partners may not exceed $100
per Unit. The Limited Partners who do not respond will participate in
production, if any, obtained from the aggregate Additional Assessments
paid into the Partnership. However, the amount of the unpaid Additional
Assessment shall bear interest at the annual rate equal to two (2)
percentage points in excess of the prime rate of interest of Bank of
Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in
effect from time to time, until paid. The Partnership will have a lien
on the defaulting Limited Partner's interest in the Partnership and the
General Partner may apply Partnership Revenue otherwise available for
distribution to the defaulting Limited Partner until an amount equal to
the unpaid Additional Assessment and interest is received. Furthermore,
the General Partner may satisfy such lien by proceeding with legal action
to enforce the lien and the defaulting Limited Partner shall pay all
expenses of collection, including interest, court costs and a reasonable
attorney's fee.
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5.4 After the General Partner's Minimum Capital Contribution has
been fully expended, the General Partner may cause the Partnership to
borrow funds for the purpose of paying Drilling Costs, Special Production
and Marketing Costs or Leasehold Acquisition Costs of productive
properties, which borrowings may be secured by interests in the Part-
nership Properties and will be repaid, including interest accruing
thereon, out of Partnership Revenue allocable to the accounts of the
Partners on whose behalf the proceeds of such borrowings are expended.
The General Partner may, but is not required to, advance funds to the
Partnership for the same purposes for which Partnership borrowings are
authorized by this Section 5.4. With respect to any such advances, the
General Partner shall receive interest in an amount equal to the lesser
of the interest which would be charged to the Partnership by unrelated
banks on comparable loans for the same purpose or the General Partner's
interest cost with respect to such loan, where it borrows the same. No
financing charges will be levied by the General Partner in connection
with any such loan. If Partnership borrowings secured by interests in
the Partnership Properties and repayable out of Partnership Revenue
cannot be arranged on a basis which, in the opinion of the General
Partner, is fair and reasonable, and the entire sum required to pay costs
of the type referred to above is not available from Partnership Revenue,
the Partnership may elect not to drill or participate in the drilling of
a well or the General Partner may dispose of the Partnership Properties
upon which such operations were to be conducted by sale (subject to any
other applicable provisions of this Agreement), farm-out or abandonment.
5.5 The General Partner may utilize Partnership Revenue allocable
to the respective accounts of the Partners to pay any Partnership costs
and expenses properly chargeable to the accounts of such Partners.
5.6 With respect to any Partnership activity and subject to the
restrictions set forth in Sections 5.3 and 5.4 above, it shall be in the
sole discretion of the General Partner whether to call for Additional
Assessments, arrange for borrowings on behalf of the Partners, utilize
Partnership Revenue or sell (subject to any other applicable provisions
of this Agreement), farm-out or abandon Partnership Properties.
5.7 The Partnership Properties and production therefrom may be
pledged, mortgaged or otherwise encumbered as security for borrowings by
the Partnership authorized by Section 5.4 above, provided that the holder
of indebtedness arising by virtue of such borrowings may not have or
acquire, at any time as a result of making any such loans, any direct or
indirect interest in the profits, capital or property of the Partnership
other than as a secured creditor.
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ARTICLE VI
Sharing of Costs, Capital Accounts and
Allocation of Charges and Income
6.1 All costs of organizing the Partnership and offering Units
therein will be paid by the General Partner. All costs incurred in the
offering and syndication of any drilling or income program formed by UPC
or UNIT and its affiliates during 1995 in which the Partnership
participates as a co-general partner will also be paid by the General
Partner.
6.2 All other Partnership costs and expenses will be charged 99% to
the accounts of the Limited Partners and 1% to the account of the General
Partner until such time as the Aggregate Subscription has been fully
expended. Thereafter and until the General Partner's Minimum Capital
Contribution has been fully expended, all of such costs and expenses will
be charged to the General Partner. After the General Partner's Minimum
Capital Contribution has been fully expended, such costs and expenses
will be charged to the respective accounts of the General Partner and the
Limited Partners on the basis of their respective Percentages.
6.3 All Partnership Revenues will be allocated between the General
Partner and the Limited Partners on the basis of their respective
Percentages.
6.4 Partnership costs, expenses and Revenues which are charged and
allocated to the Limited Partners shall be charged and allocated to their
respective accounts in the proportion the Units of each Limited Partner
bear to the total number of outstanding Units.
6.5 Capital accounts shall be established and maintained for each
Partner in accordance with tax accounting principles and with valid
regulations issued by the U.S. Treasury Department under subsection
704(b) (the "704 Regulations") of the Internal Revenue Code of 1986, as
amended (the "Code"). To the extent that tax accounting principles and
the 704 Regulations may conflict, the latter shall control. In connec-
tion with the establishment and maintenance of such capital accounts, the
following provisions shall apply:
(a) Each Partner's capital account shall be (i) increased by
the amount of money contributed by him or her to the Partnership,
the fair market value of property contributed by him or her to the
Partnership (net of liabilities securing such contributed property
that the Partnership is considered to assume or take subject to
under section 752 of the Code) and allocations to him or her of
Partnership income and gain (except to the extent such income or
gain has previously been reflected in his or her capital account by
adjustments thereto) and (ii) decreased by the amount of money
distributed to him or her by the Partnership, the fair market value
of property distributed to him or her by the Partnership (net of
liabilities securing such distributed property that such Partner is
considered to assume or take subject to under section 752 of the
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Code) and allocations to him or her of Partnership loss, deduction
(except to the extent such loss or deduction has previously been
reflected in his or her capital account by adjustments thereto) and
expenditures described in section 705(a)(2)(B) of the Code.
(b) In the event Partnership Property is distributed to a
Partner, then, before the capital account of such Partner is
adjusted as required by subsection (a) of this Section 6.5, the
capital accounts of the Partners shall be adjusted to reflect the
manner in which the unrealized income, gain, loss and deduction
inherent in such property (that has not been reflected in such
capital accounts previously) would be allocated among the Partners
if there were a taxable disposition of such property for its fair
market value on the date of distribution.
(c) If, pursuant to this Agreement, Partnership Property is
reflected on the books of the Partnership at a book value that
differs from the adjusted tax basis of such property, then the
Partners' capital accounts shall be adjusted in accordance with the
704 Regulations for allocations to the Partners of depreciation,
depletion, amortization, and gain or loss, as computed for book
purposes, with respect to such property.
(d) The Partners' capital accounts shall be adjusted for
depletion and gain or loss with respect to the Partnership's oil or
gas properties in whichever of the following manners the General
Partner determines is in the best interests of the Partners:
(i) the Partners' capital accounts shall be reduced
by a simulated depletion allowance computed on each oil or gas
property using either the cost depletion method or the
percentage depletion method (without regard to the limitations
under the Code which could apply to less than all Partners);
provided, however, that the choice between the cost depletion
method and the simulated depletion method shall be made on a
property-by-property basis in the first taxable year of the
Partnership for which such choice is relevant for an oil or gas
property, and such choice shall be binding for all Partnership
taxable years during which such oil or gas property is held by
the Partnership. Such reductions for depletion shall not
exceed the aggregate adjusted basis allocated to the Partners
with respect to such oil or gas property. Such reductions for
depletion shall be allocated among the Partners' capital
accounts in the same proportions as the adjusted basis in the
particular property is allocated to each Partner. Upon the
taxable disposition of an oil or gas property by the
Partnership, the Partnership's simulated gain or loss shall be
determined by subtracting its simulated adjusted basis
(aggregate adjusted tax basis of the Partners less simulated
depletion allowances) in such property from the amount realized
on such disposition and the Partners' capital accounts shall be
increased or reduced, as the case may be, by the amount of the
simulated gain or loss on such disposition in proportion to the
Partners' allocable shares of the total amount realized on such
disposition, or
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(ii) the Partnership shall reduce the capital
account of each Partner in an amount equal to such Partner's
depletion allowance with respect to each oil or gas property of
the Partnership (for the Partner's taxable year that ends
within the Partnership's taxable year), but such reductions for
depletion shall not exceed the adjusted basis allocated to such
Partner with respect to such property. Upon the taxable
disposition of an oil or gas property by the Partnership, the
capital account of each Partner shall be reduced or increased,
as the case may be, by the amount of the difference between
such Partner's allocable share of the total amount realized on
such disposition and such Partner's remaining adjusted tax
basis in such property.
(e) For purposes of determining the capital account balance of
any Partner as of the end of any Partnership taxable year for
purposes of Subsection 6.6(f) hereof, such Partner's capital account
shall be reduced by:
(i) adjustments that, as of the end of such year,
reasonably are expected to be made to such Partner's capital
account pursuant to paragraph (b)(2)(iv)(k) of the 704
Regulations for depletion allowances with respect to oil and
gas properties of the Partnership,
(ii) allocations of loss and deduction that, as of
the end of such year, reasonably are expected to be made to
such Partner pursuant to Code section 704(e)(2), Code section
706(d), and paragraph (b)(2)(ii) of section 1.751-1 of
regulations promulgated under the Code, and
(iii) distributions that, as of the end of such
year, reasonably are expected to be made to such Partner to the
extent they exceed offsetting increases to such Partner's
capital account that reasonably are expected to occur during
(or prior to) the Partnership taxable years in which such
distributions reasonably are expected to be made.
6.6 With respect to the various allocations of Partnership income,
gain, loss, deduction and credit for federal income tax purposes, it is
hereby agreed as follows:
(a) To the extent permitted by law, all charges, deductions
and losses shall be allocated for federal income tax purposes in the
same manner as the costs in respect of which such charges,
deductions and losses are charged to the respective accounts of the
Partners. The Partners bearing the costs shall be entitled to the
deductions (including, without limitation, cost recovery allowances,
depreciation and cost depletion) and credits that are attributable
to such costs.
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(b) The Partnership shall allocate to each Partner his or her
portion of the adjusted basis in each depletable Partnership
Property as required by Section 613A(c)(7)(D) of the Code based upon
the interest of said Partner in the capital of the Partnership as of
the time of the acquisition of such Partnership Property. To the
extent permitted by the Code, such allocation shall be based upon
said Partner's interest (i) in the Partnership capital used to
acquire the property, or (ii) in the adjusted basis of the property
if it is contributed to the Partnership. If such allocation of
basis is not permitted under the Code, then basis will be allocated
in the permissible manner which the General Partner deems will most
closely achieve the result intended above.
(c) Partnership Revenue shall be allocated for federal income
tax purposes in the same manner as it is allocated to the respective
accounts of the Partners pursuant to Sections 6.3 and 6.4 above.
(d) Depreciation or cost recovery allowance recapture and
recapture of intangible drilling and development costs, if any, due
as a result of sales or dispositions of assets shall be allocated in
the same proportion that the depreciation, cost recovery allowances
or intangible drilling and development costs being recaptured were
allocated.
(e) Notwithstanding anything to the contrary stated herein,
(i) there shall be allocated first to other Limited
Partners and then to the General Partner any item of loss,
deduction, credit or allowance that, but for this Subsection
6.6(e), would have been allocated to any Limited Partner that
is not obligated to restore any deficit balance in such Limited
Partner's capital account and would have thereupon caused or
increased a deficit balance in such Limited Partner's capital
account as of the end of the Partnership's taxable year to
which such allocation related (after taking into consideration
the numbered items specified in Subsection 6.5(e) hereof);
(ii) any Limited Partner that is not obligated to
restore any deficit balance in such Limited Partner's capital
account who unexpectedly receives an adjustment, allocation or
distribution specified in Subsection 6.5(e) hereof shall be
allocated items of income and gain in an amount and manner
sufficient to eliminate such deficit balance as quickly as
possible; and
(iii) in the event any allocations of loss, deduc-
tion, credit or allowance are made to a Limited Partner or the
General Partner pursuant to clause (i) of this Subsection
6.6(e), then such Limited Partner and/or the General Partner
shall be subsequently allocated all items of income and gain
pro rata as they were allocated the item(s) of loss, deduction,
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credit or allowance under such clause (i) until the aggregate
amount of such allocations of income and gain is equal to the
aggregate amount of any such allocations of loss, deduction,
credit or allowance allocated to such Partner(s) pursuant to
clause (i) of this Subsection 6.6(e).
(f) Notwithstanding any other provision of this Agreement, if,
under any provision of this Agreement, the capital account of any
Partner is adjusted to reflect the difference between the basis to
the Partnership of Partnership Property and such property's fair
market value, then all items of income, gain, loss and deduction
with respect to such property shall be allocated among the Partners
so as to take account of the variation between the basis of such
property and its fair market value at the time of the adjustment to
such Partner's capital account in accordance with the requirements
of subsection 704(c) of the Code, or in the same manner as provided
under subsection 704(c) of the Code.
6.7 Notwithstanding anything to the contrary that may be expressed
or implied in this Agreement, the interest of the General Partner in each
material item of Partnership income, gain, loss, deduction or credit
shall be equal to at least one percent of each such item at all times
during the existence of the Partnership. In determining the General
Partner's interest in such items, Units owned by the General Partner
shall not be taken into account.
6.8 Except as provided in subsections (a) through (d) of this
Section 6.8, in the case of a change in a Partner's interest in the
Partnership during a taxable year of the Partnership, all Partnership
income, gain, loss, deduction or credit allocable to the Partners shall
be allocated to the persons who were Partners during the period to which
such item is attributable in accordance with the Partners' interests in
the Partnership during such period regardless of when such item is paid
or received by the Partnership.
(a) With respect to certain "allocable cash basis items" (as
such term is defined in the Code) of Partnership Revenue, gain,
loss, deduction or credit, if, during any taxable year of the
Partnership there is change in any Partner's interest in the
Partnership, then, except to the extent provided in regulations
prescribed under Section 706 of the Code, each Partner's allocable
share of any "allocable cash basis item" shall be determined by (i)
assigning the appropriate portion of each such item to each day in
the period to which it is attributable, and (ii) allocating the
portion assigned to any such day among the Partners in proportion to
their interests in the Partnership at the close of such day.
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(b) If, by adhering to the method of allocation described in
the immediately preceding subsection of this Section 6.8, a portion
of any "allocable cash basis item" is attributable to any period
before the beginning of the Partnership taxable year in which such
item is received or paid, such portion shall be (i) assigned to the
first day of the taxable year in which it is received or paid, and
(ii) allocated among the persons who were Partners in the
Partnership during the period to which such portion is attributable
in accordance with their interests in the Partnership during such
period.
(c) If any portion of any "allocable cash basis item" paid or
received by the Partnership in a taxable year is attributable to a
period after the close of that taxable year, such portion shall be
(i) assigned to the last day of the taxable year in which it is paid
or received, and (ii) allocated among the persons who are Partners
in proportion to their interests in the Partnership at the close of
such day.
(d) If any deduction is allocated to a person with respect to
an "allocable cash basis item" attributable to a period before the
beginning of the Partnership taxable year and such person is not a
Partner of the Partnership on the first day of the Partnership
taxable year, such deduction shall be capitalized by the Partnership
and treated in the manner provided for in Section 755 of the Code.
ARTICLE VII
Fiscal Year, Accountings and Reports
7.1 Unless the Code requires otherwise, the fiscal year of the
Partnership will be the calendar year and the books of the Partnership
will be kept in accordance with usual and customary accounting practices
on the accrual method.
7.2 Within sixty (60) days after the end of each quarter of each
Partnership fiscal year, each person who was a Limited Partner during
such period will be furnished a report setting forth the source and
disposition of Partnership funds during the quarter.
7.3 Not later than the end of the fiscal year in which all
Partnership Wells are drilled and completed, and sufficient production
history has been obtained on Partnership Wells to evaluate properly the
reserves attributable thereto, the General Partner will make an evalua-
tion of Partnership Properties as of the last day of such fiscal year.
The report shall include an estimate of the total oil and gas proven
reserves of the Partnership and the dollar value thereof and the value of
the Limited Partner's interest in such reserve value. It shall also
contain an estimate of the present worth of the reserves. Each Limited
Partner will receive a summary statement of such report reflecting the
Limited Partners' interest in such reserve value.
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ARTICLE VIII
Tax Returns and Elections
8.1 Unless the Code requires otherwise, the General Partner will
cause the Partnership to elect the calendar year as its taxable year and
will timely file all Partnership income tax returns required to be filed
by the jurisdictions in which the Partnership conducts business or
derives income. By March 15 of each year or as soon thereafter as
practicable, the General Partner will furnish all available information
necessary for inclusion in the income tax returns of each person who was
a Limited Partner during the prior fiscal year. The General Partner
shall be the "Tax Matters Partner" for the Partnership pursuant to the
provisions of Section 6231 of the Code subject to the provisions of
Section 10.22 below.
8.2 The Partnership will elect to deduct intangible drilling and
development costs currently as an expense for income tax purposes and
will elect to use the available depreciation method which, in the General
Partner's judgment, is in the best interest of the Partners.
8.3 The General Partner shall have the right in its sole discretion
at any time to make or not to make such other elections as are authorized
or permitted by any law or regulation for income tax purposes (including
any election under Section 754 of the Code).
ARTICLE IX
Distributions
9.1 The Partnership's available cash will be distributed to the
Limited Partners and the General Partner in the same proportions that
Partnership Revenue has been allocated to them after giving effect to
previous distributions and to portions of such revenue theretofore used
or retained to pay costs incurred or expected to be incurred in con-
ducting Partnership operations or to repay borrowings theretofore or
expected to be thereafter obtained by the Partnership. Within forty-five
(45) days after the end of each calendar quarter, the General Partner
will determine the amount of cash available for distribution to the
Limited Partners and will distribute such amount, if any, as promptly
thereafter as reasonably possible. Distributions of cash to the General
Partner may be at any time the General Partner determines there is cash
available therefor. The General Partner's determination of the cash
available for distribution will be conclusive and binding upon all
Partners. All Partnership funds distributed to the Limited Partners
shall be distributed to the persons who were record holders of Units on
the day on which the distribution is made.
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ARTICLE X
Rights, Duties and Obligations of the General Partner
10.1 Subject to the limitations of this Agreement, the General
Partner will have full, exclusive and complete discretion in the
management and control of the business of the Partnership and will make
all decisions affecting its business and affairs or the Partnership
Properties. The General Partner will have, subject to the provisions of
this Article X, full power and authority to take any action described in
Article III above and execute and deliver in the name of and on behalf of
the Partnership such documents or instruments as the General Partner
deems appropriate for the conduct of Partnership business. No person,
firm or corporation dealing with the Partnership will be required to
inquire into the authority of the General Partner to take any action or
make any decision.
10.2 The General Partner will perform the duties imposed upon it
under this Agreement in an efficient and businesslike manner with due
caution and in accordance with established practices of the oil and gas
industry, but the General Partner shall not be liable, responsible or
accountable in damages or otherwise to the Partnership or any of the
Partners for, and the Partnership shall indemnify, defend against and
save harmless the General Partner, from any expense (including attorneys'
fees), loss or damage incurred by reason of any act or omission performed
or omitted in good faith on behalf of the Partnership or the Partners,
and in a manner reasonably believed by the General Partner to be within
the scope of the authority granted by this Agreement and in the best
interests of the Partnership or the Partners, provided that the General
Partner is not guilty of gross negligence or willful misconduct with
respect to such acts or omissions, and further provided that the
satisfaction of any indemnification and any saving harmless shall be from
and limited to Partnership assets including insurance proceeds, if any,
and no Partner shall have any personal liability on account thereof. For
purposes of this Section 10.2 only, the term General Partner includes the
General Partner, affiliates of the General Partner and any officer,
director or employee of the General Partner or any of its affiliates such
that all of such parties are covered by the indemnities provided herein.
10.3 The General Partner will utilize its organization and employees
and will hire outside consultants for the Partnership as necessary in
order to provide experienced, qualified and competent personnel to
conduct the Partnership's business. With certain limited exceptions it
is the intent of the Partners that the Partnership participate as a co-general
partner of any oil and gas drilling or income programs, or both, formed by the
General Partner or UNIT for third party investors during
1995 and to participate on a proportionate working interest basis in each
producing oil and gas lease acquired and in the drilling of each oil and
gas well commenced by the General Partner or UNIT for its own account
during the period from the later of January 1, 1995 or the Effective Date
through December 31, 1995 (except for wells, if any, (i) drilled outside
of the 48 contiguous United States; (ii) drilled as part of secondary or
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tertiary recovery operations which were in existence prior to the
formation of the Partnership; (iii) drilled by third parties under farm-out or
similar arrangements with the General Partner or UNIT or whereby the General
Partner or UNIT may be entitled to an overriding royalty,
reversionary or other similar interest in the production from such wells
but is not obligated to pay any of the Drilling Costs thereof; (iv)
acquired by UNIT or the General Partner through the acquisition by UNIT
or the General Partner of, or merger of UNIT or the General Partner with,
other companies; or (v) with respect to which the General Partner does
not believe that the potential economic return therefrom justifies the
costs of participation by the Partnership).
10.4 The General Partner, UNIT or any affiliate thereof will
transfer to the Partnership interests in oil and gas properties com-
prising the spacing unit on which a Partnership Well is located or is to
be drilled for the separate account of the Partnership, provided that no
broker's commissions or fees of a similar nature will be paid in
connection with any such transfer and the consideration paid by the
Partnership will be equal to the Leasehold Acquisition Costs of the
property so transferred. If the size of a spacing unit on which a
Partnership Well is located is ever reduced or increased well density is
permitted thereon, the Partnership will not be entitled to any
reimbursement or recoupment of any portion of the Leasehold Acquisition
Costs paid with respect thereto notwithstanding the provisions of Section
10.7 below.
10.5 With respect to certain transactions involving Partnership
Properties, it is hereby agreed as follows:
(a) A sale, transfer or conveyance by the General Partner or
any affiliate of less than its entire interest in such property is
prohibited unless (i) the interest retained by the General Partner
or its affiliate is a proportionate working interest, (ii) the
respective obligations of the General Partner or its affiliate and
the Partnership are substantially the same proportionately as those
of the General Partner or its affiliate at the time it acquired the
property and (iii) the Partnership's interest in revenues will not
be less than the proportionate interest therein of the General
Partner or its affiliate when it acquired the property. The General
Partner or its affiliate may retain the remaining interest for its
own account or it may sell, transfer, farm-out or otherwise convey
all or a portion of such remaining interest to non-affiliated
industry members. In connection with any such sale, transfer, farm-out or
other conveyance of such interest to non-affiliated industry members, which
may occur either before or after the transfer of the
interests in the same properties to the Partnership, the General
Partner or its affiliate may realize a profit on the interests or
may be carried to some extent with respect to its cost obligations
in connection with any drilling on such properties and any such
profit or interest will be strictly for the account of the General
Partner and the Partnership will have no claim with respect thereto.
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(b) The General Partner or its affiliates may not retain any
overrides or other burdens on property conveyed to the Partnership
(other than overriding royalty interests granted to geologists and
other persons employed or retained by the General Partner or its
affiliates).
10.6 The General Partner will cause the Partnership Properties to be
acquired in accordance with the customs of the oil and gas industry in
the area. The Partnership will be required to do only such title work
with respect to its oil and gas properties as the General Partner in its
sole judgment deems appropriate in light of the area, any applicable
drilling or expiration dates and any other material factors.
10.7 Partnership Properties shall be transferred to the Partnership
after the decision to acquire a productive property or the commitment to
drill a Partnership Well thereon has been made. The Partnership shall
acquire interests in only those properties of the General Partner or UNIT
which comprise the spacing unit on which the Partnership Well is drilled
or on which a producing Partnership Well is located. If a spacing unit
on which a Partnership Well is drilled or located is ever reduced, or any
subsequent well in which the Partnership has no interest is drilled
thereon, the Partnership will have no interest in any such subsequent or
additional wells drilled on properties which were a part of the original
spacing unit unless any such additional well is commenced during 1995 or
is drilled by a drilling or income program of which the Partnership is a
partner. Likewise if UNIT, UPC or any affiliate, including any oil and
gas partnership subsequently formed for investment or participation by
employees, directors and/or consultants of UNIT or any of its
subsidiaries, acquires additional interests in Partnership Wells after
1995 the Partnership generally will not be entitled to participate in the
acquisition of such additional interests. In addition, if a Partnership
Well drilled on a spacing unit is dry or abandoned, the Partnership will
not have an interest in any subsequent or additional well drilled on the
spacing unit unless it is commenced during 1995 or is drilled by a
drilling or income program of which the Partnership is a partner.
10.8 The General Partner, UNIT or its affiliates will either conduct
the Partnership's drilling and production operations and operate each
Partnership Well or arrange for a third party operator to conduct such
operations. The General Partner will, on behalf of the Partnership,
enter into appropriate operating agreements with other owners of
Partnership Wells authorizing the General Partner, its affiliates or a
third party operator to conduct such operations. The Partnership will
take such action in connection with operations pursuant to said operating
agreements as the General Partner, in its sole discretion, deems
appropriate and in the best interests of the Partnership, and the
decision of the General Partner with respect thereto will be binding upon
the Partnership.
10.9 The General Partner will cause the Partnership to plug and
abandon its dry holes and abandoned wells in accordance with rules and
regulations of the governmental regulatory body having jurisdiction.
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10.10 The General Partner may pool or unitize Partnership Proper-
ties with other oil and gas properties when such pooling or unitization
is required by a governmental regulatory body, when well spacing as
determined by any such body requires such pooling or unitization, or
when, in the General Partner's opinion, such pooling or unitization is in
the best interests of the Partnership.
10.11 The General Partner will have authority to make and enter
into contracts for the sale of the Partnership's share of oil or gas
production from Partnership Wells, including contracts for the sale of
such production to the General Partner, UNIT or its affiliates; provided,
however, that the production purchased by the General Partner, UNIT or
any of its affiliates will be for prices which are not less than the
highest posted price (in the case of crude oil production) or prevailing
price (in the case of natural gas production) in the same field or area.
10.12 The General Partner will use its best efforts to procure and
maintain for the Partnership, and at its expense, such insurance coverage
with responsible companies as may be reasonably available for such
premium costs as would not be considered to be unreasonably high or
prohibitive with respect to each item of coverage and as the General
Partner considers necessary for the protection of the Partnership and the
Partners. The coverage will be in such amounts and will cover such risks
as the General Partner believes warranted by the operations conducted
hereunder. Such risks may include but will not necessarily be limited to
public liability and automobile liability, each covering bodily injury,
death and property damage, workmen's compensation and employer's
liability insurance and blowout and control of well insurance.
10.13 In order to conduct properly the business of the Partnership,
and in order to keep the Partners properly informed, the General Partner
will:
(a) maintain adequate records and files identifying the
Partnership Properties and containing all pertinent information in
regard thereto that is obtained or developed pursuant to this
Agreement;
(b) maintain a complete and accurate record of the acquisition
and disposition of each Partnership Property;
(c) maintain appropriate books and records reflecting the
Partnership's revenue and expense and each Partner's participation
therein;
(d) maintain a capital account for each Partner with appro-
priate records as necessary in order to reflect each Partner's
interest in the Partnership and furnish required tax information;
and
(e) keep the Limited Partners informed by means of written
reports on the acquisition of Partnership Properties and the
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progress of the business and operations of the Partnership, which
reports will be rendered semi-annually and at such more frequent
intervals during the progress of Partnership operations as the
General Partner deems appropriate.
10.14 The General Partner, UNIT and the officers, directors,
employees and affiliates thereof may own, purchase or otherwise acquire
and deal in oil and gas properties, drill wells, conduct operations and
otherwise engage in any aspect of the oil and gas business, either for
their own accounts or for the accounts of others. Each Limited Partner
hereby agrees that engaging in any activity permitted by this Section
10.14 will not be considered a breach of any duty that the General
Partner, UNIT or the officers, directors, employees and affiliates
thereof may have to the Partnership or the Limited Partners, and that the
Partnership and the Limited Partners will not have any interest in any
properties acquired or profits which may be realized with respect to any
such activity.
10.15 Subject to Section 12.1, without the prior consent of
Limited Partners holding a majority of the outstanding Units, the General
Partner will not (i) make, execute or deliver any assignment for the
benefit of the Partnership's creditors; or (ii) contract to sell all or
substantially all of the Partnership Properties (except as permitted by
Sections 10.23 and 16.4(b)).
10.16 In contracting for services to and insurance coverage for
the Partnership and its activities and operations, and in acquiring
material, equipment and personal property on behalf of the Partnership,
the General Partner will use its best efforts to obtain such services,
insurance, material, equipment and personal property at prices no less
favorable than those normally charged in the same or in comparable
geographic areas by non-affiliated persons or companies dealing at arm's
length. No rebates, concessions or compensation of a similar nature will
be paid to the General Partner by the person or company supplying such
services, insurance, material, equipment and personal property.
10.17 The General Partner, UNIT or its affiliates are authorized
to provide equipment, materials and services to the Partnership in
connection with the conduct of its operations, provided, that the terms
of any contracts between the Partnership and the General Partner, UNIT or
any affiliates, or the officers, directors, employees and affiliates
thereof must be no less favorable to the Partnership than those of
comparable contracts entered into, and will be at prices not in excess of
those charged in the same geographical area by non-affiliated persons or
companies dealing at arm's length. Any such contracts for services must
be in writing precisely describing the services to be rendered and all
compensation to be paid.
10.18 The General Partner may cause the Partnership to hold
Partnership Properties in the Partnership's name, or in the name of the
General Partner, UNIT, any affiliates thereof or some third party as
nominee for the Partnership. If record title to a Partnership Property
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is to be held permanently in the name of a nominee, such nominee
arrangement will be evidenced and documented by a nominee agreement
identifying the Partnership Properties so held and disclaiming any
beneficial interest therein by the nominee.
10.19 The General Partner will be generally liable for the debts
and obligations of the Partnership, provided that any claims against the
Partnership shall be satisfied first out of the assets of the Partnership
and only thereafter out of the separate assets of the General Partner.
10.20 The Partnership may not make any loans to the General
Partner, UNIT or any of its affiliates.
10.21 The General Partner will use its best efforts at all times
to maintain its net worth at a level that is sufficient to insure that
the Partnership will be classified for federal income tax purposes as a
partnership, rather than as an association taxable as a corporation, on
account of the net worth of the General Partner.
10.22 The Tax Matters Partner designated in Section 8.1 above is
authorized to engage legal counsel and accountants and to incur expense
on behalf of the Partnership in contesting, challenging and defending
against any audits, assessments and administrative or judicial proceed-
ings conducted or participated in by the Internal Revenue Service with
respect to the Partnership's operations and affairs.
10.23 At any time two years or more after the Partnership has
completed substantially all of its property acquisition, drilling and
development operations, the General Partner may, without the vote,
consent or approval of the Limited Partners, cause all or substantially
all of the oil and gas properties and other assets of the Partnership to
be sold, assigned or transferred to, or the Partnership merged or
consolidated with, another partnership or a corporation, trust or other
entity for the purpose of combining the assets of two or more of the oil
and gas partnerships formed for investment or participation by employees,
directors and/or consultants of UNIT or any of its subsidiaries;
provided, however, that the valuation of the oil and gas properties and
other assets of all such participating partnerships for purposes of such
transfer or combination shall be made on a consistent basis and in a
manner which the General Partner and UNIT believe is fair and equitable
to the Limited Partners. As a consequence of any such transfer or
combination, the Partnership shall be dissolved and terminated pursuant
to Article XVI hereof and the Limited Partners shall receive partnership
interests, stock or other equity interests in the transferee or resulting
entity.
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ARTICLE XI
Compensation and Reimbursements
11.1 For the General Partner's services performed as operator of
productive Partnership Wells located on Partnership Properties and as
operator during the drilling of Partnership Wells, the Partnership will
compensate the General Partner at rates no higher than those normally
charged in the same or a comparable geographic area by non-affiliated
persons or companies dealing at arm's length. The General Partner will
not receive compensation for such services performed in connection with
the operation of Partnership Wells operated by third party operators, but
such third party operators will be compensated as provided in the
operating agreements in effect with respect to such wells and the
Partnership will pay its proportionate share of such compensation.
11.2 The General Partner will be reimbursed by the Partnership out
of Partnership Revenues for that portion of its general and administra-
tive overhead expense that is attributable to its conduct of the actual
and necessary business, affairs and operations of the Partnership. The
General Partner's general and administrative overhead expenses will be
determined in accordance with industry practices. The allocable costs
and expenses will include all customary and routine legal, accounting,
geological, engineering, travel, office rent, telephone, secretarial,
salaries, data processing, word processing and other incidental reason-
able expenses necessary to the conduct of the Partnership's business and
generated by the General Partner or allocated to it by UNIT, but will not
include filing fees, commissions, professional fees, printing costs and
other expenses incurred in forming the Partnership or offering interests
therein. Also excluded will be any general and administrative overhead
expense of the General Partner or UNIT which may be attributable to its
services as an operator of Partnership Wells for which it receives
compensation pursuant to Section 11.1 above. The portion of the General
Partner's general and administrative overhead expense to be reimbursed by
the Partnership with respect to any particular period will be determined
by allocating to the Partnership that portion of the General Partner's
total general and administrative overhead expense incurred during such
period which is equal to the ratio of the Partnership's total
expenditures compared to the total expenditures by the General Partner
for its own account. The portion of such general and administrative
overhead expense reimbursement which is charged to the Limited Partners
may not exceed an amount equal to 3% of the Aggregate Subscription during
the first 12 months of the Partnership's operations, and in each
succeeding twelve-month period, the lesser of (a) 2% of the Aggregate
Subscription and (b) 10% of the total Partnership Revenue realized in
such twelve-month period. Administrative expenses incurred directly by
the Partnership, or incurred by the General Partner on behalf of the
Partnership and reimbursable to the General Partner, such as legal,
accounting, auditing, reporting, engineering, mailing and other such
fees, costs and expenses are not to be deemed a part of the general and
administrative expense of the General Partner which is to be reimbursed
pursuant to this Section 11.2 and the amounts thereof will not be subject
to the limitations described in the preceding sentence.
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ARTICLE XII
Rights and Obligations of Limited Partners
12.1 The Limited Partners, in their capacity as such, cannot
transact any business for the Partnership or take part in the control of
its business or management of its affairs. Limited Partners will have no
power to execute any agreements on behalf of, or otherwise bind or
commit, the Partnership. They may give consents and approvals as herein
provided and exercise the rights and powers granted to them in this
Agreement, it being understood that the exercise of such rights and
powers will be deemed to be matters affecting the basic structure of the
Partnership and not the exercise of control over its business; provided,
however, that exercise of any of the rights and powers granted to the
Limited Partners in Sections 10.15, 12.3, 14.1, 16.1 and 18.1 will not be
authorized or effective unless prior to the exercise thereof the General
Partner is furnished an opinion of counsel for the Partnership or an
order or judgment of any court of competent jurisdiction to the effect
that the exercise of such rights or powers (i) will not be deemed to
evidence that the Limited Partners are taking part in the control of or
management of the Partnership's business and affairs, (ii) will not
result in the loss of any Limited Partner's limited liability and (iii)
will not result in the Partnership being classified as an association
taxable as a corporation for federal income tax purposes.
12.2 The Limited Partners will not be personally liable for any
debts or losses of the Partnership. Except as otherwise specifically
provided herein, no Partner will be responsible for losses of any other
Partners.
12.3 Except as otherwise provided in this Agreement, no Limited
Partner will be entitled to the return of his contribution. Distribu-
tions of Partnership assets pursuant to this Agreement may be considered
and treated as returns of contributions if so designated by law or,
subject to Section 12.1, by agreement of the General Partner and Limited
Partners holding a majority of the outstanding Units. The value of a
Limited Partner's undistributed contribution determined for the purposes
of Section 39 of the Act at any point in time shall be his or her
percentage of the amount of the Partnership's stated capital allocated to
the Limited Partners as reflected in the financial statements of the
Partnership as of such point in time. No Partner will receive any
interest on his or her contributions and no Partner will have any
priority over any other Partner as to the return of contributions.
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ARTICLE XIII
Transferability of Limited Partner's Interest
13.1 Notwithstanding the provisions of Section 13.3, no sale,
exchange, transfer or assignment of a Limited Partner's interest in the
Partnership may be made unless in the opinion of counsel for the
Partnership,
(a) such sale, exchange, transfer or assignment, when added to
the total of all other sales, exchanges, transfers or assignments of
interests in the Partnership within the preceding 12 months, would
not result in the Partnership being considered to have terminated
within the meaning of Section 708 of the Code (provided, however,
that this condition may be waived by the General Partner in its
discretion);
(b) such sale, exchange, transfer or assignment would not
violate, or cause the offering of the Units to be violative of, the
Securities Act of 1933, as amended, or any state securities or "blue
sky" laws (including any investor suitability standards) applicable
to the Partnership or the interest to be sold, exchanged,
transferred or assigned; and
(c) such sale, exchange, transfer or assignment would not
cause the Partnership to lose its status as a partnership for
federal income tax purposes,
and said opinion of counsel is delivered in writing to the Partnership
prior to the date of the sale, exchange, transfer or assignment.
13.2 In no event shall all or any part of an interest in the
Partnership be assigned or transferred to a minor (except in trust or
pursuant to the Uniform Gifts to Minors Act) or an incompetent (except in
trust), except by will or intestate succession.
13.3 Except for transfers or assignments (in trust or otherwise) by
a Limited Partner of all or any part of his or her interest in the
Partnership
(a) to the General Partner,
(b) to or for the benefit of himself or herself, his or her
spouse, or other members of his or her immediate family sharing the
same household,
(c) to a corporation or other entity in which all of the
beneficial owners are Limited Partners or assigns permitted in (a)
and (b) above, or
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(d) by the General Partner to any person who at the time of
such transfer is an employee of the General Partner, UNIT or its
subsidiaries,
no Limited Partner's Units or any portion thereof may be sold, assigned
or transferred except by reason of death or operation of law.
13.4 If a Limited Partner dies, his or her executor, administrator
or trustee, or, if he or she is adjudicated incompetent, his or her
committee, guardian or conservator, or, if he or she becomes bankrupt,
the trustee or receiver of his or her estate, shall have all the rights
of a Limited Partner for the purpose of settling or managing his or her
estate and such power as the deceased, incapacitated or bankrupt Limited
Partner possessed to assign all or any part of his or her interest and to
join with such assignee in satisfying conditions precedent to such
assignee's becoming a Substituted Limited Partner.
13.5 The Partnership shall not recognize for any purpose any
purported sale, assignment or transfer of all or any fraction of the
interest of a Limited Partner in the Partnership, unless the provisions
of Section 13.1 shall have been complied with and there shall have been
filed with the Partnership a written and dated notification of such sale,
assignment or transfer in form satisfactory to the General Partner,
executed and acknowledged by both the seller, assignor or transferor and
the purchaser, assignee or transferee and such notification (i) contains
the acceptance by the purchaser, assignee or transferee of all of the
terms and provisions of this Agreement and (ii) represents that such
sale, assignment or transfer was made in accordance with all applicable
laws and regulations. Any sale, assignment or transfer shall be
recognized by the Partnership as effective on the date of such
notification if the date of such notification is within thirty (30) days
of the date on which such notification is filed with the Partnership, and
otherwise shall be recognized as effective on the date such notification
is filed with the Partnership.
13.6 Any Limited Partner who shall assign all of his or her interest
in the Partnership shall cease to be a Limited Partner, except that,
unless and until a Substituted Limited Partner is admitted in his or her
stead, such assigning Limited Partner shall retain the statutory rights
of the assignor of a Limited Partner's interest under the Act.
13.7 A person who is the assignee of all or any fraction of the
interest of a Limited Partner, but does not become a Substituted Limited
Partner and desires to make a further assignment of such interest, shall
be subject to all the provisions of this Article XIII to the same extent
and in the same manner as any Limited Partner desiring to make an
assignment of his or her interest.
13.8 No Limited Partner shall have the right to substitute a
purchaser, assignee, transferee, donee, heir, legatee, distributee or
other recipient of all or any portion of such Limited Partner's interest
in the Partnership as a Limited Partner in his or her place. Any such
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purchaser, assignee, transferee, donee, legatee, distributee or other
recipient of an interest in the Partnership shall be admitted to the
Partnership as a Substituted Limited Partner only with the consent of the
General Partner, which consent shall be granted or withheld in the sole
and absolute discretion of the General Partner and may be arbitrarily
withheld, and only by an amendment to this Agreement or the certificate
of limited partnership duly executed and recorded in the proper records
of each jurisdiction in which the Partnership owns mineral interests and
filed in the proper records of the State of Oklahoma. Any such consent
by the General Partner shall be binding and conclusive without the
consent of any Limited Partners and may be evidenced by the execution of
the General Partner of an amendment to this Agreement or the certificate
of limited partnership, evidencing the admission of such person as a
Substituted Limited Partner.
13.9 No person shall become a Substituted Limited Partner until such
person shall have:
(a) become a party to, and adopted all of the terms and
conditions of, this Agreement;
(b) if such person is a corporation, partnership or trust,
provided the General Partner with evidence satisfactory to counsel
for the Partnership of such person's authority to become a Limited
Partner under the terms and provisions of this Agreement; and
(c) paid or agreed to pay the costs and expenses incurred by
the Partnership in connection with such person's becoming a Limited
Partner.
Provided, however, that for the purpose of allocating Partnership
Revenue, costs and expenses, a person shall be treated as having become,
and as appearing in the records of the Partnership as, a Substituted
Limited Partner on such date as the sale, assignment or transfer was
recognized by the Partnership pursuant to Section 13.5.
13.10 By his or her execution of his or her Subscription
Agreement, each Limited Partner represents and warrants to the General
Partner and to the Partnership that his or her acquisition of his or her
interest in the Partnership is made as principal for his or her own
account for investment purposes only and not with a view to the resale or
distribution of such interest. Each Limited Partner agrees that he or
she will not sell, assign or otherwise transfer his or her interest in
the Partnership or any fraction thereof unless such interest has been
registered under the Securities Act of 1933, as amended, or such sale,
assignment or transfer is exempt from such registration and, in any
event, he or she will not so sell, assign or otherwise transfer his or
her interest or any fraction thereof to any person who does not similarly
represent, warrant and agree.
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ARTICLE XIV
Assignments by the General Partner
14.1 The General Partner may not sell, assign, transfer or otherwise
dispose of its interest in the Partnership except with the prior consent,
subject to Section 12.1, of Limited Partners holding a majority of the
outstanding Units; provided that a sale, assignment or transfer may be
effective without such consent if pursuant to a bona fide merger, any
other corporate reorganization or a complete liquidation, pursuant to a
sale of all or substantially all of the General Partner's assets
(provided the purchasers of such assets agree to assume the duties and
obligations of the General Partner) or a sale or transfer to UNIT or any
affiliates of UNIT. If the Limited Partners' consent to a proposed
transfer is required, the General Partner will, concurrently with the
request for such consent, give the Limited Partners written notice
identifying the interest to be transferred, the date on which the
transfer is to be effective, the proposed transferee and the substitute
General Partner, if any.
14.2 Sales, assignments and transfers of the interests in the
Partnership owned by the General Partner will be subject to, and the
assignee will acquire the assigned interest subject to, all of the terms
and provisions of this Agreement.
14.3 If the Limited Partners' consent to a transfer of the General
Partner's interest in the Partnership is obtained as above provided, or
is not required, the transferee may become a substitute General Partner
hereunder. The substitute General Partner will assume and agree to
perform all of the General Partner's duties and obligations hereunder and
the transferring General Partner will, upon making a proper accounting to
the substitute General Partner, be relieved of any further duties or
obligations hereunder with respect to Partnership operations thereafter
occurring.
ARTICLE XV
Limited Partners' Right of Presentment
15.1 After December 31, 1996, each Limited Partner will have the
option, subject to the terms and conditions set forth in this Article XV,
to require the General Partner to purchase all (but not less than all) of
his or her Units, provided that the option may not be exercised after the
date of any notice that will effect a dissolution and termination of the
Partnership pursuant to Article XVI below. Any such exercise shall be
effected by written notice thereof delivered to the General Partner.
15.2 Sales of Limited Partners' Units pursuant to this Article XV
will be effective, and the purchase price for such interests will be
determined, as of the close of business on the last day of the calendar
year in which the Limited Partner's notice exercising his or her option
is given, or, at the General Partner's election, as of 7:00 o'clock A.M.
on the following day.
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15.3 The purchase price to be paid for the Units of any Limited
Partner who exercises the option granted in this Article XV will be
determined in the following manner. First, future gross revenues
expected to be derived from the production and sale of the proved
reserves attributable to Partnership Properties will be estimated, as of
the end of the calendar year in which presentment is made, by the
independent engineering firm preparing a report on the reserves of the
Partnership, or if no such firm is preparing a report as of the end of
the calendar year in which the option is exercised, then by the General
Partner. Next, future net revenues will be calculated by deducting
anticipated expenses (including Operating Expenses and other costs that
will be incurred in producing and marketing such reserves and any gross
production, excise, or other taxes, other than federal income taxes,
based on the oil and gas production of the Partnership or sales thereof)
from estimated future gross revenues. The estimates of price and cost
escalations to be used in such calculations will be those of such
independent engineering firm or the General Partner, whichever is making
the determination. Then the present worth of the future net revenues
will be calculated by discounting the estimated future net revenues at
that rate per annum which is one (1) percentage point higher than the
prime rate of interest being charged by Bank of Oklahoma, N.A., Tulsa,
Oklahoma, or any successor bank, as such prime rate of interest is
announced by said bank as of the date such reserves are estimated. This
amount will be reduced by an additional 25% to take into account the
uncertainties attendant to the production and sale of oil and gas
reserves and other unforeseen contingencies. Estimated salvage value of
tangible equipment installed on the Partnership Wells and costs of
plugging and abandoning the productive Partnership Wells, both discounted
at the aforementioned rate from the expected date of abandonment, will be
considered, and Partnership Properties, if any, which do not have proved
reserves attributable to them but which have not been condemned will be
valued at the lower of cost or their then current market value as
determined by the aforementioned independent petroleum engineering firm
or General Partner, as the case may be. The Partnership's cash on hand,
prepaid expenses, accounts receivable (less a reasonable reserve for
doubtful accounts) and the market value of its other assets as determined
by the General Partner will be added to the value of the Partnership
Properties thus determined, and the Partnership's debts, obligations and
other liabilities will be deducted, to arrive at the Partnership's net
asset value for purposes of this Section 15.3. The price to be paid for
the Limited Partner's interest will be his or her proportionate share of
such net asset value less 75% of the amount of any Partnership
distributions received by him or her which are attributable to sales of
Partnership production since the date as of which the Partnership's
proved reserves are estimated.
15.4 Within one hundred twenty (120) days after the end of any
calendar year in which a Limited Partner exercises his or her option to
require purchase of his or her Units as provided in this Article XV, the
General Partner will furnish to such Limited Partner a statement showing
the price to be paid for his or her Units and evidencing that such price
has been determined in accordance with the provisions of Section 15.3
above. The statement will show which portion of the proposed purchase
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price is represented by the value of the proved reserves and by each of
the other classes of Partnership assets and liabilities attributable to
the account of the Limited Partner. The Limited Partner will then have
thirty (30) days to confirm, by further notice to the General Partner,
his or her intention to sell his or her Units to the General Partner. If
the Limited Partner timely confirms his or her intention to sell, the
sale will be consummated and the price paid in cash within ten (10) days
after such confirmation. The General Partner will not be obligated to
purchase (i) any Units pursuant to such right if such purchase, when
added to the total of all other sales, exchanges, transfers or
assignments of the Units within the preceding 12 months, would result in
the Partnership being considered to have terminated within the meaning of
Section 708 of the Code or would cause the Partnership to lose its status
as a partnership for federal income tax purposes, or (ii) in any one
calendar year more than 20% of the Units in the Partnership then
outstanding. If less than all of the Units tendered are purchased, the
interests purchased will be selected by lot. The Limited Partners whose
tendered Units were rejected by reason of the foregoing limitation shall
be entitled to priority in the following year. Contemporaneously with
the closing of any such sale, the Limited Partner will execute such
certificates or other documents and perform such acts as the General
Partner deems necessary to effect the sale and transfer of the
liquidating Limited Partner's Units to the General Partner and to
preserve the limited liability status of the Partnership under the laws
of the jurisdictions in which it is doing business.
15.5 As used in Sections 15.3 and 15.4 above, the term "proved
reserves" shall have the meaning ascribed thereto in Regulation S-X
adopted by the Securities and Exchange Commission.
ARTICLE XVI
Termination and Dissolution of Partnership
16.1 The Partnership will terminate automatically on December 31,
2025, unless prior thereto, subject to Section 12.1 above, the General
Partner or Limited Partners holding a majority of the outstanding Units
elect to terminate the Partnership as of an earlier date. In the event
of such earlier termination, ninety (90) days' written notice will be
given to all other Partners. The termination date will be specified in
such notice and must be the last day of any calendar month following
expiration of the ninety (90) day period unless an earlier date is
approved by Limited Partners holding a majority of the outstanding Units.
16.2 Upon the dissolution (other than pursuant to a merger or other
corporate reorganization), bankruptcy, legal disability or withdrawal of
the General Partner (other than pursuant to Section 14.1 above), the
Partnership shall immediately be dissolved and terminated; provided,
however, that nothing in this Agreement shall impair, restrict or limit
the rights and powers of the Partners under the laws of the State of
Oklahoma and any other jurisdiction in which the Partnership is doing
business to reform and reconstitute themselves as a limited partnership
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within ninety (90) days following the dissolution of the Partnership
either under provisions identical to those set forth herein or under any
other provisions. The withdrawal, expulsion, dissolution, death, legal
disability, bankruptcy or insolvency of any Limited Partner will not
effect a dissolution or termination of the Partnership.
16.3 Upon termination of the Partnership by action of the Limited
Partners pursuant to Section 16.1 hereof or as a result of an event under
Section 16.2 hereof, a party designated by the Limited Partners holding
a majority of the outstanding Units will act as Liquidating Trustee. In
any other case, the General Partner will act as Liquidating Trustee.
16.4 As soon as possible after December 31, 2025, or the date of the
notice of or event causing an earlier termination of the Partnership, the
Liquidating Trustee will begin to wind up the Partnership's business and
affairs. In this regard:
(a) The Liquidating Trustee will furnish or obtain an
accounting with respect to all Partnership accounts and the account
of each Partner and with respect to the Partnership's assets and
liabilities and its operations from the date of the last previous
audit of the Partnership to the date of such dissolution;
(b) The Liquidating Trustee may, in its discretion, sell any
or all productive and non-productive properties which, except in the
case of an election by the General Partner to terminate the
Partnership prior to the tenth anniversary of the Effective Date,
may be sold to the General Partner or any of its affiliates for
their fair market value as determined in good faith by the General
Partner;
(c) The Liquidating Trustee shall:
(i) pay all of the Partnership's debts, liabilities and
obligations to its creditors, including the General Partner;
and
(ii) pay all expenses incurred in connection with the
termination, liquidation and dissolution of the Partnership and
distribution of its assets as herein provided;
(d) The Liquidating Trustee shall ascertain the fair market
value by appraisal or other reasonable means of all assets of the
Partnership remaining unsold, and each Partner's capital account
shall be charged or credited, as the case may be, as if such
property had been sold at such fair market value and the gain or
loss realized thereby had been allocated to and among the Partners
in accordance with Article VI hereof; and
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(e) On or as soon as practicable after the effective date of
the termination, all remaining cash and any other properties and
assets of the Partnership not sold pursuant to the preceding
subsections of this Section 16.4 will be distributed to the Partners
(i) in proportion to and to the extent of any remaining balances in
the Partners' capital accounts and then (ii) in undivided interests
to the Partners in the same proportions that Partnership Revenues
are being shared at the time of such termination, provided, that:
(i) the various interests distributed to the respective
Partners will be distributed subject to such liens, encum-
brances, restrictions, contracts, operating agreements,
obligations, commitments or undertakings as existed with
respect to such interests at the time they were acquired by the
Partnership or were subsequently created or entered into by the
Partnership;
(ii) if interests in the Partnership Wells that are not
subject to any operating agreement are to be distributed, the
Partners will, concurrently with the distribution, enter into
standard form operating agreements covering the subsequent
operation of each such well which will, if the termination is
effected pursuant to Section 16.1 above, be in a form satis-
factory to the General Partner and will name the General
Partner or its designee as operator; and
(iii) no Partner shall be distributed an interest in
any asset if the distribution would result in a deficit balance
or increase the deficit balance in its capital account (after
making the adjustments referred to in this Section 16.4
relating to distributions in kind).
16.5 If the General Partner has a deficit balance in its capital
account following the distribution(s) provided for in Section 16.4(e)
above, as determined after taking into account all adjustments to its
capital account for the taxable year of the Partnership during which such
distribution occurs, it shall restore the amount of such deficit balance
to the Partnership within ninety (90) days and such amount shall be
distributed to the other Partners in accordance with their positive
capital account balances.
16.6 Notwithstanding anything to the contrary in this Agreement,
upon the dissolution and termination of the Partnership, the General
Partner will contribute to the Partnership the lesser of: (a) the deficit
balance in its capital account; or (b) the excess of 1.01 percent of the
total Capital Contributions of the Limited Partners over the capital
previously contributed by the General Partner.
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<PAGE>
ARTICLE XVII
Notices
17.1 All notices, consents, requests, demands, offers, reports and
other communications required or permitted shall be deemed to be given or
made when personally delivered to the party entitled thereto, or when
sent by United States mail in a sealed envelope, with postage prepaid,
addressed, if to the General Partner, to 1000 Kensington Tower I, 7130
South Lewis Avenue, P. O. Box 702500, Tulsa, Oklahoma 74136, and, if to
a Limited Partner, to the address set forth below such Limited Partner's
signature on the counterpart of the Subscription Agreement that he or she
originally executed and delivered to the General Partner. The General
Partner may change its address by giving notice to all Limited Partners.
Limited Partners may change their address by giving notice to the General
Partner.
ARTICLE XVIII
Amendments
18.1 Limited Partners do not have the right to propose amendments to
this Agreement. The General Partner may propose an amendment or
amendments to this Agreement by mailing to the Limited Partners a notice
describing the proposed amendment and a form to be returned by the
Limited Partners indicating whether they oppose or approve of its
adoption. Such notice will include the text of the proposed amendment,
which will have been approved in advance by counsel for the Partnership.
If, within sixty (60) days, or such shorter period as may be designated
by the General Partner, after any notice proposing an amendment or
amendments to this Agreement has been mailed, Limited Partners holding a
majority of the outstanding Units have properly executed and returned the
form indicating that they approve of and consent to adoption of the
proposed amendment, such amendment will become effective as of the date
specified in such notice, provided that no amendment which alters the
allocations specified in Article VI above, changes the compensation and
reimbursement provisions set forth in Article XI above or is otherwise
materially adverse to the interests of the Limited Partners will become
effective unless approved by all Limited Partners. If an amendment does
become effective, all Partners will promptly evidence such effectiveness
by executing such certificates and other instruments as the General
Partner may deem necessary or appropriate under the laws of the
jurisdictions in which the Partnership is then doing business in order to
reflect the amendment.
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<PAGE>
ARTICLE XIX
General Provisions
19.1 This Agreement embodies the entire understanding and agreement
between the Partners concerning the Partnership, and supersedes any and
all prior negotiations, understandings or agreements in regard thereto.
19.2 In those cases where this Agreement requires opinions to be
expressed by, or actions to be approved by, counsel for Limited Partners,
such counsel must be qualified and experienced in the fields of federal
income taxation and partnership and securities laws.
19.3 This Agreement and the Subscription Agreement may be executed
in multiple counterpart copies, each of which will be considered an
original and all of which constitute one and the same instrument.
19.4 This Agreement will be deemed to have been executed and
delivered in the State of Oklahoma and will be construed and interpreted
according to the laws of that State.
19.5 This Agreement and all of the terms and provisions hereof will
be binding upon and will inure to the benefit of the Partners and their
respective heirs, executors, administrators, trustees, successors and
assigns.
EXECUTED in the name of and on behalf of the undersigned General
Partner this 1st day of March, 1995, but effective as of the
Effective Datesty.
"General Partner"
UNIT PETROLEUM COMPANY
Attest:
By /s/ Mark E. Schell By /s/ John G. Nikkel
----------------------- ---------------------------
Secretary President
(CORPORATE SEAL)
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<PAGE>
LIMITED PARTNER SUBSCRIPTION AGREEMENT AND
SUITABILITY STATEMENT
(ALL INFORMATION WILL BE TREATED CONFIDENTIALLY)
Unit 1995 Employee Oil and Gas Limited Partnership
c/o Unit Petroleum Company
1000 Kensington Center
7130 South Lewis Avenue
Tulsa, Oklahoma 74136
RE: Unit 1995 Employee Oil and
Gas Limited Partnership
Gentlemen:
In connection with the subscription of the undersigned
for units of limited partnership interest ("Units") in Unit 1995
Employee Oil and Gas Limited Partnership (the "Partnership") which
the undersigned tenders herewith to Unit Petroleum Company (the
"General Partner"), the undersigned is hereby furnishing the
Partnership and the General Partner the information set forth
herein below and makes the representations and warranties set forth
below, to indicate whether the undersigned is a suitable subscriber
for Units in the Partnership. As a condition precedent to
investing in the Partnership, the undersigned hereby represents,
warrants, covenants and agrees as follows:
1. The undersigned acknowledges that he or she has
received and reviewed a copy of the Private Offering Memorandum
(the "Offering Memorandum") dated January 6, 1995, of Unit 1995
Employee Oil and Gas Limited Partnership, relating to the offering
of Units in the Partnership, and all Exhibits thereto, including
the Agreement of Limited Partnership (the "Agreement"), and
understands that the Units will be offered to others on the terms
and in the manner described in the Offering Memorandum. The
undersigned hereby subscribes for the number of Units set forth
below pursuant to the terms of the Offering Memorandum and tenders
his or her Capital Subscription as required and agrees to pay his
or her Additional Assessments upon call or calls by the General
Partner; and the undersigned acknowledges that he or she shall have
the right to withdraw this subscription only up until the time the
General Partner executes and accepts the undersigned's subscription
and that the General Partner may reject any subscription for any
reason without liability to it; and, further, the undersigned
agrees to comply with the terms of the Agreement and to execute any
and all further documents necessary in connection with his or her
admission to the Partnership.
I-1
<PAGE>
2. The undersigned has reviewed and acknowledges
execution of the Power of Attorney set forth in the Agreement and
elsewhere in this instrument.
3. The undersigned is aware that no federal or state
regulatory agency has made any findings or determination as to the
fairness for public or private investment, nor any recommendation
or endorsement, of the purchase of Units as an investment.
4. The undersigned recognizes the speculative nature
and risks of loss associated with oil and gas investments and that
he or she may suffer a complete loss of his or her investment. The
Units subscribed for hereby constitute an investment which is
suitable and consistent with his or her investment program and that
his or her financial situation enables him or her to bear the risks
of this investment. The undersigned represents that he or she has
adequate means of providing for his or her current needs and
possible personal contingencies, and that he or she has no need for
liquidity of this investment.
5. The undersigned confirms that he or she understands,
and has fully considered for purposes of this investment, the RISK
FACTORS set forth in the Offering Memorandum and that (i) the Units
are speculative investments which involve a high degree of risk of
loss by the undersigned of his or her investment therein, (ii)
there is a risk that the anticipated tax benefits under the
Agreement could be challenged by the Internal Revenue Service or
could be affected by changes in the Internal Revenue Code of 1986,
as amended, the regulations thereunder or administrative or
judicial interpretations thereof thereby depriving Limited Partners
of anticipated tax benefits, (iii) the General Partner and its
affiliates will engage in transactions with the Partnership which
may result in a profit and, in the future, may be engaged in
businesses which are competitive with that of the Partnership, and
the undersigned agrees and consents to such activities, even though
there are conflicts of interest inherent therein, and (iv) there
are substantial restrictions on the transferability of, and there
will be no public market for, the Units and, accordingly, it may be
difficult for him or her to liquidate his or her investment in the
Units in case of emergency, if possible at all.
6. The undersigned confirms that in making his or her
decision to purchase the Units subscribed for he or she has relied
upon independent investigations made by him or her (or by his or
her own professional tax and other advisors) and that he or she has
been given the opportunity to examine all documents and to ask
questions of, and to receive answers from the General Partner or
any person(s) acting on its behalf concerning the terms and
conditions of the offering or any other matter set forth in the
Offering Memorandum, and to obtain any additional information, to
the extent the General Partner possesses such information or can
acquire it without unreasonable effort or expense, necessary to
I-2
<PAGE>
verify the accuracy of the information set forth in the Offering
Memorandum, and that no representations have been made to him or
her and no offering materials have been furnished to him or her
concerning the Units, the Partnership, its business or prospects or
other matters, except as set forth in the Offering Memorandum and
the other materials described in the Offering Memorandum.
7. The undersigned understands that the Units are being
offered and sold under an exemption from registration provided by
Sections 3(b) and/or 4(2) of the Securities Act of 1933, as amended
(the "Act"), and warrants and represents that any Units subscribed
for are being acquired by the undersigned solely for his or her own
account, for investment purposes only, and are not being purchased
with a view to or for the resale, distribution, subdivision or
fractionalization thereof; the undersigned has no agreement or
other arrangement, formal or informal, with any person to sell,
transfer or pledge any part of any Units subscribed for or which
would guarantee the undersigned any rights to such Units; the
undersigned has no plans to enter into any such agreement or
arrangement, and, consequently, he or she must bear the economic
risk of the investment for an indefinite period of time because the
Units cannot be resold or otherwise transferred unless subsequently
registered under the Act (which neither the General Partner nor the
Partnership is obligated to do), or an exemption from such
registration is available and, in any event, unless transferred in
compliance with the Agreement.
8. The undersigned further understands that the
exemption under Rule 144 of the Act will not be generally available
because of the conditions and limitations of such rule; that, in
the absence of the availability of such rule, any disposition by
him or her of any portion of his or her investment will require
compliance under the Act; and that the Partnership and the General
Partner are under no obligation to take any action in furtherance
of making such exemption available.
9. The undersigned is aware that the General Partner
will have full and complete control of Partnership operations and
that he or she must depend on the General Partner to manage the
Partnership profitably; and that a Limited Partner does not have
the same rights as a stockholder in a corporation or the protection
which stockholders might have, since limited partners have limited
rights in determining policy.
10. The undersigned is aware that the General Partner
will receive compensation for its services irrespective of the
economic success of the Partnership.
I-3
<PAGE>
11. The undersigned represents and warrants as follows
(please mark all applicable categories):
(a) If an individual, the undersigned is the sole
party in interest, and the undersigned is at least 21
years of age and a bona fide resident and domiciliary
(not a temporary or transient resident) of the state set
forth opposite his or her signature hereto;
____ YES ____ NO
(b) If a partnership or corporation, the
undersigned meets the following: (1) the entity has not
been formed for the purposes of making this investment;
(2) the entity was formed on ____________; and (3) the
entity has a history of investments similar to the type
described in the Offering Memorandum;
____ YES ____ NO
(c) The undersigned meets all suitability standards
and acknowledges being aware of all legend conditions
applicable to his or her state of residence as set forth
herein;
____ YES ____ NO
(d) (i) The undersigned has a net worth (including
home, furnishings and automobiles) of at least five times
the amount of his or her Capital Subscription, and
anticipates that he or she will have adjusted gross
income during the current year in an amount which will
enable him or her to bear the economic risks of the
investment in the Partnership;
____ YES ____ NO
and
(ii) The undersigned is a salaried employee of
Unit Corporation ("UNIT") or any of its subsidiaries at
the date of formation of the Partnership whose annual
base salary for 1995 has been set at $22,680 or more, or
the undersigned is a director of UNIT;
____ YES ____ NO
and
(e) The undersigned _____ is or _____ is not a
citizen of the United States.
I-4
<PAGE>
12. The undersigned represents and agrees that he or she
has had sufficient opportunity to make inquiries of the General
Partner in order to supplement information contained in the
Offering Memorandum respecting the offering, and that any
information so requested has been made available to his or her
satisfaction, and he or she has had the opportunity to verify such
information. The undersigned further agrees and represents that he
or she has knowledge and experience in business and financial
matters, and with respect to investments generally, and in
particular, investments generally comparable to the offering, so as
to enable him or her to utilize such information to evaluate the
risks of this investment and to make an informed investment
decision. The following is a brief description of the
undersigned's experience in the evaluation of other investments
generally comparable to the offering:
________________________________________________________________
________________________________________________________________
________________________________________________________________
________________________________________________________________
13. The undersigned is aware that the Partnership and
the General Partner have been and are relying upon the
representations and warranties set forth in this Limited Partner
Subscription Agreement and Suitability Statement, in part, in
determining whether the offering meets the conditions specified in
Rules of the Securities and Exchange Commission and the exemption
from registration provided by Sections 3(b) and/or 4(2) of the Act.
14. All of the information which the undersigned has
furnished the General Partner herein or previously with respect to
the undersigned's financial position and business experience is
correct and complete as of the date of this Agreement, and, if
there should be any material change in such information prior to
the closing of the offering period of the Units, the undersigned
will immediately furnish such revised or corrected information to
the General Partner. The undersigned agrees that the foregoing
representations and warranties shall survive his or her admission
to the Partnership, as well as any acceptance or rejection of a
subscription for the Units.
LIMITED PARTNER SIGNATURE PAGES
If the subscription tendered hereby of the undersigned is
accepted by the General Partner, the undersigned hereby executes
and swears to the Agreement of Limited Partnership of Unit 1995
Employee Oil and Gas Limited Partnership as a Limited Partner,
thereby agreeing to all the terms thereof and duly appoints the
General Partner, with full power of substitution, his or her true
and lawful attorney to execute, file, swear to and record any
Certificate of Limited Partnership or amendments thereto or
cancellation thereof and any other instruments which may be
required by law in any jurisdiction to permit qualification of the
I-5
<PAGE>
Partnership as a limited partnership or for any other purposes
necessary to implement the Partnership's purposes.
THE SECURITIES REPRESENTED BY THIS CERTIFICATE HAVE NOT
BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, THE
OKLAHOMA SECURITIES ACT OR OTHER APPLICABLE STATE SECURITIES ACTS.
THE SECURITIES HAVE BEEN ACQUIRED FOR INVESTMENT AND MAY NOT BE
SOLD OR TRANSFERRED FOR VALUE IN THE ABSENCE OF AN EFFECTIVE
REGISTRATION OF THEM UNDER THE SECURITIES ACT OF 1933, AS AMENDED,
AND/OR THE OKLAHOMA SECURITIES ACT, OR ANY OTHER APPLICABLE ACT, OR
AN OPINION OF COUNSEL TO UNIT 1995 EMPLOYEE OIL AND GAS LIMITED
PARTNERSHIP THAT SUCH REGISTRATION IS NOT REQUIRED UNDER SUCH ACT.
The undersigned hereby subscribes for _____ Units
(minimum subscription: 2 Units) at a price of $1,000 per Unit for
a total Capital Subscription (as defined in Article II of the
Agreement) of $________________, which shall be due and payable
either:
(Check One)
_______ (a) in four equal installments on March 15, 1995, June
15, 1995, September 15, 1995 and December 15, 1995, respectively;
or
_______ (b) through equal deductions from 1995 salary of the
undersigned commencing immediately after the Effective Date (as
defined in Article II of the Agreement).
RESIDENT
LIMITED PARTNER ADDRESS (If placing Units
in the name of spouse
________________ _________________ or trustee for minor
child or children,
________________ _________________ please provide name,
Signature address of such spouse
or trustee and Social
________________ Mailing Address Security or Tax
Please Print Name if different: Identification Number)
TAX I.D. OR
_________________ SOCIAL SECURITY NO.
Date: ___________ _________________ ___________________
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<PAGE>
ACCEPTED THIS _____ DAY OF February, 1995.
UNIT 1995 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
By ____________________________________
Authorized Officer of Unit
Petroleum Company, General Partner
Upon completion, an executed copy of this Limited Partner
Subscription Agreement and Suitability Statement should be returned
to Unit 1994 Employee Oil and Gas Limited Partnership, Attention
Mark E. Schell, 1000 Kensington Tower I, 7130 South Lewis Avenue,
Tulsa, Oklahoma, 74136. The General Partner, after acceptance,
will return a copy of the accepted Subscription Agreement to the
Limited Partner.
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<PAGE>
"CONNER & WINTERS" Letter Head
A Professional Corporation
Lawyers
2400 First National Tower
15 East Fifth Street
Tulsa, Oklahoma 74103-4391
(981) 586-5711
FAX (918 586-8982
January 6, 1995
Unit Petroleum Company
1000 Galleria Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
Re: Unit 1995 Employee Oil and Gas Limited Partnership
Gentlemen:
We have acted as counsel for Unit Petroleum Company, an Oklahoma
corporation (the "General Partner"), which will be the General Partner in the
Unit 1995 Employee Oil and Gas Limited Partnership, AS proposed Oklahoma
limited partnership (the "Partnership"). You have requested our opinions
regarding (I) the legality of the interests to be issued in the Partnership and
(ii) certain federal income tax matters concerning the Partnership.
We have reviewed and relied upon the accuracy of the facts and information
set forth in the Private Offering Memorandum dated January 6, 1995 (the
"Memorandum"), covering the offer and sale of units of limited partnership
interest ("Units") in the Partnership, the Agreement of Limited Partnership
included as Exhibit A to the Memorandum (the "Partnership Agreement"),
the consolidated balance sheet of the General Partner dated November 30, 1994,
and such other documents and matters as we have considered necessary in order
to render this opinion. Capitalized terms used herein have the meaning
assigned to them in the Memorandum, except as otherwise specifically indicated.
In rendering our opinions we have assumed the accuracy of and relied upon
certain representations made by you. Our opinions are conditioned upon the
initial and continuing accuracy of such representations and of the following
representations provided us:
<PAGE>
Unit Petroleum Company
January 6, 1996
Page 2
1. As of the date of the Memorandum, the Memorandum did not contain any
untrue statement of a material fact or omit to state a material fact required
to be stated therein or necessary to make the statements therein not
misleading.
2. The balance sheet of the General Partner included in the Memorandum
presents fairly its financial position as of the date indicated; said balance
sheet has been prepared in conformity with generally accepted accounting
principles applied on a consistent basis; and since the date of the most recent
balance sheet of the General Partner included in the Memorandum through the
date hereof, there has not been any material adverse change in its financial
position.
3. There is not now pending nor, to the knowledge of the General Partner
of UNIT, threatened any action, suit or proceeding by the Internal Revenue
Service under Sections 6700 or 7408 of the Internal Revenue Code relating to
the promoter penalty referred to in Section 6700 of the Code with respect to
any partnerships sponsored by the General Partner or UNIT. Neither the General
Partner, UNIT, nor, to the knowledge of any of them, any participant in such
partnerships has received any pre-riling notifications referred to in Revenue
Procedure 83-73 with respect to such partnerships or the Partnership from the
Internal Revenue Service.
4. A duly executed certificate of limited partnership for the
Partnership will be filed with the Oklahoma Secretary of State in compliance
with the Act and the organization and operation of the Partnership will be in
accordance with the Act, the Agreement and the representations made in the
Memorandum.
5. General Partner has and will maintain substantial assets which can be
reached by a creditor of the Partnership, exclusive of all interests in the
Partnership and notes and accounts receivable from and payable to the
Partnership. At the time of admission of Limited Partners to the Partnership,
the General Partner will have a minimum net worth equal to at least 10% of the
Capital Contributions made to the Partnership, excluding any net worth
attributable to any interest of the General Partner in the Partnership. For
purposes of this net worth determination, assets will be valued based upon
their current fair market value. The General Partner will use its best efforts
to ensure that the net worth of the General Partner continues to meet or exceed
an amount equal to 10% of the total Capital Contributions of the Limited
Partners in the Partnership.
6. The General Partner will, in the aggregate, at all times during the
existence of the Partnership, receive at least one percent (1%) of each
material item of the Partnership's income, gain, loss, deduction or credit
(other than by reason of the ownership of Units by the General Partner).
7. A nominee/agent agreement ("Nominee Agreement") in substantially the
form of the Nominee Agreement attached hereto as Exhibit I will be executed by
and between Unit Texas Company, an Oklahoma corporation, as agent, and the
<PAGE>
Unit Petroleum Company
January 6, 1995
Page 3
Partnership before any interests in oil and gas properties are acquired in the
name of Unit Texas Company as agent for the Partnership.
8. The terms and provisions of the Nominee Agreement entered into as
provided above will be adhered to by each party thereto and, in particular,
Unit Texas Company will be held out as agent and not the principal in all
dealings with third parties relating to the oil and gas properties which Unit
Texas Company holds as agent for the Partnership.
9. The beneficial ownership of any oil and gas property interests to be
assigned to the Partnership will be assigned to the Partnership by delivery to
Unit Texas Company, as agent for the Partnership, of an enforceable written
assignment, in substantially the form of Exhibit II hereto, properly executed
by the assignor.
10. The General Partner will accept subscriptions for at least 50 Units
in the Partnership by the termination of the offering period.
11. The Partnership Agreement will be duly executed by the General
Partner and the Subscription Agreement will be executed and delivered by those
persons who purchase Units as Limited Partners of the Partnership.
12. The truth and accuracy of the representations in each of the
Subscription Agreements.
13. There are no other documents or agreements which alter, modify, or
change in any way the validity and accuracy of the above assumption and
information.
Based on the foregoing:
1. Legality of Interests. It is our opinion that the Partnership will
be duly organized and validly existing; the Units will be legally issued, fully
paid and non-assessable except as disclosed in the Memorandum; the Partnership
will be a limited partnership under the Act and the liability of each Limited
Partner will be limited as provided by the Act assuming the Limited Partners
exercise only such rights as are provided in the Partnership Agreement.
2. Federal Income Tax Aspects. We have provided, as our opinion, the
discussion of various tax matters set forth in the Memorandum under the
headings "Summary of Program -- Federal Income Tax Aspects," "Risk Factors --
Tax Related Risks," and "Federal Income Tax Aspects." We hereby confirm that
the statements under those headings in the Memorandum which attribute certain
opinions to us are correct. In addition, we are of the opinion that such
discussions in the Memorandum address all material tax issues involved in
connection with the offer and sale of Units in the Partnership and that such
discussions fairly summarize federal income tax laws and consequences relating
to the matters set forth therein.
<PAGE>
Unit Petroleum Company
January 6, 1995
Page 4
In addition to and not in limitation of the foregoing and taking into
account Circular 230, it is our opinion that (except where there manner or
treatment is stated to be uncertain) the tax treatment set forth in the
Memorandum is more likely than not the proper treatment. The discussions and
conclusions set forth in the Memorandum are based upon our interpretation of
the Internal Revenue Code as amended to date and existing Treasury Regulations,
rules and case law. We can give no assurance that changes in such statutes or
Regulations or in the interpretation thereof will not affect the opinions
herein expressed or the conclusions set forth in the Memorandum. In view of
the changes made by the tax legislation in recent years and the fact that
a number of regulations and interpretations thereof have not been adopted or
issued and by reason of the fact that the recent legislation, as well as
existing regulations and rules, will be subject to new and ongoing judicial and
administrative interpretations, there can be no assurance that the discussions
of tax matters set forth in the Memorandum will not be subject to different
interpretations.
We hereby consent to the inclusion of this opinion as an exhibit to
the Memorandum and to the reference in the Memorandum to our having rendered
such opinion.
Very truly yours,
CONNER & WINTERS,
A Professional Corporation
<PAGE>
EXHIBIT I
NOMINEE AGREEMENT
THIS NOMINEE AGREEMENT (the "Agreement"), dated as of ______________,
1995, is between ________________________, an Oklahoma corporation (herein
called "Agent"), and Unit 1995 Employee Oil and Gas Limited Partnership, an
Oklahoma limited partnership (herein called "Owner").
Recitals
--------
It is anticipated, and Owner so desires, that Agent will from time to
time acquire record title to certain oil and gas properties, including but not
limited to certain mineral, leasehold, royalty interests and other interests
identified on Exhibit A hereto, and any other oil and gas properties that may
be designated by Agent and Owner in writing (the "Interests"), as nominee for
the benefit of Owner. The record title to the oil and gas properties held by
Agent may be for the benefit of one owner individually or two or more owners as
tenants in common.
Agreement
---------
IN CONSIDERATION of $100 and other valuable consideration, the
receipt and sufficiency of which are hereby acknowledged, Agent and Owner
hereby agree as follows:
1. Nominee. Agent shall hold legal, record title to the Interests
as nominee for the benefit of Owner, but shall hold no equitable
interest in the Interest.
2. Distribution and Management.
(a) Owner shall have the right to take in kind or to market
separately Owner's share of production from all wells
which are part of the Interests. Agent shall not be
entitled to sell such share of production except to the
extent that it is specifically directed by Owner to
execute production sales contracts, division order or
transfer orders as the holder of record title to the
Interests. Agent shall Promptly distribute all amounts,
which it receiver as holder of record title to the
Interests for the benefit of Owner, to Owner or any party
designated by Owner in writing. Owner is authorized to
receive proceeds payable with respect to the Interests,
even if payable in the name of Agent, and to endorse and
cash any and all checks and drafts payable to the order
of Agent for the account of Owner issued with respect to
such proceeds.
(b) Owner shall pay all amounts, including counsel fees,
which Owner, or Agent on Owner's behalf, may become
obligated to pay with respect to the Interest, and shall
<PAGE>
pay all rentals and similar expenses accruing with
respect to the Interests which it deems advisable to pay.
(c) The duties of Agent hereunder ate only such as are herein
specifically provided, being purely ministerial in
nature. The Interests held hereunder by Agent for the
benefit of Owner are not and shall not be subject to the
debts, obligations, or liabilities of Agent expect as
they may arise under and by virtue of this Agreement.
(d) Agent shall have no obligation to maintain the operations
or manage the Interests of assume any liability by reason
of the execution of promissory note or otherwise.
(e) Agent shall execute, acknowledge and deliver assignments
of the Interest of any part thereof to Owner, or any
Party designated by Owner, upon written request from
Owner. Such assignment shall be in proper and recordable
form and shall contain special warranties of title and
such other non-title warranties as Owner may designate.
Agent may also, at its election, deliver any such
assignments to Owner. Upon recordation of any such
assignment to Owner, this Agreement shall terminate with
respect to the part of the Interests so assigned except
as to rights and obligations previously accrued.
(f) Agent shall hold itself out as being the agent for Owner
to all third parties. All parties, dealing with Agent
are authorized and directed to treat and regard Agent as
the party entitled to deal with the Interests on behalf
of Owner and shall be fully protected in so treating and
regarding Agent and shall have no obligation to determine
the authority of Agent to deal with the Interests of for
the proper application of any proceed received by Agent
with respect to the Interests.
(g) Agent shall promptly furnish to Owner copies of all
notices and instruments of every kind relating to the
Interests which Agent may receive, including, without
limitation, rental notices, invoices, operating, pooling,
communitization and unitization agreements, pooling
declarations, authorizations for expenditures, leases,
contracts, claims and demands. Agent shall provide
reasonable advance notice to Owner of all amounts which
become payable under the terms of any of the foregoing.
(h) Agent shall follow all instructions of Owner relating to
the Interests, including, without limitation,
instructions relating to the execution of and the action
to be taken with respect to notices and instruments
relating to the Interest, including, without limitation,
mortgages, deeds of trust and financing statements,
-2-
<PAGE>
production sales contracts and transfer orders and/or
division orders.
(i) Agent shall be entitled to assume conclusively that all
instruments delivered to it under any provision of this
Agreement are valid and proper. Agent may seek advice of
counsel and shall be fully protected in any action taken
in accordance with such advice. Agent shall not be
required to defend any legal action which may be
commenced against it pertaining to the Interests unless
requested to do so by Owner and indemnified to its
satisfaction against the cost and expenses of such
defense. Agent shall commence legal action of any kind
at the direction of Owner, provided Agent is fully
indemnified by Owner against liabilities in connection
therewith and Owner undertakes to pay all of the costs
thereof. Agent shall be fully protected in acting in
accordance with any written instruments delivered to it
hereunder and believed by it to have been properly
executed.
3. Indemnity. Owner shall indemnify, protect and save and hold
harmless Agent against any loss, cost, expense, liability or
claim arising out of Agent's performance of its duties or
exercise of its rights under this Agreement. Owner shall have
no liability with respect to any third party claim settled by
Agent without Owner's prior written consent unless Owner shall,
following reasonable notification by Agent, have failed to
assume the defense of such claim.
4. Notices. All communications hereunder between Owner and Agent
shall be in writing and any communication or delivery hereunder
shall be deemed to have been duly made if actually delivered, or
if mailed by registered or certified mail, postage prepaid,
addressed as follows:
To Agent: ______________________________
1000 Galleria Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
To Owner: Unit Petroleum Company,
General Partner
1000 Galleria Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
Any party may, by written notice so given to the other, change
the address to which instruments and notices shall thereafter be
sent.
-3-
<PAGE>
5. Successors. This Agreement shall be binding upon and inure to
the benefit of Agent and Owner and their respective successors
and assigns.
6. Amendments. This Agreement may be supplemented, altered,
amended, modified or revoked by writing only, signed by all of
the affected parties.
7. Headings. The headings of the paragraphs of this Agreement are
for convenience of reference only and shall not affect the
construction hereof.
8. Termination. This Agreement is terminable by Owner at any time
and upon such terms and conditions as Owner may direct.
EXECUTED as of the date first above mentioned.
AGENT:
------
By: ___________________________
___________________________
President
OWNER:
------
UNIT 1995 EMPLOYEE OIL AND GAS
LIMITED PARTNERSHIP
By: Unit Petroleum Company
General Partner
By: ___________________________
___________________________
President
-4-
<PAGE>
EXHIBIT II
RECORDING REQUESTED BY AND WHEN RECORDED RETURN TO:
_________________________
1000 Galleria Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
THE STATE OF _________________ )
) KNOW ALL MEN BY THESE PRESENTS:
COUNTY OF ____________________ )
ASSIGNMENT, BILL OF SALE AND CONVEYANCE
This Assignment, Bill of Sale and Conveyance ("the Assignment"),
dated effective as of, __________________ at 7:00 am. local time with respect
to the jurisdictions in which each of the Properties is located (the
"Effective Time"), is from __________________________________ ("Assignor") to
______________________, a Delaware corporation, whose address is 1000 Galleria
Tower I, 7130 South Lewis, Tulsa, Oklahoma 74136 ("Assignee").
For One Hundred Dollars ($100.00) and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged,
Assignor hereby GRANTS, BARGAINS, SELLS, CONVEYS, ASSIGNS, TRANSFERS, SETS OVER
AND DELIVERS unto Assignee, effective as of the Effective Time, the following
(collectively, the "Properties," and individually, a "Property"):
(a) the interests specified on Exhibit A attached hereto
and made a part hereof for all purposes, whether full or undivided,
in and to all of the oil and gas and oil, gas, and mineral leases,
wells, units, lands, properties, rights, and estates described on
Exhibit A and all of Seller's interest in and to the oil and gas
wells (the "Wells") described on Exhibit A attached hereto, including
all contractual rights to production, and contractual rights
providing for the acquisition or earning of any such interests (each
of such interests described in this paragraph (a) being hereinafter
referred to as a "Subject Interest" and all such interests being
collectively referred to hereinafter as the "Subject Interests");
(b) the same undivided interest in all rights, privileges,
benefits and powers conferred upon the holder of any Subject Interest
with respect to the use and occupation of the surface of, and the
subsurface depths under, the land covered by such Subject Interest
<PAGE>
that may be necessary, convenient or incidental to the possession and
enjoyment of such Subject Interest; all rights in any pooled or
unitized acreage included as a whole or in part within any Subject
Interest or that accrue or are attributable to the Wells, including
all production from the pooled or unitized acreage allocated to any
such Subject Interest or Well, any and all interests in any wells
within the unit or pool associated with such Subject Interest whether
such unitized of pooled production comes from wells located within or
without the areas covered by any Subject Interest; and all tenements,
hereditaments and appurtenances belonging to such Subject Interests
and Wells;
(c) all of the permits, licenses, servitudes, easements,
rights-of-way, orders, gas purchase and sale contracts (wherein
Seller is selling party), crude purchase and sale agreements (wherein
Seller is selling party), surface leases, farmin and farmout
agreements, bottom hole agreements, transportation and marketing
agreements, acreage contribution agreements, operating agreements,
unit agreements, processing agreements, options, facilities or
equipment leases and other contracts, agreements and rights that are
owned by Seller, in whole or in part, to the extent that they are (i)
appurtenant to or affect the Subject Interests or the Wells, or (ii)
used or held for use in connection with the ownership or operation of
'the Subject Interests or the Wells or with the production or
treatment of hydrocarbons on the Subject Interest, or the sale or
disposal of water, hydrocarbons or associated substances;
(d) all of the equipment, machinery, fixtures and other
real, personal and mixed property (the "Personal Property") located
on the Subject Interests or used in the operation of the Properties
or of the Wells (whether located on or off such Subject Interests),
to the extent used in connection with or attributable to the Subject
Interests, which is owned by Seller of by third persons on behalf of
Seller, in whole or in part, including, without limitation , wells,
well equipment, casing, rods, tanks, crude oil, condensate or
products in storage or in pipelines, boilers, buildings, tubing,
pumps, motors, fixtures, machinery and other equipment, pipelines,
gathering systems, power lines, telephone and telegraph lines, roads,
field processing plants and other improvements used in the operation
thereof;
(e) all of the files, records, information and data,
whether written of electronically stored, relating to the items
described in subsections (a), (b), (c), and (d) above in the
possession of Seller, or to which Seller has reasonable access in
original form (the "Records"), including, without limitation: title
records (including abstracts of title, title opinions, certificates
of title and title curative documents); contracts; correspondence;
microfiche lists; geological data and information or other non-
proprietary records, data and information which Seller has the
unencumbered right to transfer; and production records, electric logs
core data, pressure data and decline curves and graphical production
curves and all related matters;
(f) to the extent assignable, the benefit of and the right
to enforce the covenants and warranties, if any, which Assignor is
entitled to enforce with respect to the items described in the
-2-
<PAGE>
preceding paragraphs (a) through (e) herein against Assignor's
predecessors in title thereto; and Assignee and its successors and
assigns shall be substituted and fully subrogated, to the extent
assignable, in and to all covenants and warranties, if any, made by
Assignor's predecessors in title, with full subrogation of all rights
accruing under the statutes of limitation or prescription under the
laws of the states where the items described in the preceding
paragraphs (a) through (e) are located;
(g) all crude oil, natural gas, casinghead gas, condensate,
distillate, natural gas liquids and other liquid or gaseous
hydrocarbons (including, without limitation , CO2 and hydrocarbons
that are not gaseous at atmospheric temperature and pressure) and all
other minerals of every kind and character produced and saved from or
attributable to the Subject Interests with respect to all periods
subsequent to the Effective Time, as hereinafter defined, together
with all proceeds attributable thereto.
TO HAVE AND TO HOLD the Properties unto Assignee and its successors
and assigns forever; provided, however, this Assignment is made subject to the
following terms and provisions:
I.
This Assignment is executed as part of the consummation of the
transaction contemplated by that certain Purchase and Sale Agreement (the
"Purchase Agreement") dated ____________, by an between ____________________
and _________________________. The warranties, representations, indemnities
and covenants contained in the Purchase Agreement shall survive the delivery of
the Assignment in accordance with the provisions of the Purchase Agreement and
the delivery of this Assignment shall not affect, expand, diminish or otherwise
impair any of the warranties, representations, indemnities and covenants in the
Purchase Agreement. This Assignment is made subject to the Purchase Agreement;
provided, however, any third parties transacting with Assignee concerning the
Properties may rely on this Assignment as vesting Assignee with all of the
Assignor's right, title and interest in the Properties. In the event of a
conflict between the terms of the Purchase Agreement and the terms of the
Assignment, the terms of the Purchase Agreement shall control.
II.
Assignee represents the following: Title to these Properties is held
by ___________________ as nominee for _______________________________pursuant
to the terms and conditions of a certain "Nominee Agreement" between Assignee
and _____________________. Under said Nominee Agreement, Assignee is
authorized to hold legal, record title to the Properties and to execute,
acknowledge and deliver assignments of these Properties. All parties dealing
with Assignee or the Properties are authorized and directed to treat and regard
Assignee as the party entitled to deal with the Properties and shall be fully
protected in so treating and regarding Assignee and shall have no obligation to
determine the authority of Assignee to deal with the Properties of for the
-3-
<PAGE>
proper application of any proceeds received by Assignee with respect to the
Properties. All communications and notices shall be deemed to have been duly
made and properly given if actually delivered, or if mailed by registered or
certified mail, to Assignee.
III.
Assignor does hereby bind itself to warrant and forever defend all
and singular Defensible Title (hereinafter defined) to all Properties unto
Assignee, Assignee's successors and assigns, against every person whomsoever
lawfully claiming of to claim the same or any part thereof, by, through or
under Assignor or Assignor's Affiliates (as that term is defined in the
Purchase Agreement), but not otherwise.
IV.
In the event two or more Subject Interests cover the same land
(e. g., an oil and gas leasehold interest included within the Properties may
cover the same land as a mineral or royalty interest included within the
Properties), no merger of title shall occur, and each Subject Interest covering
the same land is conveyed and shall be owned by the Assignee as a separate and
distinct Subject Interest.
V.
In addition to this Assignment, Assignor and/or Assignor's affiliates
shall execute, acknowledge, and deliver to Assign without further
consideration, any documents or instruments pi including, without limitation,
further assignments, conveyances required by any state or federal authority,
deeds, and consents to further evidence the assignment of the Properties by
Assignor to Assignee.
VI.
The provisions hereof shall be covenants running with the land and
shall be binding upon and inure to the benefit of the parties hereto, their
respective successors and assigns.
-4-
<PAGE>
EXECUTED this ______ day of ______, 1995, but effective as of and
from the Effective Time.
ASSIGNOR:
---------
ATTEST: ___________________________________
________________________________
Printed Name: __________________ By: _______________________________
Title: _________________________
[SEAL]
WITNESSES:
- ----------
________________________________
________________________________
ASSIGNEE:
---------
ATTEST: [_________________________________]
By: ____________________________ By: _______________________________
[SEAL]
WITNESSES:
- ----------
________________________________
________________________________
-5-
<PAGE>
EXHIBIT 22.1
<PAGE>
EXHIBIT 22.1
SUBSIDIARIES OF THE REGISTRANT
State or Province Percentage
Subsidiary of Incorporation Owned
- ------------------------------------- ---------------- ----------
Unit Drilling and Exploration Company Delaware 100%
Mountain Front Pipeline Company, Inc. Oklahoma 100%
Unit Drilling Company Oklahoma 100%
Unit Petroleum Company (1) Oklahoma 100%
Petroleum Supply Company Oklahoma 100%
Roundup Resources, Inc. Delaware 100%
Unit Energy Canada, Inc. Alberta 100%
- -------------
(1) Unit Petroleum Company owns 100% of one subsidiary corporation,
namely:
Unit Texas Company Oklahoma
<PAGE>
EXHIBIT 24.1
<PAGE>
EXHIBIT 24.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Unit Corporation on Form S-8 (File No.'s 33-19652, 33-44103 and 33-49724) and
Form S-3 (File No. 33-16116) of our report dated February 22,
1995, on our audits of the consolidated financial statements and financial
statement schedule of Unit Corporation as of December 31, 1994 and 1993,
and for the years ended December 31, 1994, 1993 and 1992, which report is
included in this Annual Report on Form 10-K.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
March 21, 1995
<TABLE> <S> <C>
<PAGE>
<PAGE>
<ARTICLE> 5
<LEGEND>
The schedule contains summary financial information extracted from the
Consolidated Financial Statements of Unit Corporation and Subsidiaties under
cover of Form 10-K for December 31, 1994 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-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 2,749
<SECURITIES> 0
<RECEIVABLES> 16,658
<ALLOWANCES> 289
<INVENTORY> 1,498
<CURRENT-ASSETS> 21,838
<PP&E> 244,405
<DEPRECIATION> 153,862
<TOTAL-ASSETS> 112,421
<CURRENT-LIABILITIES> 19,841
<BONDS> 0
<COMMON> 4,182
0
0
<OTHER-SE> 48,425
<TOTAL-LIABILITY-AND-EQUITY> 112,421
<SALES> 0
<TOTAL-REVENUES> 87,958
<CGS> 0
<TOTAL-COSTS> 77,916
<OTHER-EXPENSES> 3,574
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,654
<INCOME-PRETAX> 4,814
<INCOME-TAX> 20
<INCOME-CONTINUING> 4,794
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,794
<EPS-PRIMARY> .23
<EPS-DILUTED> .23
</TABLE>
