<PAGE>
F O R M 1 0 - K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1998
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:
Title of each class Name of each exchange
Common Stock, par value on which registered
$.20 per share New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in PART III of this
Form 10-K or any amendment to this Form 10-K.
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 17, 1999 - $143,274,719
Number of Shares of Common Stock
Outstanding on March 17, 1999 - 26,653,341
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting
of Stockholders to be held May 5, 1999 are incorporated by reference in Part
III.
Exhibit Index - See Page 77
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FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . 18
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . 18
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . 19
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . . 21
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . 29
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . 67
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . . 67
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . 68
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . . 68
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . 69
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . 69
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
<PAGE>
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1998
PART I
Item 1. Business and Item 2. Properties
- -----------------------------------------
GENERAL
The Company, through its wholly owned subsidiaries, is engaged in the
land contract drilling of oil and natural gas wells and the development,
acquisition and production of oil and natural gas properties. The
Company's primary exploration and production operations are conducted in
the Anadarko and Arkoma Basins, which cover portions of Oklahoma, Texas,
Kansas and Arkansas, with additional operations located in the South Texas
Basin. Additional producing properties are located in other states,
including, but not limited to, New Mexico, Louisiana, North Dakota,
Colorado, Wyoming, Montana, Alabama, Mississippi, Arkansas, Illinois and
Nebraska as well as in Canada. The Company's contract drilling operations
are primarily located in the Oklahoma and Texas areas of the Anadarko and
Arkoma Basins with additional operations in the Permian and South Texas
Basins.
The Company was originally incorporated in Oklahoma in 1963 as Unit
Drilling Company. In 1979 it became a publicly held Delaware corporation
and changed its name to Unit Drilling and Exploration Company ("UDE") to
more accurately reflect the importance of its oil and natural gas business.
In September 1986, pursuant to a merger and exchange offer, the Company
acquired all of the assets and assumed all of the liabilities of UDE and
six oil and gas limited partnerships for which UDE was the general partner,
in exchange for shares of the Company's common stock (the "Exchange
Offer").
The Company's principal executive offices are maintained at 1000
Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number
(918) 493-7700. The Company also has regional offices in Moore and
Woodward, Oklahoma and Booker and Houston, Texas. When used in this
report, the term "Company" refers to Unit Corporation and at times Unit
Corporation and/or one or more of its subsidiaries with respect to periods
from and after the Exchange Offer and to UDE with respect to periods prior
thereto.
OIL AND NATURAL GAS OPERATIONS
In 1979, the Company began to develop its exploration and production
operations to diversify its source of revenues which, up to that time, were
derived from its contract drilling. Today, the Company conducts the
development, production and sale of oil and natural gas together with the
acquisition of producing properties through its wholly owned subsidiary,
Unit Petroleum Company.
As of December 31, 1998, the Company had 3,245 Mbbls and 161,318 MMcf
of estimated proved oil and natural gas reserves, respectively. The
Company's producing oil and natural gas interests, undeveloped leaseholds
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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, Arkansas, Illinois, Nebraska and
Canada. As of December 31, 1998, the Company had an interest in a total of
2,499 wells in the United States and served as the operator of 524 wells.
The Company also had an interest in 64 wells located in Canada. The
majority of the Company's development and exploration prospects are
generated by its technical staff. When the Company is the operator of a
property, it generally employs its own drilling rigs and the Company's own
engineering staff supervises the drilling operation.
The Company intends to continue the growth in its oil and natural gas
operations utilizing funds generated from operations and its bank revolving
line of credit.
Well and Leasehold Data. The Company's oil and natural gas explora-
tion and development drilling activities and the number of wells in which
the Company had an interest, which were producing or capable of producing,
were as follows for the periods indicated:
Year Ended December 31,
-------------------------------------------------
1998 1997 1996
Wells drilled: Gross Net Gross Net Gross Net
- -------------- ------ ------ ------ ------ ------ ------
Exploratory:
Oil.............. - - - - - -
Natural gas...... - - - - - -
Dry.............. 1 .26 - - - -
------ ------ ------ ------ ------ ------
Total 1 .26 - - - -
====== ====== ====== ====== ====== ======
Development:
Oil.............. 4 .44 10 4.84 10 8.35
Natural gas...... 52 19.26 57 23.85 55 19.46
Dry.............. 21 10.62 15 9.27 7 4.26
------ ------ ------ ------ ------ ------
Total 77 30.32 82 37.96 72 32.07
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
- ------------------------------------------------------------
Oil - USA........ 726 196.64 684 197.67 717 197.71
Oil - Canada..... - - - - - -
Gas - USA........ 1,773 286.73 1,545 260.40 1,530 242.09
Gas - Canada..... 64 1.60 64 1.60 64 1.60
------ ------ ------ ------ ------ ------
Total 2,563 484.97 2,293 459.67 2,311 441.40
====== ====== ====== ====== ====== ======
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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
------- ------- ------- -------
1998
----
USA 569,076 130,440 52,958 35,371
Canada 39,040 976 22,763 22,763
------- ------- ------- -------
Total 608,116 131,416 75,721 58,134
======= ======= ======= =======
1997
----
USA 432,824 118,926 37,844 26,116
Canada 39,040 976 18,970 18,970
------- ------- ------- -------
Total 471,864 119,902 56,814 45,086
======= ======= ======= =======
1996
----
USA 455,713 115,326 29,245 19,124
Canada 39,040 976 - -
------- ------- ------- -------
Total 494,753 116,302 29,245 19,124
======= ======= ======= =======
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Price and Production Data. The Company's average sales price, oil and
natural gas production volumes and average production cost per equivalent
Mcf (1 barrel (Bbl) of oil = 6 thousand cubic feet (Mcf) of natural gas) of
production for the periods indicated were as follows:
Year Ended December 31,
----------------------------------
1998 1997 1996
-------- -------- --------
Average sales price per barrel
of oil produced:
USA $ 12.81 $ 19.19 $ 20.40
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 1.90 $ 2.43 $ 2.21
Canada $ 1.46 $ .93 $ 1.18
Oil production (Mbbls):
USA 443 493 579
Canada - - -
-------- -------- --------
Total 443 493 579
======== ======== ========
Natural gas production (MMcf):
USA 16,427 13,742 12,974
Canada 38 74 51
-------- -------- --------
Total 16,465 13,816 13,025
======== ======== ========
Average production expense per
equivalent Mcf:
USA $ .61 $ .64 $ 0.68
Canada $ .54 $ .33 $ 0.27
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,
---------------------------------
1998 1997 1996
------- ------- -------
Oil (Mbbls):
USA 3,245 4,131 5,204
Canada - - -
------- ------- -------
Total 3,245 4,131 5,204
======= ======= =======
Natural gas (MMcf):
USA 160,795 144,661 128,408
Canada 523 723 753
------- ------- -------
Total 161,318 145,384 129,161
======= ======= =======
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Further information relating to oil and natural gas operations is
presented in Notes 1,5,12 and 14 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
LAND CONTRACT DRILLING OPERATIONS
Unit Drilling Company, a wholly owned subsidiary of the Company, is
engaged 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, substructure, 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 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.
On November 20, 1997, the Company acquired Hickman Drilling Company,
an Oklahoma corporation pursuant to an Agreement and Plan of Merger ("the
Merger Agreement"), dated November 20, 1997 entered into by and between the
Company, the Company's wholly owned subsidiary Unit Drilling Company,
Hickman Drilling Company and all of the holders of the outstanding capital
stock of Hickman Drilling Company (the "Selling Stockholders"). Under the
terms of this acquisition, the Selling Stockholders received, in aggregate,
1,300,000 shares of Common Stock and promissory notes in the aggregate
principal amount of $5,000,000 payable in five equal annual installments
commencing January 2, 1999. The acquisition included nine land contract
drilling rigs with depth capacities ranging from 9,500 to 17,000 feet,
spare drilling equipment and approximately $2.1 million in working capital.
As part of the acquisition the Company retained Hickman Drilling Company's
Woodward, Oklahoma corporate office as a regional office for its contract
drilling operations. In December 1997, the Company also purchased a Mid-
Continent U-36A, 650 horsepower rig with a 13,000 feet depth capacity and
spare components from two additional rigs for a total consideration of
$1 million, of which $200,000 was paid at closing and the balance is to be
paid over a period ending no later than three years. The balance is to be
paid out monthly with the monthly amount to be calculated on the basis of a
predetermined daily rate multiplied by the number of days in such month
that the acquired rig is employed for the account of the seller, all as
more fully specified in the acquisition agreement. If the balance of the
purchase price has not been fully paid at the end of three years the
remaining amount is to be paid in cash to the seller.
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With the acquisitions noted above, the Company's drilling rig fleet
expanded to 34 rigs with depth capacities ranging from 7,000 to 25,000
feet. At December 31, 1998, 29 of the Company's rigs were located in the
Anadarko and Arkoma Basins of Oklahoma and Texas while five of its larger
horsepower rigs were located in South Texas. In the Anadarko and Arkoma
Basins the Company's primary focus is on the utilization of its medium
depth rigs which have a depth range of 8,000 to 14,000 feet. These medium
depth rigs are suited to the contract drilling currently undertaken by
operators in these two basins.
At present, the Company does not have a shortage of drilling rig
related equipment. During 1996 and through 1997, the Company increased
its drill pipe acquisitions since certain grades of drill pipe were in high
demand, due to increased rig utilization. However, at any given time, the
Company's ability to utilize its full complement of drilling rigs is
dependent upon the availability of qualified labor, drilling supplies and
equipment as well as demand. Should industry conditions improve rapidly,
there is no assurance that sufficient supplies of drill pipe, other
drilling equipment and qualified labor will be readily available, not only
within the Company, but in the industry as a whole.
The following table sets forth, for each of the periods indicated,
certain data concerning the Company's contract drilling operations:
Year Ended December 31,
---------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Number of operational rigs owned
at end of period 34 34(1) 24 22 25
Average number of rigs utilized (2) 22.9 19.2 14.7 10.9 9.5
Number of wells drilled 198 167 130 111 95
Total footage drilled (feet in 1000's) 2,203 1,736 1,468 1,196 1,027
- -------------------
(1) Includes 10 rigs acquired in the fourth quarter of 1997.
(2) 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 February 23, 1999, 22 of the Company's 34 drilling rigs were
operating under contract.
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The following table sets forth, as of February 23, 1999, the type and
approximate depth capability of each of the Company's drilling rigs:
Approximate
Depth
Capability
Rig# Type (feet)
---- ---- ----------
1 U-15 Unit Rig 11,000
2 BDW 650 13,000
3 BDW 650 13,500
4 U-15 Unit Rig 11,000
5 U-15 Unit Rig 11,000
6 BDW 800 15,000
7 U-15 Unit Rig 11,000
8 Gardner Denver 800 15,000
9 BDW 800 16,000
10 BDW 450T 9,500
11 Gardner Denver 700 15,000
12 BDW 800-M1 15,000
14 Gardner Denver 700 15,000
15 Mid-Continent 914-C 20,000
16 U-15 Unit Rig 11,000
17 Brewster N-75A 15,000
18 BDW 650 12,000
19 Gardner Denver 500 12,000
20 Gardner Denver 700 15,000
21 Gardner Denver 700 15,000
22 BDW 800 15,000
23 Gardner Denver 700M 15,000
24 Gardner Denver 700M 15,000
25 Gardner Denver 700 15,000
29 Brewster N-75A 15,000
30 BDW 1350-M 20,000
31 SU-15 North Texas Machine 12,000
32 Brewster N-75 15,000
34 National 110-UE 20,000
35 Continental Emsco C-1-E 20,000
36 Gardner Denver 1500-E 25,000
37 Mid-Continent 914-EC 20,000
38 Mid-Continent 1220-E 25,000
39 U-36-A 13,000
During the previous decade, the Company's contract drilling services
encountered significant competition due to depressed levels of activity in
contract drilling. In the last 6 months of 1996 and throughout 1997 and
the first three quarters of 1998, the Company's drilling operation showed
significant improvements in rig utilization. However, in late 1998, the
Company and the industry as a whole experienced a significant reduction in
demand. The Company anticipates that competition within the industry will,
for the foreseeable future, continue to adversely affect the Company.
Drilling Contracts. Most of the Company's drilling contracts are
obtained through competitive bidding. Generally, the contracts are for a
single well with the terms and rates varying depending upon the nature and
duration of the work, the equipment and services supplied and other
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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. To date, the Company has not experienced significant losses
in performing turnkey contracts. For 1998, turnkey revenue represented
approximately 15 percent of the Company's contract drilling revenues.
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.
Customers. During the fiscal year ended December 31, 1998, 10
contract drilling customers accounted for approximately 24 percent of the
Company's total revenues and approximately 5 percent of the Company's total
revenues were generated by drilling on oil and natural gas properties of
which the Company was the operator (including properties owned by limited
partnerships for which the Company acted as general partner). Such drill-
ing was pursuant to contracts containing terms and conditions comparable to
those contained in the Company's customary drilling contracts with non-
affiliated operators.
Further information relating to contract drilling operations is
presented in Notes 1, 2 and 12 of Notes to Consolidated Financial State-
ments set forth in Item 8 hereof.
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VOLATILE NATURE OF THE COMPANY'S OIL AND NATURAL GAS MARKETS;
FLUCTUATIONS IN PRICES
The Company's revenue and profitability are substantially dependent
upon prevailing prices for natural gas and crude oil. Oil and natural gas
prices have historically been volatile and are expected by the Company to
continue to be volatile in the future. These prices vary based on factors
beyond the control of the Company, including the extent of domestic produc-
tion and importation of crude oil and natural gas, the proximity and
capacity of oil and natural gas pipelines, costs of gathering natural gas,
the marketing of competitive fuels, general fluctuations in the supply and
demand for oil and natural gas, the effect of federal and state regulation
of production, refining, transportation and sales, the use and allocation
of oil and natural gas and their substitute fuels and general national and
worldwide economic conditions. In addition, natural gas spot prices
received by the Company are influenced by weather conditions impacting the
continental United States.
The Company's oil and condensate production is sold at or near the
Company's wells under purchase contracts at prevailing prices in accordance
with arrangements which are customary in the oil industry. The Company's
natural gas production is sold to intrastate and interstate pipelines as
well as to independent marketing firms under contracts with original terms
ranging from one month to several years. Most of these contracts contain
provisions for readjustment of price, termination and other terms which are
customary in the industry.
The worldwide supply of oil has been largely dependent upon rates of
production of foreign reserves. Although the demand for oil has increased
in the United States, imports of foreign oil continue to increase. Future
domestic oil prices will depend largely upon the actions of foreign
producers with respect to rates of production and it is virtually
impossible to predict what actions those producers will take in the future.
Prices may also be affected by political, social and other factors relating
to the Middle East. In view of the many uncertainties affecting the supply
and demand for oil and natural gas, the Company is unable to predict future
oil and natural gas prices or the overall effect, if any, that a decline in
demand or oversupply of such products would have on the Company.
COMPETITION
All lines of business in which the Company engages are highly com-
petitive. Competition in land contract drilling traditionally involves
such factors as price, efficiency, condition of equipment, availability of
labor and equipment, reputation and customer relations. Some of the
Company's competitors in the land contract drilling business are sub-
stantially larger than the Company and have appreciably greater financial
and other resources. As a result of the decrease in demand for land
contract drilling services over the past decade, a surplus of certain types
of drilling rigs currently exists within the industry while inventories of
certain components such as specific grades of drill pipe have been depleted
from continued use. Accordingly, the competitive environment within which
the Company's drilling operations presently operates is uncertain and
extremely price oriented.
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The Company's oil and natural gas operations likewise encounter strong
competition from major oil companies, independent operators, and others.
Many of these competitors have appreciably greater financial, technical and
other resources and are more experienced in the exploration for and
production of oil and natural gas than the Company.
OIL AND NATURAL GAS PROGRAMS
The Company currently serves as a general partner to 4 oil and gas
limited partnerships and 10 employee oil and gas limited partnerships. The
employee partnerships acquire an interest fixed annually, ranging from 5%
to 15% of the Company's interest, in most oil and natural gas drilling
activities and purchases of producing oil and natural gas properties
participated in by the Company. The limited partners in the employee
partnerships are either employees or directors of the Company or its sub-
sidiaries.
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.
EMPLOYEES
As of February 23, 1999, the Company had approximately 453 employees
in its land contract drilling operations, 47 employees in its oil and natu-
ral gas operations and 44 in its general corporate area. None of the
Company's employees are represented by a union or labor organization nor
have the Company's operations ever been interrupted by a strike or work
stoppage. The Company considers relations with its employees to be
satisfactory.
OPERATING AND OTHER RISKS
The Company's land contract drilling and oil and natural gas
operations are subject to a variety of oil field hazards such as fire,
explosion, blowouts, cratering and oil spills or certain other types of
possible surface and subsurface pollution, any of which can cause personal
injury and loss of life and severely damage or destroy equipment, suspend
drilling operations and cause substantial damage to surrounding areas or
property of others. As protection against some, but not all, of these
operating hazards, the Company maintains broad insurance coverage,
including all-risk physical damage, employer's liability and comprehensive
general liability. In all states in which the Company operates except
Oklahoma, the Company maintains a large deductible worker's compensation
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policy that insures for losses exceeding $200,000. In Oklahoma, starting
in August 1991, the Company elected to become self insured. In
consideration therewith, the Company purchased an excess liability
reinsurance policy to insure losses exceeding $250,000. 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 inter-
ruptions 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
may be 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 mar-
keted. 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.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which the Company
conducts activities impose restrictions on the drilling, production and
sale of oil and natural gas, which often include requirements relating to
well spacing, waste prevention, production limitations, pollution preven-
tion and clean-up, obtaining drilling permits and similar matters. The
following discussion summarizes, in part, the regulations of the United
States oil and natural gas industry and is not intended to constitute a
complete discussion of the many statutes, rules, regulations and
governmental orders to which the Company's operations may be subject.
The Company's activities are subject to existing federal and state
laws and regulations governing environmental quality and pollution control.
Various states and governmental agencies are considering, and some have
adopted, laws and regulations regarding environmental control which could
adversely affect the business of the Company. Such laws and regulations
may substantially increase the costs of doing business and may prevent or
delay the commencement or continuation of given operations. Compliance
with such legislation and regulations, together with any penalties
resulting from noncompliance therewith, will increase the cost of oil and
natural gas drilling, development, production and processing. In the
opinion of the Company's management, its operations to date comply in all
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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
firm shippers can release unwanted capacity to those desiring capacity
(which program replaces previous "capacity brokering" and "buy-sell"
programs); existing bundled firm sales entitlement are converted to
unbundled firm sales entitlement and to unbundled firm transportation
rights on the effective date of a particular pipeline's blanket sales
certificate; and pipeline transportation rights must be developed under the
Straight Fixed Variable (SFV) method of cost classification, allocation and
rate design unless the FERC permits the pipeline to use some other method.
The FERC will not permit a pipeline to change the new resulting rates until
the FERC accepts the pipeline's formal restructuring plans.
In essence, the goal of Order 636 is to make a pipeline's position as
natural gas merchant indistinguishable from that of a non-pipeline
supplier. It, therefore, pushes the point of sale of natural gas by
pipelines upstream, perhaps all the way to the wellhead. Order 636 also
requires pipelines to give firm transportation customers flexibility with
respect to receipt and delivery points (except that a firm shipper's choice
of delivery point cannot be downstream of the existing primary delivery
point) and to allow "no-notice" service (which means that natural gas is
12
<PAGE>
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. Due to the continuing evolutionary nature of Order 636 and
its implementation, it is not possible to project the overall potential
impact on transportation rates for natural gas or market prices of natural
gas.
The future interpretation and application by FERC of these rules and
its broad authority, or of the state and local regulations by the relevant
agencies, could affect the terms and availability of transportation
services for transportation of natural gas to customers and the prices at
which natural gas can be sold by the Company. For instance, as a result of
Order 636, more interstate pipeline companies have begun divesting their
gathering systems, either to unregulated affiliates or to third persons, a
practice which could result in separate, and higher, rates for gathering a
producer's natural gas. In proceedings during mid and late 1994 allowing
various interstate natural gas companies' spindowns or spinoffs of
gathering facilities, the FERC held that, except in limited circumstances
of abuse, it generally lacks jurisdiction over a pipeline's gathering
affiliates, which neither transport natural gas in interstate commerce nor
sell gas in interstate commerce for resale. However, pipelines spinning
down gathering systems have to include two Order No. 497 standards of
conduct in their tariffs: nondiscriminatory access to transportation for
all sources of supply and no tying of pipeline transportation service to
any service by the pipeline's gathering affiliate. In addition, if unable
to reach a mutually acceptable gathering contract with a present user of
the gathering facilities, the FERC required that the pipeline must offer a
two-year "default contract" to existing users of the gathering facilities.
However, on appeal, while the United States Court of Appeals for the
District of Columbia upheld the FERC's allowing the spinning down of
gathering facilities to a non-regulated affiliate, in Conoco Inc. v. FERC,
90 F.3d 536, 552-53 (D.C. Cir. 1996)the D.C. Circuit remanded the FERC's
default contract mechanism. On February 18, 1997, the United States
Supreme Court denied review of the D.C. Circuit's decision.
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 controlling 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
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.
14
<PAGE>
Violation of environmental legislation and regulations may result in
the imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the abatement of the conditions,
or suspension of the activities, giving rise to the violation. The Company
believes that the Company has complied with all orders and regulations
applicable to its operations. However, in view of many uncertainties with
respect to the current controls, including their duration and possible
modification, the Company cannot predict the overall effect of such
controls on such operations. Similarly, the Company cannot predict what
future environmental laws may be enacted or regulations may be promulgated
and what, if any, impact they would have on operations.
SAFE HARBOR STATEMENT OF FURTHER ACTIVITY
In the normal course of its business, the Company, in an effort to
help keep its shareholders and the public informed about the Company's
operations, may, from time to time, issue certain statements, either in
writing or orally, that contain or may contain forward looking information.
Generally, these statements relate to projections involving the anticipated
revenues to be received from the Company's oil and natural gas production
or drilling operations, the utilization rate of its drilling rigs, growth
of its oil and natural gas reserves, well performance, and the Company's
anticipated debt.
Statements in this Annual Report on Form 10-K under the captions
"Business" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations", as well as oral statements that may be made by
the Company or by officers, directors or employees of the Company acting on
the Company's behalf, that are not historical facts constitute "forward-
looking statements" within the meaning of the Private Securities Litigation
Reform Act of 1995. Words such as "believes", "anticipates" and similar
expressions, although not inclusive, identify forward-looking statements.
Such forward-looking statements are subject to a number of factors that may
tend to influence the accuracy of the statements and the projections upon
which the statements are based. As noted elsewhere in this report, all
phases of the Company's operations are subject to a number of influences
outside the control of the Company, any one of which, or a combination of
which, could materially affect the results of the Company's operations.
All future written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any forward looking statements made
by the Company, the following discussion outlines certain factors that in
the future could cause the Company's consolidated results for 1999 and
beyond to differ materially from those that may be set forth in any such
forward-looking statement made by or on behalf of the Company.
15
<PAGE>
Commodity Prices
The prices received by the Company for its oil and natural gas
production have a direct impact on the Company's revenues, profitability
and cash flow as well as its ability to meet its projected financial and
operational goals. The prices for natural gas and crude oil are heavily
dependent on a number of factors beyond the control of the Company,
including, but not limited to, the demand for oil and/or natural gas;
current weather conditions in the continental United States which can
greatly influence the demand for natural gas at any given time as well as
the price to be received for such gas; and the ability of current
distribution systems in the United States to effectively meet the demand
for oil and or natural gas at any given time, particularly in times of peak
demand which may result due to adverse weather conditions. Oil prices are
extremely sensitive to foreign influences that may be based on political,
social or economic underpinnings, any one of which could have an immediate
and significant effect on the price and supply of oil. In addition, prices
of both natural gas and oil are becoming more and more influenced by
trading on the commodities markets which, at times, has tended to increase
the volatility associated with these prices resulting at times in large
difference in such prices even on a month to month basis. All these
factors, especially when coupled with the fact that much of the Company's
product prices are determined on a month to month basis, can, and at times
do, lead to wide fluctuations in the prices received by the Company.
Based upon the results of operations for the year ended December
31, 1998, the Company estimates that a change of $0.10/Mcf in the average
price of natural gas and a change of $1.00/Bbl in the price of crude oil
throughout such period would have resulted in approximate changes in net
income before income taxes of $1,541,000 and $414,000, respectively. During
1998, substantially all of the natural gas and crude oil volume of the
Company were sold at market responsive prices.
Customer Demand
Demand for the Company's drilling services is dependent almost entirely on
the needs of third parties. Based on past history, such parties' requirements
are subject to a number of factors, independent of any subjective factors, that
directly impact the demand for the Company's drilling rigs. These include the
funds available to such companies to carry out their drilling operations during
any given time period which, in turn, are often subject to downward revision
based on decreases in the then current prices of oil and natural gas. Many of
the Company's customers are small to mid-size oil and natural gas companies
whose drilling budgets tend to be susceptible to the influences of current price
fluctuations. Other factors that affect the Company's ability to work its
drilling rigs are the weather, which can, under adverse circumstances, delay or
even cause a project to be abandoned by an operator, the competition faced by
the Company in securing the award of a drilling contract in a given area, the
experience and recognition of the Company in a new market area, and the
availability of labor to run the Company's drilling rigs.
16
<PAGE>
Uncertainty Of Oil And Natural Gas Reserves And Well Performance
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Estimating quantities of proved reserves is imprecise. Such estimates are
based upon certain assumptions pertaining to future production levels,
future natural gas and crude oil prices, timing and amount of development
expenditures and future operating costs, using currently available
geologic, engineering and economic data, some or all of which may prove to
be incorrect over time. As a result of changes in these assumptions that
will occur in the future, and based upon further production history,
results of future exploration and development activities, future natural
gas and crude oil prices and other factors, the reported quantity of
reserves may be subject to upward or downward revision.
In addition to the foregoing, projections regarding the potential
production and reserve capabilities of newly drilled and/ or completed
wells are subject to additional uncertainties that may significantly
influence such projections. Such wells have a very limited production
history, if any, on which to base future forecasts of their capabilities.
Since an established rate of production is a primary factor used by
reservoir engineers to forecast oil and natural gas reserves as well as a
well's production rate, the lack of this information decreases the
Company's ability to accurately project such information. In addition,
there are inherent risks in both the drilling and completion phases of a
new well which could cause a well bore to be prematurely abandoned due
either to the loss of the well bore in the physical sense or due to the
costs associated with operational problems which could render further
operations uneconomical.
Debt and Bank Borrowing
The amount of the Company's existing debt as well as its future debt
is, to a large extent, a function of the costs associated with the projects
undertaken by the Company at any given time and the cash flow received by
the Company. Generally, the costs incurred by the Company in its normal
operations are those associated with the drilling of oil and natural gas
wells, the acquisition of producing properties, and the costs associated
with the maintenance of its drilling rig fleet. To some extent, these
costs, particularly the first two items, are discretionary and the Company
maintains a degree of control regarding the timing and/ or the need to
incur the same. However, in some cases, unforseen circumstances may arise,
such as in the case of an unanticipated opportunity to acquire a large
producing property package or the need to replace a costly rig component
due to an unexpected loss, which could force the Company to incur increased
debt above that which it had expected or forecast. Likewise, for many of
the reasons mentioned above, the Company's cash flow may not be sufficient
to cover its current cash requirements which would then require the Company
to increase its debt either through bank borrowings or otherwise.
17
<PAGE>
International Operations and Risks
Currently all of the Company's contract land drilling operations are
conducted within the continental United States. Should, however, the
Company at some point in the future undertake international drilling
operations, such operations would be subject to a number of risks including
foreign exchange restrictions, currency fluctuations, foreign taxation,
changing political conditions and foreign and domestic policies,
expropriation, nationalization, nullification, modification or
renegotiation of contracts, war and civil disturbances or other risks that
may limit or disrupt markets. In addition, the Company would incur certain
additional costs in establishing and running such operations.
Item 3. Legal Proceedings
- --------------------------
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
should result in judgments which would have a material adverse effect on
the Company.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted to the security holders during the fourth
quarter of the Company's calendar year ended December 31, 1998.
18
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 23, 1999, the Company had 2,543 holders of record of
its common stock the only form of stock issued as of that date. 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 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, and only if
working capital provided from operations during said year is equal to or
greater than 175 percent of current maturities of long-term debt at the end
of such year. 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:
1998 1997
-------------------- --------------------
QUARTER High Low High Low
------- --------- --------- --------- ---------
First $ 9 13/16 $ 6 7/16 $12 1/4 $ 7 1/2
Second $ 9 7/8 $ 5 1/2 $11 7/8 $ 7 7/8
Third $ 6 5/16 $ 3 3/4 $15 3/8 $ 9 5/8
Fourth $ 6 15/16 $ 3 5/8 $15 13/16 $ 8 7/16
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<PAGE>
Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
---------------------------------------------------
1998 1997 1996 1995 1994
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $93,337 $91,864 $72,070 $53,074 $43,895
======= ======= ======= ======= =======
Income From Continuing
Operations $ 2,246 $11,124 $ 8,333 $ 3,751 (1) $ 4,628 (2)
======= ======= ======= ======= =======
Net Income $ 2,246 $11,124 $ 8,333 $ 3,999 (1) $ 4,794 (2)
======= ======= ======= ======= =======
Basic Earnings Per
Common Share:
Continuing Operations $.09 $.46 $.37 $.18 (1) $.22 (2)
Discontinued Operation - - - .01 .01
---- ---- ---- ---- ----
Net Income $.09 $.46 $.37 $.19 (1) $.23 (2)
==== ==== ==== ==== ====
Diluted Earnings Per
Common Share:
Continuing Operations $.09 $.45 $.37 $.18 (1) $.22 (2)
Discontinued Operation - - - .01 .01 (2)
---- ---- ---- ---- ----
Net Income $.09 $.45 $.37 $.19 (1) $.23
==== ==== ==== ==== ====
Total Assets $223,064 $202,497 $137,993 $110,922 $103,933
======== ======== ======== ======== ========
Long-Term Debt $ 72,900 $ 54,100 $ 40,600 $ 41,100 $ 37,300
======== ======== ======== ======== ========
Other Long-Term
Liabilities $ 2,301 $ 2,279 $ 2,276 $ 2,109 $ 2,673
======== ======== ======== ======== ========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
======== ======== ======== ======== ========
___________
(1) Includes a $635,000 gain on compressor sale, a $850,000 gain from
settlement of litigation and a net $530,000 deferred tax benefit.
(2) Includes a $742,000 gain on sale of a natural gas gathering
system.
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1998, 1997 and 1996 activity.
20
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------------------------------------------------------------------------
Results of Operations
- ---------------------
Financial Condition and Liquidity
- ---------------------------------
The Company's loan agreement ("Loan Agreement"), provides for a total
facility of $100 million, consisting of a revolving credit facility through
May 1, 2002 and a term loan thereafter, maturing on May 1, 2005. Borrowings
under the revolving credit facility are limited to a borrowing value which
is subject to a semi-annual redetermination. As of the latest borrowing
value determination, $85 million of the commitment is available to the
Company. The Loan Agreement contains certain covenants which require the
Company to maintain consolidated tangible net worth of at least $75
million, a current ratio of not less than 1 to 1, a ratio of long-term
debt, as defined in the Loan Agreement, to consolidated tangible net worth
not greater than 1.2 to 1 and a ratio of total liabilities, as defined in
the Loan Agreement, to consolidated tangible net worth not greater than
1.65 to 1. In addition, working capital provided by operations, as defined
in the Loan Agreement, cannot be less than $18 million in any year. At
December 31, 1998, borrowings under the Loan Agreement totaled $68.9
million. At February 23, 1999, borrowings under the Loan Agreement totaled
$71.0 million with $11.4 million available for future borrowings. The
interest rate on the bank debt was 6.27 and 6.31 percent at December 31,
1998 and February 23, 1999, respectively. At the Company's election, any
portion of the debt outstanding may be fixed at the London Interbank
Offered Rate ("Libor Rate"), as adjusted per the Loan Agreement depending
on the level of debt as a percentage of the total borrowing base, for 30,
60, 90 or 180 days with the remainder of the outstanding debt subject to
the Chase Manhattan Bank, N. A. prime rate ("Chase Prime Rate"). During
any Libor Rate funding period, the Company may not pay in part or in whole
the outstanding principal balance of the note to which such Libor Rate
option applies. At both December 31, 1998 and February 23, 1999, $63.0
million of borrowings were subject to the Libor Rate as adjusted. A
commitment fee of 3/8 of 1 percent is charged for any unused portion of the
borrowing base.
Shareholders' equity at December 31, 1998 was $111.3 million, making
the Company's ratio of long-term debt-to-equity .66 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 Loan Agreement. Net cash provided by operating
activities in 1998 was $33.5 million as compared to $34.4 million in 1997.
At December 31, 1998 and January 31, 1999, the Company had working capital
of $1.6 million and $1.0 million, respectively.
The Company's capital expenditures during 1998 were $50.1 million.
The Company's oil and natural gas operations had capital expenditures of
$38.4 million, with $24.9 million and $9.0 million used for exploration and
development drilling and producing property acquisitions, respectively.
Capital expenditures made by the Company's contract drilling operations
were $11.5 million in 1998. Drilling capital expenditures in 1998 were for
drill pipe and collars, the refurbishment of one drilling rig previously
stacked and major overhauls on large rig components of drilling rigs in
21
<PAGE>
service. The Company's drilling rigs are composed of large components some
of which, on a rotational basis, are required to be overhauled to assure
continued proper performance. Such capital expenditures will continue in
future years with approximately $2.5 million projected for 1999.
During 1999, the Company's oil and natural gas exploration subsidiary
plans to continue its developmental drilling program. However, lower spot
market natural gas prices in the fourth quarter of 1998 have increased the
potential availability of economical producing property acquisitions and,
as a result, a larger portion of the Company's capital expenditure budget
may be shifted to producing property acquisitions in 1999. The majority of
the Company's capital expenditures are discretionary and primarily directed
toward increasing reserves and future growth. Current operations are not
dependent on the Company's ability to obtain funds outside of the Company's
Loan Agreement. The decision to acquire or drill on oil and natural gas
properties at any given time depends on market conditions, potential return
on investment, future drilling potential and the availability of
opportunities to obtain financing given the circumstances involved, thus
providing the Company with a large degree of flexibility in incurring such
costs. Depending, in part, on commodity pricing, the Company plans to
spend approximately $20 million on its exploration capital expenditure
program in 1999.
On November 20, 1997, the Company acquired Hickman Drilling Company,
pursuant to an Agreement and Plan of Merger ("the Merger Agreement"),
entered into by and between the Company, Hickman Drilling Company and all
of the holders of the outstanding capital stock of Hickman Drilling Company
(the "Selling Stockholders"). Under the terms of this acquisition, the
Selling Stockholders received, in aggregate, 1,300,000 shares of Common
Stock and promissory notes in the aggregate principal amount of $5,000,000
payable in five equal annual installments commencing January 2, 1999. The
acquisition included nine land contract drilling rigs with depth capacities
ranging from 9,500 to 17,000 feet, spare drilling equipment and
approximately $2.1 million in working capital. The notes bear interest at
the Chase Prime Rate which at both December 31, 1998 and February 23, 1999
was 7.75 percent. In December 1997, the Company also purchased a Mid-
Continent U-36-A, 650 horsepower rig with a 13,000 feet depth capacity and
spare components from two additional rigs for a total consideration of $1
million, of which $200,000 was paid at closing and the balance is being
paid out over a period ending no later than three years after the
acquisition date. The balance is paid out monthly with the monthly amount
calculated on the basis of a predetermined daily rate multiplied by the
number of days in such month that the acquired rig is employed for the
account of the seller, all as more fully specified in the acquisition
agreement. If the balance of the purchase price has not been fully paid at
the end of three years the remaining amount is to be paid in cash to the
seller. At December 31, 1998, the balance remaining under this purchase
agreement was $331,000.
In March of 1998, a Vice President of South America Drilling
Operations was hired to facilitate the Company's efforts to expand its
contract drilling operations outside the continental United States,
specifically into areas of South America. Drilling markets in South
America have the potential to provide higher profit margins and higher
profit contributions, with longer term multi-year contracts which could
also provide a leveling effect on drilling rig utilization. The Company
22
<PAGE>
has not previously conducted international contract drilling operations,
but it anticipates that such operations would involve a number of
additional political, economic, currency, tax and other risks and costs not
generally encountered in its domestic operations. To date, the Company has
not entered into any contracts for international work.
Prior to December 31, 1997, the Company received 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"). The monthly payments paid by the purchaser for
natural gas not taken (the "Prepayment Balance") were subject to recoupment
in volumes of natural gas through a period ending on the earlier of
recoupment or December 31, 1997 (the "Recoupment Period"). At December 31,
1997, the Settlement Agreement and the natural gas purchase contracts which
were subject to the Settlement Agreement terminated. As a result of the
Settlement Agreement, the December 31, 1997 Prepayment Balance of $2.2
million became payable in equal annual payments over a five year period.
The first payment of $441,000 was due and paid on June 1, 1998. The price
per Mcf under the Settlement Agreement was substantially higher than
current spot market prices. The impact of the higher price received under
the Settlement Agreement increased pre-tax income approximately $540,000
and $650,000 in 1997 and 1996, respectively. The natural gas previously
subject to the Settlement Agreement is now being sold at spot market prices
consistent with primarily all of the rest of the natural gas sold by the
Company.
Oil and natural gas prices received by the Company were volatile
throughout 1998. Average oil prices received by the Company in December
1998, as compared to January 1998, dropped by 35 percent. Average natural
gas prices in December 1998, as compared to January 1998, were one percent
higher after recovering from a 20 percent decrease in August and September
of 1998. The Company's average price received for oil during 1998 was
$12.81 and the average natural gas price was $1.90. Average oil prices and
natural gas spot prices received in February 1999 were up 5 percent for oil
and down 16 percent for natural gas, when compared with December 31, 1998
average prices. The large drop in natural gas prices in February 1999 had
a significant impact to the value of the Company's natural gas reserves as
reported at December 31, 1998. If this lower natural gas price had
occurred at year-end 1998, it would have caused the Company to reduce the
carrying value of its natural gas properties by approximately $22.0 million
before taxes. If prices do not recover from this February level and
depending on other variables, the Company will record a provision to reduce
the carrying value of oil and natural gas properties in the first quarter
of 1999. 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. Declines in natural
gas or oil prices could also adversely effect the Company operationally by,
for example, adversely impacting future demand for its drilling rigs or
financially by reducing the price received for its oil and natural gas
sales and also by adversely effecting the semi-annual borrowing value
determination under the Company's Loan Agreement since this determination
is calculated on the value of the Company's oil and natural gas reserves.
23
<PAGE>
At December 31, 1998, the Company did not have any hedge against the
fluctuation in the price of oil and natural gas nor did the Company
maintain any forward or future contracts relating to the production of its
oil and natural gas. In the first quarter of 1999, the Company initiated
swap transactions to help manage its exposure to commodity price risk in
the month to month sale of natural gas. These transactions cover
approximately 20 percent of the Company's daily production and cover the
period from March 1, 1999 to June 30, 1999. These activities have been
designated as hedging activities by the Company and will be accounted for
as such. Increases (decreases) in the fair value of these instruments will
generally offset increases (decreases) in the spot market prices of natural
gas. Implicit gains or losses, resulting from changes in the fair value of
hedges which have not yet been settled, are not recognized to the extent
that they relate to changes in the spot price of anticipated natural gas
sales. Gains or losses arising from hedge transactions are recorded in
sales in the month of the hedged transaction.
As a result of the depressed condition existing in the contract
drilling industry over much of the past decade, the Company's ability to
fully utilize its complement of drilling rigs during portions of 1997 and
1998 when there was a rapid increase in drilling activity was limited due
to the lack of qualified labor and certain support 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. Although the Company currently does not have a
shortage of rig labor or support equipment, the Company's management
expects that these factors will continue to influence the Company's rig
utilization especially if demand should rapidly increase.
In the third quarter of 1994, the Company's Board of Directors
authorized the Company to purchase up to 1,000,000 shares of the Company's
outstanding common stock on the open market. Since that time, 160,100
shares have been repurchased at prices ranging from $2.50 to $9.69 per
share. During the first quarters of 1998, 1997 and 1996, 19,863, 23,892
and 44,686 of the purchased shares, respectively, were reissued as the
Company's matching contribution to its 401(k) Employee Thrift Plan. At
December 31, 1998, 25,000 treasury shares were held by the Company.
Year 2000 Statement
- -------------------
The Company has initiated a comprehensive assessment of its
information technology ("IT") and non-information technology ("non-IT")
systems to try and ensure that such systems will be Year 2000 compliant.
The Year 2000 problem exists because many existing computer programs use
only the last two digits to define the year. Therefore, these computer
programs do not recognize years that begin with a "20" and assume that all
years begin with a "19". If not corrected many computer applications could
fail or create erroneous results which could cause disruption of operations
not only for the Company but also for its customers and suppliers, so the
Company has also initiated an assessment of its customers' and suppliers'
efforts to become year 2000 compliant.
24
<PAGE>
Evaluation of the Company's IT systems began in house during 1997.
The Company's IT systems consist mainly of office computers, related
computer programs and mangement financial information software. The
Company believes nearly all of the Company's hardware is Year 2000
compliant and approximately 20 percent of its related computer programs and
software are Year 2000 compliant. The Company has expended approximately
$92,000 and estimates it will expend an additional $40,000 to bring the
remaining systems compliant by the end of the second quarter of 1999.
The Company's non-IT systems consist of office equipment and other
systems associated with its oil and natural gas properties and its drilling
rigs. The Company began assessing these non-IT systems and the associated
cost during the fourth quarter of 1998. The assessment and replacement of
equipment, if any, should be completed by the end of the second quarter of
1999. The Company anticipates that the cost associated with non-IT systems
will be minimal.
During the third quarter of 1998, the Company issued questionnaires to
its key suppliers and customers to assess their preparation for Year 2000
compliance. The Company received responses from 41 percent of these
entities. Approximately 90 percent of the responses indicated that these
entities are aware of and are in the process of resolving their Year 2000
issues. During the first quarter of 1999, the Company will issue second
request questionnaires to those key suppliers and customers who did not
respond to the questionnaires issued during the third quarter of 1998.
Upon the return of the second request questionnaires from these non-
affiliated entities, the Company will review their responses and will begin
the process of assessing the preparedness of these entities.
As noted, the Company currently anticipates that all of its internal
systems and equipment will be Year 2000 compliant by the end of the second
quarter of 1999 and that the associated costs will not have a material
adverse effect on the Company's results of operations and financial
condition. However, the failure to properly assess or timely implement a
material Year 2000 problem could result in a disruption in the Company's
normal business activities or operations. Such failures, depending on the
extent and nature, could materially and adversely effect the Company's
operations and financial condition. As a result, the Company will continue
to evaluate its Year 2000 exposure, both internally and externally. Since
a portion of the Company's overall evaluation of its Year 2000 readiness
will, of necessity, be based on the information to be supplied by and the
readiness of the Company's key suppliers and customers, the Company cannot
currently determine the impact, if any, such third parties will have on the
Company's Year 2000 exposure. As noted, the Company intends to evaluate
this information as, if and when it is made available to it. To date, the
Company has not developed a contingency plan.
25
<PAGE>
Effects of Inflation
- ---------------------
The effects of inflation on the Company's operations in previous years
have been minimal due to low inflation rates. However, during third and
fourth quarters of 1996 and throughout 1997 as drilling rig day rates and
drilling rig utilization increased, the impact of inflation intensified as
the availability of related equipment, third party services and qualified
labor decreased. In 1998, the impact of inflation was reduced as oil and
natural gas prices became depressed. The impact on the Company in the
future will depend on the relative increase, if any, the Company may
realize in its drilling rig rates and the selling price of its oil and
natural gas. If industry activity suddenly increases substantially,
shortages in support equipment such as drill pipe, third party services and
qualified labor will occur resulting in additional corresponding increases
in material and labor costs. These market conditions may limit the
Company's ability to realize improvements in operating profits.
Results of Operations
- ---------------------
1998 versus 1997
- ----------------
Net income for 1998 was $2,246,000, compared with $11,124,000 in 1997.
Increases in the number of rigs utilized and increased natural gas
production were more than offset by substantial decreases in the average
price received for both oil and natural gas and to a lesser extent from
reduced oil production and contract drilling day rates.
Oil and natural gas revenues decreased 13 percent in 1998 due to a 21
percent and 33 percent decrease in average natural gas and oil prices
received, respectively along with a 10 percent reduction in oil production.
These decreases were partially offset by a 19 percent increase in natural
gas production. Oil production declined from 1997 levels due to the
Company's emphasis over the past three years in drilling development wells
which focused on replacing and increasing natural gas reserves. Average
natural gas spot market prices received by the Company decreased 20
percent. The natural gas previously subject to the Settlement Agreement,
which ended at December 31, 1997 and contained provisions for prices higher
than current spot market prices, is now being sold at spot market prices
consistent with the rest of the natural gas sold by the Company. The
impact of higher prices received under the Settlement Agreement increased
pre-tax income by approximately $540,000 in 1997.
In 1998, revenues from contract drilling operations increased by 16
percent as average rig utilization increased from 19.2 rigs operating in
1997 to 22.9 rigs operating in 1998. Daywork revenues per rig per day
decreased 3 percent between the comparative years. During the first three
quarters of 1998, the Company's monthly rig utilization consistently
remained at or above 23 rigs with daywork revenue per rig per day declining
by 8 percent from the January 1998 rate. In the fourth quarter utilization
dropped 27 percent from the previous quarter and dayrates decreased another
6 percent from the previous quarter. Total daywork revenues represented 64
percent of total drilling revenues in 1998 and 72 percent in 1997. 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.
26
<PAGE>
Operating margins (revenues less operating costs) for the Company's
oil and natural gas operations were 64 percent in 1998 compared to 71
percent in 1997. Decreased operating margins resulted primarily from the
decrease in average natural gas and oil prices received by the Company
between the two years. Total operating costs were 9 percent higher in 1998
compared to 1997 as the Company continues to add producing properties.
Operating margins for contract drilling decreased from 21 percent in
1997 to 18 percent in 1998. Margins in 1998 were lower primarily due to
decreases in both daily rig rates and utilization in the fourth quarter of
1998. Total operating costs for contract drilling were up 20 percent in
1998 versus 1997 due to increased drilling rig utilization and costs
associated with the November 1997 Hickman Acquisition.
Contract drilling depreciation increased 37 percent in response to
increased rig utilization and additional drilling capital expenditures
throughout 1997 and 1998. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 27 percent as the
Company increased its equivalent barrels of production by 14 percent and
the Company's average DD&A rate per equivalent barrel increased 11 percent
to $4.99 in 1998.
General and administrative expenses increased 6 percent as certain
employee costs increased. Interest expense increased 65 percent as the
Company's average outstanding debt increased 65 percent during 1998. The
average interest rate decreased from 7.28 percent in 1997 to 7.11 percent
in 1998.
1997 versus 1996
- ----------------
Net income for 1997 was $11,124,000, compared with $8,333,000 in 1996.
Increases in rig utilization, contract drilling day rates, average natural
gas prices received and natural gas production from new wells drilled
during the year all combined to produce the increase in 1997 net income.
Oil and natural gas revenues increased 6 percent in 1997 due to a 6
percent and 10 percent increase in natural gas production and average
natural gas prices received, respectively. These increases were partially
offset by a 15 percent decline in oil production and a 6 percent decrease
in average oil prices received by the Company in 1997. Oil production
declined from 1996 levels due to the Company's emphasis over the past two
years in drilling development wells which focused on replacing and
increasing natural gas reserves. Average natural gas spot market prices
received by the Company increased 11 percent while volumes produced from
certain wells included under the Settlement Agreement, which ended at
December 31, 1997 and contained provisions for prices higher than current
spot market prices, dropped 7 percent. The impact of higher prices
received under the Settlement Agreement increased pre-tax income by
approximately $540,000 and $650,000 in 1997 and 1996, respectively.
In 1997, revenues from contract drilling operations increased by 60
percent as average rig utilization increased from 14.7 rigs operating in
1996 to 19.2 rigs operating in 1997, and daywork revenues per rig per day
increased 22 percent. During the first three quarters of 1997, the
Company's monthly rig utilization consistently remained above 18 rigs with
27
<PAGE>
daywork revenue per rig per day steadily climbing by 15 percent. In October
utilization dropped slightly below 18 rigs before the Company acquired 9
rigs through the Hickman acquisition in late November 1997 and another rig
in December 1997, raising the Company's rig count to 34 rigs and its
utilization in December to 26.2 rigs. Daywork revenue per rig per day
continued to rise in the fourth quarter, but the Company's average dayrate
declined 9 percent in December compared to November since the acquired
rigs, due to their depth capabilities, earned lower dayrates. Total daywork
revenues represented 72 percent of total drilling revenues in 1997 and 68
percent in 1996. Turnkey and footage contracts typically provide for higher
revenues since a greater portion of the expense of drilling the well is
born by the drilling contractor.
Operating margins (revenues less operating costs) for the Company's
oil and natural gas operations were 71 percent in 1997 compared to 69
percent in 1996. Increased operating margins resulted primarily from the
increase in natural gas production and the increase in natural gas prices
received by the Company between the two years. Total operating costs were
2 percent lower in 1997 compared to 1996.
Operating margins for contract drilling increased from 16 percent in
1996 to 21 percent in 1997. Margins in 1997 improved due to increases in
daily rig rates and utilization. Total operating costs for contract
drilling were up 50 percent in 1997 versus 1996 due to increased drilling
rig utilization.
Contract drilling depreciation increased 43 percent in response to
increased rig utilization and additional drilling capital expenditures
throughout 1997. Depreciation, depletion and amortization ("DD&A") of oil
and natural gas properties increased 17 percent as the Company increased
its equivalent barrels of production by 2 percent and the Company's average
DD&A rate per equivalent barrel increased 15 percent to $4.49 in 1997.
General and administrative expenses increased 12 percent as certain
employee costs and outside services increased. Interest expense decreased 8
percent as the average interest rate on the Company's outstanding bank debt
decreased from 7.69 percent in 1996 to 7.27 percent in 1997. Average bank
debt also decreased 4 percent during 1997.
Prior to 1996, the Company's effective income tax rate was
significantly impacted by its net operating loss carryforwards. As of
December 31, 1995, the Company's net operating loss and statutory depletion
carryforwards were fully recognized for financial reporting purposes;
therefore, the Company's effective income tax rate in 1996 and 1997
increased to approximately the statutory rate.
28
<PAGE>
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
-------------------------
ASSETS 1998 1997
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 446 $ 458
Accounts receivable (less allowance for
doubtful accounts of $274 and $354) 13,149 19,813
Materials and supplies 3,298 3,535
Prepaid expenses and other 2,650 2,206
---------- ----------
Total current assets 19,543 26,012
---------- ----------
Property and Equipment:
Drilling equipment 123,258 119,155
Oil and natural gas properties, on the full
cost method 271,960 233,659
Transportation equipment 2,955 2,825
Other 6,870 6,948
---------- ----------
405,043 362,587
Less accumulated depreciation, depletion,
amortization and impairment 207,883 192,613
---------- ----------
Net property and equipment 197,160 169,974
---------- ----------
Other Assets 6,361 6,511
---------- ----------
Total Assets $ 223,064 $ 202,497
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
29
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
-------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY 1998 1997
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,801 $ 727
Accounts payable 8,517 11,112
Accrued liabilities 7,362 7,762
Contract advances 310 92
---------- ----------
Total current liabilities 17,990 19,693
---------- ----------
Other Long-Term Liabilities (Note 5) 2,301 2,279
---------- ----------
Long-Term Debt 72,900 54,100
---------- ----------
Deferred Income Taxes 18,583 17,560
---------- ----------
Commitments and Contingencies (Note 11)
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, 25,563,165 and
25,514,836 shares issued, respectively 5,113 5,103
Capital in excess of par value 82,187 82,043
Retained earnings 24,121 21,875
Treasury stock, at cost (25,000 and
19,863 shares, respectively) (131) (156)
---------- ----------
Total shareholders' equity 111,290 108,865
---------- ----------
Total Liabilities and Shareholders' Equity $ 223,064 $ 202,497
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
30
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
----------------------------------
1998 1997 1996
-------- -------- --------
(In thousands except per share amounts)
Revenues:
Contract drilling $53,528 $46,199 $28,819
Oil and natural gas 39,703 45,581 43,013
Other 106 84 238
-------- -------- --------
Total revenues 93,337 91,864 72,070
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 43,729 36,419 24,259
Depreciation 5,766 4,216 2,944
Oil and natural gas:
Operating costs 14,328 13,201 13,409
Depreciation, depletion
and amortization 16,069 12,625 10,807
General and administrative 4,891 4,621 4,122
Interest 4,815 2,921 3,162
-------- -------- --------
Total expenses 89,598 74,003 58,703
-------- -------- --------
Income Before Income Taxes 3,739 17,861 13,367
-------- -------- --------
Income Tax Expense:
Current 139 118 4
Deferred 1,354 6,619 5,030
-------- -------- --------
Total income taxes 1,493 6,737 5,034
-------- -------- --------
Net Income $ 2,246 $11,124 $ 8,333
======== ======== ========
Net Income Per Common Share:
Basic $ .09 $ .46 $ .37
======== ======== ========
Diluted $ .09 $ .45 $ .37
======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
31
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1996, 1997 and 1998
Capital
In Excess
Common Of Par Retained Treasury
Stock Value Earnings Stock Total
-------- -------- --------- -------- ---------
(In thousands)
Balances,
January 1, 1996 $ 4,195 $50,181 $ 2,418 $ (188) $ 56,606
Net income - - 8,333 - 8,333
Activity in employee
compensation plans
(321,667 shares) 64 615 - 123 802
Issuance of stock on
exercise of
warrants
(2,859,555 shares) 572 11,939 - - 12,511
Purchase of treasury
stock (5,000
shares) - - - (42) (42)
-------- -------- --------- -------- ---------
Balances,
December 31, 1996 4,831 62,735 10,751 (107) 78,210
Net income - - 11,124 - 11,124
Activity in employee
compensation plans
(57,524 shares) 12 718 - 89 819
Issuance of stock
for acquisition
(1,300,000 shares) 260 18,590 - - 18,850
Purchase of treasury
stock
(15,000 shares) - - - (138) (138)
-------- -------- --------- -------- ---------
Balances,
December 31, 1997 5,103 82,043 21,875 (156) 108,865
Net income - - 2,246 - 2,246
Activity in employee
compensation plans
(48,329 shares) 10 144 - 156 310
Purchase of treasury
stock
(25,000 shares) - - - (131) (131)
-------- -------- --------- -------- ---------
Balances,
December 31, 1998 $ 5,113 $82,187 $ 24,121 $ (131) $111,290
======== ======== ========= ======== =========
The accompanying notes are an integral part of the
consolidated financial statements
32
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
Cash Flows From Operating Activities:
Net Income $ 2,246 $ 11,124 $ 8,333
Adjustments to reconcile net
income to net cash provided
(used) by operating activities:
Depreciation, depletion, and
amortization 22,186 17,199 14,079
Loss (gain) on disposition
of assets 17 (94) (185)
Employee stock compensation plans 561 244 214
Bad debt expense - 250 -
Deferred tax expense (benefit) 1,354 6,619 5,030
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 6,664 (1,762) (5,444)
Materials and supplies 237 (1,233) (254)
Prepaid expenses and other (444) (211) (418)
Accounts payable 948 2,062 (2,288)
Accrued liabilities (27) 1,430 540
Contract advances 218 (1,208) 890
Other liabilities (447) (70) 167
--------- --------- ---------
Net cash provided
by operating activities 33,513 34,350 20,664
--------- --------- ---------
The accompanying notes are an integral part of the
consolidated financial statements
33
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions) $(53,654) $(45,115) $(34,111)
Cash received on acquisition
of drilling company (Note 2) - 1,611 -
Proceeds from disposition of
property and equipment 964 792 1,009
(Acquisition) disposition
of other assets- (93) (314) 215
--------- --------- ---------
Net cash used in
investing activities (52,783) (43,026) (32,887)
--------- --------- ---------
Cash Flows From Financing Activities:
Borrowings under line of credit 52,700 34,400 31,500
Payments under line of credit (32,900) (25,900) (32,000)
Net payments on notes payable
and other long-term debt (470) - (20)
Proceeds from sale of common stock 59 225 12,798
Acquisition of treasury stock (131) (138) (42)
--------- --------- ---------
Net cash provided by
financing activities 19,258 8,587 12,236
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents (12) (89) 13
Cash and Cash Equivalents,
Beginning of Year 458 547 534
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 446 $ 458 $ 547
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 4,064 $ 2,910 $ 3,189
Income taxes $ 507 $ 102 $ 63
The accompanying notes are an integral part of the
consolidated financial statements
34
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Principles of Consolidation
The consolidated financial statements include the accounts of Unit
Corporation and its directly and indirectly wholly owned subsidiaries (the
"Company"). The Company's investment in limited partnerships is accounted
for on the proportionate consolidation method, whereby its share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business
The Company is engaged in the development, acquisition and production
of oil and natural gas properties and the land contract drilling of oil and
natural gas wells primarily in the Anadarko, Arkoma and South Texas Basins.
These basins are located in Oklahoma, Texas, Kansas and Arkansas.
Additional producing properties are located in Canada and other states,
including New Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana,
Alabama, Mississippi, Arkansas, Illinois and Nebraska. At December 31,
1998, the Company has an interest in 2,563 wells and served as operator of
524 of those wells. Land contract drilling of oil and natural gas wells is
performed for a wide range of customers using the drilling rigs owned and
operated by the Company. In 1998, 31 of the Company's 34 rigs were in
operation.
Drilling Contracts
The Company recognizes revenues generated from "daywork" drilling
contracts as the services are performed, which is similar to the percentage
of completion method. For all contracts under which the Company bears the
risk of completion of the wells ("footage" and "turnkey" drilling
contracts), revenues and expenses are recognized using the completed
contract method. The duration of all three types of contracts range
typically from 20 to 90 days. 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 and are included in other current assets.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and
all investments with maturities at date of purchase of three months or less
which are readily convertible into known amounts of cash.
35
<PAGE>
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated
useful lives, including a minimum provision of 20 percent of the active
rate when the equipment is idle. The Company uses the composite method of
depreciation for drill pipe and collars and calculates the depreciation by
footage actually drilled compared to total estimated remaining footage.
Depreciation of other property and equipment is computed using the
straight-line method over the estimated useful lives of the assets ranging
from 3 to 15 years.
Realization of the carrying value of the Company's property and
equipment is reviewed for possible impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable.
Assets are determined to be impaired if a forecast of undiscounted
estimated future net operating cash flows directly related to the asset
including disposal value if any, is less than the carrying amount of the
asset. If any asset is determined to be impaired, the loss is measured as
the amount by which the carrying amount of the asset exceeds its fair
value. An estimate of fair value is based on the best information
available, including prices for similar assets. Changes in such estimates
could cause the Company to reduce the carrying value of its property and
equipment.
When property and equipment components are disposed of, the cost and
the related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For
dispositions of drill pipe and drill collars, an average cost for the
appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.
Goodwill
Goodwill represents the excess of the cost of the acquisition of
Hickman Drilling Company over the fair value of the net assets acquired and
is being amortized on the straight-line method over 25 years. Goodwill is
evaluated periodically for impairment, when it appears an impairment may
have occurred, based on the estimated undiscounted future cash flow of the
acquired entity. Net goodwill reported in other assets at December 31,
1998 and 1997 was $5,818,000 and $6,061,000, respectively with accumulated
amortization at December 31, 1998 and 1997 of $264,000 and $20,000,
respectively.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and
development activities on the full cost method of accounting prescribed by
the Securities and Exchange Commission ("SEC"). Accordingly, all
productive and non-productive costs incurred in connection with the
acquisition, exploration and development of oil and natural gas reserves
are capitalized and amortized on a composite units-of-production method
based on proved oil and natural gas reserves. The Company's determination
of its oil and natural gas reserves are reviewed annually by independent
36
<PAGE>
petroleum engineers. The average composite rates used for depreciation,
depletion and amortization ("DD&A") were $4.99, $4.49 and $3.90 per
equivalent barrel in 1998, 1997 and 1996, respectively. The Company's
calculation of DD&A includes estimated future expenditures to be incurred
in developing proved reserves and estimated dismantlement and abandonment
costs, net of estimated salvage values. In the event the unamortized cost
of oil and natural gas properties being amortized exceeds the full cost
ceiling, as defined by the SEC, the excess is charged to expense in the
period during which such excess occurs. The full cost ceiling is based
principally on the estimated future discounted net cash flows from the
Company's oil and natural gas properties. As discussed in Note 14, such
estimates are imprecise. Changes in these estimates or declines in oil and
natural gas prices could cause the Company in the near-term to reduce the
carrying value of its oil and natural gas properties.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties
in which the Company has an interest or on properties in which a
partnership, of which the Company is a general partner, has an interest.
Accordingly, in 1998 and 1997 the Company recorded $437,000 and $314,000 of
contract drilling profits, respectively, as a reduction of the carrying
value of its oil and natural gas properties rather than including these
profits in current operations. No contract drilling profits were realized
on such interests in 1996.
Limited Partnerships
The Company's wholly owned subsidiary, Unit Petroleum Company, is a
general partner in fourteen oil and natural gas limited partnerships sold
privately and publicly. Certain of the Company's officers, directors and
employees own interests in most of these partnerships.
The Company shares in partnership revenues and costs in accordance with
formulas prescribed in each limited partnership agreement. The
partnerships also reimburse the Company for certain administrative costs
incurred on behalf of the partnerships.
Income Taxes
Measurement of current and deferred income tax liabilities and assets
is based on provisions of enacted tax law; the effects of future changes in
tax laws or rates are not included in the measurement. Valuation
allowances are established where necessary to reduce deferred tax assets to
the amount expected to be realized. Income tax expense is the tax payable
for the year and the change during that year in deferred tax assets and
liabilities.
37
<PAGE>
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 1998 average spot market natural gas price of $1.90 per
Mcf, the Company estimates its balancing position to be approximately $4.6
million on under-produced properties and approximately $2.8 million on
over-produced properties.
The Company's policy is to expense its pro-rata share of lease
operating costs from all wells as incurred. Such expenses relating to the
Company's balancing position on wells in which the Company has imbalances
are not material.
Stock Based Compensation
The Company applies APB Opinion 25 in accounting for its stock option
plans. Under this standard, no compensation expense is recognized for
grants of options which include an exercise price equal to or greater than
the market price of the stock on the date of grant. Accordingly, based on
the Company's grants in 1998, 1997 and 1996 no compensation expense has
been recognized. As provided by Financial Accounting Standard No. 123
"Accounting for Stock-Based Compensation," the Company has disclosed the
pro forma effects of recording compensation for such option grants based on
fair value in Note 8 to the financial statements.
Self Insurance
The Company utilizes self insurance programs for employee group health
and worker's compensation. Self insurance costs are accrued based upon the
aggregate of estimated liabilities for reported claims and claims incurred
but not yet reported.
Financial Instruments and Concentrations of Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
credit risk is considered by management to be limited due to the large
number of customers comprising the Company's customer base. In addition,
at December 31, 1998 and 1997, the Company had a concentration of cash of
$1.5 million and $0.3 million, respectively, with one bank.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
38
<PAGE>
Earnings Per Share
In the fourth quarter of 1997, the Company adopted Financial
Accounting Standards Board Statement of Financial Accounting Standards No.
128, Earnings Per Share ("FAS 128"). Earnings per share amounts for all
previous periods presented give effect to the application of FAS 128.
Impact of Financial Accounting Pronouncements
On June 15, 1998, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities (FAS 133). FAS 133 is
effective for all fiscal quarters of fiscal years beginning after June 15,
1999 (January 1, 2000 for the Company). FAS 133 requires that all
derivative instruments be recorded on the balance sheet at their fair
value. Changes in the fair value of derivatives are recorded each period
in current earnings or other comprehensive income, depending on whether a
derivative is designated as part of a hedge transaction and, if it is, the
type of hedge transaction. Management of the Company anticipates that, due
to its limited use of derivative instruments, the adoption of FAS 133 will
not have a significant effect on the Company's results of operations or its
financial position.
NOTE 2 - ACQUISITION OF DRILLING COMPANY
- ----------------------------------------
On November 20, 1997, the Company acquired Hickman Drilling Company.
The selling stockholders of Hickman Drilling Company received, in the
aggregate, 1,300,000 shares of common stock valued at $18,850,000 and
promissory notes of $5,000,000 to be paid in five equal annual installments
commencing January 2, 1999. The acquisition has been accounted for as a
purchase and the results of Hickman Drilling Company have been included in
the accompanying consolidated financial statements since the date of
acquisition. The acquisition is summarized as follows:
(In thousands)
Current assets net of current liabilities $ 2,072
Property and equipment 23,187
Goodwill 6,081
Deferred tax liability - long-term (7,490)
---------
Total acquisition $ 23,850
=========
39
<PAGE>
NOTE 3 - EARNINGS PER SHARE
- ---------------------------
The following data shows the amounts used in computing earnings per
share.
For the Year Ended
December 31, 1998
--------------------------------------
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ----------- ----------
Basic earnings per common
share $ 2,246,000 25,544,000 $ 0.09
==========
Effect of dilutive
stock options - 340,000
----------- -----------
Diluted earnings per common
share $ 2,246,000 25,884,000 $ 0.09
=========== =========== ==========
For the Year Ended
December 31, 1997
-------------------------------------
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ----------- ----------
Basic earnings per common
share $11,124,000 24,327,000 $ 0.46
==========
Effect of dilutive
stock options - 380,000
----------- -----------
Diluted earnings per common
share $11,124,000 24,707,000 $ 0.45
=========== =========== ==========
40
<PAGE>
For the Year Ended
December 31, 1996
--------------------------------------
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ----------- ----------
Basic earnings per common
share $ 8,333,000 22,463,000 $ 0.37
==========
Effect of dilutive
stock options - 302,000
----------- -----------
Diluted earnings per common
share $ 8,333,000 22,765,000 $ 0.37
=========== =========== ==========
The following options and their average exercise prices were not included
in the computation of diluted earnings per share because the option
exercise prices were greater than the average market price on common shares
for the years ended December 31,:
1998 1997 1996
----------- ---------- ----------
Options 191,000 2,500 161,500
=========== ========== ==========
Average exercise price $ 8.60 $ 11.32 $ 8.60
=========== ========== ==========
NOTE 4 - WARRANTS
- -----------------
In 1987, the Company issued 2.873 million Units, consisting of three
shares of the Company's common stock and one warrant, at a price of $10.375
per Unit. Each warrant entitled the holder to purchase one share of the
Company's common stock at a price of $4.375. Prior to the warrants
expiration on August 30, 1996, 2.86 million warrants were exercised
providing $12.5 million in additional capital to the Company.
41
<PAGE>
NOTE 5 - OTHER LONG-TERM LIABILITIES
- ------------------------------------
Other long-term liabilities consisted of the following as of December
31, 1998 and 1997:
1998 1997
--------- ---------
(In thousands)
Natural gas purchaser prepayment $ 1,759 $ 2,206
Separation benefit plan 1,012 -
Rig acquisition 331 800
--------- ---------
3,102 3,006
Less current portion 801 727
--------- ---------
$ 2,301 $ 2,279
========= =========
In March 1988, the Company entered into a settlement agreement with a
natural gas purchaser. During early 1991, the Company and the natural gas
purchaser superseded the original agreement with a new settlement agreement
effective retroactively to January 1, 1991. Under these settlement
agreements ("Settlement Agreement"), the Company has a prepayment balance
of $1.8 million at December 31, 1998 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. At December
31, 1997, the Settlement Agreement and the natural gas purchase contracts
which were subject to the Settlement Agreement terminated. The December
31, 1997 Prepayment Balance of $2.2 million became payable in equal annual
payments over a five year period. The first payment of $441,000 was due
and paid on June 1, 1998.
The Company has other long-term liabilities of $1,343,000, consisting
of $331,000 from the December 9, 1997 acquisition of a Mid-Continent U-36-
A, 650 horsepower rig plus additional spare rig equipment and $1,012,000
from the liability accrued for the Company's Separation Benefit Plan. The
debt for rig equipment is payable over a maximum of three years from the
closing date of the acquisition.
42
<PAGE>
NOTE 6 - LONG-TERM DEBT
- ------------------------
Long-term debt consisted of the following as of December 31, 1998 and
1997:
1998 1997
--------- ---------
(In thousands)
Revolving credit and term loan,
with interest at December 31,
1998 and 1997 of 6.3 percent
and 7.3 percent, respectively $ 68,900 $ 49,100
Notes payable for Hickman
Drilling Company acquisition
with interest at December 31,
1998 and 1997 of 7.8 percent
and 8.5 percent, respectively 5,000 5,000
--------- ---------
73,900 54,100
Less current portion 1,000 -
--------- ---------
Total long-term debt $ 72,900 $ 54,100
========= =========
At December 31, 1998, the Company's loan agreement ("Loan Agreement")
provided for a total loan commitment of $100 million consisting of a
revolving credit facility through May 1, 2002 and a term loan thereafter,
maturing on May 1, 2005. Borrowings under the Loan Agreement are limited
to a borrowing value which as of December 31, 1998 was $85 million. The
Loan Value under the revolving credit facility is subject to a semi-annual
redetermination calculated as the sum of a percentage of the discounted
future value of the Company's oil and natural gas reserves, as determined
by the banks, plus the greater of (i) 50 percent of the appraised value of
the Company's contract drilling rigs or (ii) two times the previous 12
months cash flow from the contract drilling rigs, limited in either case to
$20 million. Any declines in commodity prices would adversely impact the
determination of the borrowing value.
Borrowings under the revolving credit facility bear interest at the
Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London
Interbank Offered Rates ("Libor Rate") plus .75 to 1.25 percent depending
on the level of debt as a percentage of the total borrowing base.
Subsequent to May 1, 2002, borrowings under the Loan Agreement bear
interest at the Prime Rate plus .25 percent or the Libor rate plus 1.0 to
1.5 percent depending on the level of debt as a percentage of the total
borrowing base.
43
<PAGE>
At the Company's election, any portion of the debt outstanding may be
fixed at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate
funding period the Company may not pay in part or in whole the outstanding
principal balance of the note to which such Libor Rate option applies.
Borrowings under the Prime Rate option may be paid anytime in part or in
whole without premium or penalty.
The Company paid an origination fee of $85,000 at inception of the
Loan Agreement and a facility fee of 3/8 of one percent is charged for any
unused portion of the borrowing value. Virtually all of the Company's
drilling rigs are collateral for such indebtedness and the balance of the
Company's assets are subject to a negative pledge.
The Loan Agreement includes prohibitions against (i) the payment of
dividends (other than stock dividends) during any fiscal year in excess of
25 percent of the consolidated net income of the Company during the
preceding fiscal year, and only if working capital provided from operations
during said year is equal to or greater than 175 percent of current
maturities of long-term debt at the end of such year, (ii) the incurrence
by the Company or any of its subsidiaries of additional debt with certain
very limited exceptions and (iii) the creation or existence of mortgages or
liens, other than those in the ordinary course of business, on any property
of the Company or any of its subsidiaries, except in favor of its banks.
The Loan Agreement also requires that the Company maintain consolidated net
worth of at least $75 million, a current ratio of not less than 1 to 1, a
ratio of long-term debt, as defined in the Loan Agreement, to consolidated
tangible net worth not greater than 1.2 to 1 and a ratio of total
liabilities, as defined in the Loan Agreement, to consolidated tangible net
worth not greater than 1.65 to 1. In addition, working capital provided by
operations, as defined in the Loan Agreement, cannot be less than $18
million in any year.
In November 1997, the Company completed its acquisition of Hickman
Drilling Company. In association with this acquisition, the Company issued
an aggregate of $5.0 million in promissory notes payable in five equal
annual installments commencing January 2, 1999, with interest at the Prime
Rate.
Estimated annual principal payments under the terms of all long-term
liabilities and debt from 1999 through 2003 are $1,801,000, $1,484,000,
$1,440,000, $14,837,000 and $23,967,000. Based on the borrowing rates
currently available to the Company for debt with similar terms and
maturities, long-term debt at December 31, 1998 approximates its fair
value.
44
<PAGE>
NOTE 7 - 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:
1998 1997 1996
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 1,271 $ 6,073 $ 4,545
State income tax, net of federal 150 733 499
Goodwill and other 72 (69) (10)
-------- -------- --------
Income tax expense (benefit) $ 1,493 $ 6,737 $ 5,034
======== ======== ========
Deferred tax assets and liabilities are comprised of the following at
December 31, 1998 and 1997:
1998 1997
--------- ---------
(In thousands)
Deferred tax assets:
Allowance for losses $ 1,680 $ 1,348
Net operating loss carryforwards 12,541 15,819
Statutory depletion carryforward 2,260 2,260
Investment tax credit carryforward 530 1,552
Alternative minimum tax credit
carryforward 431 167
--------- ---------
Gross deferred tax assets 17,442 21,146
Valuation allowance (530) (1,552)
Deferred tax liability-
Depreciation, depletion and amortization (35,495) (37,154)
--------- ---------
Net deferred tax liability $(18,583) $(17,560)
========= =========
The deferred tax asset valuation allowance reflects that the
investment tax credit carryforwards may not be utilized before the
expiration dates due in part to the effects of anticipated future
exploratory and development drilling costs. The reduction in the valuation
allowance was the result of the expiration of investment tax credit
carryforwards in 1998.
45
<PAGE>
Realization of the deferred tax asset is dependent on generating
sufficient taxable income prior to expiration of loss carryforwards.
Although realization is not assured, management believes it is more likely
than not that the deferred tax asset will be realized. The amount of the
deferred tax asset considered realizable, however, could be reduced in the
near-term if estimates of future taxable income during the carryforward
period are reduced.
At December 31, 1998, the Company has net operating loss carryforwards
for regular tax purposes of approximately $33,003,000 and net operating
loss carryforwards for alternative minimum tax purposes of approximately
$19,953,000 which expire in various amounts from 2000 to 2011. The Company
has investment tax credit carryforwards of approximately $530,000 which
expire from 1999 to 2000. In addition, a statutory depletion carryforward
of approximately $5,948,000, which may be carried forward indefinitely, is
available to reduce future taxable income, subject to statutory
limitations.
NOTE 8 - EMPLOYEE BENEFIT AND COMPENSATION PLANS
- ------------------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common
stock were authorized for issuance under the Plan. On May 3, 1995, the
Company's shareholders approved and amended the Plan to increase by 250,000
shares the aggregate number of shares of common stock that could be issued
under the Plan. Under the terms of the Plan, bonuses may be granted to
employees in either cash or stock or a combination thereof, and are payable
in a lump sum or in annual installments subject to certain restrictions.
No shares were issued under the Plan in 1998, 1997 or 1996.
On December 22, 1998, the Board of Directors approved a stock bonus of
87,376 shares of common stock to be issued on January 4, 1999 for payment
of the Company's year end bonuses.
The Company also has a Stock Option Plan which provides for the
granting of options for up to 1,500,000 shares of common stock to officers
and employees. The plan permits the issuance of qualified or nonqualified
stock options. Options granted become exercisable at the rate of 20
percent per year one year after being granted and expire after ten years
from the original grant date. The exercise price for options granted to
date was based on the fair market value on the date of the grant.
46
<PAGE>
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
--------- --------
Outstanding at
January 1, 1996 865,600 $ 2.23
Granted 149,500 8.75
Exercised (371,200) 1.59
Canceled (7,100) 2.92
--------- --------
Outstanding at
December 31, 1996 636,800 4.13
Granted 24,000 9.00
Exercised (56,440) 2.71
Canceled (30,200) 7.89
--------- --------
Outstanding at
December 31, 1997 574,160 4.28
Granted 226,000 3.96
Exercised (21,300) 2.71
Canceled (10,500) 7.05
--------- --------
Outstanding at
December 31, 1998 768,360 $ 4.19
========= ========
OUTSTANDING OPTIONS
--------------------------------------
WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE
EXERCISE OF REMAINING EXERCISE
PRICES SHARES CONTRACTUAL LIFE PRICE
----------------------------------------------------------
$ 2.37 - $ 4.00 614,860 5.7 years $3.07
$ 7.25 - $11.32 153,500 8.1 years $8.67
EXERCISABLE OPTIONS
-----------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
-----------------------------------------
$ 2.37 - $ 4.00 374,660 $2.68
$ 8.00 - $11.32 52,000 $8.76
Options for 427,000, 383,000 and 375,000 shares were exercisable with
weighted average exercise prices of $3.42, $3.01 and $2.64 at December 31,
1998, 1997 and 1996, respectively.
47
<PAGE>
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued upon exercise of the stock options.
On the first business day following each annual meeting of stockholders of
the Company, each person who is then a member of the Board of Directors of
the Company and who is not then an employee of the Company or any of its
subsidiaries will be granted an option to purchase 2,500 shares of common
stock. The option price for each stock option is the fair market value of
the common stock on the date the stock options are granted. No stock
options may be exercised during the first six months of its term except in
case of death and no stock options are exercisable after ten years from the
date of grant.
Activity pertaining to the Directors' Plan is as
follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
-------- --------
Outstanding at
January 1, 1996 42,500 $ 2.96
Granted 12,500 6.88
-------- --------
Outstanding at
December 31, 1996 55,000 3.85
Granted 12,500 8.94
Exercised (7,500) 2.67
-------- --------
Outstanding at
December 31, 1997 60,000 5.06
Granted 12,500 9.00
-------- --------
Outstanding at
December 31, 1998 72,500 $ 5.74
======== ========
OUTSTANDING AND
EXERCISABLE OPTIONS
---------------------------------------
WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE
EXERCISE OF REMAINING EXERCISE
PRICES SHARES CONTRACTUAL LIFE PRICE
----------------------------------------------------------
$ 1.75 - $ 3.75 35,000 4.9 years $ 3.03
$ 6.87 - $ 9.00 37,500 8.3 years $ 8.28
48
<PAGE>
The Company applies APB Opinion 25 in accounting for its Stock Option
Plan and Non-Employee Director's Stock Option Plan. Accordingly, based on
the nature of the Company's grants of options, no compensation cost has
been recognized in 1998, 1997 and 1996. Had compensation been determined
on the basis of fair value pursuant to FASB Statement No. 123, net income
and earnings per share would have been reduced as follows:
1998 1997 1996
------- ------- -------
Net Income (In thousands):
As reported $ 2,246 $11,124 $ 8,333
======= ======= =======
Pro forma $ 1,933 $10,748 $ 8,244
======= ======= =======
Basic Earnings per Share:
As reported $ .09 $ .46 $ .37
======= ======= =======
Pro forma $ .08 $ .44 $ .37
======= ======= =======
Diluted Earnings per Share:
As reported $ .09 $ .45 $ .36
======= ======= =======
Pro forma $ .07 $ .43 $ .36
======= ======= =======
The fair value of each option granted is estimated using the Black-
Scholes model. The Company's stock volatility was 0.53, 0.52 and 0.51 in
1998, 1997 and 1996, respectively, based on previous stock performance.
Dividend yield was estimated to remain at zero with a risk free interest
rate of 4.95, 5.80 and 6.55 percent in 1998, 1997 and 1996, respectively.
Expected life ranged from 1 to 10 years based on prior experience depending
on the vesting periods involved and the make up of participating employees.
The aggregate fair value of options granted during 1998, 1997 and 1996
under the Stock Option Plan were $527,000, $136,000 and $753,000,
respectively, and under the Non-Employee Stock Option Plan were $71,000,
$74,000 and $56,000, respectively.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in
full or on a partial basis. The Company made discretionary contributions
under the plan of 46,892, 23,892 and 44,686 shares of common stock and
recognized expense of $536,000, $329,000 and $268,000 in 1998, 1997 and
1996, respectively.
49
<PAGE>
The Company provides a salary deferral plan ("Deferral Plan") which
allows participants to defer the recognition of salary for income tax
purposes until actual distribution of benefits which occurs at either
termination of employment, death or certain defined unforeseeable emergency
hardships. Funds set aside in a trust to satisfy the Company's obligation
under the Deferral Plan at December 31, 1998 and 1997 totaled $1,035,000
and $752,000, respectively. The Company recognizes payroll expense and
records a liability at the time of deferral.
Effective January 1, 1997, the Company adopted a separation benefit
plan ("Separation Plan"). The Separation Plan allows eligible employees
whose employment with the Company is involuntarily terminated or, in the
case of an employee who has completed 20 years of service, voluntarily or
involuntarily terminated, to receive benefits equivalent to 4 week's salary
for every whole year of service completed with the Company up to a maximum
of 104 weeks. Benefits received under the Separation Plan will be reduced
by the amount of any other benefits received from other disability or
severance plans which may be in effect during the payment period. To
receive payments the recipient must waive any claims against the Company
in exchange for receiving the separation benefits. On October 28, 1997,
the Company adopted a Separation Benefit Plan for Senior Management
("Senior Plan"). The Senior Plan provides certain officers and key
executives of the Company with benefits generally equivalent to the
Separation Plan. The Compensation Committee of the Board of Directors has
absolute discretion in the selection of the individuals covered in this
plan. The Company recognized expense of $577,000 and $466,000 in 1998 and
1997, respectively, for benefits associated with anticipated payments from
both separation plans.
NOTE 9 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through
1998, with a subsidiary of the Company serving as General Partner. The
Partnerships were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as co-general
partner with the Company in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with the Company in most drilling operations and most producing property
acquisitions commenced by the Company for its own account during the period
from the formation of the Partnership through December 31 of each year.
Amounts received in the years ended December 31 from both public and
private Partnerships for which the Company is a general partner are as
follows:
1998 1997 1996
-------- -------- --------
(In thousands)
Contract drilling $ 180 $ 135 $ 37
Well supervision and other fees $ 415 $ 384 $ 349
General and administrative
expense reimbursement $ 133 $ 119 $ 105
50
<PAGE>
Related party transactions for contract drilling and well supervision
fees are the related party's share of such costs. These costs are billed
to related parties on the same basis as billings to unrelated parties for
such services. General and administrative reimbursements are both direct
general and administrative expense incurred on the related party's behalf
and indirect expenses allocated to the related parties. Such allocations
are based on the related party's level of activity and are considered by
management to be reasonable.
A subsidiary of the Company paid the Partnerships, for which the
Company or a subsidiary is the general partner, $21,000, $32,000 and
$31,000 during the years ended December 31, 1998, 1997 and 1996,
respectively, for purchases of natural gas production.
During 1997 and 1996 a bank owned by one of the Company's former
Directors was a participant in the Company's Loan Agreement. The bank's
pro rata share of the Company's line of credit was limited to an amount not
to exceed $1.5 million.
NOTE 10 - SHAREHOLDER RIGHTS PLAN
- --------------------------------
The Company maintains a Shareholder Rights Plan (the "Plan") designed
to deter coercive or unfair takeover tactics, to prevent a person or group
from gaining control of the Company without offering fair value to all
shareholders and to deter other abusive takeover tactics which are not in
the best interest of shareholders.
Under the terms of the Plan, each share of common stock is accompanied
by one right, which given certain acquisition and business combination
criteria, entitles the shareholder to purchase from the Company one one-
hundredth of a newly issued share of Series A Participating Cumulative
Preferred Stock at a price subject to adjustment by the Company or to
purchase from an acquiring Company certain shares of its common stock or
the surviving company's common stock at 50 percent of its value.
The rights become exercisable 10 days after the Company learns that an
acquiring person (as defined in the Plan) has acquired 15 percent or more
of the outstanding common stock of the Company or 10 business days after
the commencement of a tender offer which would result in a person owning 15
percent or more of such shares. The Company can redeem the rights for
$0.01 per right at any date prior to the earlier of (i) the close of
business on the tenth day following the time the Company learns that a
person has become an acquiring person or (ii) May 19, 2005 (the "Expiration
Date"). The rights will expire on the Expiration Date, unless redeemed
earlier by the Company.
51
<PAGE>
NOTE 11 - COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
The Company leases office space under the terms of operating leases
expiring through January 31, 2002. Future minimum rental payments under
the terms of the leases are approximately $372,000, $104,000, $73,000 and
$7,000 in 1999, 2000, 2001 and 2002, respectively. No minimum rental
payments are due in 2003. Total rent expense incurred by the Company was
$412,000, $373,000 and $323,000 in 1998, 1997 and 1996, respectively.
The Company had letters of credit supported by its Loan Agreement
totaling $210,000 at December 31, 1998.
The Company as a 40 percent owner in a corporation which provides gas
gathering services, guarantees certain indebtedness of that corporation up
to a maximum of $2 million (approximately $950,000 at December 31, 1998).
The guarantee extends for a period ending on June 21, 2001.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership agreements along with the employee oil and gas
limited partnerships require, upon the election of a limited partner, that
the Company repurchase the limited partner's interest at amounts to be
determined by appraisal in the future. Such repurchases in any one year
are limited to 20 percent of the units outstanding. The Company made
repurchases of $15,000 and $30,000 in 1998 and 1996, respectively, for such
limited partners' interests and did not make any such repurchases in 1997.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
will result in judgements which would have a material adverse effect on the
Company.
52
<PAGE>
NOTE 12 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
In 1998, the Company adopted Statement of Financial Accounting
Standard No. 131 "Disclosures about Segments of an Enterprise and Related
Information." The Company has two business segments: Contract Drilling
and Oil and Natural Gas, representing its two strategic business units
offering different products and services. The Contract Drilling segment
provides land contract drilling of oil and natural gas wells and the Oil
and Natural Gas segment is engaged in the development, acquisition and
production of oil and natural gas properties.
The accounting policies of the segments are the same as those
described in the Summary of Significant Accounting Policies (Note 1). The
Company evaluates the performance of its operating segments based on
operating income, which is defined as operating revenues less operating
expenses and depreciation, depletion and amortization. The Company has
natural gas production in Canada which is not significant.
1998 1997 1996
--------- --------- ---------
(In thousands)
Revenues:
Contract drilling $ 53,528 $ 46,199 $ 28,819
Oil and natural gas 39,703 45,581 43,013
Other 106 84 238
--------- --------- ---------
Total revenues $ 93,337 $ 91,864 $ 72,070
========= ========= =========
Operating Income (1):
Contract drilling $ 4,033 $ 5,564 $ 1,616
Oil and natural gas 9,306 19,755 18,797
--------- --------- ---------
Total operating income 13,339 25,319 20,413
General and administrative (4,891) (4,621) (4,122)
Expense
Interest expense (4,815) (2,921) (3,162)
Other income (expense)- net 106 84 238
--------- --------- ---------
Income before income taxes $ 3,739 $ 17,861 $ 13,367
========= ========= =========
53
<PAGE>
1998 1997 1996
--------- --------- ---------
(In thousands)
Identifiable Assets (2):
Contract drilling $ 69,147 $ 66,188 $ 24,500
Oil and natural gas 150,718 132,332 110,207
--------- --------- ---------
Total identifiable assets 219,865 198,520 134,707
Corporate assets 3,199 3,977 3,286
--------- --------- ---------
Total assets $223,064 $202,497 $137,993
========= ========= =========
Capital Expenditures:
Contract drilling $ 11,485 $ 35,193 $ 9,910
Oil and natural gas 38,409 33,525 25,644
Other 216 1,464 989
--------- --------- ---------
Total capital expenditures $ 50,110 $ 70,182 $ 36,543
========= ========= =========
Depreciation, Depletion and
Amortization:
Contract drilling $ 5,766 $ 4,216 $ 2,944
Oil and natural gas 16,069 12,625 10,807
Other 351 358 328
--------- --------- ---------
Total depreciation,
depletion and amortization $ 22,186 $ 17,199 $ 14,079
========= ========= =========
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion and amortization and does not include non-operating
revenues, general corporate expenses, interest expense or income taxes.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements,
furniture and equipment.
54
<PAGE>
NOTE 13 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1998 and 1997 is as
follows:
Three Months Ended
------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- --------- --------- ------------
(In thousands except per share amounts)
Year ended December 31, 1998:
Revenues $ 24,249 $ 26,054 $ 23,627 $ 19,407
========= ========= ========= =========
Gross profit(1) $ 3,471 $ 4,450 $ 3,537 $ 1,881
========= ========= ========= =========
Income before
income taxes $ 1,163 $ 2,053 $ 1,136 $ (613)
========= ========= ========= =========
Net Income $ 725 $ 1,235 $ 654 $ (368)
========= ========= ========= =========
Earnings per common share:
Basic (2) $ .03 $ .05 $ .03 $ (.01)
========= ========= ========= =========
Diluted (2) $ .03 $ .05 $ .03 $ (.01)
========= ========= ========= =========
Year ended December 31, 1997:
Revenues $ 24,322 $ 19,806 $ 21,585 $ 26,151
========= ========= ========= =========
Gross profit(1) $ 7,970 $ 4,161 $ 5,227 $ 7,961
========= ========= ========= =========
Income before
income taxes $ 6,219 $ 2,299 $ 3,409 $ 5,934
========= ========= ========= =========
Net Income $ 3,874 $ 1,432 $ 2,121 $ 3,697
========= ========= ========= =========
Earnings per common share:
Basic $ .16 $ .06 $ .09 $ .15
========= ========= ========= =========
Diluted (2) $ .16 $ .06 $ .09 $ .15
========= ========= ========= =========
(1) Gross profit excludes other revenues, general and administrative
expense and interest expense.
55
<PAGE>
(2) Due to the effect of price changes of the Company's stock, diluted
earnings per share for the year's four quarters, which includes the
effect of potential dilutive common shares calculated during each
quarter, does not equal the annual diluted earnings per share, which
includes the effect of such potential dilutive common shares calculated
for the entire year.
NOTE 14 - 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)
1998:
Capitalized costs:
Proved properties $ 261,299 $ 480 $ 261,779
Unproved properties 9,900 281 10,181
---------- -------- ----------
271,199 761 271,960
Less accumulated depreciation,
depletion, amortization
and impairment (130,894) (412) (131,306)
---------- -------- ----------
Net capitalized costs $ 140,305 $ 349 $ 140,654
========== ======== ==========
Cost incurred:
Unproved properties $ 4,297 $ 203 $ 4,500
Producing properties 9,026 - 9,026
Exploration 2,270 - 2,270
Development 22,613 - 22,613
---------- -------- ----------
Total costs incurred $ 38,206 $ 203 $ 38,409
========== ======== ==========
1997:
Capitalized costs:
Proved properties $ 225,166 $ 480 $ 225,646
Unproved properties 7,935 78 8,013
---------- -------- ----------
233,101 558 233,659
Accumulated depreciation,
depletion, amortization
and impairment (115,000) (405) (115,405)
---------- -------- ----------
Net capitalized costs $ 118,101 $ 153 $ 118,254
========== ======== ==========
Cost incurred:
Unproved properties $ 3,540 $ 78 $ 3,618
Producing properties 1,518 - 1,518
Exploration 1,785 - 1,785
Development 26,604 - 26,604
---------- -------- ----------
Total costs incurred $ 33,447 $ 78 $ 33,525
========== ======== ==========
56
<PAGE>
USA CANADA TOTAL
---------- --------- ----------
(In thousands)
1996:
Capitalized costs:
Proved properties $ 195,528 $ 480 $ 196,008
Unproved properties 4,602 - 4,602
---------- --------- ----------
200,130 480 200,610
Less accumulated depreciation,
depletion, amortization
and impairment (102,463) (389) (102,852)
---------- --------- ----------
Net capitalized costs $ 97,667 $ 91 $ 97,758
========== ========= ==========
Cost incurred:
Unproved properties $ 1,640 $ - $ 1,640
Producing properties 2,338 - 2,338
Exploration 1,501 - 1,501
Development 20,150 15 20,165
---------- --------- ----------
Total costs incurred $ 25,629 $ 15 $ 25,644
========== ========= ==========
57
<PAGE>
The results of operations for producing activities are provided below.
USA CANADA TOTAL
--------- -------- ---------
(In thousands)
1998:
Revenues $ 36,861 $ 55 $ 36,916
Production costs (11,572) (20) (11,592)
Depreciation, depletion
and amortization (15,893) (8) (15,901)
--------- -------- ---------
9,396 27 9,423
Income tax expense (3,752) (9) (3,761)
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 5,644 $ 18 $ 5,662
========= ======== =========
1997:
Revenues $ 42,830 $ 69 $ 42,899
Production costs (10,678) (24) (10,702)
Depreciation, depletion
and amortization (12,537) (16) (12,553)
--------- -------- ---------
19,615 29 19,644
Income tax expense (7,394) (17) (7,411)
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 12,221 $ 12 $ 12,233
========= ======== =========
1996:
Revenues $ 40,432 $ 60 $ 40,492
Production costs (11,195) (14) (11,209)
Depreciation, depletion
and amortization (10,723) (11) (10,734)
--------- -------- ---------
18,514 35 18,549
Income tax expense (6,986) (15) (7,001)
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 11,528 $ 20 $ 11,548
========= ======== =========
58
<PAGE>
Estimated quantities of proved developed oil and natural gas reserves
and changes in net quantities of proved developed and undeveloped oil and
natural gas reserves were as follows:
USA CANADA TOTAL
---------------- --------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- ------- ------- --------
(In thousands)
1998:
Proved developed and
undeveloped reserves:
Beginning of year 4,131 144,661 - 723 4,131 145,384
Revision of previous
estimates (1,142) (5,207) - (162) (1,142) (5,369)
Extensions, discoveries
and other additions 445 31,460 - - 445 31,460
Purchases of minerals
in place 257 6,840 - - 257 6,840
Sales of minerals in
place (3) (532) - - (3) (532)
Production (443) (16,427) - (38) (443) (16,465)
------- -------- ----- ----- ------- --------
End of Year 3,245 160,795 - 523 3,245 161,318
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,406 115,071 - 295 3,406 115,366
End of year 2,365 119,415 - 421 2,365 119,836
1997:
Proved developed and
undeveloped reserves:
Beginning of year 5,204 128,408 - 753 5,204 129,161
Revision of previous
estimates (927) (12,780) - 44 (927) (12,736)
Extensions, discoveries
and other additions 399 41,108 - - 399 41,108
Purchases of minerals
in place 6 2,618 - - 6 2,618
Sales of minerals in
place (58) (951) - - (58) (951)
Production (493) (13,742) - (74) (493) (13,816)
------- -------- ----- ----- ------- --------
End of Year 4,131 144,661 - 723 4,131 145,384
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 4,509 107,536 - 326 4,509 107,862
End of year 3,406 115,071 - 295 3,406 115,366
59
<PAGE>
USA CANADA TOTAL
---------------- --------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- ------- ------- --------
(In thousands)
1996:
Proved developed and
undeveloped reserves:
Beginning of year 5,428 107,950 - 778 5,428 108,728
Revision of previous
estimates (387) (3,822) - 26 (387) (3,796)
Extensions, discoveries
and other additions 718 34,625 - - 718 34,625
Purchases of minerals
in place 67 3,036 - - 67 3,036
Sales of minerals
in place (43) (407) - - (43) (407)
Production (579) (12,974) - (51) (579) (13,025)
------- -------- ----- ----- ------- --------
End of Year 5,204 128,408 - 753 5,204 129,161
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 4,697 94,975 - 350 4,697 95,325
End of year 4,509 107,536 - 326 4,509 107,862
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made
in connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's
reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog-
ical and engineering data, appear with reasonable certainty to be recov-
erable in the future from known oil and natural gas reservoirs under exist-
ing economic and operating conditions. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods. Proved undeveloped reserves are
those reserves which are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expendi-
ture is required.
Estimates of oil and natural gas reserves require extensive judgments
of reservoir engineering data as previously explained. Assigning monetary
values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. Indeed the uncertainties inherent in the
disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves. The information set forth herein is therefore
subjective and, since judgments are involved, may not be comparable to
estimates submitted by other oil and natural gas producers. In addition,
since prices and costs do not remain static and no price or cost escala-
60
<PAGE>
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.
The standardized measure of discounted future net cash flows ("SMOG")
was calculated using year-end prices and costs, and year-end statutory tax
rates, adjusted for permanent differences, that relate to existing proved
oil and natural gas reserves. SMOG as of December 31 is as follows:
USA CANADA TOTAL
---------- -------- ----------
(In thousands)
1998:
Future cash flows $ 388,887 $ 1,089 $ 389,976
Future production and
development costs (154,843) (271) (155,114)
Future income tax expenses (47,305) (160) (47,465)
---------- -------- ----------
Future net cash flows 186,739 658 187,397
10% annual discount for
estimated timing of cash flows (62,770) (259) (63,029)
---------- -------- ----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 123,969 $ 399 $ 124,368
========== ======== ==========
1997:
Future cash flows $ 427,292 $ 1,684 $ 428,976
Future production and
development costs (153,220) (312) (153,532)
Future income tax expenses (63,868) (794) (64,662)
---------- -------- ----------
Future net cash flows 210,204 578 210,782
10% annual discount for
estimated timing of cash flows (71,768) (187) (71,955)
---------- -------- ----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 138,436 $ 391 $ 138,827
========== ======== ==========
61
<PAGE>
USA CANADA TOTAL
---------- -------- ----------
(In thousands)
1996:
Future cash flows $ 626,945 $ 2,735 $ 629,680
Future production and
development costs (171,749) (339) (172,088)
Future income tax expenses (125,540) (1,422) (126,962)
---------- -------- ----------
Future net cash flows 329,656 974 330,630
10% annual discount for
estimated timing of cash flows (129,610) (368) (129,978)
---------- -------- ----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 200,046 $ 606 $ 200,652
========== ======== ==========
62
<PAGE>
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
---------- -------- ----------
(In thousands)
1998:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (25,289) $ (35) $ (25,324)
Net changes in prices and
production costs (35,654) (186) (35,840)
Revisions in quantity estimates
and changes in production timing (17,020) (335) (17,355)
Extensions, discoveries and improved
recovery, less related costs 24,256 - 24,256
Purchases of minerals in place 6,062 - 6,062
Sales of minerals in place (603) - (603)
Accretion of discount 16,719 91 16,810
Net change in income taxes 16,083 486 16,569
Other - net 979 (13) 966
---------- -------- ----------
Net change (14,467) 8 (14,459)
Beginning of year 138,436 391 138,827
---------- -------- ----------
End of year $ 123,969 $ 399 $ 124,368
========== ======== ==========
1997:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (32,152) $ (45) $ (32,197)
Net changes in prices and
production costs (111,745) (651) (112,396)
Revisions in quantity estimates
and changes in production timing (19,377) 47 (19,330)
Extensions, discoveries and improved
recovery, less related costs 46,787 - 46,787
Purchases of minerals in place 2,235 - 2,235
Sales of minerals in place (2,282) - (2,282)
Accretion of discount 26,227 147 26,374
Net change in income taxes 33,473 345 33,818
Other - net (4,776) (58) (4,834)
---------- -------- ----------
Net change (61,610) (215) (61,825)
Beginning of year 200,046 606 200,652
---------- -------- ----------
End of year $ 138,436 $ 391 $ 138,827
========== ======== ==========
63
<PAGE>
USA CANADA TOTAL
---------- -------- ----------
(In thousands)
1996:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (29,237) $ (46) $ (29,283)
Net changes in prices and
production costs 92,541 738 93,279
Revisions in quantity estimates
and changes in production timing (13,390) 58 (13,332)
Extensions, discoveries and improved
recovery, less related costs 69,942 - 69,942
Purchases of minerals in place 5,821 - 5,821
Sales of minerals in place (514) - (514)
Accretion of discount 12,101 71 12,172
Net change in income taxes (44,039) (470) (44,509)
Other - net 3,998 (60) 3,938
---------- -------- ----------
Net change 97,223 291 97,514
Beginning of year 102,823 315 103,138
---------- -------- ----------
End of year $ 200,046 $ 606 $ 200,652
========== ======== ==========
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.
64
<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.
In early 1999, the oil and natural gas industry has experienced a
downturn in natural gas prices. The Company's reserves were determined at
December 31, 1998 using an oil and natural gas price of $11.10 per barrel
and $2.08 per Mcf. During February 1999, the oil and natural gas prices
received by the Company were approximately $11.62 and $1.74, respectively.
The decreases in natural gas prices would have a significant effect on the
SMOG value of the Company's reserves at December 31, 1998 and would result
in a provision to reduce the carrying value of oil and natural gas
properties of approximately $22 million before taxes.
65
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
In our opinion, the accompanying consolidated balance sheet and the
related consolidated statements of operations, stockholders' equity and
cash flows present fairly in all material respects, the financial position
of Unit Corporation and its subsidiaries at December 31, 1998 and 1997, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles. In addition, in our opinion, the
accompanying financial statement schedule presents fairly, in all material
respects, the information set forth therein when read in conjunction with
the related consolidated financial statements. These financial statements
and financial statement schedule are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits. We
conducted our audits of these financial statements in accordance with
generally accepted auditing standards which require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 23, 1999
66
<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 71 Chairman of the Board, Chief Executive
Officer and Director
John G. Nikkel 64 President, Chief Operating Officer and
Director
Earle Lamborn 64 Senior Vice President, Drilling and
Director
Philip M. Keeley 57 Senior Vice President, Exploration and
Production
Larry D. Pinkston 44 Vice President, Treasurer and Chief
Financial Officer
Mark E. Schell 41 General Counsel and Secretary
________
Mr. Kirchner, a co-founder of the Company, has been the Chairman of
the Board and a director since 1963 and was President until November 1983.
Mr. Kirchner is a Registered Professional Engineer within the State of
Oklahoma, having received degrees in Mechanical Engineering from Oklahoma
State University and in Petroleum Engineering from the University of
Oklahoma.
Mr. Nikkel joined the Company in 1983 as its President and a director.
From 1976 until January 1982 when he co-founded Nike Exploration Company,
Mr. Nikkel was an officer and director of Cotton Petroleum Corporation,
serving as the President of that Company from 1979 until his departure.
Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production
Company for 18 years, last serving as Division Geologist for Amoco's Denver
Division. Mr. Nikkel presently serves as President and a director of Nike
Exploration Company. Mr. Nikkel received a Bachelor of Science degree in
Geology and Mathematics from Texas Christian University.
67
<PAGE>
Mr. Lamborn has been actively involved in the oil field for over 45
years, joining the Company's predecessor in 1952 prior to it becoming a
publicly-held corporation. He was elected Vice President, Drilling in 1973
and to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice
President, Exploration and Production. Prior to that time, Mr. Keeley co-
founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and
serves as Executive Vice President and a director of that company. From
1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation,
serving first as Manager of Land and from 1979 as Vice President and a
director. Before joining Cotton, Mr. Keeley was employed for four years by
Apexco, Inc. as Manager of Land and prior thereto he was employed by
Texaco, Inc. for nine years. He received a Bachelor of Arts degree in
Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as
Corporate Budget Director and Assistant Controller prior to being appointed
as Controller in February 1985. He has been Treasurer since December 1986
and was elected to the position of Vice President and Chief Financial
Officer in May 1989. He holds a Bachelor of Science Degree in Accounting
from East Central University of Oklahoma and is a Certified Public
Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and
General Counsel. From 1979 until joining the Company, Mr. Schell was
Counsel, Vice President and a member of the Board of Directors of C & S
Exploration, Inc. He received a Bachelor of Science degree in Political
Science from Arizona State University and his Juris Doctorate degree from
the University of Tulsa Law School. He is a member of the Oklahoma and
American Bar Association as well as being a member of the American
Corporate Counsel Association and the American Society of Corporate
Secretaries.
The balance of the information required in this Item 10 is incorpo-
rated by reference from the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1999
annual meeting of stockholders.
Item 11. Executive Compensation
- ---------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1999 annual meeting of
stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1999 annual meeting of
stockholders.
68
<PAGE>
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1999 annual meeting of
stockholders.
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, 1998 and 1997
Consolidated Statements of Operations for the years ended December
31, 1998, 1997 and 1996
Consolidated Statements of Changes in Shareholders' Equity for the
years ended December 31, 1998, 1997 and 1996
Consolidated Statements of Cash Flows for the years ended December
31, 1998, 1997 and 1996
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, 1998,
1997 and 1996:
Schedule II - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under
which they are required or because the required information is included
in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers
assigned such exhibits in the Exhibit Table of Item 601 of Regulation
S-K.
3. Exhibits:
---------
2 Certificate of Ownership and Merger of the Company and Unit
Drilling Co., dated February 22, 1979 (filed as an Exhibit to
the Company's Registration Statement No. 2-63702, which is
incorporated herein by reference).
2.1 Agreement and Plan of Merger dated November 21, 1997, by and
among the Registrant, Unit Drilling Company, the Shareholders
and Hickman Drilling Company (filed as an Exhibit to the
Company's Form 8-K dated November 21, 1997, which is
incorporated herein by reference).
69
<PAGE>
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).
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).
4.1 Form of Promissory Note to be issued to the Shareholders of
Hickman Drilling Company pursuant to the Agreement and Plan of
Merger dated November 21, 1997 (filed as an Exhibit to the
Company's Form 8-K dated November 21, 1997, which is
incorporated herein by reference).
4.2.1 Form of Warrant Agreement between the Company and the Warrant
Agent (filed as Exhibit 4.1 to the Company's Registration
statement on Form S-2 as S.E.C. File No. 33-16116, which is
incorporated herein by reference).
4.2.2 Form of Warrant (filed as Exhibit 4.3 to the Company's
Registration Statement of Form S-2 as S.E.C. File No. 33-
16116, which is incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.2 on Form
S-2 as S.E.C. File No. 33-16116, which is incorporated herein
by reference).
4.2.4 First Amendment to Warrant Agreement (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1992, which is incorporated herein
by reference).
4.2.5 Second Amendment to Warrant Agreement (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1994, which is incorporated herein
by reference).
4.2.6 Rights Agreement dated as of May 19, 1995 between the Company
and Chemical Bank, as Rights Agent (filed as Exhibit 1 to the
Company's Form 8-A filed May 23, 1995, File No. 1-92601 and
incorporated herein by reference).
70
<PAGE>
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).
10.1.17 Second Amendment to Amended and Restated Credit Agreement, dated
March 3, 1993 and effective as of March 1, 1993, by and
between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank
and Trust Company, Fourth National Bank of Tulsa, and Western
National Bank of Tulsa (filed as an Exhibit to the Company's
Quarterly Report under cover of Form 10-Q for the quarter
ended March 31, 1993, which is incorporated herein by
reference).
10.1.18 Third Amendment to Amended and Restated Credit Agreement
effective as of March 31, 1994, by and between Unit
Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust
Company, Bank IV, Oklahoma, N.A. and American National Bank
and Trust Company of Shawnee (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the
quarter ended March 31, 1994, which is incorporated herein by
reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement dated
as of December 12, 1994, by and between Unit Corporation
and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank
IV, Oklahoma, N.A. and American National Bank and Trust
Company of Shawnee (filed as an Exhibit in Form 8-K dated
December 15, 1994, which is incorporated herein by reference).
10.1.20 Loan Agreement dated August 3, 1995 (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended June 30, 1995, which is incorporated herein
by reference).
10.1.21 First Amendment to the Loan Agreement effective as of
September 4, 1996, by and between Unit Corporation and Bank of
Oklahoma, N.A., The First National Bank of Boston, Bank IV
Oklahoma, N.A. and American National Bank and Trust Company of
Shawnee (filed as an Exhibit to the Company's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1996, which is incorporated herein by reference).
71
<PAGE>
10.1.22 Second Amendment to the Loan Agreement effective as of December
16, 1996 by and between Unit Corporation and Bank of Oklahoma,
N.A., The First National Bank of Boston, Boatman's
National Bank of Oklahoma and American National Bank and Trust
Company of Shawnee (filed herewith).
10.1.23 Loan Agreement dated April 30, 1998 (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended June 30, 1998, 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).
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).
72
<PAGE>
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 Amended and Restated Stock Option Plan (filed as
an Exhibit to the Company's Registration Statement on Form S-8
as S.E.C. File No's. 33-19652, 33-44103 and 33-64323 which is
incorporated herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan (filed
as an Exhibit to Form S-8 as S.E.C. File No. 33-49724,
which is incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed as an Exhibit to
Form S-8 as S.E.C. File No. 33-53542, which is incorporated
herein by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1993,
which is incorporated herein by reference).
10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to
the Company's Annual Report under cover of Form 10-K for the
year ended December 31, 1993, which is incorporated herein by
reference).
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report, under cover of Form 10-K for the year ended
December 31, 1994, which is incorporated herein by reference).
10.2.29 Unit 1996 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the
Company's Annual Report under cover of Form 10-K for the year
ended December 31, 1995, which is incorporated herein by
reference).
73
<PAGE>
10.2.30* Separation Benefit Plan of Unit Corporation and Participating
Subsidiaries (filed as an Exhibit to the Company's Annual
Report under the cover of Form 10-K for the year ended
December 31, 1996).
10.2.31 Unit 1997 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under the cover of Form 10-K for the year ended
December 31, 1996).
10.2.32 Unit Corporation Separation Benefit Plan for Senior
Management(filed as an Exhibit to the Company's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1997, which is incorporated herein by
reference).
10.2.33 Unit 1998 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under the cover of Form 10-K for the year ended
December 31, 1997).
10.2.34 Unit 1999 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed herewith).
10.5 Acquisition and Development Agreement, dated September 26, 1991,
between Registrant and Municipal Energy Agency of
Nebraska (filed as an Exhibit to Form 8-K dated September 30,
1991, which is incorporated herein by reference).
10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco
Exploration, Inc. and Aleco Production Company (as "Seller")
and Unit Petroleum Company (a "Buyer") and Helmerich & Payne,
Inc. (a "Buyer") (filed as an Exhibit to Form 8-K dated May
21, 1992, which is incorporated herein by reference).
10.7 Asset Purchase Agreement, dated as of November 28, 1994, between
the Registrant and Patrick Petroleum Corp of Michigan
and American National Petroleum Company (filed as an Exhibit
to Form 8-K dated December 15, 1994, which is incorporated
herein by reference).
21 Subsidiaries of the Registrant (filed herewith).
23 Consent of Independent Accountants (filed herewith).
27 Financial Data Schedules (filed herewith).
* Indicates a management contract or compensatory plan identified
pursuant to the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
No reports under Form 8-K were filed during the quarter ended
December 31, 1998.
74
<PAGE>
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance
Balance at charged to Deductions at
beginning costs & & net end of
Description of period expenses write-offs period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1998 $ 354 $ - $ 80 $ 274
======== ======== ======== ========
Year ended
December 31, 1997 $ 104 $ 250 $ - $ 354
======== ======== ======== ========
Year ended
December 31, 1996 $ 116 $ - $ 12 $ 104
======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance
Balance at at
beginning end of
Description of period Additions Deductions period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1998 $ 1,552 $ - $ 1,022 $ 530
======== ======== ======== ========
Year ended
December 31, 1997 $ 3,530 $ - $ 1,978 $ 1,552
======== ======== ======== ========
Year ended
December 31, 1996 $ 3,530 $ - $ - $ 3,530
======== ======== ======== ========
75
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 17, 1999 By: /s/ John G. Nikkel
-------------- ---------------------------
JOHN G. NIKKEL
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities indicated on the 17th day of March, 1997.
Name Title
/s/ King P. Kirchner
- ------------------------------- Chairman of the Board and Chief
KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel
- ------------------------------- President and Chief Operating
JOHN G. NIKKEL Officer, Director
/s/ Earle Lamborn
- ------------------------------- Senior Vice President, Drilling,
EARLE 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/ J. Michael Adcock
- ------------------------------- Director
J. MICHAEL ADCOCK
/s/ Don Cook
- ------------------------------- Director
DON COOK
/s/ William B. Morgan
- ------------------------------- Director
WILLIAM B. MORGAN
/s/ John S. Zink
- ------------------------------- Director
JOHN S. ZINK
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
76
<PAGE>
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
------ ----------------------------------------------- -----
10.2.34 Unit 1999 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
27 Financial Data Schedules.
77
<PAGE>
CONFIDENTIAL
For Private Placement Purposes Only Copy No.
_________________
UNIT 1999 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
1000 Kensington Tower I
7130 South Lewis
Tulsa, Oklahoma 74136
(918) 493-7700
A PRIVATE OFFERING
OF
UNITS OF LIMITED PARTNERSHIP INTEREST
_____________________________________
THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURITIES
ACT OF 1933, AS AMENDED, OR UNDER APPLICABLE STATE SECURITIES ACTS IN
RELIANCE ON EXEMPTIONS PROVIDED BY SUCH ACTS. THESE SECURITIES MAY NOT
BE SOLD OR TRANSFERRED IN THE ABSENCE OF AN EFFECTIVE REGISTRATION UNDER
SUCH ACTS OR AN OPINION OF COUNSEL ACCEPTABLE TO THE GENERAL PARTNER
THAT SUCH REGISTRATION IS NOT REQUIRED. FURTHER, THE RESALE OF A UNIT MAY
RESULT IN SUBSTANTIAL TAX LIABILITY TO THE INVESTOR. SEE "FEDERAL INCOME
TAX CONSIDERATIONS." ACCORDINGLY, THESE UNITS SHOULD BE CONSIDERED ONLY
FOR LONG-TERM INVESTMENT. SEE "PLAN OF DISTRIBUTION -- SUITABILITY OF
INVESTORS."
_____________________________________
THE INFORMATION CONTAINED IN THIS PRIVATE OFFERING
MEMORANDUM IS PROVIDED BY THE GENERAL PARTNER SOLELY FOR THE PERSONS
RECEIVING IT FROM THE GENERAL PARTNER AND ANY REPRODUCTION OR
DISTRIBUTION OF THIS PRIVATE OFFERING MEMORANDUM, IN WHOLE OR IN PART, OR
THE DIVULGENCE OF ANY OF ITS CONTENTS IS PROHIBITED AND MAY CONSTITUTE A
VIOLATION OF CERTAIN STATE SECURITIES LAWS. THE OFFEREE, BY ACCEPTING
DELIVERY OF THIS PRIVATE OFFERING MEMORANDUM, AGREES TO RETURN IT AND
ALL ENCLOSED DOCUMENTS TO THE GENERAL PARTNER IF THE OFFEREE DOES NOT
UNDERTAKE TO PURCHASE ANY OF THE UNITS OFFERED HEREBY.
_____________________________________
Private Offering Memorandum Date January 6, 1999
(i)
<PAGE>
600 Preformation
Units of Limited Partnership Interest
in the
UNIT 1999 EMPLOYEE
OIL AND GAS LIMITED PARTNERSHIP
_____________________________________
$1,000 Per Unit Plus Possible
Additional Assessments of $100 Per Unit
(Minimum Investment - 2 Units)
Minimum Aggregate Subscriptions Necessary
to Form Partnership - 50 Units
_____________________________________
A maximum of 600 (minimum of 50) units of limited partnership interest
("Units") in the UNIT 1999 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.
(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 adjustment to their reported tax
liabilities; and
. Limited Partners will not benefit from their shares of
Partnership deductions 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 Amended and Restated Stock Option Plan and related
prospectuses covering shares of Common Stock issuable upon exercise
of outstanding options.
5. UNIT's Non Employee Directors' Stock Option Plan.
6. The Credit Agreement and the notes payable of UNIT.
7. All periodic reports on Forms 10-K, 10-Q and 8-K and all proxy
materials filed by or on behalf of UNIT with the Securities and
Exchange Commission pursuant to the Securities Exchange Act of 1934,
as amended, during calendar year 1998, the annual report to
shareholders and all quarterly reports to shareholders submitted by
UNIT to its shareholders during calendar year 1998.
8. The agreements of limited partnership for the prior oil and gas
drilling programs and prior employee programs of Unit Petroleum
Company, UNIT and Unit Drilling and Exploration Company ("UDEC").
9. All periodic reports filed with the Securities and Exchange
Commission and all reports and information provided to limited
partners in all limited partnerships of which Unit Petroleum Company,
UNIT or UDEC now serves or has served in the past as a general
partner.
10. The agreement of limited partnership for the Unit 1986 Energy Income
Limited Partnership.
(v)
<PAGE>
SUMMARY OF CONTENTS
Page
SUMMARY OF PROGRAM. . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Terms of the Offering . . . . . . . . . . . . . . . . . . . . . . . .1
Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . .2
Additional Financing. . . . . . . . . . . . . . . . . . . . . . . . .4
Proposed Activities . . . . . . . . . . . . . . . . . . . . . . . . .5
Application of Proceeds . . . . . . . . . . . . . . . . . . . . . . .5
Participation in Costs and Revenues . . . . . . . . . . . . . . . . .6
Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . .7
Federal Income Tax Considerations; Opinion of Counsel . . . . . . . .7
RISK FACTORS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8
INVESTMENT RISKS. . . . . . . . . . . . . . . . . . . . . . . . . . .8
TAX STATUS AND TAX RISKS. . . . . . . . . . . . . . . . . . . . . . 14
OPERATIONAL RISKS . . . . . . . . . . . . . . . . . . . . . . . . . 16
TERMS OF THE OFFERING . . . . . . . . . . . . . . . . . . . . . . . . . . 18
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Limited Partnership Interests . . . . . . . . . . . . . . . . . . . 18
Subscription Rights . . . . . . . . . . . . . . . . . . . . . . . . 19
Payment for Units; Delinquent Installment . . . . . . . . . . . . . 20
Right of Presentment. . . . . . . . . . . . . . . . . . . . . . . . 21
Rollup or Consolidation of Partnership. . . . . . . . . . . . . . . 23
ADDITIONAL FINANCING. . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Additional Assessments. . . . . . . . . . . . . . . . . . . . . . . 23
Prior Programs. . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Partnership Borrowings. . . . . . . . . . . . . . . . . . . . . . . 24
PLAN OF DISTRIBUTION. . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Suitability of Investors. . . . . . . . . . . . . . . . . . . . . . 25
RELATIONSHIP OF THE PARTNERSHIP,
THE GENERAL PARTNER AND AFFILIATES. . . . . . . . . . . . . . . . . 26
PROPOSED ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Partnership Objectives. . . . . . . . . . . . . . . . . . . . . . . 29
Areas of Interest . . . . . . . . . . . . . . . . . . . . . . . . . 29
Transfer of Properties. . . . . . . . . . . . . . . . . . . . . . . 29
Record Title to Partnership Properties. . . . . . . . . . . . . . . 30
Marketing of Reserves . . . . . . . . . . . . . . . . . . . . . . . 30
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . 31
APPLICATION OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . 31
(vi)
<PAGE>
PARTICIPATION IN COSTS AND REVENUES . . . . . . . . . . . . . . . . . . . 32
COMPENSATION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Supervision of Operations . . . . . . . . . . . . . . . . . . . . . 33
Purchase of Equipment and Provision of Services . . . . . . . . . . 34
Prior Programs. . . . . . . . . . . . . . . . . . . . . . . . . . . 35
MANAGEMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
The General Partner . . . . . . . . . . . . . . . . . . . . . . . . 36
Officers, Directors and Key Employees . . . . . . . . . . . . . . . 37
Prior Employee Programs . . . . . . . . . . . . . . . . . . . . . . 39
Ownership of Common Stock . . . . . . . . . . . . . . . . . . . . . 41
Interest of Management in Certain Transactions . . . . . . . . . . 43
CONFLICTS OF INTEREST . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Acquisition of Properties and Drilling Operations . . . . . . . . . 43
Participation in UNIT's Drilling or Income Programs . . . . . . . . 45
Transfer of Properties. . . . . . . . . . . . . . . . . . . . . . . 45
Partnership Assets. . . . . . . . . . . . . . . . . . . . . . . . . 46
Transactions with the General Partner or Affiliates . . . . . . . . 46
Right of Presentment Price Determination. . . . . . . . . . . . . . 47
Receipt of Compensation Regardless of Profitability . . . . . . . . 47
Legal Counsel . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
FIDUCIARY RESPONSIBILITY. . . . . . . . . . . . . . . . . . . . . . . . . 47
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Liability and Indemnification . . . . . . . . . . . . . . . . . . . 48
PRIOR ACTIVITIES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Prior Employee Programs . . . . . . . . . . . . . . . . . . . . . . 53
Results of the Prior Oil and Gas Programs . . . . . . . . . . . . . 54
FEDERAL INCOME TAX CONSIDERATIONS . . . . . . . . . . . . . . . . . . . . 65
Summary of Conclusions. . . . . . . . . . . . . . . . . . . . . . . 65
General Tax Effects of Partnership Structure. . . . . . . . . . . . 68
Ownership of Partnership Properties . . . . . . . . . . . . . . . . 69
Intangible Drilling and Development Costs Deductions. . . . . . . . 70
Depletion Deductions. . . . . . . . . . . . . . . . . . . . . . . . 71
Depreciation Deductions . . . . . . . . . . . . . . . . . . . . . . 72
Interest Deductions . . . . . . . . . . . . . . . . . . . . . . . . 72
Transaction Fees. . . . . . . . . . . . . . . . . . . . . . . . . . 72
Basis and At Risk Limitations . . . . . . . . . . . . . . . . . . . 73
Passive Loss Limitations. . . . . . . . . . . . . . . . . . . . . . 73
Alternative Minimum Tax . . . . . . . . . . . . . . . . . . . . . . 74
Gain or Loss on Sale of Property or Units . . . . . . . . . . . . . 74
Partnership Distributions . . . . . . . . . . . . . . . . . . . . . 75
Partnership Allocations . . . . . . . . . . . . . . . . . . . . . . 76
(vii)
<PAGE>
Profit Motive . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
Administrative Matters. . . . . . . . . . . . . . . . . . . . . . . 76
Accounting Methods and Periods. . . . . . . . . . . . . . . . . . . 78
State and Local Taxes . . . . . . . . . . . . . . . . . . . . . . . 78
Individual Tax Advice Should Be Sought. . . . . . . . . . . . . . . 78
COMPETITION, MARKETS AND REGULATION . . . . . . . . . . . . . . . . . . . 78
Marketing of Production . . . . . . . . . . . . . . . . . . . . . . 78
Regulation of Partnership Operations. . . . . . . . . . . . . . . . 79
Natural Gas Price Regulation . . . . . . . . . . . . . . . . . . . 80
Oil Price Regulation. . . . . . . . . . . . . . . . . . . . . . . . 84
State Regulation of Oil and Gas Production. . . . . . . . . . . . . 84
Legislative and Regulatory Production and Pricing Proposals . . . . 85
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
Limited Liability . . . . . . . . . . . . . . . . . . . . . . . . 88
Records, Reports and Returns . . . . . . . . . . . . . . . . . . . 89
Transferability of Interests . . . . . . . . . . . . . . . . . . . 90
Amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
Voting Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
Exculpation and Indemnification of the General Partner. . . . . . . 93
Termination . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
COUNSEL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
GLOSSARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
FINANCIAL STATEMENTS. . . . . . . . . . . . . . . . . . . . . . . . . . . 98
EXHIBIT A - AGREEMENT OF LIMITED PARTNERSHIP
EXHIBIT B - LEGAL OPINION
(viii)
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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 1999 Employee Oil and Gas Limited
Partnership, a proposed Oklahoma limited partnership (the "Partnership"), hereby
offers 600 preformation units of limited partnership interest ("Units") in the
Partnership. The offer is made only to certain employees of Unit Corporation
("UNIT") and its subsidiaries and directors of UNIT (see "TERMS OF THE OFFERING
- - Subscription Rights"). Unless the context otherwise requires, all references
in this Memorandum to UNIT shall include all or any of its subsidiaries. Unit
Petroleum Company ("UPC" or the "General Partner"), a wholly owned subsidiary of
UNIT, will serve as General Partner of the Partnership.
To invest in the Units, the Limited Partner Subscription Agreement and
Suitability Statement (the "Subscription Agreement") (see Attachment I to
Exhibit A hereto) must be executed and forwarded to the offices of the General
Partner at its address listed on the cover of this Memorandum. The Subscription
Agreement must be received by the General Partner not later than 5:00 P.M.
Central Standard Time on February 5, 1999 (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, 1999 and the
remaining three of such Installments being due on June 15, 1999, September 15,
1999 and December 15, 1999, respectively, or (ii) through equal deductions from
1999 salary commencing immediately after formation of the Partnership.
The purchase price of each Unit is $1,000, and the minimum permissible
purchase is two Units ($2,000) for each subscriber. Additional Assessments of
up to $100 per Unit may be required (see "ADDITIONAL FINANCING - Additional
Assessments"). Maximum purchases by employees (other than directors) will be
for an amount equal to one-half of their base salaries for calendar year 1999.
Each member of the Board of Directors of UNIT may subscribe for up to 200 Units
($200,000). The Partnership must sell at least 50 Units ($50,000) before the
Partnership will be formed. No Units will be offered for sale after the
Effective Date (see "GLOSSARY") except upon compliance with the provisions of
Article XIII of the Agreement. The General Partner may, at its option, purchase
Units as a Limited Partner, including any amount that may be necessary to meet
the minimum number of Units required for formation of the Partnership. The
Partnership will terminate on December 31, 2029, unless it is terminated earlier
pursuant to the provisions of the Agreement or by operation of law. See "TERMS
OF THE OFFERING - Limited Partnership Interests"; "TERMS OF THE OFFERING -
Subscription Rights"; and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
Termination."
Units will be offered only to those qualified employees of UNIT or any of
its subsidiaries at the date of formation of the Partnership whose annual base
salaries for 1999 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
1
<PAGE>
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 1998 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 1998.
Directors' subscriptions may not be for more than 200 Units ($200,000). Only
employees and directors who are U.S. citizens are eligible to participate in
the offering. In addition, employees and directors must be able to bear the
economic risks of an investment in the Partnership and must have sufficient
investment experience and expertise to evaluate the risks and merits of such an
investment. See "TERMS OF THE OFFERING -Subscription Rights."
Right of Presentment. After December 31, 2000 and annually thereafter, the
Limited Partners will have the right to present their Units to the General
Partner for purchase. The General Partner will not be obligated to purchase
more than 20% of the then outstanding Units in any one calendar year. The
purchase price to be paid for the Units will be determined by a specific
valuation formula. See "TERMS OF THE OFFERING - Right of Presentment" for a
description of the valuation formula and a discussion of the manner in which the
right of presentment may be exercised by the Limited Partners.
Risk Factors
An investment in the Partnership has many risks. The "RISK FACTORS"
section of this Memorandum contains a detailed discussion of the most important
risks, organized into Investment Risks (the risks related to the Partnership's
investment in oil and gas properties and drilling activities, to an investment
in the Partnership and to the provisions of the Agreement); Tax Risks (the risks
arising from the tax laws as they apply to the Partnership and its investment in
oil and gas properties and drilling activities); and Operational Risks (the
risks involved in conducting oil and gas operations). The following are certain
of the risks which are more fully described under "RISK FACTORS". Each
prospective investor should review the "RISK FACTORS" section carefully before
deciding to subscribe for Units.
Investment Risks:
. Future oil and natural gas prices are unpredictable. If oil and
natural gas prices go down, the Partnership's 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.
2
<PAGE>
. 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, 2000 to present their Units to the
General Partner for purchase, Limited Partners will not be able to
liquidate their investments.
. The Partnership could be formed with as little as $50,000 in Capital
Contributions (excluding the Capital Contributions of the General
Partner). As the total amount of Capital Contributions to the
Partnership will determine the number and diversification of
Partnership Properties, the ability of the Partnership to pursue its
investment objectives may be restricted in the event that the
Partnership receives only the minimum amount of Capital Contributions.
. The drilling and completion operations to be undertaken by the
Partnership for the development of oil and natural gas reserves
involve the possibility of a total loss of an investment in the
Partnership.
. The General Partner will have the exclusive management and control of
all aspects of the business of the Partnership. The Limited Partners
will have no opportunity to participate in the management and control
of any aspect of the Partnership's activities. Accordingly, the
Limited Partners will be entirely dependent upon the management skills
and expertise of the General Partner.
. Conflicts of interest exist and additional conflicts of interest may
arise between the General Partner and the Limited Partners, and there
are no pre-determined procedures for resolving any such conflicts.
Accordingly the General Partner could cause the Partnership to take
actions to the benefit of the General Partner but not to the benefit
of the Limited Partners.
. Certain provisions in the Agreement modify what would otherwise be the
applicable Oklahoma law as to the fiduciary standards for a general
partner in a limited partnership. The fiduciary standards in the
Agreement could be less advantageous to the Limited Partners and
more advantageous to the General Partner than corresponding fiduciary
standards otherwise applicable under Oklahoma law. The purchase of
Units may be deemed as consent to the fiduciary standards set forth in
the Agreement.
. There can be no assurances that the Partnership will have adequate
funds to provide cash distributions to the Limited Partners. The
amount and timing of any such distributions will be within the
complete discretion of the General Partner.
. The amount of any cash distributions which Limited Partners may
receive from the Partnership could be insufficient to pay the tax
liability incurred by such Limited Partners with respect to income or
gain allocated to such Limited Partners by the Partnership.
Tax Risks:
. Tax laws and regulations applicable to partnership investments may
change at any time and these changes may be applicable retroactively.
3
<PAGE>
. The Partnership may not qualify or may fail to continue to qualify as
a partnership for federal income tax purposes.
. Certain allocations of income, gain, loss and deduction of the
Partnership among the Partners may be challenged by the Internal
Revenue Service (the "Service"). A successful challenge would result
in a Limited Partner having to report additional taxable income or
being denied a deduction.
. Investment as a Limited Partner may be less advisable for a person who
does not have substantial current taxable income from passive trade or
business activities.
. Federal income tax payable by a Limited Partner by reason of his or
her allocated share of Partnership income for any year may exceed the
cash distributed to such Partner by the Partnership.
. Even though the Partnership will not register with the Service as a
"tax shelter," there still remains a possibility of an audit of the
Partnership's returns by the Service.
Operational Risks:
. The search for oil and gas is highly speculative and the drilling
activities conducted by the Partnership may result in a well that may
be dry or productive wells that do not produce sufficient oil and gas
to produce a profit or result in a return of the Limited Partners'
investment.
. Certain hazards may be encountered in drilling wells which could lead
to substantial liabilities to third parties or governmental entities.
In addition, governmental regulations or new laws relating to
environmental matters could increase Partnership costs, delay or
prevent drilling a well, require the Partnership to cease operations
in certain areas or expose the Partnership to significant liabilities
for violations of such laws and regulations.
Additional Financing
Additional Assessments. After the Aggregate Subscription received from the
Limited Partners has been fully expended or committed and the General Partner's
Minimum Capital Contribution has been fully expended, the General Partner may
make one or more calls for Additional Assessments from the Limited Partners if
additional funds are required to pay the Limited Partners' share of Drilling
Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs.
The maximum amount of total Additional Assessments which may be called for by
the General Partner is $100 per Unit. See "ADDITIONAL FINANCING -- Additional
Assessments".
Partnership Borrowings. After the General Partner's Minimum Capital
Contribution has been expended, the General Partner may cause the Partnership to
borrow funds required to pay Drilling Costs, Special Production and Marketing
Costs or Leasehold Acquisition Costs of Productive properties. Additionally,
the General Partner may, but is not required to, advance funds to the
Partnership to pay such costs. See "ADDITIONAL FINANCING -- Partnership
Borrowings".
4
<PAGE>
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, 1999, if the Partnership is formed
prior to such date or from the date of the formation of the Partnership if
subsequent to January 1, 1999, until December 31, 1999, 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 1999. 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
1999. UNIT hopes that participation in the Partnership will provide the
participants with greater proprietary interests in UNIT's operations and the
potential for realizing a more direct benefit in the event these operations
prove to be profitable. The Partnership has been structured to achieve the
objective of providing the Limited Partners with essentially the same economic
returns that UNIT realizes from the wells drilled or acquired during 1999.
Application of Proceeds
The offering proceeds will be used to pay the Leasehold Acquisition Costs
incurred by the Partnership to acquire those producing oil and gas leases in
which the Partnership participates and the Leasehold Acquisition Costs,
exploration, drilling and development costs incurred by the Partnership pursuant
to drilling activities in which the Partnership participates. The General
Partner estimates (based on historical operating experience) that such costs may
be expended as shown below based on the assumption of a maximum number of
subscriptions in the first column and a minimum number of subscriptions in the
second column:
$600,000 $50,000
Program Program
-------- -------
Leasehold Acquisition Costs
of Properties to Be Drilled.......... $ 30,000 $ 2,500
Drilling Costs of Exploratory
Wells(1)............................. 30,000 2,500
Drilling Costs of Development
Wells(1)............................. 420,000 35,000
Leasehold Acquisition Costs of
Productive Properties................ 120,000 10,000
Reimbursement of General
Partner's Overhead Costs(2).......... --------- ---------
Total............................ $ 600,000 $ 50,000
(1) See "GLOSSARY."
5
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(2) The Agreement provides that the General Partner shall be reimbursed
by the Partnership for that portion of its general and
administrative overhead expense attributable to its conduct of
Partnership business and affairs but such reimbursement will be made
only out of Partnership Revenue. See "COMPENSATION."
Participation in Costs and Revenues
Partnership costs, expenses and revenues will be allocated among the
Partners in the following percentages:
General Limited
COSTS AND EXPENSES Partner Partners
Organizational and offering costs of the
Partnership and any drilling or income
programs in which the Partnership
participates as a co-general partner 100% 0%
All other Partnership costs and expenses
Prior to time Limited Partner Capital
Contributions are entirely expended 1% 99%
After expenditure of Limited Partner
Capital Contributions and until
expenditure of General Partner's
Minimum Capital Contribution 100% 0%
After expenditure of General
Partner's Minimum Capital General Partner's Limited Partners'
Contribution Percentage(1) Percentage(1)
REVENUES General Partner's Limited Partners'
Percentage(1) Percentage(1)
____________________
1) See "GLOSSARY."
6
<PAGE>
Compensation
The General Partner will not receive any management fees in connection with
the operation of the Partnership. The Partnership will reimburse the General
Partner for that portion of its general and administrative overhead expense
attributable to its conduct of Partnership business and affairs. See
"COMPENSATION."
Federal Income Tax Considerations; Opinion of Counsel
The General Partner has received an opinion from its tax counsel, Conner &
Winters, A Professional Corporation ("Conner & Winters"), concerning all
material federal income tax issues applicable to an investment in the
Partnership. To be fully understood, the complete discussion of these matters
set forth in the full tax opinion in Exhibit B should be read by each
prospective investor. Based upon current laws, regulations, interpretations,
and court decisions, Conner & Winters has rendered its opinion that (i) the
material federal income tax benefits in the aggregate from an investment in the
Partnership will be realized; (ii) the Partnership will be treated as a
partnership for federal income tax purposes and not as a corporation
and not as an association taxable as a corporation; (iii) to the extent the
Partnership's wells are timely drilled and amounts are timely paid, the Partners
will be entitled to their pro rata share of the Partnership's intangible
drilling and development costs ("IDC") paid in 1999; (iv) Limited Partners'
interests will be considered a passive activity within the meaning of Section
469 of the Internal Revenue Code of 1986, as amended (the "Code"), and losses
generated therefrom will be limited by the passive activity provisions; (v) to
the extent provided herein, the Partners' distributive shares of Partnership tax
items will be determined and allocated substantially in accordance with the
terms of the Partnership Agreement; and (vi) the Partnership will not be
required to register with the Service as a tax shelter.
Due to the lack of authority regarding, or the essentially factual nature
of certain issues, Conner & Winters expresses no opinion on the following: (i)
the impact of an investment in the Partnership on an investor's alternative
minimum tax liability; (ii) whether, under Code Section 183, the losses of the
Partnership will be treated as derived from "activities not engaged in for
profit," and therefore nondeductible from other gross income (due to the
inherently factual nature of a Partner's interest and motive in engaging in the
transaction); (iii) whether any of the Partnership's properties will be
considered "proven" for purposes of depletion deductions; (iv) whether any
interest incurred by a Partner with respect to any borrowings incurred to
purchase Units will be deductible or subject to limitations on deductibility;
and (v) whether the Partnership will be treated as the tax owner of Partnership
Properties acquired by the General Partner as nominee for the Partnership.
THIS MEMORANDUM CONTAINS AN EXPLANATION OF THE MORE SIGNIFICANT
TERMS AND PROVISIONS OF THE AGREEMENT OF LIMITED PARTNERSHIP WHICH IS
ATTACHED AS EXHIBIT A. THE SUMMARY OF THE AGREEMENT CONTAINED IN THIS
MEMORANDUM IS QUALIFIED IN ITS ENTIRETY BY SUCH REFERENCE AND
ACCORDINGLY THE AGREEMENT SHOULD BE CAREFULLY REVIEWED AND
CONSIDERED.
7
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RISK FACTORS
Prospective purchasers of Units should carefully study the information
contained in this Memorandum and should make their own evaluations of the
probability for the discovery of oil and natural gas through exploration.
INVESTMENT RISKS
Financial Risks of Drilling Operations
The Partnership will participate with the General Partner (including, with
certain limited exceptions, other drilling programs sponsored by it, or UNIT)
and, in some cases, other parties ("joint interest parties") in connection with
drilling operations conducted on properties in which the Partnership has an
interest. It is not anticipated that all such drilling operations will be
conducted under turnkey drilling contracts and, thus, all of the parties
participating in the drilling operations on a particular property, including the
Partnership, may be fully liable for their proportionate share of all costs of
such operations even if the actual costs significantly exceed the original cost
estimates. Further, if any joint interest party defaults in its obligation
to pay its share of the costs, the other joint interest parties may be required
to fund the deficiency until, if ever, it can be collected from the defaulting
party. As a result of forced pooling or similar proceedings (see "COMPETITION,
MARKETS AND REGULATION"), the Partnership may acquire larger fractional
interests in Partnership Properties than originally anticipated and, thus, be
required to bear a greater share of the costs of operations. As a result of the
foregoing, the Partnership could become liable for amounts significantly in
excess of the amounts originally anticipated to be expended in connection with
the operations and, in such event, would have only limited means for providing
needed additional funds (see "ADDITIONAL FINANCING"). Also, if a well is
operated by a company which does not or cannot pay the costs and expenses of
drilling or operating a Partnership Well, the Partnership's interest in such
well may become subject to liens and claims of creditors who supplied services
or materials in connection with such operations even though the Partnership may
have previously paid its share of such costs and expenses to the operator.
If the operator is unable or unwilling to pay the amount due, the Partnership
might have to pay its share of the amounts owing to such creditors in order to
preserve its interest in the well which would mean that it would, in effect, be
paying for certain of such costs and expenses twice.
Dependence Upon General Partner
The Limited Partners will acquire interests in the Partnership, not in the
General Partner or UNIT. They will not participate in either increases or
decreases in the General Partner's or UNIT's net worth or the value of its
common stock. Nevertheless, because the General Partner is primarily
responsible for the proper conduct of the Partnership's business and affairs and
is obligated to provide certain funds that will be required in connection with
its operations, a significant financial reversal for the General Partner or UNIT
could have an adverse effect on the Partnership and the Limited Partners'
interests therein.
Under the Partnership Agreement, UPC is designated as the General Partner
of the Partnership and is given the exclusive authority to manage and operate
the Partnership's business. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
- - Power and Authority". Accordingly, Limited Partners must rely solely on the
8
<PAGE>
General Partner to make all decisions on behalf of the Partnership, as the
Limited Partners will have no role in the management of the business of the
Partnership.
The Partnership's success will depend, in part, upon the management
provided by the General Partner, the ability of the General Partner to select
and acquire oil and gas properties on which Partnership Wells capable of
producing oil and natural gas in commercial quantities may be drilled, to fund
the acquisition of revenue producing properties, and to market oil and natural
gas produced from Partnership Wells.
Conflicts of Interest
UNIT and its subsidiaries have engaged in oil and gas exploration and
development and in the acquisition of producing properties for their own account
and as the sponsors of drilling and income programs formed with third party
investors. It is anticipated that UNIT and its subsidiaries will continue to
engage in such activities. However, with certain exceptions, it is likely that
the Partnership will participate as a working interest owner in all producing
oil and gas leases acquired and in all oil and gas wells commenced by the
General Partner or UNIT for its own account during the period from January 1,
1999, if the Partnership is formed prior to such date, or from the date of the
formation of the Partnership, if subsequent to January 1, 1999, through December
31, 1999 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 1999. 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 1999. 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 1999 and will have no rights in production from
wells commenced in years other than 1999. Likewise, if additional interests are
acquired in wells participated in by the Partnership after 1999, the Partnership
will generally not be entitled to participate in the acquisition of such
additional interests. See "CONFLICTS OF INTEREST - Acquisition of Properties
and Drilling Operations."
The Partnership may enter into contracts for the drilling of some or all of
the Partnership Wells with affiliates of the General Partner. Likewise the
Partnership may sell or market some or all of its natural gas production to an
affiliate of the General Partner. These contracts may not necessarily be
negotiated on an arm's - length basis. The General Partner is subject to a
conflict of interest in selecting an affiliate of the General Partner to drill
the Partnership Wells and/or market the natural gas therefrom. The compensation
under these contracts will be determined at the time of entering into each such
contract, and the costs to be paid thereunder or the sale price to be received
will be one which is competitive with the costs charged or the prices paid by
unaffiliated parties in the same geographic region. The General Partner will
make the determination of what are competitive rates or prices in the area. No
provision has been made for an independent review of the fairness and
reasonableness of such compensation. See "CONFLICTS OF INTERESTS - Transactions
with the General Partner or Affiliates".
9
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Prohibition on Transferability; Lack of Liquidity
Except for certain transfers (i) to the General Partner, (ii) to or for the
benefit of the transferor Limited Partner or members of his or her immediate
family sharing the same residence, and (iii) by reason of death or operation of
law, a Limited Partner may not transfer or assign Units. The General Partner
has agreed, however, that it will, if requested at any time after December 31,
2000, buy Units for prices determined either by an independent petroleum
engineering firm or the General Partner pursuant to a formula described under
"TERMS OF THE OFFERING - Right of Presentment." This obligation of the General
Partner to purchase Units when requested is limited and does not assure the
liquidity of a Limited Partner's investment, and the price received may be less
than if the Limited Partner continued to hold his or her Units. In addition,
similar commitments have been made and may hereafter be made to investors in
other oil and gas drilling, income and employee programs sponsored by the
General Partner or UNIT. There can be no assurance that the General Partner
will have the financial resources to honor its repurchase commitments. See
"TERMS OF THE OFFERING - Right of Presentment."
Delay of Cash Distributions
For income tax purposes, a Limited Partner must report his or her
distributive (allocated) share of the income, gains, losses and deductions of
the Partnership whether or not cash distributions are made. No cash
distributions are expected to be made earlier than the first quarter of 2000.
In addition, to the extent that the Partnership uses its revenues to repay
borrowings or to finance its activities (see "ADDITIONAL FINANCING"), the funds
available for cash distributions by the Partnership will be reduced or may be
unavailable. It is possible that the amount of tax payable by a Limited Partner
on his or her distributive share of the income of a Partnership will exceed his
or her cash distributions from the Partnership. See "FEDERAL INCOME TAX
CONSIDERATIONS."
The date any distributions commence and their subsequent timing or amount
cannot be accurately predicted. The decision as to whether or not the
Partnership will make a cash distribution at any particular time will be made
solely by the General Partner.
Limitations on Voting and Other Rights of Limited Partners
The Agreement, as permitted under the Oklahoma Revised Uniform Limited
Partnership Act (the "Act"), eliminates or limits the rights of the Limited
Partners to take certain actions, such as:
. withdrawing from the Partnership,
. transferring Units without restrictions, or
. consenting to or voting upon certain matters such as:
(i) admitting a new General Partner,
(ii) admitting Substituted Limited Partners, and
(iii) dissolving the Partnership.
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Furthermore, the Agreement imposes restrictions on the exercise of voting rights
granted to Limited Partners. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT
- -- Voting Rights." Without the provisions to the contrary which are contained
in the Agreement, the Act provides that certain actions can be taken only with
the consent of all Limited Partners. Those provisions of the Agreement which
provide for or require the vote of the Limited Partners, generally permit the
approval of a proposal by the vote of Limited Partners holding a majority of the
outstanding Units. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -- Voting
Rights." Thus, Limited Partners who do not agree with or do not wish to be
subject to the proposed action may nevertheless become subject to the action if
the required majority approval is obtained. Notwithstanding the rights granted
to Limited Partners under the Agreement and the Act, the General Partner retains
substantial discretion as to the operation of the Partnership.
Rollup or Consolidation of Partnership
Under the terms of the Agreement, at any time two years or more after the
Partnership has completed substantially all of its property acquisition,
drilling and development operations, the General Partner is authorized to cause
the Partnership to transfer its assets to, or to merge or consolidate with,
another partnership or a corporation or other entity for the purpose of
combining the oil and gas properties and other assets of the Partnership with
those of other partnerships formed for investment or participation by the
employees, directors and/or consultants of UNIT or any of its subsidiaries.
Such transfer or combination may be effected without the vote, approval or
consent of the Limited Partners. In such event, the Limited Partners will
receive interests in the transferee or resulting entity which will mean that
they will most likely participate in the results of a larger number of
properties but will have proportionately smaller allocable interests therein.
Any such transaction is required to be effected in a manner which UNIT and the
General Partner believe is fair and equitable to the Limited Partners but there
can be no assurance that such transaction will in fact be in the best interests
of the Limited Partners. Limited Partners have no dissenters' or appraisal
rights under the terms of the Agreement or the Act. Such a transaction would
result in the termination and dissolution of the Partnership. While there can
be no assurance that the Partnership will participate in such a transaction, the
General Partner currently anticipates that the Partnership will, at the
appropriate time, be involved in such a transaction. See "TERMS OF OFFERING",
and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT."
Partnership Borrowings
The General Partner has the authority to cause the Partnership to borrow
funds to pay certain costs of the Partnership. While the use of financing to
preserve the Partnership's equity in oil and gas properties will be intended to
increase the Partnership's profits, such financing could have the effect of
increasing the Partnership's losses if the Partnership is unsuccessful. In
addition, the Partnership may have to mortgage its oil and gas properties and
other assets in order to obtain additional financing. If the Partnership
defaults on such indebtedness, the lender may foreclose and the Partnership
could lose its investment in such oil and gas properties and other assets. See
"ADDITIONAL FINANCING -- Partnership Borrowings."
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Limited Liability
Under the Act a Limited Partner's liability for the obligations of the
Partnership is limited to such Limited Partner's Capital Contribution and such
Limited Partner's share of Partnership assets. In addition, if a Limited
Partner receives a return of any part of his or her Capital Contribution, such
Limited Partner is generally liable to the Partnership for a period of one year
thereafter (or six years in the event such return is in violation of the
Agreement) for the amount of the returned contribution. A Limited Partner will
not otherwise be liable for the obligations of the Partnership unless, in
addition to the exercise of his or her rights and powers as a Limited Partner,
such Limited Partner participates in the control of the business of the
Partnership.
The Agreement provides that by a vote of a majority in interest, the
Limited Partners may effect certain changes in the Partnership such as
termination and dissolution of the Partnership and amendment of the Agreement.
The exercise of any of these and certain other rights is conditioned upon
receipt of an opinion by counsel for the Limited Partners or an order or
judgment of a court of competent jurisdiction to the effect that the exercise of
such rights will not result in the loss of the limited liability of the Limited
Partners or cause the Partnership to be classified as an association taxable as
a corporation (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Amendments"
and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Termination"). As a result
of certain judicial opinions it is not clear that these rights will ever be
available to the Limited Partners. Nevertheless, in spite of the receipt of any
such opinion or judicial order, it is still possible that the exercise of any
such rights by the Limited Partners may result in the loss of the Limited
Partners' limited liability. The Partnership will be governed by the Act. The
Act expressly permits limited partners to vote on certain specified partnership
matters without being deemed to be participating in the control of the
Partnership's business and, thus, should result in greater certainty and more
easily obtainable opinions of counsel regarding the exercise of most of the
Limited Partners' rights.
If the Partnership is dissolved and its business is not to be continued,
the Partnership will be wound up. In connection with the winding up of the
Partnership, all of its properties may be sold and the proceeds thereof credited
to the accounts of the Partners. Properties not sold will, upon termination of
the Partnership, be distributed to the Partners. The distribution of
Partnership Properties to the Limited Partners would result in their having
unlimited liability with respect to such properties. See "SUMMARY OF THE
LIMITED PARTNERSHIP AGREEMENT - Limited Liability."
Partnership Acting as Co-General Partner
It is currently anticipated that the Partnership will serve as a co-general
partner in any drilling or income programs formed by the General Partner or UNIT
during 1999. See "PROPOSED ACTIVITIES." Accordingly, the Partnership generally
will be liable for the obligation and recourse liabilities of any such
drilling or income program formed. While a Limited Partner's liability for such
claims will be limited to such Limited Partners Capital Contribution and share
of Partnership assets, such claims if satisfied from the Partnership's assets
could adversely affect the operations of the Partnership.
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Past-Due Installments; Acceleration; Additional Assessments
Installments and Additional Assessments (see "ADDITIONAL FINANCING") are
legally binding obligations and past-due amounts will bear interest at the rate
set forth in the Agreement; provided, however, that if the General Partner
determines that the total Aggregate Subscription is not required to fund the
Partnership's business and operations, then the General Partner may, at its sole
option, elect to release the Limited Partners from their obligation to pay one
or more Installments and amend any relevant Partnership documents accordingly.
It is currently anticipated that the total Aggregate Subscription will be
required to fund the Partnership's business and operations. In the event an
Installment is not paid when due and the General Partner has not released the
Limited Partners from their obligation to pay such Installment, then the
General Partner may, at its sole option, purchase all Units of the director or
employee who fails to pay such Installment, at a price equal to the amount of
the prior Installments paid by such person. The General Partner may also bring
legal proceedings to collect any unpaid Installments not waived by it or
Additional Assessments. In addition, as indicated under "TERMS OF THE OFFERING
- - Payment for Units; Delinquent Installment," if an employee's employment with
or position as a director of the General Partner, UNIT or any affiliate thereof
is terminated other than by reason of Normal Retirement (see "GLOSSARY"), death
or disability prior to the time the full amount of the subscription price for
his or her Units has been paid, all unpaid Installments not waived by the
General Partner as described above will become due and payable upon
such termination.
Partnership Funds
Except for Capital Contributions, Partnership funds are expected to be
commingled with funds of the General Partner or UNIT. Thus, Partnership funds
could become subject to the claims of creditors of the General Partner or UNIT.
The General Partner believes that its assets and net worth are such that the
risk of loss to the Partnership by virtue of such fact is minimal but there can
be no assurance that the Partnership will not suffer losses of its funds to
creditors of the General Partner or UNIT.
Compliance With Federal and State Securities Laws
This offering has not been registered under the Securities Act of 1933, as
amended, in reliance upon exemptive provisions of said act. Further, these
interests are being sold pursuant to exemptions from registration in the various
states in which they are being offered and may be subject to additional
restrictions in such jurisdictions on transfer. There is no assurance that the
offering presently qualifies or will continue to qualify under such exemptive
provisions due to, among other things, the adequacy of disclosure and the
manner of distribution of the offering, the existence of similar offerings
conducted by the General Partner or UNIT or its affiliates in the past or in the
future, a failure or delay in providing notices or other required filings, the
conduct of other oil and gas activities by the General Partner or UNIT and its
affiliates or the change of any securities laws or regulations.
If and to the extent suits for rescission are brought and successfully
concluded for failure to register this offering or other offerings under the
Securities Act of 1933, as amended, or state securities acts, or for acts or
omissions constituting certain prohibited practices under any of said acts, both
the capital and assets of the General Partner and the Partnership could be
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adversely affected, thus jeopardizing the ability of the Partnership to operate
successfully. Further, the time and capital of the General Partner could be
expended in defending an action by investors or by state or federal authorities
even where the Partnership and the General Partner are ultimately exonerated.
Title To Properties
The Partnership Agreement empowers the General Partner, UNIT or any of
their affiliates, to hold title to the Partnership Properties for the benefit of
the Partnership. As such it is possible that the Partnership Properties could
be subject to the claims of creditors of the General Partner. The General
Partner is of the opinion that the likelihood of the occurrence of such claims
is remote. However, the Partnership Property could be subject to claims and
litigation in the event that the General Partner failed to pay its debts or
became subject to the claims of creditors.
Use of Partnership Funds to Exculpate and Indemnify the General Partner
The Agreement contains certain provisions which are intended to limit the
liability of the General Partner and its affiliates for certain acts or
omissions within the scope of the authority conferred upon them by the
Agreement. In addition, under the Agreement, the General Partner will be
indemnified by the Partnership against losses, judgments, liabilities, expenses
and amounts paid in settlement sustained by it in connection with the
Partnership so long as the losses, judgments, liabilities, expenses or amounts
were not the result of gross negligence or willful misconduct on the part of the
General Partner. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT --
Exculpation and Indemnification of the General Partner."
The Partnership Agreement May Limit the Fiduciary Obligation of the General
Partner to the Partnership and the Limited Partners
The Agreement contains certain provisions which modify what would otherwise
be the applicable Oklahoma law relating to the fiduciary standards of the
General Partner to the Limited Partners. The fiduciary standards in the
Agreement could be less advantageous to the Limited Partners and more
advantageous to the General Partner than the corresponding fiduciary standards
otherwise applicable under Oklahoma law (although there are very few legal
precedents clarifying exactly what fiduciary standards would otherwise be
applicable under Oklahoma law). The purchase of Units may be deemed as consent
to the fiduciary standards set forth in the Agreement. See "FIDUCIARY
RESPONSIBILITY." As a result of these provisions in the Agreement, the Limited
Partners may find it more difficult to hold the General Partner responsible for
acting in the best interest of the Partnership and the Limited Partners than if
the fiduciary standards of the otherwise applicable Oklahoma law governed the
situation.
TAX STATUS AND TAX RISKS
It is possible that the tax treatment currently available with respect to
oil and gas exploration and production will be modified or eliminated on a
retroactive or prospective basis by legislative, judicial, or administrative
actions. The limited tax benefits associated with oil and gas exploration do
not eliminate the inherent attendant risks. See "Federal Income Tax
Considerations."
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Partnership Classification
Conner & Winters has rendered its opinion that the Partnership will be
classified for federal income tax purposes as a partnership and not as an
association taxable as a corporation or as a "publicly traded partnership."
Such opinion is not binding on the Service or the courts. If the Partnership
were classified as a corporation, association taxable as a corporation or
publicly traded partnership, any income, gain, loss, deduction, or credit of the
Partnership would remain at the entity level, and not flow through to the
Partners, the income of the Partnership would be subject to corporate tax rates
at the entity level and distributions to the Partners could be considered
dividend distributions. See "Federal Income Tax Considerations General
Tax Effects of Partnership Structure."
Limited Partner Interests
An investment as a Limited Partner may not be advisable for a person who
does not anticipate having substantial current taxable income from passive trade
or business activities (not counting dividend or interest income). Such a
person cannot utilize any passive losses generated by the Partnership until he
or she is in receipt of "passive income". Partnership income, losses, gains,
and deductions allocable to any Limited Partners will be subject to the passive
activity rules.
Tax Liabilities in Excess of Cash Distributions
Federal income tax payable by a Partner by reason of his or her
distributive share of Partnership taxable income for any year may exceed the
cash distributed to such Partner by the Partnership. A Partner must include in
his or her own return for a taxable year his or her share of the items of the
Partnership's income, gain, profit, loss, and deductions for the year, to the
extent required under the Code as then in effect, whether or not cash proceeds
are actually distributed to the Partner. For example, income from the
Partnership's sale of gas production will be taxable to Partners as ordinary
income subject to depletion and other deductions whether or not it is actually
distributed (for example, where Partnership income is used to repay Partnership
indebtedness).
Items Not Covered by the Tax Opinion
Due to the lack of authority regarding, or the essentially factual nature
of certain issues, Conner & Winters has expressed no opinion as to the
following: (i) whether the losses of the Partnership will be treated as derived
from "activities not engaged in for profit," and therefore nondeductible from
other gross income, (ii) whether any of the Partnership's properties will be
entitled to percentage depletion, (iii) whether any interest incurred by a
Partner with respect to any borrowings will be deductible or subject to
limitations on deductibility, and (iv) the impact of an investment in the
Partnership on a Partner's alternative minimum tax liability and (v) the amount,
if any, of the fees and expense reimbursements paid to third parties, the
General Partner, or their affiliates that will be deductible or amortizable.
The determination of various of the above-referenced issues is dependent on
facts that will not be known until the future. Therefore, Conner & Winters is
unable to render an opinion at this time with respect to such issues. Also,
the facts when they become known with respect to the various issues referred to
above will vary from Partner to Partner and will result in different tax
consequences and burdens for individual Partners.
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Prospective investors should recognize that an opinion of counsel merely
represents such counsel's best legal judgment under existing statutes, judicial
decisions, and administrative regulations and interpretations. There can be no
assurance, however, that some of the deductions claimed by the Partnership
will not be challenged successfully by the Service.
OPERATIONAL RISKS
Risks Inherent in Oil and Gas Operations
The Partnership will be participating with the General Partner in acquiring
producing oil and gas leases and in the drilling of those oil and gas wells
commenced by the General Partner from the later of January 1, 1999 or the time
the Partnership is formed through December 31, 1999 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 1999.
All drilling to establish productive oil and natural gas properties is
inherently speculative. The techniques presently available to identify the
existence and location of pools of oil and natural gas are indirect, and,
therefore, a considerable amount of personal judgment is involved in the
selection of any prospect for drilling. The economics of oil and natural gas
drilling and production are affected or may be affected in the future by a
number of factors which are beyond the control of the General Partner, including
(i) the general demand in the economy for energy fuels, (ii) the worldwide
supply of oil and natural gas, (iii) the price of, as well as governmental
policies with respect to, oil imports, (iv) potential competition from competing
alternative fuels, (v) governmental regulation of prices for oil and natural
gas, (vi) state regulations affecting allowable rates of production, well
spacing and other factors, and (vii) availability of drilling rigs, casing and
other necessary goods and services. See "COMPETITION, MARKETS AND REGULATION."
The revenues, if any, generated from Partnership operations will be highly
dependent upon the future prices and demand for oil and natural gas. The
factors enumerated above affect, and will continue to affect, oil and
natural gas prices. Recently, prices for oil and natural gas have fluctuated
over a wide range.
Operating and Environmental Hazards
Operating hazards such as fires, explosions, blowouts, unusual formations,
formations with abnormal pressures and other unforeseen conditions are sometimes
encountered in drilling wells. On occasion, substantial liabilities to third
parties or governmental entities may be incurred, the payment of which could
reduce the funds available for exploration and development or result in loss of
Partnership Properties. The Partnership will attempt to maintain customary
insurance coverage, but the Partnership may be subject to liability for
pollution and other damages or may lose substantial portions of its properties
due to hazards against which it cannot insure or against which it may elect not
to insure due to unreasonably high or prohibitive premium costs or for other
reasons. The activities of the Partnership may expose it to potential
liability for pollution or other damages under laws and regulations relating to
environmental matters (see "Government Regulation and Environmental Risks"
below).
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Competition
The oil and gas industry is highly competitive. The Partnership will be
involved in intense competition for the acquisition of quality undeveloped
leases and producing oil and gas properties. There can be no assurance that a
sufficient number of suitable oil and gas properties will be available for
acquisition or development by the Partnership. The Partnership will be
competing with numerous major and independent companies which possess financial
resources and staffs larger than those available to it. The Partnership,
therefore, may be unable in certain instances to acquire desirable leases or
supplies or may encounter delays in commencing or completing Partnership
operations.
Markets for Oil and Natural Gas Production
There is currently a worldwide surplus of oil production capacity.
Historically (prior to the early 1980s), world oil prices were established and
maintained largely as a result of the actions of members of OPEC to limit, and
maintain a base price for, their oil production. In more recent years, however,
members of OPEC have been unable to agree to and maintain price and production
controls, which has resulted in significant downward pressure on oil prices.
Although future levels of production by the members of OPEC or the degree to
which oil prices will be affected thereby cannot be predicted, it is possible
that prices for oil produced in the future will be higher or lower than those
currently available. There can be no assurance that the Partnership will be
able to market any oil that it produces or, if such oil can be marketed, that
favorable price and other contractual terms can be negotiated. See
"COMPETITION, MARKETS AND REGULATION - Marketing of Production."
The natural gas market is also currently unsettled due to a number of
factors. In the past, production from natural gas wells in some geographic
areas of the United States has been curtailed for considerable periods of time
due to a lack of market demand. In addition, there may be an excess supply of
natural gas in areas where Partnership Wells are located. In that event, it is
possible that such Partnership Wells will be shut-in or that natural gas in
these areas will be sold on terms less favorable than might otherwise be
obtained. Competition for available markets has been vigorous and there remains
great uncertainty about prices that purchasers will pay. In recent years,
significant court decisions and regulatory changes have affected the
natural gas markets. As a result of such court decisions, regulatory changes
and unsettled market conditions, natural gas regulations may be modified in the
future and may be subject to further judicial review or invalidation. The
combination of these factors, among others, makes it particularly difficult to
estimate accurately future prices of natural gas, and any assumptions concerning
future prices may prove incorrect. Natural gas surpluses could result in the
Partnership's inability to market natural gas profitably, causing Partnership
Wells to curtail production and/or receive lower prices for its natural gas,
situations which would adversely affect the Partnership's ability to make cash
distributions to its participants. See "COMPETITION, MARKETS AND REGULATION."
In the event that the Partnership discovers or acquires natural gas
reserves, there may be delays in commencing or continuing production due to the
need for gathering and pipeline facilities, contract negotiation with the
available market, pipeline capacities, seasonal takes by the gas purchaser or a
surplus of available gas reserves in a particular area.
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Government Regulation and Environmental Risks
The oil and gas business is subject to pervasive government regulation
under which, among other things, rates of production from producing properties
may be fixed and the prices for gas produced from such producing properties may
be impacted. It is possible that these regulations pertaining to rates of
production could become more pervasive and stringent in the future. The
activities of the Partnership may expose it to potential liability under laws
and regulations relating to environmental matters which could adversely affect
the Partnership. Compliance with these laws and regulations may increase
Partnership costs, delay or prevent the drilling of wells, delay or prevent the
acquisition of otherwise desirable producing oil and gas properties, require the
Partnership to cease operations in certain areas, and cause delays in the
production of oil and gas. See "COMPETITION, MARKETING AND REGULATION."
Leasehold Defects
In certain instances, the Partnership may not be able to obtain a title
opinion or report with respect to a producing property that is acquired.
Consequently, the Partnership's title to any such property may be uncertain.
Furthermore, even if certain technical defects do appear in title opinions or
reports with respect to a particular property, the General Partner, in its sole
discretion, may determine that it is in the best interest of the Partnership to
acquire such property without taking any curative action.
TERMS OF THE OFFERING
General
. 600 Maximum Units; 50 Minimum Units
. $1,000 Units; Minimum subscription: $2,000
. Minimum Partnership: $50,000 in subscriptions
. Maximum Partnership: $600,000 in subscriptions
Limited Partnership Interests
The Partnership hereby offers to certain employees (described under
"Subscription Rights" below) and directors of UNIT and its subsidiaries an
aggregate of 600 Units. The purchase price of each Unit is $1,000, and the
minimum permissible purchase by any eligible subscriber is two Units ($2,000).
See "Subscription Rights" below for the maximum number of Units that may be
acquired by subscribers.
The Partnership will be formed as an Oklahoma limited partnership upon the
closing of the offering of Units made by this Memorandum. The General Partner
will be Unit Petroleum Company (the "General Partner", or "UPC"), an Oklahoma
corporation. Partnership operations will be conducted from the General
Partner's offices, the address of which is 1000 Kensington Tower I, 7130 South
Lewis Avenue, Tulsa, Oklahoma 74136, telephone (918) 493-7700.
The offering of Units will be closed on February 5, 1999 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
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any time prior to such date if it believes it to be in the best interests of the
eligible employees and Directors or the General Partner not to proceed with the
offering.
If at least 50 Units ($50,000) are not subscribed prior to the termination
of the offering, the Partnership will not commence business. The General
Partner may, on its own accord, purchase Units and, in such capacity, will enjoy
the same rights and obligations as other Limited Partners, except the General
Partner will have unlimited liability. The General Partner may, in its
discretion, purchase Units sufficient to reach the minimum Aggregate
Subscription ($50,000). Because the General Partner or its affiliates might
benefit from the successful completion of this offering (see "PARTICIPATION IN
COSTS, AND REVENUES" and "COMPENSATION"), investors should not expect that sales
of the minimum Aggregate Subscription indicate that such sales have been made to
investors that have no financial or other interest in the offering or that have
otherwise exercised independent investment discretion. Further, the sale of the
minimum Aggregate Subscription is not designed as a protection to investors to
indicate that their interest is shared by other unaffiliated investors and no
investor should place any reliance on the sale of the minimum Aggregate
Subscription as an indication of the merits of this offering. Units acquired by
the General Partner will be for investment purposes only without a present
intent for resale and there is no limit on the number of Units that may be
acquired by it.
Subscription Rights
Units are offered only to persons who are salaried employees of UNIT or its
subsidiaries at the date of formation of the Partnership and who are exempt
under the Fair Labor Standards Act and whose annual base salaries for 1999
(excluding bonuses) have been set at $22,680 or more and to Directors of UNIT.
Only employees and Directors who are U.S. citizens are eligible to participate
in the offering. In addition, employees and Directors must be able to bear the
economic risks of an investment in the Partnership and must have sufficient
investment experience and expertise to evaluate the risks and merits of such an
investment. See "PLAN OF DISTRIBUTION - Suitability of Investors."
Eligible employees and Directors are restricted as to the number of Units
they may purchase in the offering. The maximum number of Units which can be
acquired by any employee is that number of whole Units which can be purchased
with an amount which does not exceed one-half of the employee's base salary
for 1999. Each Director of UNIT may subscribe for a maximum of 200 Units
(maximum investment of $200,000). At December 16, 1998 there were approximately
156 Directors and employees eligible to purchase Units.
Eligible employees and Directors may acquire Units through a corporation or
other entity in which all of the beneficial interests are owned by them or
permitted assignees (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
Transferability of Interests"); provided that such employees or Directors
will be jointly and severally liable with such entity for payment of the Capital
Subscription.
If all eligible employees and Directors subscribed for the maximum number
of Units, the Units would be oversubscribed. In that event, Units would be
allocated among the respective subscribers in the proportion that each
subscription amount bears to total subscriptions obtained.
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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, 1999 and the remaining three of such Installments being due on June
15, 1999, September 15, 1999 and December 15, 1999, respectively, or (ii) by
employees so electing in the space provided on the Subscription Agreement,
through equal deductions from 1999 salary paid to the employee by the General
Partner, UNIT or its subsidiaries commencing immediately after formation of the
Partnership. If an employee or Director who has subscribed for Units (either
directly or through a corporation or other entity) ceases to be employed by or
serve as a Director of the General Partner, UNIT or any of its subsidiaries for
any reason other than death, disability or Normal Retirement prior to the
time the full amount of all Installments not waived by the General Partner as
described below are due, then the due date for any such unpaid Installments
shall be accelerated so that the full amount of his or her unpaid Capital
Subscription will be due and payable on the effective date of such termination.
Each Installment will be a legally binding obligation of the Limited
Partner and any past due amounts will bear interest at an annual rate equal to
two percentage points in excess of the prime rate of interest of Bank of
Oklahoma, N.A., Tulsa, Oklahoma; provided, however, that if the General Partner
determines that the total Aggregate Subscription is not required to fund the
Partnership's business and operations, then the General Partner may, at its sole
option, elect to release the Limited Partners from their obligation to pay one
or more Installments. If the General Partner elects to waive the payment of an
Installment, it will notify all Limited Partners promptly in writing of its
decision and will, to the extent required, amend the certificate of limited
partnership and any other relevant Partnership documents accordingly. It is
currently anticipated that the total Aggregate Subscription will be required,
however, to fund the Partnership's business and operations.
In the event a Limited Partner fails to pay any Installment when due and
the General Partner has not released the Limited Partners from their obligation
to pay such Installment, then the General Partner, at its sole option and
discretion, may elect to purchase the Units of such defaulting Limited Partner
at a price equal to the total amount of the Capital Contributions actually paid
into the Partnership by such defaulting Limited Partner, less the amount of any
Partnership distributions that may have been received by him or her. Such
option may be exercised by the General Partner by written notice to the Limited
Partner at any time after the date that the unpaid Installment was due and will
be deemed exercised when the amount of the purchase price is first tendered to
the defaulting Limited Partner. The General Partner may, in its discretion,
accept payments of delinquent Installments not waived by it but will not be
required to do so.
In the event that the General Partner elects to purchase the Units of a
defaulting Limited Partner, it must pay into the Partnership the amount of the
delinquent Installment (excluding any interest that may have accrued thereon)
and pay each additional Installment, if any, payable with respect to such Units
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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, 2000, and annually thereafter, Limited Partners will
have the right to present their Units to the General Partner for purchase. The
General Partner will not be obligated to purchase more than 20% of the then
outstanding Units in any one calendar year. The purchase price to be paid for
the Units of any Limited Partner presenting them for purchase will be based on
the net asset value of the Partnership which shall be equal to:
(1) The value of the proved reserves attributable to the Partnership
Properties, determined as set forth below; plus
(2) The estimated salvage value of tangible equipment installed on
Partnership Wells less the costs of plugging and abandoning the wells,
both discounted at the rate utilized to determine the value of the
Partnership's reserves as set forth below; plus
(3) The lower of cost or fair market value of all Partnership Properties
to which proved reserves have not been attributed but which have not
been condemned, as determined by an independent petroleum engineering
firm or the General Partner, as the case may be; plus
(4) Cash on hand; plus
(5) Prepaid expenses and accounts receivable (less a reasonable reserve
for doubtful accounts); plus
(6) The estimated market value of all other Partnership assets not
included in (1) through (5) above, determined by the General Partner;
MINUS
(7) An amount equal to all debts, obligations and other liabilities of the
Partnership.
The price to be paid for each Limited Partner's interest of the net asset value
will be his or her proportionate share of such net asset value less 75% of the
amount of any distributions received by him or her which are attributable to the
sales of the Partnership production since the date as of which the Partnership's
proved reserves are estimated.
The value of the proved reserves attributable to Partnership Properties
will be determined as follows:
(i) First, the future net revenues from the production and sale of the
proved reserves will be estimated as of the end of the calendar year
in which presentment is made based on an independent engineering
firm's report and its 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
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which is one percentage point higher than the prime rate of interest
being charged by the Bank of Oklahoma, N.A., Tulsa, Oklahoma, or any
successor bank, as of the date such reserves are estimated; and
(iii) Finally, the total discounted value of the future net revenues from
the production and sale of proved reserves will be reduced by an
additional 25% to take into account the risks and uncertainties
associated with the production and sale of the reserves and other
unforeseen uncertainties.
A Limited Partner who elects to have his or her Units purchased by the
General Partner should be aware that estimates of future net recoverable
reserves of oil and gas and estimates of future net revenues to be received
therefrom are based on a great many factors, some of which, particularly future
prices of production, are usually variable and uncertain and are always
determined by predictions of future events. Accordingly, it is common for the
actual production and revenues received to vary from earlier estimates.
Estimates made in the first few years of production from a property will be
based on relatively little production history and will not be as reliable as
later estimates based on longer production history. As a result of all the
foregoing, reserve estimates and estimates of future net revenues from
production may vary from year to year.
This right of presentment may be exercised by written notice from a Limited
Partner to the General Partner. The sale will be effective as of the close of
business on the last day of the calendar year in which such notice is given or,
at the General Partner's election, at 7:00 A.M. on the following day. Within
120 days after the end of the calendar year, the General Partner will furnish
each Limited Partner who gave such notice during the calendar year a statement
showing the cash purchase price which would be paid for the Limited Partner's
interest as of December 31 of the preceding year, which statement will include a
summary of estimated reserves and future net revenues and sufficient material to
reveal how the purchase price was determined. The Limited Partner must, within
30 days after receipt of such statement, reaffirm his or her election to sell to
the General Partner.
As noted above, the General Partner will not be obligated to purchase in
any one calendar year more than 20% of the Units in the Partnership then
outstanding. Moreover, the General Partner will not be obligated to purchase
any Units pursuant to such right if such purchase, when added to the total of
all other sales, exchanges, transfers or assignments of Units within the
preceding 12 months, would result in the Partnership being considered to have
terminated within the meaning of Section 708 of the Code or would cause the
Partnership to lose its status as a partnership for federal income tax purposes.
If more than the number of Units which may be purchased are tendered in any one
year, the Limited Partners from whom the units are to be purchased will be
determined by lot. Any Units presented but not purchased with respect to
one year will have priority for such purchase the following year.
The General Partner does not intend to establish a cash reserve to fund its
obligation to purchase Units, but will use funds provided by its operations or
borrowed funds (if available), using its assets (including such Units purchased
or to be purchased from Limited Partners) as collateral to fund such
obligations. However, there is no assurance that the General Partner will have
sufficient financial resources to discharge its obligations.
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<PAGE>
Rollup or Consolidation of Partnership
The Agreement provides that two years or more after the Partnership has
completed substantially all of its property acquisition, drilling and
development operations, the General Partner may, without the vote, consent or
approval of the Limited Partners, cause all or substantially all of the oil and
gas properties and other assets of the Partnership to be sold, assigned or
transferred to, or the Partnership merged or consolidated with, another
partnership or a corporation, trust or other entity for the purpose of combining
the assets of two or more of the oil and gas partnerships formed for investment
or participation by employees, directors and/or consultants of UNIT or any of
its subsidiaries; provided, however, that the valuation of the oil and gas
properties and other assets of all such participating partnerships for purposes
of such transfer or combination shall be made on a consistent basis and in a
manner which the General Partner and UNIT believe is fair and equitable to the
Limited Partners. As a consequence of any such transfer or combination, the
Partnership shall be dissolved and terminated and the Limited Partners shall
receive partnership interests, stock or other equity interests in the transferee
or resulting entity. Any such action will cause the Limited Partners'
attributable interest in the Partnership Properties to be diluted but it will
also provide them with attributable interests in the properties and other assets
of the other partnerships participating in the consolidation. It also may
reduce somewhat the amount of their attributable shares of the direct and
indirect costs of administering the Partnership. See "RISK FACTORS - Investment
Risks - Roll-Up or Consolidation of Partnership."
ADDITIONAL FINANCING
The General Partner will use its best efforts, consistent with Partnership
objectives, to acquire Productive properties and complete the Partnership's
drilling and development operations before the Aggregate Subscription has been
fully expended or committed. However, funds in addition to the Aggregate
Subscription may be required to pay costs and expenses which are chargeable to
the Limited Partners. In those instances described below, the General Partner
may call for Additional Assessments or may apply Partnership Revenue allocable
to the Limited Partners in payment and satisfaction of such costs or the General
Partner may, but shall not be required to, fund the deficiency with Partnership
borrowings to be repaid with Partnership Revenue.
Additional Assessments
When the Aggregate Subscription has been fully expended or committed, the
General Partner may make one or more calls for any portion or all of the maximum
Additional Assessments of $100 per Unit. However, no Additional Assessments may
be required before the General Partner's Minimum Capital Contribution has been
fully expended. Such assessments may be used to pay the Limited Partners' share
of the Drilling Costs, Special Production and Marketing Costs or Leasehold
Acquisition Costs of Productive properties which are chargeable to the Limited
Partners. The amount of the Additional Assessment so called shall be due and
payable on or before such date as the General Partner may set in such call,
which in no event will be earlier than thirty (30) days after the date of
mailing of the call. The notice of the call for Additional Assessments will
specify the amount of the assessment being required, the intended use of such
funds, the date on which the contributions are payable and describe the
consequences of nonpayment. Although the Limited Partners who do not respond
will participate in production, if any, obtained from operations conducted with
the proceeds from the aggregate Additional Assessments paid into the
23
<PAGE>
Partnership, the amount of the unpaid Additional Assessment shall bear interest
at the annual rate equal to two (2) percentage points in excess of the prime
rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank,
as announced and in effect from time to time, until paid. The Partnership will
have a lien on the defaulting Limited Partner's interest in the Partnership and
the General Partner may retain Partnership Revenue otherwise available for
distribution to the defaulting Limited Partner until an amount equal to the
unpaid Additional Assessment and interest is received. Furthermore, the General
Partner may satisfy such lien by proceeding with legal action to enforce the
lien and the defaulting Limited Partner shall pay all expenses of collection,
including interest, court costs and a reasonable attorney's fee.
Prior Programs
In the prior employee programs conducted by UNIT or the General Partner in
each of the years 1984 through 1998, Additional Assessments could be called for
as provided herein. At September 30, 1998, there had been no calls for
Additional Assessments in such programs. There can be no assurance, however,
that Additional Assessments will not be required to pay Partnership costs.
Partnership Borrowings
At any time after the General Partner's Minimum Capital Contribution has
been fully expended, the General Partner may cause the Partnership to borrow
funds for the purpose of paying Drilling Costs, Special Production and Marketing
Costs or Leasehold Acquisition Costs of Productive properties, which borrowings
may be secured by interests in the Partnership Properties and will be repaid,
including interest accruing thereon, out of Partnership Revenue. The General
Partner may, but is not required to, advance funds to the Partnership for the
same purposes for which Partnership borrowings are authorized. With respect to
any such advances, the General Partner will receive interest in an amount equal
to the lesser of the interest which would be charged to the Partnership by
unrelated banks on comparable loans for the same purpose or the General
Partner's interest cost with respect to such loan, where it borrows the same.
No financing charges will be levied by the General Partner in connection with
any such loan. If Partnership borrowings secured by interests in the
Partnership Wells and repayable out of Partnership Revenue cannot be arranged on
a basis which, in the opinion of the General Partner, is fair and reasonable,
and the entire sum required to pay such costs is not available from Partnership
Revenue, the General Partner may dispose of some or all of the Partnership
Properties upon which such operations were to be conducted by sale, farm-out or
abandonment.
If the Partnership requires funds to conduct Partnership operations during
the period between any of the Installments due from the Limited Partners, then,
notwithstanding the foregoing, the General Partner shall advance funds to the
Partnership in an amount equal to the funds then required to conduct such
operations but in no event more than the total amount of the Aggregate
Subscription remaining unpaid. With respect to any such advances, the General
Partner shall receive no interest thereon and no financing charges will be
levied by the General Partner in connection therewith. The General Partner
shall be repaid out of the Installments thereafter paid into the capital of the
Partnership when due.
The Partnership may attempt to finance any expenses in excess of the
Partners' Capital Subscriptions by the foregoing means and any other means which
the General Partner deems in the best interests of the Partnership, but the
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<PAGE>
Partnership's inability to meet such costs could result in the deferral of
drilling operations or in the inability to participate in future drilling or in
non-consent penalties pursuant to which co-owners of particular working
interests recover several times the amount which would have been funded by the
Partnership in accordance with its ownership interest before the Partnership
would participate in revenues.
The use of Partnership Revenue allocable to the Limited Partners to pay
Partnership costs and expenses and to repay any Partnership borrowings will mean
that such revenue will not be available for distribution to the Limited
Partners. Nonetheless, the Limited Partners may incur income tax liability by
virtue of that revenue and, thus, may not receive distributions from the
Partnership in amounts necessary to pay such income tax. However, the use of
such revenue to pay Partnership costs and expenses may generate additional
deductions for the Limited Partners.
PLAN OF DISTRIBUTION
Units will be offered privately only to select persons who can demonstrate
to the General Partner that they have both the economic means and investment
expertise to qualify as suitable investors. The Units will be offered and sold
by the officers and directors of UPC or UNIT.
Suitability of Investors
Subscriptions should be made only by appropriate persons who can reasonably
benefit from an investment in the Partnership. In this regard, a subscription
will generally be accepted only from a person who can represent that such person
has (or in the case of a husband and wife, acting as joint tenants, tenants
in common or tenants in the entirety, that they have) a net worth, including
home, furnishings and automobiles, of at least five times the amount of his or
her Capital Subscription, and estimates that such person will have during the
current year adjusted gross income in an amount which will enable him or her to
bear the economic risks of his or her investment in the Partnership. Such
person must also demonstrate that he or she has sufficient investment experience
and expertise to evaluate the risks and merits of an investment
in the Partnership.
Participation in the Partnership is intended only for those persons willing
to assume the risk of a speculative, illiquid, long-term investment.
Entitlement to and maintenance of the exemptions from registration provided by
Sections 3(b) and/or 4(2) of the Securities Act of 1933, as amended, require the
imposition of certain limitations on the persons to whom offers may be made, and
from whom subscriptions may be accepted. Therefore, this offering is limited to
persons who, by virtue of investment acumen or financial resources, satisfy the
General Partner that they meet suitability standards consistent with the
maintenance and preservation of the exemptions provided by Sections 3(b) and/or
4(2) and by the applicable rules and regulations of the Securities and Exchange
Commission, as well as those contained herein and in the Subscription Agreement.
Persons offering interests shall sufficiently inquire of a prospective investor
to be reasonably assured that such investor meets such acceptable standards.
Suitability standards may also be imposed by the regulatory authorities of the
various states in which interests may be offered.
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<PAGE>
RELATIONSHIP OF THE PARTNERSHIP,
THE GENERAL PARTNER AND AFFILIATES
The following diagram depicts the primary relationships among the
Partnership, the General Partner and certain of its affiliates.
UNIT CORPORATION
----------------
|
|
|------------------|-------------------|
| |
Unit Petroleum Company Unit Drilling Company
---------------------- ---------------------
| General Partner
| ---------------
|
|
|
Unit 1999 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 1999. 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 1999 and (ii) serving as a co-general partner in any
drilling or income programs, or both, formed by the General Partner or UNIT
during 1999.
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, 1999, or the time of the
formation of the Partnership if subsequent to January 1, 1999, until December
31, 1999, except for wells, if any:
(i) drilled outside the 48 contiguous United States;
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<PAGE>
(ii) drilled as part of secondary or tertiary recovery operations which
were in existence prior to formation of the Partnership;
(iii) drilled by third parties under farm-out or similar arrangements
with UNIT or the General Partner or whereby UNIT or the General
Partner may be entitled to an overriding royalty, reversionary or
other similar interest in the production from such wells but is not
obligated to pay any of the Drilling Costs thereof;
(iv) acquired by UNIT or the General Partner through the acquisition by
UNIT or the General Partner of, or merger of UNIT or the General
Partner with, other companies (However, this exception may, at the
discretion of Unit or the General Partner, be waived); or
(v) with respect to which the General Partner does not believe that the
potential economic return therefrom justifies the costs of
participation by the Partnership.
Instances referred to in (v) could occur when UNIT or one of its subsidiaries
agrees to participate in the ownership of a prospect for its own account in
order to obtain the contract to drill the well thereon. There may be situations
where the potential economic return of the well alone would not be sufficient to
warrant participation by UNIT but when considered in light of the revenues
expected to be realized as a result of the drilling contract, such participation
is desirable from UNIT's standpoint. However, in such a situation, the
Partnership would not be entitled to any of the revenues generated by the
drilling contract so its participation in the well would not be desirable.
For these purposes, the drilling of a well will be deemed to have commenced
on the "spud date," i.e., the date that the drilling rig is set up and actual
drilling operations are commenced. Any clearing or other site
preparation operations will not be considered part of the drilling operations
for these purposes.
Participation in Drilling or Income Programs. Except for certain limited
exceptions it is anticipated that the Partnership will participate with UPC or
UNIT as a co-general partner of any drilling or income programs, or both, formed
by UPC or UNIT and its affiliates during 1999. The Partnership will be charged
with 5% of the total costs and expenses charged to the general partners and
allocated 5% of the revenues allocable to the general partners in any such
program and UPC or UNIT will be charged with the remaining 95% of the general
partners' share of costs and expenses and allocated the remaining 95% of the
general partners' share of program revenues.
UNIT or its affiliates formed drilling programs for outside investors from
1979 through 1984. In 1987, the Unit 1986 Energy Income Limited Partnership
(the "1986 Energy Program") was formed primarily to acquire interests in
producing oil and gas properties. See "PRIOR ACTIVITIES". All of the
programs were formed as limited partnerships and interests in 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
1998. Although it does not currently contemplate doing so, UNIT may form such
drilling or income programs during 1999. If such a program is formed, there
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<PAGE>
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 1999 for outside investors would likely have some amount of "promote"
for the general partner(s).
Any income program may use the same or a similar format as that used for
the 1986 Partnership. In the 1986 Partnership, virtually all partnership costs
and expenses other than property acquisition costs are allocated to the partners
in the same percentages that partnership revenue is being shared at the time
such expenses are incurred, with property acquisition costs and certain other
expenses being charged 85% to the accounts of the limited partners and 15% to
the accounts of the general partners. Partnership revenue in the 1986
Partnership is allocated 85% to the limited partners' accounts and 15% to the
general partners' accounts until program payout (as defined in the agreement of
limited partnership for the 1986 Partnership). After program payout, the
percentages of partnership revenue allocable to the respective accounts of the
partners depend upon the length of the period during which program payout occurs
and range from 60% to the limited partners' accounts and 40% to the general
partners' accounts to 85% to the limited partners' accounts and 15%
to the general partners' accounts.
As co-general partners of any drilling or income programs that may be
formed by UNIT and/or UPC during 1999 and participated in by the Partnership,
UNIT and/or UPC and the Partnership will share the costs, expenses and revenues
allocable to the general partners on a proportionate basis, 95% for the account
of UNIT and/or UPC and 5% for the account of the Partnership. The Partnership
will not receive any portion of any management fees payable to the general
partners nor any fees or payments for supervisory services which UNIT or UPC may
render to such programs as operator of program wells or other fees and payments
which UNIT or UPC may be entitled to receive from such programs for services
rendered to them or goods, materials, equipment or other property sold to them.
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 1999 nor can it predict what
producing properties, if any, will be acquired by it during 1999. 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"
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<PAGE>
Exploratory Wells which are located in areas where production has been
established and where objective horizons have produced from similar geological
features in the vicinity. Based on UNIT's historical profile of its drilling
operations, it is presently anticipated that the portion of the Aggregate
Subscription expended for Partnership drilling operations (see "APPLICATION OF
PROCEEDS") will be spent approximately 7% on Exploratory Wells and 93% on
Development Wells. However, these percentages may vary significantly.
Certain of the Partnership's Development Wells may be drilled on prospects
on which initial drilling operations were conducted by the General Partner or
UNIT prior to the formation of the Partnership. Further, certain of the
Partnership Wells will be drilled on prospects on which the General Partner,
UNIT or possibly future employee programs may conduct additional drilling
operations in years subsequent to 1999. In either instance, the Partnership
will have an interest only in those wells begun in 1999 and will have no rights
in production from wells commenced in years other than 1999 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 1999, UNIT, UPC or possibly future employee programs will acquire additional
interests in wells participated in by the Partnership. In such event the
Partnership will generally not be entitled to share in the acquisition of such
additional interests. With respect to the acquisition of producing properties,
UNIT will endeavor to diversify its investments by acquiring properties located
in differing geographic locations and by balancing its investments between
properties having high rates of production in early years and properties with
more consistent production over a longer term. See "CONFLICTS OF INTERESTS -
Acquisition of Properties and Drilling Operations."
Partnership Objectives
The Partnership is being formed to provide eligible employees and directors
the opportunity to participate in the oil and gas exploration and producing
property acquisition activities of UNIT during 1999. 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 1999.
Areas of Interest
The Agreement authorizes the Partnership to engage in oil and gas
exploration, drilling and development operations and to acquire producing oil
and gas properties anywhere in the United States, but the areas presently under
consideration are located in the states of Oklahoma, Texas, Louisiana, Kansas,
Arkansas, Colorado, Montana, North Dakota and Wyoming. It is possible that the
Partnership may drill in inland waterways, riverbeds, bayous or marshes but no
drilling in the open seas will be attempted. Plans to conduct drilling and
development operations or to acquire producing properties in certain of these
states may be abandoned if attractive prospects cannot be obtained upon
satisfactory terms or if the Partnership is not fully subscribed.
Transfer of Properties
In the case of wells drilled or producing properties acquired by the
Partnership and UPC or UNIT for their own accounts and not through another
29
<PAGE>
drilling or income program, the Partnership will acquire from UPC or UNIT a
portion of the fractional undivided working interest in the properties or
portions thereof comprising the spacing unit on which a proposed Partnership
Well is to be drilled or on which a producing Partnership Well is located, and
UPC or UNIT will retain for its own account all or a portion of the remainder
of such working interest. Such working interests will be sold to the
Partnership for an amount equal to the Leasehold Acquisition Costs attributable
to the interest being acquired. Neither UNIT nor its affiliates will retain any
overrides or other burdens on the working interests conveyed to the Partnership,
and the respective working interests of UPC or UNIT and the Partnership in a
property will bear their proportionate shares of costs and revenues.
The Partnership's direct interest in a property will only encompass the
area included within the spacing unit on which a Partnership Well is to be
drilled or on which a producing Partnership Well is located, and, in the case of
a Partnership Well to be drilled, it will acquire that interest only when the
drilling of the well is ready to commence. If the size of a spacing unit is
ever reduced, or any subsequent well in which the Partnership has no interest is
drilled thereon, the Partnership will have no interest in any additional wells
drilled on properties which were part of the original spacing unit unless such
additional wells are commenced during 1999. If additional interests in
Partnership Wells are acquired in years subsequent to 1999 the Partnership will
generally not be entitled to participate or share in the acquisition of such
additional interests. In addition, if the Partnership Well drilled on a spacing
unit is dry or abandoned, the Partnership will not have an interest in any
subsequent or additional well drilled on the spacing unit unless it is commenced
during 1999. The Partnership will never own any significant amounts of
undeveloped properties or have an occasion to sell or farm out any undeveloped
Partnership Properties.
Transfers of properties to any drilling or income programs of which the
Partnership serves as a general partner will be governed by the provisions of
the agreement of limited partnership in effect with respect thereto. If any
such program is to be offered publicly, those provisions will have to be
consistent with the provisions contained in the Guidelines for the Registration
of Oil and Gas Programs adopted by the North American Securities Administrators
Association, Inc.
Record Title to Partnership Properties
Record title to the Partnership Properties will be held by the General
Partner. However, the General Partner will hold the Partnership Properties as a
nominee for the Partnership under a form of nominee agreement to be entered into
between the General Partner and the Partnership. Under the form of nominee
agreement, the General Partner will disclaim any beneficial interest in the
Partnership Properties held as 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").
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<PAGE>
Conduct of Operations
The General Partner will have full, exclusive and complete discretion and
control over the management, business and affairs of the Partnership and will
make all decisions affecting the Partnership Properties. To the extent that
Partnership funds are reasonably available, the General Partner will cause the
Partnership to (1) test and investigate the Partnership Properties by
appropriate geological and geophysical means, (2) conduct drilling and
development operations on such Partnership Properties as it deems appropriate
in view of such testing and investigation, (3) attempt completion of wells so
drilled if in its opinion conditions warrant the attempt and (4) properly equip
and complete productive Partnership Wells. The General Partner will also cause
the Partnership's productive wells to be operated in accordance with sound and
economical oil and gas recovery practices.
The General Partner will operate certain drilling and productive wells on
behalf of the Partnership in accordance with the terms of the Agreement (see
"COMPENSATION"). In those cases, execution of separate operating agreements
will not be necessary unless third party owners are involved, e.g., fractional
undivided interest Partnership Properties and Partnership Properties that are
pooled or unitized with other properties owned by third parties. In such cases,
and in all cases where Partnership Properties are operated by third parties, the
General Partner will, where appropriate, make or cause to be made and enter into
operating agreements, pooling agreements, unitization agreements, etc., in the
form in general use in the area where the affected property is located. The
General Partner is also authorized to execute production sales contracts on
behalf of the Partnership.
APPLICATION OF PROCEEDS
The Aggregate Subscription will be used to pay costs and expenses incurred
in the operations of the Partnership which are chargeable to the Limited
Partners. The organizational costs of the Partnership and the offering costs of
the Units will be paid by the General Partner.
If all 600 Units offered hereby are sold, the proceeds to the Partnership
would be $600,000. If the minimum 50 Units are sold, the proceeds to the
Partnership would be $50,000. The General Partner estimates that the gross
proceeds will be expended as follows:
$600,000 Program $50,000 Program
---------------- ------------------
Percent Amount Percent Amount
------- -------- ------- --------
Leasehold Acquisition Costs
of Properties to Be Drilled... 5% $ 30,000 5% $ 2,500
Drilling Costs of Exploratory
Wells......................... 5% 30,000 5% 2,500
Drilling Costs of Develop-
ment Wells.................... 70% 420,000 70% 35,000
Leasehold Acquisition Costs
of Productive Properties...... 20% 120,000 20% 10,000
Total......................... 100% $600,000 100% $50,000
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The foregoing allocation between Drilling Costs and Leasehold Acquisition
Costs is solely an estimate and the actual percentages may vary materially from
this estimate. Funds otherwise available for drilling Exploratory Wells will be
reduced to the extent that such funds are used in conducting development
operations in which the Partnership participates.
Until Capital Contributions are invested in the Partnership's operations,
they will be temporarily deposited, with or without interest, in one or more
bank accounts of the Partnership or invested in short-term United States
government securities, money market funds, bank certificates of deposit or
commercial paper rated as "A1" or "P1" as the General Partner deems advisable.
Partnership funds other than Capital Contributions may be commingled with the
funds of the General Partner or UNIT.
PARTICIPATION IN COSTS AND REVENUES
All costs of organizing the Partnership and offering Units therein will be
paid by the General Partner. All costs incurred in the offering and syndication
of any drilling or income program formed by UPC or UNIT and its affiliates
during 1999 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, 1999 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, 1999 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
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<PAGE>
such costs and expenses proves to be higher than the actual costs and expenses,
the General Partner will continue to bear Partnership costs and expenses that
would otherwise have been chargeable to the Limited Partners until the
total Partnership costs and expenses charged to it (including, without
limitation, offering and organizational costs, Operating Expenses, general and
administrative overhead costs and reimbursements and Special Production and
Marketing Costs as well as Leasehold Acquisition Costs and Drilling Costs) since
the formation of the Partnership equals the General Partner's Minimum Capital
Contribution. In addition to actual contributions of cash or properties, any
Partner will be deemed to have contributed amounts of Partnership Revenues
allocated to it which are used to pay its share of Partnership costs and
expenses.
The following table presents a summary of the allocation of Partnership
costs, expenses and revenues between the General Partner and the Limited
Partners:
COSTS AND EXPENSES General Partner Limited Partners
--------------- ----------------
. Organizational and offering costs
of the Partnership and any drilling
or income programs in which the
Partnership participates as a
co-general partner 100% 0%
. All other Partnership Costs and
Expenses:
. Prior to time Limited Partner
Capital Contributions are
entirely expended 1% 99%
. After expenditure of Limited
Partner Capital Contributions
and until expenditure of
General Partner's Minimum
Capital Contribution 100% 0%
. After expenditure of General General Partner's Limited Partners'
Partner's Minimum Capital Percentage Percentage
Contribution
REVENUES General Partner's Limited Partners'
Percentage Percentage
COMPENSATION
Supervision of Operations
It is anticipated that the General Partner will operate most, if not all,
Partnership Properties during the drilling of Partnership Wells and most, if not
all, productive Partnership Wells. For the General Partner's services performed
as operator, the Partnership will compensate the General Partner its pro rata
portion of the compensation due to the General Partner under the operating
agreements, if any, in effect with respect to such wells or, if none is in
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<PAGE>
effect for such wells, at rates no higher than those normally charged in the
same or a comparable geographic area by non-affiliated persons or companies
dealing at arm's length.
That portion of the General Partner's general and administrative overhead
expense that is attributable to its conduct of the actual and necessary
business, affairs and operations of the Partnership will be reimbursed
by the Partnership out of Partnership Revenue. The General Partner's general
and administrative overhead expenses are determined in accordance with industry
practices. The costs and expenses to be allocated include all customary and
routine legal, accounting, geological, engineering, travel, office rent,
telephone, secretarial, salaries, data processing, word processing and other
incidental reasonable expenses necessary to the conduct of the Partnership's
business and generated by the General Partner or allocated to it by UNIT, but
will not include filing fees, commissions, professional fees, printing costs and
other expenses incurred in forming the Partnership or offering interests
therein. The amount of such costs and expenses to be reimbursed with respect
to any particular period will be determined by allocating to the Partnership
that portion of the General Partner's total general and administrative overhead
expense incurred during such period which is equal to the ratio of the
Partnership's total expenditures compared to the total expenditures by the
General Partner for its own account. The portion of such general and
administrative overhead expense reimbursement which is charged to the Limited
Partners may not exceed an amount equal to 3% of the Aggregate Subscription
during the first 12 months of the Partnership's operations, and in each
succeeding twelve-month period, the lesser of (a) 2% of the Aggregate
Subscription and (b) 10% of the total Partnership Revenue realized in such
twelve-month period. Administrative expenses incurred directly by the
Partnership, or incurred by the General Partner on behalf of the Partnership and
reimbursable to the General Partner, such as legal, accounting, auditing,
reporting, engineering, mailing and other such fees, costs and expenses are not
considered a part of the general and administrative expense reimbursed to the
General Partner and the amounts thereof will not be subject to the limitations
described in the preceding sentence.
Purchase of Equipment and Provision of Services
UNIT, through its subsidiary Unit Drilling Company, will probably perform
significant drilling services for the Partnership. In addition, UNIT owns a 40%
interest in Superior Pipeline Company, L.L.C., an Oklahoma limited liability
company, which may build or own an interest in certain gathering systems
through which a portion of the Partnership's gas production is transported.
These persons are in the business of supplying such equipment and services
to non-affiliated parties in the industry and any such equipment and such
services will be acquired or provided at prices or rates no higher than those
normally charged in the same or comparable geographic area by non-affiliated
persons or companies dealing at arms' length. Production purchased by any
affiliate of UNIT will be for prices which are not less than the highest posted
price (in the case of crude oil) or prevailing price (in the case of natural
gas) in the same field or area.
UNIT or one of its affiliates may provide other goods or services to the
Partnership in which event the compensation received therefor will be subject to
the same restrictions and conditions described above and under "CONFLICTS OF
INTEREST" below.
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<PAGE>
Prior Programs
UNIT was formed in 1986 in connection with a major reorganization and
recapitalization whereby UNIT acquired all of the assets and liabilities of all
of the limited partnerships formed by UNIT's predecessor, Unit Drilling and
Exploration Company ("UDEC"), during the period of 1980 through 1983 in exchange
for shares of UNIT's common stock and UDEC was merged with a wholly owned
subsidiary of UNIT whereby UDEC was the surviving corporation and thereby became
a wholly owned subsidiary of UNIT. UNIT has conducted one oil and gas program
since the date of its formation, the 1986 Energy Program. The 1986 Energy
Program was formed on June 12, 1987 with total subscriptions of one million
dollars. The Unit 1986 Employee Oil and Gas Limited Partnership is a co-general
partner with Unit Petroleum Company of the 1986 Energy Program. Direct
compensation charged to or paid by the partnerships and earned by the General
Partners for their services in connection with these programs through September
30, 1998, is set forth below.
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 $1,970,213 $2,302,336 $1,835,762
1980............ 200,000 261,456 1,345,158 1,810,310
1981............ 1,250,000(5) 329,695 1,892,568 4,047,260
1981-II........ 450,000 158,406 1,607,706 1,629,201
1982-A........ 634,200 521,910 1,688,024 4,110,107
1982-B........ 316,650 331,594 1,224,023 4,945,437
1983-A........ 50,600 151,289 698,597 695,255
1984............ -- 230,146 750,116 829,503
1984 Employee(*) -- 3,924 5,000 13,452
1985 Employee(*) -- 10,316 -- 54,892
1986 Employee(*) -- 23,505 -- 59,446
1986 Energy
Income Fund(**) -- 188,818 795,062 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 -- 323,212 -- 144,722
1992 Employee -- 79,198 -- 14,861
1993 Employee -- 43,668 -- 68,504
Consolidated
Program(*) -- 79,494 -- --
1994 Employee -- 51,017 -- 40,507
1995 Employee -- 29,657 -- 33,586
1996 Employee -- 25,900 -- 112,830
1997 Employee -- 11,266 -- 222,815
1998 Employee -- 1,134 -- 143,940
_____________
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<PAGE>
(*) 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 -1998 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 1985-1998 Employee
Programs provides that the General Partner is entitled to
reimbursement for the general administrative and overhead expenses
attributable to each of such programs, the General Partner has to date
elected not to seek such reimbursement. However, there can be no
assurance that the General Partner will continue to forego such
reimbursement in the future.
(5) Includes a special allocation of gross revenues totaling $500,000.
MANAGEMENT
The General Partner
UNIT was formed in 1986 in connection with a major reorganization and
recapitalization whereby UNIT acquired all of the assets and liabilities of all
of the limited partnerships formed by UNIT's predecessor, UDEC, during the
period of 1980 through 1983 in exchange for shares of UNIT's common stock and
UDEC was merged with a wholly owned subsidiary of UNIT whereby UDEC was the
surviving corporation and thereby became a wholly owned subsidiary of UNIT. UPC
was incorporated in the State of Oklahoma on February 9, 1984 as Sunshine
Development Corporation ("SDC"). On October 8, 1985 pursuant to the terms
of a Stock Purchase Agreement," UDEC purchased all of the issued and outstanding
stock of SDC whereby SDC became a wholly owned subsidiary of UDEC. On February
1, 1988, pursuant to the terms of an "Amended and Restated Certificate of
Incorporation", SDC was renamed Unit Petroleum Company.
UPC's as well as UNIT's, principal office is at 1000 Kensington Tower I,
7130 South Lewis Avenue, Tulsa, Oklahoma 74136 and its telephone number is (918)
493-7700. UNIT through its various subsidiaries is engaged in the onshore
contract drilling of oil and gas wells and in the exploration for and production
of oil and gas. Unless the context otherwise requires, references in this
Memorandum to UNIT include its predecessor as well as all or any of its
subsidiaries.
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<PAGE>
Officers, Directors and Key Employees
The Partnership will have no directors or officers. The directors of the
General Partner are elected annually and serve until their successors are
elected and qualified. Directors of UNIT are elected at the Annual Meeting of
Shareholders for a staggered term of three years each, or until their successors
are duly elected and qualified. The executive officers of the General Partner
are elected by and serve at the pleasure of its Board of Directors. The names,
ages and respective positions of the directors and executive officers of
UNIT are as follows:
Name Age Position
---- --- --------
King P. Kirchner 71 Chairman of the Board and
Chief Executive Officer
John G. Nikkel 63 President, Chief Operating
Officer and Director
O. Earle Lamborn 63 Senior Vice President,
Drilling and Director
Philip M. Keeley 57 Senior Vice President,
Exploration and Production
Larry D. Pinkston 44 Vice President, Treasurer
and Chief Financial Officer
Mark E. Schell 41 Secretary and General Counsel
William B. Morgan 54 Director
Don Cook 73 Director
John S. Zink 70 Director
John H. Williams 80 Director
J. Michael Adcock 49 Director
The names, ages and respective positions of the directors and executive
officers of UPC are as
follows:
Name Age Position
---- --- --------
King P. Kirchner 71 Chairman of the Board
John G. Nikkel 63 President and Director
Philip M. Keeley 57 Vice President and Director
Mark E. Schell 41 Secretary, General Counsel
and Director
Larry D. Pinkston 44 Treasurer
37
<PAGE>
Mr. Kirchner, a co-founder of UNIT, has been the Chairman of the Board and
a director since 1963 and was President until November 1983. Mr. Kirchner is a
Registered Professional Engineer within the State of Oklahoma, having received
degrees in Mechanical Engineering from Oklahoma State University and in
Petroleum Engineering from the University of Oklahoma.
Mr. Nikkel joined UNIT in 1983 as its President and a director. From 1976
until January 1982 when he co-founded Nike Exploration Company, Mr. Nikkel was
an officer and director of Cotton Petroleum Corporation, serving as the
President of the Company from 1979 until his departure. Prior to joining
Cotton, Mr. Nikkel was employed by Amoco Production Company for 18 years, last
serving as Division Geologist for Amoco's Denver Division. Mr. Nikkel presently
serves as President and a director of Nike Exploration Company. Mr. Nikkel
received a Bachelor of Science degree in Geology and Mathematics from Texas
Christian University.
Mr. Lamborn has been actively involved in the oil field for over 45 years,
joining UNIT's predecessor in 1952 prior to its becoming a privately-held
corporation. He was elected Vice President, Drilling in 1973 and to his current
position as Senior Vice President, Drilling and director in 1979.
Mr. Keeley joined UNIT in November 1983 as Senior Vice President,
Exploration and Production. Prior to that time, Mr. Keeley co-founded (with Mr.
Nikkel) Nike Exploration Company in January 1982 and serves as Executive Vice
President and a director of that company. From 1977 until 1982, Mr. Keeley was
employed by Cotton Petroleum Corporation, serving first as Manager of Land and
from 1979 as Vice President and a director. Before joining Cotton, Mr. Keeley
was employed for four years by Apexco, Inc. as Manager of Land and prior thereto
he was employed by Texaco, Inc. for nine years. He received a Bachelor of Arts
degree in Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined UNIT in December 1981. He had served as Corporate
Budget Director and Assistant Controller prior to being appointed Controller in
February 1985. He has been Treasurer since December 1986 and was elected to the
position of Vice President and Chief Financial Officer in May 1989. He holds a
Bachelor of Science Degree in Accounting from East Central University of
Oklahoma and is a Certified Public Accountant.
Mr. Schell joined UNIT in January 1987, as its Secretary and General
Counsel. From 1979 until joining UNIT, Mr. Schell was Counsel, Vice President
and a member of the Board of Directors of C&S Exploration, Inc. He received a
Bachelor of Science degree in Political Science from Arizona State University
and his Juris Doctorate degree from the University of Tulsa Law School. He is a
member of the Oklahoma and American Bar Association as well as being a member of
the American Corporate Counsel Association and the American Society of Corporate
Secretaries.
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<PAGE>
Mr. Morgan was elected a director of UNIT in February 1988. Mr. Morgan has
been Executive Vice President and General Counsel of St. John Health System,
Inc., Tulsa, Oklahoma, since March 1, 1995 and, since October 1, 1996, the
President of its principal for profit subsidiary Utica Services, Inc. Before
that, he was a Partner in the law firm of Doerner, Saunders, Daniel and
Anderson, Tulsa, Oklahoma, for over 20 years.
Mr. Cook has served as a director of UNIT since UNIT's inception. He is a
Certified Public Accountant and was a partner in the accounting firm of Finley &
Cook, Shawnee, Oklahoma, from 1950 until 1987, when he retired.
Mr. Zink was elected a director of UNIT in May 1982. For over 5 years, he
has been a principal in several privately held companies engaged in the
businesses of designing and manufacturing equipment used in the petroleum
industry, construction and heating and air conditioning services and
installation. He holds a Bachelor of Science degree in Mechanical Engineering
from Oklahoma State University. He is also a director of Matrix Service
Company, Tulsa, Oklahoma.
Mr. Williams was elected a director of UNIT in December 1988. Prior to
retiring on December 31, 1978, he was Chairman of the Board and Chief Executive
Officer of The Williams Companies, Inc. where he continues to serve as an
honorary director. Mr. Williams also serves as a director of Apco Argentina,
Inc., Westwood Corporation, and Willbros Group, Inc.
Mr. Adcock was elected a director of UNIT in December 1997. He is an
attorney and currently manages a private trust which deals in real estate, oil
and gas properties and commercial banking as well as other equity investments.
He is Chairman of the Board of Arvest American National Bank & Co. of Shawnee
and a member of the Board of Directors of Medicine Lodge Bankshares. Between
1997 through September, 1998 he was the Chairman of the Board of Ameribank and
President and Chief Executive Officer of American National Bank and Trust
Company of Shawnee, Oklahoma, and Chairman of AmeriTrust Corporation, Tulsa,
Oklahoma. Prior to holding these positions, he was engaged in the private
practice of law from January 1, 1994 though March 1, 1996 and from March 1, 1996
until November 1, 1997 he served as General Counsel of Ameribank Corporation.
Mr. Adcock was also a director of Grant Geophysical, Inc., from June 1994 until
September 1997 when he resigned. Grant Geophysical, Inc., filed a petition
under Chapter 11 of the Federal Bankruptcy Code in October, 1996.
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.
39
<PAGE>
Limited
Partners'
Capital
Name Formed Subscriptions
- ----------------------------- ----------------- -------------
Unit 1984 Employee Oil
and Gas Program April 1984 $348,000
Unit 1985 Employee Oil
and Gas Limited Partnership January 1985 $378,000
Unit 1986 Employee Oil
and Gas Limited Partnership January 1986 $307,000
Unit 1987 Employee Oil
and Gas Limited Partnership March 1987 $209,000
Unit 1988 Employee Oil
and Gas Limited Partnership April 29, 1988 $177,000
Unit 1989 Employee Oil
and Gas Limited Partnership December 30, 1988 $157,000
Unit 1990 Employee Oil
and Gas Limited Partnership January 19, 1990 $253,000
Unit 1991 Employee Oil
and Gas Limited Partnership January 7, 1991 $263,000
Unit 1992 Employee Oil
and Gas Limited Partnership January 23, 1992 $240,000
Unit 1993 Employee Oil
and Gas Limited Partnership January 21, 1993 $245,000
Unit 1994 Employee Oil
and Gas Limited partnership January 19, 1994 $284,000
Unit 1995 Employee Oil
and Gas Limited Partnership March 7, 1995 $454,000
Unit 1996 Employee Oil
and Gas Limited Partnership February 5, 1996 $437,000
Unit 1997 Employee Oil
and Gas Limited Partnership February 4, 1997 $413,000
Unit 1998 Employee Oil
and Gas Limited Partnership February 19, 1998 $471,000
One-half of the capital subscriptions from all limited partners were
required to be paid in the 1984 Employee Program, three-fourths of the capital
subscriptions from all limited partners were required to be paid in the 1985
Employee Program and the 1986 Employee Program. All of the capital
subscriptions from all limited partners, including those shown below, were
40
<PAGE>
required to be paid in the 1987 through 1998 Employee Programs. The capital
subscriptions of the following limited partners to the 1996, 1997 and 1998
Employee Programs were as shown below:
Amount of Capital
Subscription
Position with -----------------------------------
Subscriber UNIT 1996 1997 1998
- ---------------- -------------------------- ----------- ----------- -----------
King P. Kirchner Chairman of the Board and $50,000(1) $50,000(1) $50,000(1)
Chief Executive Officer
John G. Nikkel President, Chief Operating $107,120(2) $117,120(2) $143,400(2)
Officer and Director
Philip M. Keeley Senior Vice President, $32,880(2) $32,880(2) $38,600(2)
Exploration and Production
__________________
(1) Mr. Kirchner invested $50,000 indirectly in each of the 1996 Employee
Program, the 1997 Employee Program, and the 1998 Employee Program,
through the King P. Kirchner Revocable Trust as permitted by the
limited partnership agreement of those Employee Programs.
(2) Messrs. Nikkel and Keeley have invested in the 1996, 1997 and 1998
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 1996, 1997 and 1998 Employee Programs by Messrs. Nikkel
and Keeley are set forth below:
Nike
Employee Mr. Nikkel Mr. Keeley Exploration
Program Directly Directly Company
-------- ---------- ---------- -----------
1996 $50,000 $10,000 $80,000
1997 $60,000 $10,000 $80,000
1998 $72,000 $10,000 $100,000
Ownership of Common Stock
UNIT's Common Stock is listed on the New York Stock Exchange as reported on
the Composite Tape. On December 17, 1998 there were 25,563,165 shares
outstanding.
As of December 17, 1998, 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 Outstanding
------------------- ------ -----------
Neuberger & Berman, LLC
605 Third Avenue 1,306,800(1) 5.1
New York, New York 10158-3698
41
<PAGE>
(1) This information is based on Schedule 13G, dated February 12, 1998,
filed by this person with the Securities and Exchange Commission.
As of December 17, 1998, the directors and officers of UNIT owned of
record or beneficially owned shares of UNIT Common Stock as follows:
Amount of
Beneficial % of
Name Ownership (1) Outstanding(1)
---------------- ---------- -----------
King P. Kirchner........... 1,155,899 (2) 4.5
John Williams.............. 18,500 (3) *
Don Cook................... 23,138 (3) *
Philip M. Keeley........... 210,961 (2)(4) *
O. Earle Lamborn........... 311,468 (2)(4) *
John G. Nikkel............. 428,909 (2)(4) 1.6
Larry D. Pinkston.......... 136,503 (2)(4) *
Mark E. Schell............. 65,876 (2)(4) *
John S. Zink............... 58,500 (3) *
William B. Morgan.......... 20,000 (3) *
J. Michael Adcock..... ... 1,196,373 (3)(5) 4.6
All Officers and Directors
as a Group............... 3,626,127 13.9
_______________
*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 17, 1998, pursuant to the exercise of currently
exercisable stock options. For purposes of calculating the percent of the
shares outstanding held by each owner, the total number of shares excludes the
shares which all other persons have the right to acquire within 60 days after
December 17, 1998 pursuant to the exercise of currently exercisable stock
options.
(2) Includes shares of common stock held under UNIT's 401(k) thrift plan
as of December 15, 1998 for the account of: King P. Kirchner, 7,979; Earle
Lamborn, 9,753; John G. Nikkel, 28,313; Philip M. Keeley, 29,185; Larry D.
Pinkston, 14,262; and Mark E. Schell, 9,574.
(3) Includes unexercised stock options granted under UNIT's non-Employee
Directors' Stock Option Plan to each of the following, all of which are
currently exercisable at the discretion of the holder: J. Michael Adcock, 2,500;
Don Cook, 17,500; William B. Morgan, 10,000; John H. Williams, 17,500; John
S. Zink, 17,500; and all non-Employee Directors, including the estate of Mr. Don
Bodard a former Director, as a group, 72,500.
(4) Includes unexercised stock options granted under UNIT's Amended and
Restated Stock Option Plan to each of the following, all of which are currently
exercisable at the discretion of the holder: John G. Nikkel 122,460; Philip M.
Keeley, 55,500; Earle Lamborn, 64,500; Larry D. Pinkston, 36,500; and Mark E.
Schell, 36,500.
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<PAGE>
(5) Of the shares shown, Mr. J. Michael Adcock is deemed to be the
beneficial owner of 1,178,148 shares by virtue of his position as one of three
trustees of the Don Bodard 1995 Revocable Trust.
Interest of Management in Certain Transactions
Reference is made to "COMPENSATION" for a discussion of the compensation
for supervision and operation of productive wells and the reimbursement of
overhead expenses attributable to the Partnership's operations to which UNIT is
entitled under the terms of the Partnership Agreement.
CONFLICTS OF INTEREST
There will be situations in which the individual interests of the General
Partner and the Limited Partners will conflict. Although the General Partner is
obligated to deal fairly and in good faith with the Limited Partners and conduct
Partnership operations using the standards of a prudent operator in the oil and
gas industry, such conflicts may not in every instance be resolved to the
maximum advantage of the Limited Partners. Certain circumstances which will or
may involve potential conflicts of interest are as follows:
. The General Partner currently manages and in the future will sponsor and
manage oil and natural gas drilling programs similar to the Partnership.
. The General Partner will decide which prospects the Partnership will
acquire.
. The General Partner will act as operator for Partnership Wells and will,
through its affiliates, furnish drilling and/or marketing services with
respect to Partnership Wells, the terms of which have not been
negotiated by non-affiliated persons.
. The General Partner is a general partner of numerous other partnerships,
and owes duties of good faith dealing to such other partnerships.
. The General Partner and its affiliates engage in drilling, operating and
producing activities for other partnerships.
Acquisition of Properties and Drilling Operations
With certain limited exceptions it is anticipated that the Partnership will
participate in each producing property, if any, acquired by the General Partner
and in the drilling of each of the wells, if any, commenced by the General
Partner for its own account during the period commencing January 1, 1999, or
from the formation of the Partnership if subsequent to January 1, 1999, through
December 31, 1999 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;
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<PAGE>
(iii) drilled by third parties under farm-out or similar arrangements with
UNIT or the General Partner or whereby UNIT or the General Partner
may be entitled to an overriding royalty, reversionary or other
similar interest in the production from such wells but is not
obligated to pay any of the Drilling Costs thereof;
(iv) acquired by UNIT or the General Partner through the acquisition by
UNIT or the General Partner of, or merger of UNIT or the General
Partner with, other companies; 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 1999. In the
latter case, the Partnership would have no right to participate in the drilling
of such development or offset wells.
Sometimes UNIT will agree to participate in drilling operations on a
prospect which it may not believe are fully warranted from an economic
standpoint if it believes that such participation is necessary for, or will
significantly increase its chances of, obtaining a contract to drill the well
with one of its drilling rigs and the revenues from the contract make the
economics of the entire arrangement desirable from UNIT's standpoint.
In such an instance, the Partnership would not be entitled to any of the
drilling contract revenues so the General Partner will not cause the Partnership
to participate in such a well. However, an analysis of the economic potential
of any proposed well is a very inexact science and wells which have a very high
potential commonly prove to be dry or only marginally profitable and
occasionally a well with apparently very little promise may prove to be very
profitable. Thus, there can be no assurance that the General Partner will
always make the most profitable decision from the Partnership's standpoint in
determining in which of such potential wells the Partnership should or should
not participate.
Because the Partnership will acquire an interest only in those properties
comprising the spacing unit on which each Partnership Well is located, it will
not be entitled to participate in other wells drilled by the General Partner,
UNIT or any of its affiliates in the same prospect area unless the drilling of
those wells commences during the period from January 1, 1999, or from the
formation of the Partnership if subsequent to January 1, 1999, through December
31, 1999. 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, 1999, or from the formation of the
Partnership if subsequent to January 1, 1999, through December 31, 1999.
Likewise the Partnership would have no interest in any increased density wells
drilled on the original spacing unit unless such wells were drilled during 1999.
In addition, if additional interests are acquired in wells participated in
by the Partnership after 1999, 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
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<PAGE>
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 1999, it is anticipated
that the Partnership will serve as a co-general partner with UNIT in any such
drilling or income programs, or both. As the other co-general partner of any
such drilling or income program, UNIT would have exclusive management and
control over the business, operations and affairs of the drilling or income
program. Conflicts of interest may arise between the limited partners and the
general partners of such drilling or income program and it is possible that UNIT
may elect to resolve those conflicts in favor of the limited partners. Further,
if any such drilling or income program is offered publicly, the program
agreement will be required to contain a number of provisions concerning the
conduct of program operations and handling conflicts of interests required by
the Guidelines for the Registration of Oil and Gas Programs adopted by the North
American Securities Administrators Association, Inc. Such provisions may
significantly reduce the flexibility of UNIT in managing such programs or may
affect the profitability of the program operations or the transactions between
the general partners and the program.
Transfer of Properties
The General Partner or its affiliates are authorized to transfer interests
in oil and gas properties to the Partnership, in which case the General Partner
or its affiliate will receive an amount equal to the Leasehold Acquisition Costs
attributable to the interests being acquired by the Partnership in the spacing
unit on which the Partnership Well is located or is to be drilled. The amount
of the Leasehold Acquisition Costs attributable to the fractional undivided
interest in a property transferred to the Partnership by the General Partner or
any affiliate shall not be reduced or offset by the amount of any gain or profit
the General Partner or its affiliate might have realized by any prior sale or
transfer of a fractional undivided interest in the property to an unaffiliated
third party for a price in excess of the portion of the Leasehold Acquisition
Costs of the property that is attributable to the transferred interest. The
Partnership will not be reimbursed for or refunded any Leasehold Acquisition
Costs if the size of a spacing unit on which a Partnership Well is located or
drilled is reduced even though the Partnership will have no interest in any
subsequent wells drilled on the area encompassed by the original spacing unit
unless they are commenced during 1999.
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;
45
<PAGE>
(2) the obligations of the Partnership with respect to the properties will
be substantially the same proportionately as those of the General
Partner or its affiliates at the time it acquired the properties; and
(3) the Partnership's interest in revenues will not be less than the
proportionate interest therein of the General Partner or its
affiliates when it acquired the properties.
With respect to the General Partner or its affiliates' remaining interest, it
may retain such interest for its own account or it may sell, transfer, farm-out
or otherwise convey all or a portion of such remaining interest to non-
affiliated industry members, which may occur either before or after the transfer
of the interests in the same properties to the Partnership. The General Partner
or its affiliates may realize a profit on the interests or may be carried to
some extent with respect to its cost obligations in connection with any drilling
on such properties and any such profit or interests will be strictly for the
account of the General Partner or its affiliates and the Partnership will have
no claim with respect thereto. The General Partner or its affiliates may not
retain any overrides or other burdens on the property conveyed to the
Partnership (other than overriding royalty interests granted to geologists and
other persons employed or retained by the General Partner or its affiliates) and
may not enter into any farm-out arrangements with respect to its retained
interest except to non-affiliated third parties or other programs managed by the
General Partner or its affiliates.
Partnership Assets
The General Partner will not take any action with respect to assets or
property of the Partnership which does not benefit primarily the Partnership as
a whole. The General Partner will not utilize the funds of the Partnership as
compensating balances for the benefit of the General Partner or its affiliates.
All benefits from marketing arrangements or other relationships affecting
property of the Partnership will be fairly and equitably apportioned according
to the respective interests of the Partnership and the General Partner.
The Partnership Agreement provides that when the Partnership is terminated,
there will be an accounting with respect to its assets, liabilities and
accounts. The Partnership's physical property and its oil and gas properties
may be sold for cash. Except in the case of an election by the General Partner
to terminate the Partnership before the tenth anniversary of the Effective Date,
Partnership Properties may be sold to the General Partner or any of its
affiliates for their fair market value as determined in good faith by the
General Partner.
Transactions with the General Partner or Affiliates
UNIT provides through its subsidiary Unit Drilling Company contract
drilling services in the ordinary course of its business. UNIT also owns a 40%
interest in Superior Pipeline Company, L.L.C. which is engaged in the business
of buying and building gas gathering systems. It is anticipated that the
Partnership will obtain services, equipment and supplies from one or both of
such persons. In addition, UNIT may supply other goods or services to the
Partnership. The terms of any contracts or agreements between the Partnership
and UNIT or any affiliate will be no less favorable to the Partnership than
those of comparable contracts or agreements entered into, and will be at prices
not in excess of (or in the case of purchases of production, less than) those
charged in the same geographical area, by non-affiliated persons or companies
dealing at arm's length.
46
<PAGE>
For its services as a drilling contractor, Unit Drilling Company will
charge the Partnership on either a daywork (a specified per day rate for each
day a drilling rig is on the drill site), a footage (a specified rate per foot
drilled) or a turnkey (specified amount for drilling the well) basis. The rate
charged by Unit Drilling Company for such services will be the same as those
offered to unaffiliated third parties in the same or similar geographic areas.
Right of Presentment Price Determination
Under the terms of the Partnership Agreement, a Limited Partner can,
subject to certain conditions, require the General Partner to purchase his or
her Units at a price determined by the application of a stated formula to the
estimated future net revenues attributable to the Partnership's estimated proved
reserves. See "TERMS OF THE OFFERING - Right of Presentment." It is
anticipated that if an independent engineering firm makes an evaluation of the
proved reserves of the Partnership, the result of that evaluation will be used
in determining the price to be paid to a Limited Partner exercising his or her
right of presentment. However, if no such independent evaluation is made, the
right of presentment purchase price will be determined by using the proved
reserves and future net revenue estimates of the technical staff of the General
Partner.
Receipt of Compensation Regardless of Profitability
The General Partner is entitled to receive its fees and other compensation
and reimbursements from the Partnership regardless of whether the Partnership
operates at a profit or loss. See "PARTICIPATION IN COSTS AND REVENUES" and
"COMPENSATION." Such fees, compensation and reimbursements will decrease the
Limited Partners' share of any profits generated by operations of the
Partnership or increase losses if such operations should prove unprofitable.
Legal Counsel
Conner & Winters, A Professional Corporation, serves as special legal
counsel for the General Partner. Such firm has performed legal services for the
General Partner and UNIT and is expected to render legal services to the
Partnership. Although such firm has indicated its intention to withdraw from
representation of the Partnership if conflicts of interest do in fact arise,
there can be no assurance that representation of both the General Partner or
UNIT and the Partnership by such firm will not be disadvantageous to the
Partnership.
FIDUCIARY RESPONSIBILITY
General
Under Oklahoma law, the General Partner will have a fiduciary duty to the
Limited Partners and consequently must exercise good faith, fairness and loyalty
in the handling of the Partnership's affairs. The General Partner must provide
Limited Partners (or their representatives) with timely and full information
concerning matters affecting the business of the Partnership. Each Limited
Partner may inspect the 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.
47
<PAGE>
Regardless of the fiduciary obligations of the General Partner, the General
Partner, UNIT or its affiliates, subject to any restrictions or requirements set
forth in the Agreement, may:
. engage independently of the Partnership in all aspects of the oil and
gas business, either for their own accounts or for the accounts of
others;
. sell interests in oil and gas properties held by them to, purchase oil
and gas production from, and engage in other transactions with, the
Partnership;
. serve as general partner of other oil and gas drilling or income
partnerships, including those which may be in competition with the
Partnership; and
. engage in other activities that may involve conflicts of interest.
See "CONFLICTS OF INTEREST." Thus, unlike the strict duty of a fiduciary who
must act solely in the best interests of his or her beneficiary, the Agreement
permits the General Partner to consider, among other things, the interests of
other partnerships sponsored by the General Partner, UNIT or its affiliates in
resolving investment and other conflicts of interest. The foregoing provisions
permit the General Partner to conduct its own operations and to act as the
general partner of more than one similar partnership or investment program and
for the Partnership to benefit from its experience resulting therefrom, but
relieves the General Partner of the strict fiduciary duty of a general partner
acting as such for only one investment program at a time. These provisions are
primarily intended to reconcile the applicable duties under Oklahoma law with
the fact that the General Partner will manage and administer its own oil and gas
operations and a number of other oil and gas investment programs with which
possible conflicts of interests may arise and resolve such conflicts in a manner
consistent with the expectation of the investors in all such programs, the
General Partner's fiduciary duties and customary business practices and statutes
applicable thereto.
Liability and Indemnification
The Agreement provides that the General Partner will perform its duties in
an efficient and businesslike manner with due caution and in accordance with
established practices of the oil and gas industry. The Agreement further
provides that the General Partner and its affiliates will not be liable to the
Partnership or the Partners, and will be indemnified by the Partnership, for any
expense (including attorney fees), loss or damage incurred by reason of any act
or omission performed or omitted in good faith in a manner reasonably believed
by the General Partner or its affiliates to be within the scope of authority and
in the best interest of the Partnership or the Partners unless the General
Partner or its affiliates is guilty of gross negligence or willful misconduct.
While not totally certain under Oklahoma law, absent specific provisions in the
partnership agreement to the contrary, a general partner of a limited
partnership may be liable to its limited partners if it fails to conduct the
partnership affairs with the same amount of care which ordinarily prudent
persons would use in similar circumstances. Consequently, the Agreement may be
viewed as requiring a lesser standard of duty and care than what Oklahoma law
might otherwise require of the General Partner.
48
<PAGE>
Any claim against the Partnership for indemnification must be satisfied
only out of Partnership assets including insurance proceeds, if any, and none of
the Limited Partners will have personal liability therefor.
The Limited Partners may have more limited rights of action than they would
have absent the liability and indemnification provisions above. Moreover,
indemnification enforced by the General Partner under such provisions will
reduce the assets of the Partnership. It should be noted, however, that it is
the position of the Securities and Exchange Commission ("Commission") that any
attempt to limit the liability of a general partner or to indemnify a general
partner under the federal securities laws is contrary to public policy and,
therefore, unenforceable. The General Partner has been advised of the position
of the Commission.
Generally, the Limited Partners' remedy for the General Partner's breach of
a fiduciary duty will be to bring a legal action against the General Partner to
recover any damages, generally measured by the benefits earned by the General
Partner as a result of the fiduciary breach. Additionally, Limited Partners may
also be able to obtain other forms of relief, including injunctive relief. The
Act provides that a limited partner may bring an action in the name of a limited
partnership (a partnership derivative action) to recover a judgment in its favor
if general partners with authority to do so have refused to bring the action or
if an effort to cause such general partners to bring the action is not likely to
succeed.
49
<PAGE>
PRIOR ACTIVITIES
UNIT has been engaged in oil and gas exploration and development operations
since late 1974 and has conducted oil and gas drilling programs using the
limited partnership format since 1979. The following table depicts the drilling
results achieved as of September 30, 1998 by UNIT during each year since 1975.
Because of the unpredictability of oil and gas exploration in general, such
results should not be considered indicative of the results that may be achieved
by the Partnership.
Gross Wells(2) Net Wells(3)
Year Ended -------------------------- -----------------------------
July 31(1) Total Oil Gas Dry Total Oil Gas Dry
----- --- --- ---- ----- ----- ----- -----
1975 Exploratory.. 2 0 2 0 .01 0 .01 0
Development.. 4 0 2 2 .07 0 .03 .04
----- --- --- --- ----- ----- ----- -----
6 0 4 2 .08 0 .04 .04
===== === === === ===== ===== ===== =====
1976 Exploratory.. 1 0 0 1 .01 0 0 .01
Development.. 8 0 6 2 .29 0 .28 .01
----- --- --- --- ----- ----- ----- -----
9 0 6 3 .30 0 .28 .02
===== === === === ===== ===== ===== =====
1977 Exploratory.. 9 0 3 6 1.50 0 .45 1.05
Development.. 16 0 9 7 2.00 0 .70 1.30
----- --- --- --- ----- ----- ----- -----
25 0 12 13 3.50 0 1.15 2.35
===== === === === ===== ===== ===== =====
1978 Exploratory.. 8 1 1 6 1.17 .34 .15 .68
Development.. 26 0 13 13 2.64 0 .76 1.88
----- --- --- --- ----- ----- ----- -----
34 1 14 19 3.81 .34 .91 2.56
===== === === === ===== ===== ===== =====
1979 Exploratory.. 10 0 5 5 1.40 0 .76 .64
Development.. 16 1 8 7 1.99 .06 .95 .98
----- --- --- --- ----- ----- ----- -----
26 1 13 12 3.39 .06 1.71 1.62
===== === === === ===== ===== ===== =====
1980 Exploratory.. 1 0 1 0 1.28 0 .23 1.05
Development.. 10 0 8 2 3.13 0 .85 2.28
----- --- --- --- ----- ----- ----- -----
11 0 9 2 4.41 0 1.08 3.33
===== === === === ===== ===== ===== =====
50
<PAGE>
Gross Wells(2) Net Wells(3)
Year Ended -------------------------- -----------------------------
December 31(1) Total Oil Gas Dry Total Oil Gas Dry
----- --- --- ---- ----- ----- ----- -----
1981 Exploratory.. 14 1 4 9 1.12 .02 .16 .94
Development.. 66 18 29 19 7.38 2.96 1.77 2.65
----- --- --- --- ----- ----- ----- -----
Total 80 19 33 28 8.50 2.98 1.93 3.59
===== === === === ===== ===== ===== =====
1982 Exploratory.. 40 5 9 26 3.39 .60 .32 2.47
Development.... 100 22 51 27 11.70 4.70 2.71 4.29
----- --- --- --- ----- ----- ----- -----
Total 140 27 60 53 15.09 5.30 3.03 6.76
===== === === === ===== ===== ===== =====
1983 Exploratory.. 6 2 0 4 1.31 .72 0 .59
Development.... 72 18 26 28 8.01 3.45 1.17 3.39
----- --- --- --- ----- ----- ----- -----
Total 78 20 26 32 9.32 4.17 1.17 3.98
===== === === === ===== ===== ===== =====
1984 Exploratory.. 2 1 1 0 .52 .49 .03 0
Development.... 50 15 22 13 6.81 3.42 2.74 .65
----- --- --- --- ----- ----- ----- -----
Total 52 16 23 13 7.33 3.91 2.77 .65
===== === === === ===== ===== ===== =====
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
===== === === === ===== ===== ===== =====
51
<PAGE>
Gross Wells(2) Net Wells(3)
Year Ended -------------------------- -----------------------------
December 31(1) Total Oil Gas Dry Total Oil Gas Dry
----- --- --- ---- ----- ----- ----- -----
1990 Exploratory.. 5 0 2 3 1.22 0 .12 1.10
Development.. 35 11 14 10 16.53 8.38 3.52 4.63
----- --- --- --- ----- ----- ----- -----
Total 40 11 16 13 17.75 8.38 3.64 5.73
===== === === === ===== ===== ===== =====
1991 Exploratory.. 4 0 0 4 .82 0 0 .82
Development.. 28 10 9 9 15.88 8.61 3.91 3.36
----- --- --- --- ----- ----- ----- -----
Total 32 10 9 13 16.70 8.61 3.91 4.18
===== === === === ===== ===== ===== =====
1992 Exploratory.. 0 0 0 0 0 0 0 0
Development.. 18 1 11 6 5.81 1.00 3.33 1.48
----- --- --- --- ----- ----- ----- -----
Total 18 1 11 6 5.81 1.00 3.33 1.48
===== === === === ===== ===== ===== =====
1993 Exploratory.. 1 0 0 1 .10 0 0 .10
Development.. 16 9 6 1 12.48 8.98 3.32 .18
----- --- --- --- ----- ----- ----- -----
Total 17 9 6 2 12.58 8.98 3.32 .28
===== === === === ===== ===== ===== =====
1994 Exploratory.. 3 0 1 2 1.71 0 .95 .76
Development.. 57 5 40 12 25.79 4.75 14.14 6.90
----- --- --- --- ----- ----- ----- -----
Total 60 5 41 14 27.50 4.75 15.09 7.66
===== === === === ===== ===== ===== =====
1995 Exploratory.. 0 0 0 0 0 0 0 0
Development.. 45 15 24 6 14.94 4.67 8.04 2.23
----- --- --- --- ----- ----- ----- -----
Total 45 15 24 6 14.94 4.67 8.04 2.23
===== === === === ===== ===== ===== =====
1996 Exploratory.. 0 0 0 0 0 0 0 0
Development.. 70 10 51 9 32.09 7.61 20.09 4.39
----- --- --- --- ----- ----- ----- -----
Total 70 10 51 9 32.09 7.61 20.09 4.39
===== === === === ===== ===== ===== =====
1997 Exploratory.. 2 0 0 2 2.00 0 0 2.00
Development.. 80 8 58 14 35.94 4.35 23.29 8.30
----- --- --- --- ----- ----- ----- -----
Total 82 8 58 16 37.94 4.35 23.29 10.30
===== === === === ===== ===== ===== =====
52
<PAGE>
Gross Wells(2) Net Wells(3)
-------------------------- -----------------------------
Total Oil Gas Dry Total Oil Gas Dry
----- --- --- ---- ----- ----- ----- -----
Period of January 1, 1998
to September 30, 1998
Exploratory.. 1 0 1 0 .38 0 .38 0
Development.. 66 3 44 19 27.57 .31 16.53 10.73
----- --- --- --- ----- ----- ----- -----
Total 67 3 45 19 27.95 .31 16.91 10.73
===== === === === ===== ===== ===== =====
________________
(1) Except as indicated, the figures used in this table relate to wells
drilled and completed during each of the 12 month periods ended July 31 or
December 31, as the case may be. Oil wells and gas wells shown include
both producing wells and wells capable of production.
(2) "Gross Wells" refers to the total number of wells in which there was
participation by UNIT.
(3) "Net Wells" refers to the aggregate leasehold working interest of UNIT in
such wells. For example, a 50% leasehold working interest in a well
drilled represents 1.0 Gross Well, but a .50 Net Well.
Prior Employee Programs
During the period of 1979 to 1983, persons who were designated key
employees of UNIT by its board of directors participated in the Unit Key
Employee Exploration Funds (the "Funds"). These Funds were formed as general
partnerships for the purpose of participating in 10% of all of the exploration
and development operations conducted by UNIT during a specified period. Except
for the Fund formed in 1983, each of the prior Funds served as one of the
general partners in at least one of the prior drilling programs sponsored by
UNIT and was allocated 10% of the expenses and revenues allocable to the general
partners as a group. In each of these Funds the costs charged to it in
connection with its operations were financed with the proceeds of bank
borrowings and out of the Funds' share of revenues.
The 1983 Fund served as the sole capital limited partner in the Unit 1983-A
Oil and Gas Program and as such made no contribution to the capital of that
program and shared in 10% of the costs and revenues otherwise allocable to the
General Partner after the distributions to the General Partner from the program
equaled the amount of its contributions thereto plus UNIT's interest costs with
respect to the unrecovered amount of its contributions.
Because of the differences in structure, format and plan of operations
between the prior Funds and the Partnership and because of the uncertainties
which are inherent in oil and gas operations generally, the results achieved by
the prior Funds should not be considered indicative of the results the
Partnership may achieve.
53
<PAGE>
For each year from 1984 through 1998, a separate Employee Program was
formed as an Oklahoma limited partnership with UNIT or UPC as its sole general
partner (UPC now serves as the sole general partner of each of these Employee
Programs) and with eligible employees and directors of UNIT and its subsidiaries
who subscribed for units therein as the limited partners. Each Employee Program
participated on a proportionate basis (to the extent of 10% of the General
Partner's interest in each case except for the 1986 and 1987 Employee Programs,
in which case the percentage participation was 15% and the 1992-1998 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 limited partners and 45% to the general
partners. The revenue sharing terms of the Unit 1980 Oil and Gas Program were
generally 60% to the limited partners and 40% to the general partners. The
revenue sharing terms of the Unit 1981 Oil and Gas Program were generally 70% to
the limited partners and 30% to the general partners until program payout and
50% to the limited partners and 50% to the general partners thereafter. The
revenue sharing terms of the Unit 1981-II Oil and Gas Program, the Unit 1982-A
Oil and Gas Program and the Unit 1982-B Oil and Gas Program (60% to the limited
partners and 40% to the general partners) were substantially the same as those
of the Unit 1983-A Oil and Gas Program and the Unit 1984 Oil and Gas Limited
Partnership (65% to the limited partners and 35% to the general partner) except
that the general partners' cost percentage and the general partners' revenue
share in each of those prior programs could not be less than 25%. The following
tables depict the drilling results at September 30, 1998, and the economic
results at September 30, 1998 of prior oil and gas programs and the 1984-1998
Employee Programs. On September 12, 1986, in connection with a major
restructuring and recapitalization, UNIT acquired all of the assets and
liabilities of the programs formed during 1980 through 1983 and these programs
have now been dissolved. Effective December 31, 1993, pursuant to an Agreement
and Plan of Merger, dated as of December 28, 1993, all of the assets and all of
the liabilities of the 1984, 1985, 1986, 1987, 1988, 1989 and 1990 Employee
54
<PAGE>
Programs were merged with and consolidated into a new Employee Program called
the Unit Consolidated Employee Oil and Gas Limited Partnership, an Oklahoma
Limited Partnership which was formed November 30, 1993 (the "Consolidated
Program"). The Consolidated Program holds no assets other than those acquired
in the merger with the 1984 through 1990 Employee Programs. The Unit 1979 Oil
and Gas Program continues in existence as do the 1991, 1992, 1993, 1994, 1995,
1996, 1997 and 1998 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.
55
<PAGE>
DRILLING RESULTS
----------------
As of September 30, 1998
Gross Wells Net Wells
-------------------- --------------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- ----- --- --- ---- ----- ----- ----- -----
1979 Exploratory Wells 6 0 2 4 2.43 0.00 0.65 1.78
Development Wells 21 16 1 4 17.28 14.14 0.03 3.11
----- --- --- ---- ----- ----- ----- -----
Total........ 27 16 3 8 19.71 14.14 0.68 4.89
===== === === ==== ===== ===== ===== =====
1980(1) Exploratory Wells 15 2 5 8 5.65 0.50 2.14 3.01
Development Wells 32 5 15 12 12.77 1.17 5.75 5.85
----- --- --- ---- ----- ----- ----- -----
Total........ 47 7 20 20 18.42 1.67 7.89 8.86
===== === === ==== ===== ===== ===== =====
1981(1) Exploratory Wells 11 1 4 6 4.61 0.33 0.88 3.40
Development Wells 67 14 34 19 21.77 5.03 6.61 10.13
----- --- --- ---- ----- ----- ----- -----
Total........ 78 15 38 25 26.38 5.36 7.49 13.53
===== === === ==== ===== ===== ===== =====
1981-II(1) Exploratory Wells 13 1 5 7 5.21 0.25 1.12 3.84
Development Wells 45 3 29 13 9.07 0.69 4.78 3.60
----- --- --- ---- ----- ----- ----- -----
Total........ 58 4 34 20 14.28 0.94 5.90 7.44
===== === === ==== ===== ===== ===== =====
1982-A(1) Exploratory Wells 11 3 1 7 3.55 0.78 0.00 2.77
Development Wells 69 23 22 24 25.22 13.09 3.59 8.54
----- --- --- ---- ----- ----- ----- -----
Total........ 80 26 23 31 28.77 13.87 3.59 11.31
===== === === ==== ===== ===== ===== =====
1982-B(1) Exploratory Wells 4 1 1 2 2.28 0.80 0.08 1.40
Development Wells 41 16 9 16 18.60 9.47 1.01 8.12
----- --- --- ---- ----- ----- ----- -----
Total........ 45 17 10 18 20.88 10.27 1.09 9.52
===== === === ==== ===== ===== ===== =====
1983-A(1) Exploratory Wells 1 1 0 0 1.00 1.00 0.00 0.00
Development Wells 26 14 10 2 6.60 4.39 1.27 0.94
----- --- --- ---- ----- ----- ----- -----
Total........ 27 15 10 2 7.60 5.39 1.27 0.94
===== === === ==== ===== ===== ===== =====
1984 Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Development Wells 21 1 10 10 5.89 0.38 3.08 2.43
----- --- --- ---- ----- ----- ----- -----
Total........ 21 1 10 10 5.89 0.38 3.08 2.43
===== === === ==== ===== ===== ===== =====
56
<PAGE>
(1) On September 12, 1986, Unit acquired all of the assets and liabilities of
this Program and the Program has been dissolved.
EMPLOYEE PROGRAMS
-----------------
As of September 30, 1998
Gross Wells Net Wells
-------------------- --------------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- ----- --- --- ---- ----- ----- ----- -----
1984(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 25 4 12 9 .14 .02 .06 .06
----- --- --- ---- ----- ----- ----- -----
Total....... 25 4 12 9 .14 .02 .06 .06
===== === === ==== ===== ===== ===== =====
1985(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 30 8 10 12 .38 .12 .08 .18
----- --- --- ---- ----- ----- ----- -----
Total....... 30 8 10 12 .38 .12 .08 .18
===== === === ==== ===== ===== ===== =====
1986(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 18 6 8 4 .48 .12 .30 .06
----- --- --- ---- ----- ----- ----- -----
Total....... 18 6 8 4 .48 .12 .30 .06
===== === === ==== ===== ===== ===== =====
1987(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00
Empl. Development Wells 21 12 5 4 1.17 .74 .25 .18
----- --- --- ---- ----- ----- ----- -----
Total....... 21 12 5 4 1.17 .74 .25 .18
===== === === ==== ===== ===== ===== =====
1988(1) Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 29 15 9 5 1.55 1.03 .28 .24
----- --- --- ---- ----- ----- ----- -----
Total....... 29 15 9 5 1.55 1.03 .28 .24
===== === === ==== ===== ===== ===== =====
1989(1) Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 32 7 14 11 1.48 .59 .36 .53
----- --- --- ---- ----- ----- ----- -----
Total....... 32 7 14 11 1.48 .59 .36 .53
===== === === ==== ===== ===== ===== =====
1990(1) Exploratory Wells 5 0 2 3 .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
===== === === ==== ===== ===== ===== =====
57
<PAGE>
Gross Wells Net Wells
-------------------- --------------------------
Program Total Oil Gas Dry Total Oil Gas Dry
- ------- ----- --- --- ---- ----- ----- ----- -----
1991 Exploratory Wells 4 0 0 4 .08 0 0 .08
Empl. Development Wells 28 10 9 9 1.59 .86 .39 .34
----- --- --- ---- ----- ----- ----- -----
Total....... 32 10 9 13 1.67 .86 .39 .42
===== === === ==== ===== ===== ===== =====
1992 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 18 1 11 6 .29 .05 .17 .07
----- --- --- ---- ----- ----- ----- -----
Total....... 18 1 11 6 .29 .05 .17 .07
===== === === ==== ===== ===== ===== =====
1993 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 16 9 6 1 .63 .45 .17 .01
----- --- --- ---- ----- ----- ----- -----
Total....... 16 9 6 1 .63 .45 .17 .01
===== === === ==== ===== ===== ===== =====
1994 Exploratory Wells 3 0 1 2 .09 0 .05 .04
Empl. Development Wells 57 5 40 12 1.29 .24 .70 .35
----- --- --- ---- ----- ----- ----- -----
Total....... 60 5 41 14 1.38 .24 .75 .39
===== === === ==== ===== ===== ===== =====
1995 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 45 15 24 6 .74 .23 .40 .11
----- --- --- ---- ----- ----- ----- -----
Total....... 45 15 24 6 .74 .23 .40 .11
===== === === ==== ===== ===== ===== =====
1996 Exploratory Wells 0 0 0 0 0 0 0 0
Empl. Development Wells 53 7 38 8 1.24 .27 .76 .21
----- --- --- ---- ----- ----- ----- -----
Total....... 53 7 38 8 1.24 .27 .76 .21
===== === === ==== ===== ===== ===== =====
1997 Exploratory Wells 2 0 0 2 .10 0 0 .10
Empl. Development Wells 80 8 58 14 1.80 .22 1.16 .42
----- --- --- ---- ----- ----- ----- -----
Total....... 82 8 58 16 1.90 .22 1.16 .52
===== === === ==== ===== ===== ===== =====
1998 Exploratory Wells 1 0 1 0 .02 0 .02 0
Empl. Development Wells 66 3 44 19 1.38 .02 .82 .54
----- --- --- ---- ----- ----- ----- -----
Total....... 67 3 45 19 1.40 .02 .84 .54
===== === === ==== ===== ===== ===== =====
_______________
(1) Effective December 31, 1993 this Program was merged with and into
the Consolidated Program.
(2) This information is as of September 30, 1998. It is anticipated
58
<PAGE>
that this program may participate in approximately 14 additional
wells.
GENERAL PARTNERS' PAYOUT TABLE(1)
As of September 30, 1998
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, 1998
- --------------------------- ------------ ------------ ------------------
1979........................... $8,207,976 $9,967,897 $39,750
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........................... 2,273,535 1,749,563 18,150
1984 Employee(*)............... 1,542 1,745 -
1985 Employee(*)............... 2,820 1,808 -
1986 Energy Income Fund(**).... 1,356,828 1,443,101 14,359
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.................. 1,917,570 2,035,976 36,006
1992 Employee.................. 198,990 262,187 5,999
1993 Employee.................. 417,158 532,873 12,252
Consolidated Program........... 4,125 8,914 287
1994 Employee.................. 1,175,845 1,095,024 25,536
1995 Employee.................. 427,945 343,373 19,319
1996 Employee.................. 813,294 493,493 30,455
1997 Employee.................. 1,040,327 362,507 84,415
1998 Employee.................. 684,688 54,121 29,278
__________
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
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<PAGE>
LIMITED PARTNERS' PAYOUT TABLE(1)
As of September 30, 1998
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, 1998
- --------------------------- ------------ ------------ ------------------
1979........................... $13,930,231 $17,764,602 $48,635
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........................... 2,830,315 1,813,120 18,502
1984 Employee(*)............... 120,942 171,540 -
1985 Employee(*)............... 277,901 178,984 -
1986 Energy Income Fund(**).... 2,526,487 3,285,030 21,493
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.................. 504,196 543,459 9,615
1992 Employee.................. 512,529 678,110 15,465
1993 Employee.................. 385,219 494,051 11,347
Consolidated Program........... 381,119 883,353 28,580
1994 Employee.................. 476,096 449,719 10,429
1995 Employee.................. 660,716 542,382 30,386
1996 Employee.................. 499,087 304,249 18,950
1997 Employee.................. 474,407 164,091 38,201
1998 Employee.................. 368,678 29,494 15,891
__________
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
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<PAGE>
GENERAL PARTNERS' NET CASH TABLE(1)
As of September 30, 1998
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 1998 Distributed 1998
- ------------ ------------ ------------ ------------ ------------ -------------
1979........ $2,941,570 $4,701,491 $ (194) $3,767,294 $ 3,300
1980........ 2,628,978 2,629,803 - 2,635,751 -
1981........ 6,546,160 4,558,739 - 5,368,272 -
1981-II..... 4,817,145 2,169,886 - 2,609,000 -
1982-A...... 6,297,972 3,890,023 - 3,755,000 -
1982-B...... 2,565,504 1,478,120 - 1,158,000 -
1983-A...... 1,380,331 415,348 - 819,000 -
1984........ 933,798 409,826 6,079 729,916 7,700
1984
Employee(*). 874 1,077 - 1,000 -
1985
Employee(*). 2,300 1,288 - 1,035 -
1986
Energy
Income
Fund(**).... 229,082 315,355 (165) 386,653 300
1986
Employee(*). 2,698 5,108 - 4,486 -
1987
Employee(*). 357,368 548,372 - 465,800 -
1988
Employee(*). 770,272 1,161,840 - 942,800 -
1989
Employee(*). 1,010,133 752,569 - 607,900 -
1990
Employee(*). 466,272 338,281 - 266,600 -
1991
Employee.... 1,048,767 1,167,173 14,736 1,058,625 25,900
1992
Employee.... 99,181 162,245 3,211 139,200 3,400
1993
Employee.... 290,531 406,246 8,835 344,450 10,600
Consolidated
Program..... 308 5,097 154 5,022 595
1994
Employee.... 842,962 762,141 10,691 600,625 20,400
1995
Employee.... 323,192 238,620 13,870 184,550 16,900
1996
Employee.... 706,864 387,063 23,550 183,400 32,100
1997
Employee.... 976,433 298,613 68,964 64,200 43,400
1998
Employee.... 673,080 42,514 21,454 - -
61
<PAGE>
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
62
<PAGE>
LIMITED PARTNERS' NET CASH TABLE(1)
As of September 30, 1998
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 1998 Distributed 1998
- --------- ----------- ----------- ----------- --------- ---------- ---------
1979..... $ 3,000,000 $ 6,285,683 $10,120,054 $ (185) $6,008,361 $ -
1980..... 12,000,000(3) 14,469,265 3,729,906 - 760,000 -
1981..... 29,255,000(4) 32,700,741 11,395,621 - 5,335,065 -
1981-II.. 15,000,000 16,603,760 4,994,106 - 1,710,001 -
1982-A... 21,140,000 21,591,442 9,434,313 - 6,342,000 -
1982-B... 10,555,000 9,935,850 3,233,596 - 2,828,740 -
1983-A... 2,530,000 2,993,705 1,145,026 - 227,700 -
1984..... 1,575,000 2,036,287 1,019,092 6,431 667,671 9,430(5)
1984
Employee(*) 174,000 86,664 137,262 - 125,280 -
1985
Employee(*) 283,500 227,670 128,753 - 182,644 -
1986
Energy
Income
Fund(**). 1,000,000 1,075,333 1,833,876 (284) 1,654,700 2,900(6)
1986
Employee(*) 229,750 267,008 508,122 - 460,007 -
1987
Employee(*) 209,000 207,060 335,044 - 324,845 -
1988
Employee(*) 177,000 214,712 326,858 - 281,630 -
1989
Employee(*) 157,000 157,306 153,044 - 147,737 -
1990
Employee(*) 253,000 254,483 142,479 - 180,895 -
1991
Employee 253,000 273,433 312,696 3,961 290,352 7,101 (7)
1992
Employee 240,000 255,853 421,434 8,295 389,768 10,560 (8)
1993
Employee 245,000 268,479 377,311 8,195 340,795 10,780 (9)
Consolidated - 30,721 523,956 15,198 535,364 12,692(10)
1994
Employee 284,000 340,076 313,699 4,437 237,708 7,384(11)
1995
Employee 454,000 496,746 378,412 21,857 309,204 27,694(12)
1996
Employee 437,000 441,294 246,456 14,703 218,500 16,169(13)
1997
Employee 413,000 445,993 135,677 31,244 58,646 20,237(14)
1998
Employee 353,250 362,428 23,244 11,678 - -
__________
63
<PAGE>
(*) Effective December 31, 1993, this program was merged with and into the
Consolidated Program.
(**) Formed primarily for purposes of acquiring producing oil and gas
properties.
(1) Amounts reflect the accrual method of accounting.
(2) Does not include expenditures of $237,600, $920,453, $2,252,900,
$1,480,248, $2,079,268, $985,371 and $241,076 which were obtained from bank
borrowings and used to pay the limited partners' share of sales commissions
of $237,600, $722,453, $1,940,400, $1,183,248, $1,656,468, $827,046 and
$190,476 and organization costs of $--0--, $198,000, $312,500, $297,000,
$422,800, $158,325 and $50,600 for the 1979, 1980, 1981, 1981-II, 1982-A,
1982-B and 1983-A Programs, respectively.
(3) Includes original subscriptions of limited partners totaling
$10,000,000 and additional assessments totaling $2,000,000.
(4) Includes original subscriptions of limited partners totaling
$25,000,000 and additional assessments totaling $4,255,000.
(5) In November 1998 the 1984 Program made a distribution of $4,725
to that program's limited partners.
(6) In November 1998 the 1986 Program made a distribution of $4,200
to that program's limited partners.
(7) In November 1998 the 1991 Employee Program made a distribution of
$4,734 to that program's limited partners.
(8) In November 1998 the 1992 Employee Program made a distribution of
$8,640 to that program's limited partners.
(9) In November 1998 the 1993 Employee Program made a distribution of
$8,575 to that program's limited partners.
(10) In November 1998 the Consolidated Program made a distribution of
$18,418 to that program's limited partners.
(11) In November 1998 the 1994 Employee Program made a distribution of
$7,384 to that program's limited partners.
(12) In November 1998 the 1995 Employee Program made a distribution of
$9,988 to that program's limited partners.
(13) In November 1998 the 1996 Employee Program made a distribution of
$14,858 to that program's limited partners.
(14) In November 1998 the 1997 Employee Program made a distribution of
$30,149 to that program's limited partners.
64
<PAGE>
FEDERAL INCOME TAX CONSIDERATIONS
The full tax opinion of Conner & Winters is attached to this Memorandum as
Exhibit B. All prospective investors should review Exhibit B in its entirety
before investing in the Partnership. All references in this "Federal Income Tax
Considerations" section are to the tax opinion set forth in Exhibit B.
The following is a summary of the opinions of Conner & Winters, A
Professional Corporation, counsel to the Partnership, which represent counsel's
opinions on all material federal income tax consequences to the Partnership and
to the Limited Partners. There may be aspects of a particular investor's tax
situation which are not addressed in the following discussion or in Exhibit B.
Additionally, the resolution of certain tax issues depends upon future facts and
circumstances not known to counsel as of the date of this Memorandum; thus, no
assurance as to the final resolution of such issues should be drawn from the
following discussion.
The following statements are based upon the provisions of the Code,
including revisions to the Code effected by the Internal Revenue Service
Restructuring and Reform Act of 1998 and the Tax and Trade Relief Extension Act
of 1998, existing and proposed regulations, current administrative rulings, and
court decisions. It is possible that legislative or administrative changes or
future court decisions may significantly modify the statements and opinions
expressed herein. Such changes could be retroactive with respect to the
transactions prior to the date of such changes.
Moreover, uncertainty exists concerning some of the federal income tax
aspects of the transactions being undertaken by the Partnership. Some of the
tax positions being taken by the Partnership may be challenged by the Service
and any such challenge could be successful. Thus, there can be no assurance
that all of the anticipated tax benefits of an investment in the Partnership
will be realized.
Counsel's opinion is based upon the transactions described in this
Memorandum (the "Transaction") and upon facts as they have been represented to
counsel or determined by it as of the date of the opinion. Any alteration of
the facts may adversely affect the opinions rendered. It is possible, however,
that some of the tax benefits will be eliminated or deferred to future years.
Because of the factual nature of the inquiry, and in certain cases the lack
of clear authority in the law, it is not possible to reach a judgment as to the
outcome on the merits (either favorable or unfavorable) of certain material
federal income tax issues as described more fully herein.
Summary of Conclusions
Opinions expressed: The following is a summary of the specific opinions
expressed by counsel with respect to Federal Income Tax Considerations discussed
herein.
TO BE FULLY UNDERSTOOD, THE COMPLETE DISCUSSION OF THESE MATTERS SET
FORTH IN THE FULL TAX OPINION IN EXHIBIT B SHOULD BE READ BY EACH PROSPECTIVE
LIMITED PARTNER.
1. The material federal income tax benefits in the aggregate from an
investment in the Partnership will be realized.
65
<PAGE>
2. The Partnership will be treated as a partnership for federal income
tax purposes and not as a corporation and not as association taxable as a
corporation. See "Partnership Status;" "Federal Taxation of Partnerships."
3. To the extent the Partnership's wells are timely drilled and amounts
are timely paid, the Partners will be entitled to their pro rata share of the
Partnership's IDC paid in 1999. See "Intangible Drilling and Development Costs
Deductions."
4. Limited Partners' Units will be considered a passive activity within
the meaning of Code Section 469 and losses generated therefrom will be limited
by the passive activity provisions. See "Passive Loss and Credit Limitations."
5. To the extent provided herein, the Partners' distributive shares of
Partnership tax items will
be determined and allocated substantially in accordance with the terms of the
Partnership Agreement. See
"Partnership Allocations."
6. The Partnership will not be required to register with the Service as a
tax shelter. See "Registration as a Tax Shelter."
No opinion expressed: Due to the lack of authority, or the essentially
factual nature of the question, counsel expresses no opinion on the following:
1. The impact of an investment in the Partnership on an investor's
alternative minimum tax liability, due to the factual nature of the issue. See
"Alternative Minimum Tax."
2. Whether, under Code Section 183, the losses of the Partnership will be
treated as derived from "activities not engaged in for profit," and therefore
nondeductible from other gross income, due to the inherently factual nature of a
Partner's interest and motive in engaging in the Transaction. See "Profit
Motive."
3. Whether each Partner will be entitled to percentage depletion since
such a determination is dependent upon the status of the Partner as an
independent producer and on the Partner's other oil and gas production. Due to
the inherently factual nature of such a determination, counsel is unable to
render an opinion as to the availability of percentage depletion. See
"Depletion Deductions."
4. Whether any interest incurred by a Partner with respect to any
borrowings to acquire a Unit will be deductible or subject to limitations on
deductibility, due to the factual nature of the issue.
5. Whether the Partnership will be treated as the tax owner of
Partnership Properties acquired by the General Partner as nominee for the
Partnership.
General Information: Certain matters contained herein are not considered
to address a material tax consequence and are for general information, including
the matters contained in sections dealing with gain or loss on the sale of Units
or of Property, Partnership distributions, tax audits, penalties, and state,
local, and self-employment tax. See "General Tax Effects of Partnership
Structure," "Gain or Loss on Sale of Properties or Units," "Partnership
Distributions," "Administrative Matters," "Accounting Methods and Periods," and
"State and Local Tax."
66
<PAGE>
Facts and Representations: The opinions of counsel are also based upon the
facts described in this Memorandum and upon certain representations made to it
by the General Partner for the purpose of permitting counsel to render its
opinions, including the following representations with respect to the
Partnership:
1. The Partnership Agreement to be entered into by and among the General
Partner and Limited Partners and any amendments thereto will be duly executed
and will be made available to any Limited Partner upon written request. The
Partnership Agreement will be duly recorded in all places required under the
Oklahoma Revised Uniform Limited Partnership Act (the "Act") for the due
formation of the Partnership and for the continuation thereof in accordance with
the terms of the Partnership Agreement. The Partnership will at all times be
operated in accordance with the terms of the Partnership Agreement, the
Memorandum, and the Act.
2. No election will be made by the Partnership, Limited Partners, or
General Partner to be excluded from the application of the provisions of
Subchapter K of the Code.
3. The Partnership will own operating mineral interests, as defined in
the Code and in the Regulations, and none of the Partnership's revenues will be
from non-working interests.
4. The General Partner will cause the Partnership to properly elect to
deduct currently all IDC.
5. The Partnership will have a December 31 taxable year and will report
its income on the accrual basis.
6. All Partnership wells will be spudded by not later than December 31,
1999. The entire amount to be paid under any drilling and operating agreements
entered into by the Partnership will be attributable to IDC.
7. Such drilling and operating agreements will be duly executed and will
govern the operation of the Partnership's wells.
8. Based upon the General Partner's review of its experience with its
previous oil and gas partnerships for the past several years and upon the
intended operations of the Partnership, the General Partner believes that the
sum of (i) the aggregate deductions, including depletion deductions, and (ii)
350 percent of the aggregate credits from the Partnership will not, as of the
close of any of the first five years ending after the date on which Units are
offered for sale, exceed two times the cash invested by the Partners in the
Partnership as of such dates. In that regard, the General Partner has reviewed
the economics of its similar oil and gas partnerships for the past several
years, and has represented that it has determined that none of those
partnerships has resulted in a "tax shelter ratio", as such term is defined in
the Code and Regulations, greater than two to one. Further, the General Partner
has represented that the deductions that are or will be represented as
potentially allowable to an investor will not result in the Partnership having a
tax shelter ratio, as such term is defined in the Code and Regulations, greater
than two to one and believes that no person could reasonably infer from
representations made, or to be made, in connection with the offering of Units
that such sums as of such dates will exceed two times the Partners' cash
investments as of such dates.
67
<PAGE>
9. The General Partner believes that at least 90% of the gross income of
the Partnership will constitute income derived from the exploration,
development, production, and/or marketing of oil and gas. The General Partner
does not believe that any market will ever exist for the sale of Units and the
General Partner will not make a market for the Units,. Further, the Units will
not he traded on an established securities market.
10. The Partnership and each Partner will have the objective of carrying
on the business of the Partnership for profit and dividing the gain therefrom.
The opinions of counsel are also subject to all the assumptions,
qualifications, and limitations set forth in the following discussion and in the
opinion, including the assumptions that each of the Partners has full
power, authority, and legal right to enter into and perform the terms of the
Partnership Agreement and to take any and all actions thereunder in connection
with the transactions contemplated thereby.
Each prospective investor should be aware that, unlike a ruling from the
Service, an opinion of counsel represents only such counsel's best judgment.
THERE CAN BE NO ASSURANCE THAT THE SERVICE WILL NOT SUCCESSFULLY ASSERT
POSITIONS WHICH ARE INCONSISTENT WITH THE OPINIONS OF COUNSEL SET FORTH IN THIS
DISCUSSION AND EXHIBIT B OR IN THE TAX REPORTING POSITIONS TAKEN BY THE PARTNERS
OR THE PARTNERSHIP. EACH PROSPECTIVE INVESTOR SHOULD CONSULT HIS OR HER OWN TAX
ADVISOR TO DETERMINE THE EFFECT OF THE TAX ISSUES DISCUSSED HEREIN AND IN
EXHIBIT B ON HIS OR HER INDIVIDUAL TAX SITUATION.
General Tax Effects of Partnership Structure
The Partnership will be formed as a limited partnership pursuant to the
Partnership Agreement and the laws of the State of Oklahoma.
NO TAX RULING WILL BE SOUGHT FROM THE SERVICE AS TO THE STATUS OF
THE PARTNERSHIP AS A PARTNERSHIP FOR FEDERAL INCOME TAX PURPOSES.
The applicability of the federal income tax consequences described herein
depends on the treatment of the Partnership as a partnership for federal income
tax purposes and not as a corporation and not as an association taxable as a
corporation. Any tax benefits anticipated from an investment in the Partnership
would be adversely affected or eliminated if the Partnership is treated as a
corporation for federal income tax purposes.
Counsel to the Partnership is of the opinion that, at the time of its
formation, the Partnership will be treated as a partnership for federal income
tax purposes. The opinion is based on the provisions of the Partnership
Agreement and applicable state law and representations made by the General
Partner. The opinion of counsel is not binding on the Service and is based on
existing law, which is to a great extent the result of administrative and
judicial interpretation. In addition, no assurance can be given that the
Partnership will not lose partnership status as a result of changes in the
manner in which it is operated or other facts upon which the opinion of counsel
is based.
Under the Code, a partnership is not a taxable entity and, accordingly,
incurs no federal income tax liability. Rather, a partnership is a "pass-
through" entity which is required to file an information return with
the Service. In general, the character of a partner's share of each item of
income, gain, loss, deduction, and credit is determined at the partnership
68
<PAGE>
level. Each partner is allocated a distributive share of such items in
accordance with the partnership agreement and is required to take such items
into account in determining the partner's income. Each partner includes such
amounts in income for any taxable year of the partnership ending within or with
the taxable year of the partner, without regard to whether the partner has
received or will receive any cash distributions from the Partnership.
Ownership of Partnership Properties
The General Partner has indicated that it, as nominee for the Partnership
(the "Nominee"), will acquire and hold title to Partnership Properties on behalf
of the Partnership. The Nominee and the Partnership will enter into an agency
agreement before the Nominee acquires any oil and gas properties on behalf of
the Partnership. That agency agreement will reflect that the Nominee's
acquisition of Partnership Properties is on behalf of the Partnership. For
various cost and procedural reasons, the assignments of all oil and gas
interest acquired by the Nominee on behalf of the Partnership to the Partnership
will not be recorded in the real estate records in the counties in which the
Partnership Properties are located. That is, while the Partnership will be the
owner of the Partnership Properties, there will be no public record of that
ownership. It is possible that the Service could assert that the Nominee should
be treated for federal income tax purposes as the owner of the Partnership
Properties, notwithstanding the assignment of those Properties to the
Partnership. If the Service were to argue successfully that the Nominee should
be treated as the tax owner of the Partnership Properties, there would be
significant adverse federal income tax consequences to the Limited Partners,
such as the unavailability of depletion deductions in respect of income from
Partnership Properties. The Service is concerned that taxpayers not be able to
shift the tax consequences of transactions between parties based on the parties'
declaration that one party is the agent of another; the Service generally
requires that taxpayers respect the form of their transactions and ownership of
property. Based on this concern, the Service may challenge the Partnership's
treatment of Partnership Properties, and tax attributes thereof, which are held
of record by the Nominee.
In Commissioner of Internal Revenue v. Bollinger, 485 U.S. 340 (1988), the
United States Supreme Court reviewed a principal-agent relationship and held for
the taxpayer in concluding that the principal should be treated as the tax owner
of property held in the name of the agent. In that case the Supreme Court noted
that "It seems to us that the genuineness of the agency relationship is
adequately assured, and tax-avoiding manipulation adequately avoided, when the
fact that the corporation is acting as agent for its shareholders with
respect to a particular asset is set forth in a written agreement at the time
the asset is acquired, the corporation functions as agent and not principal with
respect to the asset for all purposes, and the corporation is held out
as the agent and not principal in all dealings with third parties relating to
the asset." While the Partnership and the Nominee will have in place an
agreement defining their relationship before any Partnership Properties
are acquired by the Nominee and the Nominee will function as agent with respect
to those Partnership Properties on behalf of the Partnership, the Nominee will
not hold itself out to all third parties as the agent of the Partnership in
dealings relating to the Partnership Properties. Unlike the relationship
between the principal and the agent in Bollinger, the Nominee will, however,
assign title to Partnership Properties to the Partnership, but will not record
those assignments. Accordingly, the facts related to the relationship between
the Nominee and the Partnership are not the same as the facts in Bollinger and
69
<PAGE>
it is not clear that the failure of the Nominee to hold itself out to third
partes as the agent of the Partnership in dealings relating to Partnership
Properties should result in the treatment of the Nominee as the tax owner of the
Partnership Properties. For the foregoing reasons, Counsel have not expressed
an opinion on this issue, but Counsel believe that substantial arguments may be
made that the Partnership should be treated as the tax owner of Partnership
Properties acquired by the Nominee on the Partnership's behalf. If the
Partnership were not treated as the tax owner of Partnership Properties, then
the following discussions which relate to the Partners' deduction of tax items
which are derived from Partnership Properties, such as IDC, depletion and
depreciation, would not be applicable.
Intangible Drilling and Development Costs Deductions
Congress granted to the Treasury Secretary the authority to prescribe
regulations that would allow taxpayers the option of deducting, rather than
capitalizing, IDC. The Secretary's rules state that, in general,
the option to deduct IDC applies only to expenditures for drilling and
development items that do not have a salvage value.
The Memorandum provides that 75% of the Partners' capital contributions
will be utilized for IDC, which is deductible in the year of investment. The
deduction by Limited Partners will be restricted to passive income. Based on a
75% deduction, a one Unit ($1,000) investor in a 35% marginal Federal tax
bracket would reduce taxes payable by $262. The investor could also realize
additional tax savings on Oklahoma state income taxes.
Classification of Costs. In general, IDC consists of those costs which in
and of themselves have no salvage value. In previous partnerships intangible
drilling costs have ranged from 72% to 27% of the investors' contributions.
While the planned activities of the Partnership are similar in nature to those
of prior partnerships, the amount of expenditures classified as IDC could be
greater than or less than for prior partnerships. In addition, a partnership's
classification of a cost as IDC is not binding on the government, which might
reclassify an item labeled as IDC as a cost which must be capitalized. To the
extent not deductible, such amounts will be included in the Partnership's basis
in a mineral property and in the Partners' bases in their interests in the
Partnership.
Timing of Deductions. Although the Partnership will elect to deduct IDC,
each investor has an option of deducting IDC, or capitalizing all or a part of
the IDC and amortizing it on a straight-line basis over a sixty-month period,
beginning with the taxable month in which the expenditure is made. In addition
to the effect of this change on regular taxable income, the two methods have
different treatment under the Alternative Minimum Tax ("AMT") (see "Alternative
Minimum Tax").
Although the General Partner will attempt to satisfy each requirement of
the Service and judicial authority for deductibility of IDC in 1999 for the
Partnership, no assurance can be given that the Service will not successfully
contend that the IDC of a well which is not completed until 2000 for the
Partnership are not deductible in whole or in part until 2000. Notwithstanding
the foregoing, no assurance can be given that the Service will not challenge the
current deduction of IDC because of the prepayment being made to a related
party. If the Service were successful with such challenge, the Partners'
deductions for IDC would be deferred to later years.
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Recapture of IDC. IDC previously deducted that is allocable to a property
(directly or through the ownership of an interest in a partnership) and which
would have been included in the adjusted basis of the property is recaptured to
the extent of any gain realized upon the disposition of the property. Treasury
regulations provide that recapture is determined at the partner level (subject
to certain anti-abuse provisions). Where only a portion of recapture property
is disposed of, any IDC related to the entire property is recaptured to the
extent of the gain realized on the portion of the property sold. In the case of
the disposition of an undivided interest in a property (as opposed to the
disposition of a portion of the property), a proportionate part of the IDC with
respect to the property is treated as allocable to the transferred undivided
interest to the extent of any realized gain.
Depletion Deductions
The owner of an economic interest in an oil and gas property is entitled to
claim the greater of percentage depletion or cost depletion with respect to oil
and gas properties which qualify for such depletion methods. In the case of
partnerships, the depletion allowance must be computed separately by each
partner and not by the partnership. For properties placed in service after
1986, depletion deductions, to the extent they reduce basis in an oil and gas
property, are subject to recapture under Code section 1254.
Cost depletion for any year is determined by multiplying the number of
units (e.g., barrels of oil or Mcf of gas) sold during the year by a fraction,
the numerator of which is the cost or other basis of the mineral interest and
the denominator of which is total reserves available at the beginning of the
period. In no event can the cost depletion exceed the adjusted basis of the
property to which it relates.
Percentage depletion is a statutory allowance pursuant to which a deduction
currently equal to 15% of the taxpayer's gross income from each property is
allowed in any taxable year, not to exceed 100% of the taxpayer's taxable income
from the property (computed without the allowance for depletion) with the
aggregate deduction limited to 65% of the taxpayer's taxable income for the year
(computed without regard to percentage depletion and net operating loss and
capital loss carrybacks). The percentage depletion deduction rate will vary
with the price of oil, but the rate will not be less than 15%. A percentage
depletion deduction that is disallowed in a year due to the 65% of taxable
income limitation may be carried forward and allowed as a deduction for the
following year, subject to the 65% limitation in that subsequent year.
Percentage depletion deductions reduce the taxpayer's adjusted basis in the
property. However, unlike cost depletion, deductions under percentage depletion
are not limited to the adjusted basis of the property; the percentage depletion
amount continues to be allowable as a deduction after the adjusted basis has
been reduced to zero.
The availability of depletion, whether cost or percentage, will be
determined separately by each Partner. Each Partner must separately keep
records of his share of the adjusted basis in an oil or gas property,
adjust such share of the adjusted basis for any depletion taken on such
property, and use such adjusted basis each year in the computation of his cost
depletion or in the computation of his gain or loss on the disposition
of such property. These requirements may place an administrative burden on a
Partner.
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Depreciation Deductions
The Partnership will claim depreciation, cost recovery, and amortization
deductions with respect to its basis in Partnership Property as permitted by the
Code. For most tangible personal property placed in service after December 31,
1986, the "modified accelerated cost recovery system" ("MACRS") must be used
in calculating the cost recovery deductions. Thus, the cost of lease equipment
and well equipment, such as casing, tubing, tanks, and pumping units, and the
cost of oil or gas pipelines cannot be deducted currently but must be
capitalized and recovered under MACRS. The cost recovery deduction for most
equipment used in domestic oil and gas exploration and production and for most
of the tangible personal property used in natural gas gathering systems is
calculated using the 200% declining balance method switching to the straight-
line method, a seven-year recovery period, and a half-year convention. If an
accelerated depreciation method is used, a portion of the depreciation will be a
preference item for AMT purposes.
Interest Deductions
In the Transaction, the Limited Partners will acquire their interests by
remitting cash in the amount of $1,000 per Unit to the Partnership. Some
Limited Partners may choose to borrow the funds necessary to acquire a Unit and
may incur interest expense in connection with those loans. Based upon the
purely factual nature of any such loans, counsel is unable to express an opinion
with respect to the deductibility of any interest paid or incurred thereon.
Transaction Fees
The Partnership may classify a portion of the fees or expense
reimbursements to be paid to third parties and to the General Partner as
expenses which are deductible as organizational expenses or otherwise.
There is no assurance that the Service will allow the deductibility of such
expenses and counsel expresses no opinion with respect to the allocation of such
fees or reimbursements to deductible and nondeductible items.
Generally, expenditures made in connection with the creation of, and with
sales of interests in, a partnership will fit within one of several categories.
A partnership may elect to amortize and deduct its organizational expenses
ratably over a period of not less than 60 months commencing with the month the
partnership begins business. Examples of organizational expenses are legal fees
for services incident to the organization of the partnership, such as
negotiation and preparation of a partnership agreement, accounting fees for
services incident to the organization of the partnership, and filing fees.
No deduction is allowable for "syndication expenses," examples of which
include brokerage fees, registration fees, legal fees of the underwriter or
placement agent and the issuer (general partners or the partnership) for
securities advice and for advice pertaining to the adequacy of tax disclosures
in the Memorandum or private placement memorandum for securities law purposes,
printing costs, and other selling or promotional material. These costs must be
capitalized. Payments for services performed in connection with the acquisition
of capital assets must be amortized over the useful life of such assets.
No deduction is allowable with respect to "start-up expenditures," although
such expenditures may be capitalized and amortized over a period of not less
than 60 months.
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The Partnership intends to make overhead reimbursement payments to the
General Partner, as described in greater detail in the Memorandum. To be
deductible, payments to a general partner must be for services rendered by the
partner other than in his capacity as a partner or for compensation determined
without regard to partnership income. Payments which are not deductible because
they fail to meet this test may be treated as special allocations of income to
the recipient partner and thereby decrease the net loss, or increase the net
income among all partners. If the Service were to successfully challenge the
General Partner's allocations, a Partner's taxable income could be increased,
thereby resulting in increased taxes and in liability for interest and
penalties.
Basis and At Risk Limitations
A Partner's share of Partnership losses will be allowed only to the extent
of the aggregate amount with respect to which the taxpayer is "at risk" for such
activity at the close of the taxable year. Any such loss disallowed by the "at
risk" limitation shall be treated as a deduction allocable to the activity in
the first succeeding taxable year.
The Code provides that a taxpayer must recognize taxable income to the
extent that his or her "at risk" amount is reduced below zero. This recaptured
income is limited to the sum of the loss deductions previously allowed to the
taxpayer, less any amounts previously recaptured. A taxpayer may be allowed a
deduction for the recaptured amounts included in his taxable income if and when
he increases his amount "at risk" in a subsequent taxable year.
The Limited Partners will purchase Units by tendering cash to the
Partnership. To the extent the cash contributed constitutes the "personal
funds" of the Partners, the Partners should be considered at risk with
respect to those amounts. To the extent the cash contributed constitutes
"personal funds," in the opinion of counsel, neither the at risk rules nor the
adjusted basis rules will limit the deductibility of losses generated
from the Partnership. In no event, however, may a Partner utilize his
distributive share of partnership loss where such share exceeds the Partner's
basis in the Partnership.
Passive Loss Limitations
Introduction. The deductibility of losses generated from passive
activities will be limited for certain taxpayers. The passive activity loss
limitations apply to individuals, estates, trusts, and personal service
corporations as well as, to a lesser extent, closely held C corporations.
The definition of a "passive activity" generally encompasses all rental
activities as well as all activities with respect to which the taxpayer does not
"materially participate." Notwithstanding this general rule, however, the term
"passive activity" does not include "any working interest in any oil or gas
property which the taxpayer holds directly or through an entity which does not
limit the liability of the taxpayer with respect to such interest." A taxpayer
will be considered as materially participating in a venture only if the taxpayer
is involved in the operations of the activity on a "regular, continuous, and
substantial" basis. In addition, no limited partnership interest will be
treated as an interest with respect to which a taxpayer materially participates.
A passive activity loss ("PAL") is the amount by which the aggregate losses
from all passive activities for the taxable year exceed the aggregate income
from all passive activities for such year.
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Individuals and personal service corporations will be entitled to PALs only
to the extent of their passive income whereas closely held C corporations (other
than personal service corporations) can offset PALs against both passive and net
active income, but not against portfolio income. In calculating passive
income and loss, however, all activities of the taxpayer are aggregated. PALs
disallowed as a result of the above rules will be suspended and can be carried
forward indefinitely to offset future passive (or passive and active, in the
case of a closely held C corporation) income.
Upon the disposition of an entire interest in a passive activity in a fully
taxable transaction not involving a related party, any passive loss that was
suspended by the provisions of the passive activity rules
is deductible from either passive or non-passive income. The deduction must be
reduced, however, by the amount of income or gain realized from the activity in
previous years.
Limited Partner Interests. A Limited Partner's distributive share of the
Partnership's losses will be treated as PALs, the availability of which will be
limited to the Partner's passive income. If a Limited Partner does not have
sufficient passive income to utilize the PALs, the disallowed PALs will be
suspended and may be carried forward to be deducted against passive income
arising in future years. Further, upon the disposition of the interest to an
unrelated party in a fully taxable transaction, such suspended losses will be
available, as described above.
Limited Partners should generally be entitled to offset their distributive
shares of passive income from the Partnership with deductions from other passive
activities, but not portfolio income.
Alternative Minimum Tax
Tax benefits associated with oil and gas exploration activities similar to
that of the Partnership had for several years been subject to the AMT.
Specifically, prior to January 1, 1993, IDC was an AMT preference item to the
extent that "excess IDC" exceeded 65% of a taxpayer's net income from oil and
gas properties for the year. Excess IDC was the amount by which the taxpayer's
IDC deduction exceeded the deduction that would have been allowed if the IDC had
been capitalized and amortized on a straight-line basis over ten years.
Percentage depletion, to the extent it exceeded a property's basis, was also an
AMT preference item.
For independent producers in taxable years beginning after 1992, the Energy
Policy Act of 1992 repealed the treatment of percentage depletion as a
preference item for AMT purposes and reduced the AMT on expensing of IDC by 30%.
Gain or Loss on Sale of Property or Units
In the event some or all of the property of the Partnership is sold, or
upon sale of a Unit, a Limited Partner will recognize gain to the extent the
amount realized exceeds his or her basis in the investment. In addition, there
may be recapture of IDCs and depletion which is treated as additional ordinary
income for tax purposes. If the gain exceeds the amount of the recaptured
income, the investor will recognize ordinary income to the extent of the
recapture and capital gains for the balance.
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It is possible that a Limited Partner will be required to recognize
ordinary income pursuant to the recapture rules in excess of the taxable income
on the disposition transaction or in a situation where the disposition
transaction resulted in a taxable loss. To balance the excess income, the
Limited Partner would recognize a capital loss for the difference between the
gain and the income. Depending on a Limited Partner's particular tax situation,
some or all of this loss might be deferred to future years, resulting in a
greater tax liability in the year in which the sale was made and a reduced
future tax liability.
Any partner who sells or exchanges interests in a partnership must
generally notify the partnership in writing within 30 days of such transaction
in accordance with Regulations and must attach a statement to his tax return
reflecting certain facts regarding the sale or exchange. The notice must
include names, addresses, and taxpayer identification numbers (if known) of the
transferor and transferee and the date of the exchange. The partnership also is
required to provide copies of the information it provides to the Service to the
transferor and the transferee.
A Limited Partner who is required to notify the Partnership of a transfer
of his or her Partnership interest, and, who fails to do so, may be fined $50
for each failure, limited to $100,000, provided no intentional disregard of the
filing requirement. Similarly, the Partnership may be fined for failure to
report the transfer. The partnership's penalty is $50 for each failure, limited
to $250,000, provided no intentional disregard of the filing requirement.
The tax consequences to an assignee purchaser of a Unit from a Partner are
not described herein. Any assignor of a Unit should advise his assignee to
consult his own tax advisor regarding the tax consequences of such assignment.
Partnership Distributions
Under the Code, any increase in a partner's share of partnership
liabilities, or any increase in such partner's individual liabilities by reason
of an assumption by him or her of partnership liabilities is considered
to be a contribution of money by the partner to the partnership. Similarly, any
decrease in a partner's share of partnership liabilities or any decrease in such
partner's individual liabilities by reason of the partnership's assumption of
such individual liabilities will be considered as a distribution of money to the
partner by the partnership.
The Partners' adjusted bases in their Units will initially consist of the
cash they contribute to the Partnership. Their bases will be increased by their
share of Partnership income and decreased by their share of Partnership losses
and distributions. To the extent that such actual or constructive distributions
are in excess of a Partner's adjusted basis in his or her Partnership interest
(after adjustment for contributions and his or her share of income and losses of
the Partnership), that excess will generally be treated as gain from the sale of
a capital asset. In addition, gain could be recognized to a distributee partner
upon the disproportionate distribution to a partner of unrealized receivables or
substantially appreciated inventory. The Partnership Agreement prohibits
distributions to a Limited Partner to the extent such would create or increase
a deficit in the Limited Partner's Capital Account.
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Partnership Allocations
The Partners' distributive shares of partnership income, gain, loss, and
deduction should be determined and allocated substantially in accordance with
the terms of the Partnership Agreement.
The Service could contend that the allocations contained in the Partnership
Agreement do not have substantial economic effect or are not in accordance with
the Partners' interests in the Partnership and may seek to reallocate these
items in a manner that will increase the income or gain or decrease the
deductions allocable Partner.
Profit Motive
The existence of economic, non-tax motives for entering into the
Transaction is essential if the Partners are to obtain the tax benefits
associated with an investment in the Partnership.
Where an activity entered into by an individual is not engaged in for
profit, the individual's deductions with respect to that activity are limited to
those not dependent upon the nature of the activity (e.g., interest and taxes);
any remaining deductions will be limited to gross income from the activity for
the year. Should it be determined that a Partner's activities with respect to
the Transaction are "not for profit," the Service could disallow all or a
portion of the deductions generated by the Partnership's activities.
The Code generally provides for a presumption that an activity is entered
into for profit where gross income from the activity exceeds the deductions
attributable to such activity for three or more of the five consecutive taxable
years ending with the taxable year in question. At the taxpayer's election,
such presumption can relate to three or more of the taxable years in the 5-year
period beginning with the taxable year in which the taxpayer first engages in
the activity.
Due to the inherently factual nature of a Partner's intent and motive in
engaging in the Transaction, counsel does not express an opinion as to the
ultimate resolution of this issue in the event of a challenge by the Service.
Partners must, however, seek to make a profit from their activities with respect
to the Transaction beyond any tax benefits derived from those activities or risk
losing those tax benefits.
Administrative Matters
Returns and Audits. While no federal income tax is required to be paid by
an organization classified as a partnership for federal income tax purposes, a
partnership must file federal income tax information returns, which are subject
to audit by the Service. Any such audit may lead to adjustments, in which event
the Limited Partners may be required to file amended personal federal income tax
returns. Any such audit may also lead to an audit of a Limited Partner's
individual tax return and adjustments to items unrelated to an investment in
Units.
For purposes of reporting, audit, and assessment of additional federal
income tax, the tax treatment of "partnership items" is determined at the
partnership level. Partnership items will include those items that the
Regulations provide are more appropriately determined at the partnership level
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than the partner level. The Service generally cannot initiate deficiency
proceedings against an individual partner with respect to partnership items
without first conducting an administrative proceeding at the partnership level
as to the correctness of the partnership's treatment of the item. An individual
partner may not file suit for a credit or a refund arising out of a partnership
item without first filing a request for an administrative proceeding by the
Service at the partnership level. Individual partners are entitled to notice of
such administrative proceedings and decisions therein, except in the case of
partners with less than 1% profits interest in a partnership having more than
100 partners. If a group of partners having an aggregate profits interest of 5%
or more in such a partnership so requests, however, the Service also must mail
notice to a partner appointed by that group to receive notice. All partners,
whether or not entitled to notice, are entitled to participate in the
administrative proceedings at the partnership level, although the Partnership
Agreement provides for waiver of certain of these rights by the Limited
Partners. All Partners, including those not entitled to notice, may be bound by
a settlement reached by the Partnership's representative "tax matters partner",
which will be Unit Petroleum Company. If a proposed tax deficiency is contested
in any court by any Partner or by the General Partner, all Partners may be
deemed parties to such litigation and bound by the result reached therein.
Consistency Requirements. A Partner must generally treat Partnership items
on his or her federal income tax returns consistently with the treatment of such
items on the Partnership information return unless he or she files a statement
with the Service identifying the inconsistency or otherwise satisfies the
requirements for waiver of the consistency requirement. Failure to satisfy this
requirement will result in an adjustment to conform the Partner's treatment of
the item with the treatment of the item on the Partnership return. Intentional
or negligent disregard of the consistency requirement may subject a Partner to
substantial penalties.
Compliance Provisions. Taxpayers are subject to several penalties and
other provisions that encourage compliance with the federal income tax laws,
including an accuracy-related penalty in an amount equal to 20% of the portion
of an underpayment of tax caused by negligence, intentional disregard of rules
or regulations or any "substantial understatement" of income tax. A
"substantial understatement" of tax is an understatement of income tax that
exceeds the greater of (a) 10% of the tax required to be shown on the
return (the correct tax), or (b) $5,000 ($10,000 in the case of a corporation
other than an S corporation or personal holding corporation).
Except in the case of understatements attributable to "tax shelter" items,
an item of understatement may not give rise to the penalty if (a) there is or
was "substantial authority" for the taxpayer's treatment of the item or (b) all
facts relevant to the tax treatment of the item are disclosed on the return or
on a statement attached to the return, and there is a reasonable basis for the
tax treatment of such item by the taxpayer. In the case of partnerships, the
disclosure is to be made on the return of the partnership. Under the applicable
Regulations, however, an individual partner may make adequate disclosure with
respect to partnership items if certain conditions are met.
In the case of understatements attributable to "tax shelter" items, the
substantial understatement penalty may be avoided only if the taxpayer
establishes that, in addition to having substantial authority for his or her
position, he or she reasonably believed the treatment claimed was more likely
than not the proper treatment of the item. A "tax shelter" item is one that
arises from a partnership (or other form of investment) the principal purpose of
which is the avoidance or evasion of federal income tax.
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Based on the definition of a "tax shelter" in the Regulations, performance
of previous partnerships, and the planned activities of the Partnership, the
General Partner does not believe that the Partnership will qualify as a "tax
shelter" under the Code, and will not register it as such.
Accounting Methods and Periods
The Partnership will use the accrual method of accounting and will select
the calendar year as its taxable year.
State and Local Taxes
The opinions expressed herein are limited to issues of federal income tax
law and do not address issues of state or local law. Prospective investors are
urged to consult their tax advisors regarding the impact of state and local laws
on an investment in the Partnership.
Individual Tax Advice Should Be Sought
The foregoing is only a summary of the material tax considerations that may
affect an investor's decision regarding the purchase of Units. The tax
considerations attendant to an investment in a Partnership are complex and vary
with individual circumstances. Each prospective investor should review such tax
consequences with his tax advisor.
COMPETITION, MARKETS AND REGULATION
The oil and gas industry is highly competitive in all its phases. The
Partnership will encounter strong competition from both major independent oil
companies and individuals, many of which possess substantial financial
resources, in acquiring economically desirable prospects and equipment and labor
to operate and maintain Partnership Properties. There are likewise numerous
companies and individuals engaged in the organization and conduct of oil and gas
drilling programs and there is a high degree of competition among such companies
and individuals in the offering of their programs.
Marketing of Production
The availability of a ready market for any oil and gas produced from
Partnership Wells will depend upon numerous factors beyond the control of the
Partnership, including the extent of domestic production and importation of oil
and gas, the proximity of Partnership Wells to gas pipelines and the capacity of
such gas pipelines, the marketing of other competitive fuels, fluctuation in
demand, governmental regulation of production, refining and transportation,
general national and worldwide economic conditions, and the pricing, use and
allocation of oil and gas and their substitute fuels.
The demand for gas decreased significantly in the 1980s due to economic
conditions, conservation and other factors. As a result of such reduced demand
and other factors, including the Power Plant and Industrial Fuel Use Act (the
"Fuel Use Act") which related to the use of oil and gas in the United States in
certain fuel burning installations, many pipeline companies began purchasing gas
on terms which were not as favorable to sellers as terms governing purchases of
gas prior thereto. Spot market gas prices declined generally during that
period. While the Fuel Use Act has been repealed and the General Partner
expects that the markets for gas may 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.
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In the event the Partnership acquires an interest in a gas well or
completes a productive gas well, or a well that produces both oil and gas, the
well may be shut in for a substantial period of time for lack of a market if the
well is in an area distant from existing gas pipelines. The well may remain
shut in until such time as a gas pipeline, with available capacity, is extended
to such an area or until such time as sufficient wells are drilled to establish
adequate reserves which would justify the construction of a gas pipeline,
processing facilities, if necessary, and a transmission system.
The worldwide supply of oil has been largely dependent upon rates of
production of foreign reserves. Although in recent years the demand for oil has
slightly increased in this country, imports of foreign oil continue to increase.
Consequently, the prices for domestic oil production have remained low. Future
domestic oil prices will depend largely upon the actions of foreign producers
with respect to rates of production and it is virtually impossible to predict
what actions those producers will take in the future. Prices may also be
affected by political and other factors relating to the Middle East. As a
result, it is possible that prices for oil, if any, produced from a Partnership
Well will be lower than those currently available or projected at the time the
interest therein is acquired. In view of the many uncertainties affecting the
supply and demand for crude oil and natural gas, and the change in the makeup of
the Congress of the United States and the resulting potential for a different
focus for the United States energy policy, the General Partner is unable to
predict what future gas and oil prices will be.
Regulation of Partnership Operations
Production of any oil and gas found by the Partnership will be affected by
state and federal regulations. All states in which the Partnership intends to
conduct activities have statutory provisions regulating the production and sale
of oil and gas. Such statutes, and the regulations promulgated in connection
therewith, generally are intended to prevent waste of oil and gas and to protect
correlative rights and the opportunities to produce oil and gas as between
owners of a common reservoir. Certain state regulatory authorities also
regulate the amount of oil and gas produced by assigning allowable rates of
production to each well or proration unit. Pertinent state and federal statutes
and regulations also extend to the prevention and clean-up of pollution. These
laws and regulations are subject to change and no predictions can be made as to
what changes may be made or the effect of such changes on the Partnership's
operations.
Under the laws and administrative regulations of the State of Oklahoma
regarding forced pooling, owners of oil and gas leases or unleased mineral
interests may be required to elect to participate in the drilling of a well with
other fractional undivided interest owners within an established spacing unit or
to sell or farm out their interest therein. The terms of any such sale or farm-
out are generally those determined by the Oklahoma Corporation Commission to be
equal to the most favorable terms then available in the area in arm's length
transactions although there can be no assurance that this will be the case. In
addition, if properties become the subject of a forced pooling order, drilling
operations may have to be undertaken at a time or with other parties which the
General Partner feels may not be in the best interest of the Partnership. In
such event, the Partnership may have to farm out or assign its interest in such
properties. In addition, if a property which might otherwise be acquired by the
Partnership becomes subject to such an order, it may become unavailable to the
Partnership. Finally, as a result of forced pooling proceedings involving a
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Partnership Property, the Partnership may acquire a larger than anticipated
interest in such property, thereby increasing its share of the costs of
operations to be conducted.
Natural Gas Price Regulation
Partnership Revenues are likely to be dependent on the sale and
transportation of natural gas that may be subject to regulation by the Federal
Energy Regulatory Commission ("FERC"). Historically the sale of natural gas has
been regulated by the FERC under the Natural Gas Act of 1938 ("NGA") and/or the
Natural Gas Policy Act of 1978 ("NGPA"). Under the NGPA, natural gas is divided
into numerous, complex categories based on, among other things, when, where and
how deep the gas well was drilled and whether the gas was committed to
interstate or intrastate commerce on the day before the date of enactment of the
statute. These categories determine whether the natural gas remains subject to
non-price regulation under the NGA and/or to maximum price restrictions under
the NGPA. In addition to setting ceiling prices for natural gas, FERC approval
is required for both the commencement and abandonment of sales of certain
categories of gas in interstate commerce for resale and for the transportation
of natural gas in interstate commerce. FERC has general investigatory and other
powers, including limited authority to set aside or modify terms of gas purchase
contracts subject to its jurisdiction. Price and non-price regulation of
natural gas produced from most wells drilled after 1978 has terminated. That
gas may be sold without prior regulatory approval and at whatever price the
market will bear.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 became
effective. Consequently, due to this statutory deregulation and FERC's issuance
of Order No. 547 discussed below, as of January 7, 1993 the price of virtually
all gas produced by producers not affiliated with interstate pipelines has been
deregulated by FERC.
Market determined prices for deregulated categories of natural gas
fluctuate in response to market pressures which currently favor purchasers and
disfavor producers. As a result of the deregulation of a greater proportion of
the domestic United States gas market and an increased availability of natural
gas transportation, a competitive trading market for gas has developed. For
several reasons the supply of gas has exceeded demand. The General Partner
cannot reliably predict at this time whether such supply/demand imbalance will
improve or worsen from a producer's viewpoint.
During the past several years, FERC has adopted several regulations
designed to create a more competitive, less regulated market for natural gas.
These regulations have materially affected the market for natural gas.
FERC's initial major initiative was adoption of its "open-access
transportation program," through Order No.s 436 and 500. Regulation of Natural
Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, 50 Fed. Reg.
42,408 (October 18, 1985), vacated and remanded, Associated Gas Distributors v.
FERC, 824 F.2d 981 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988),
readopted on an interim basis, Order No. 500, 52 Fed. Reg. 30,344 (Aug. 14,
1987), remanded, American Gas Association v. FERC, 888 F.2d 136 (D.C. Cir.
1989), readopted, Order No. 500-H, 54 Fed. Reg. 52,344 (Dec. 21, 1989), reh'g
granted in part and denied in part, Order No. 500-I, 55 Red. Reg. 6605 (Feb. 26,
1990), aff'd in part and remanded in part, American Gas Association v. FERC, 912
F.2d 1496 (D.C. Cir. 1990), cert. denied, 111 S. Ct. 957 (1991). Order 436
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implemented three key requirements: (1) jurisdictional pipelines were required
to permit their firm sales customers to convert their firm sales entitlements to
a volumetrically equivalent amount of firm transportation service over a five-
year period; (2) jurisdictional pipelines were required to offer their open-
access transportation services without discrimination or preference; and (3)
jurisdictional pipelines were required to design maximum rates to ration
capacity during peak periods and to maximize throughput for firm service during
off-peak periods and for interruptible service during all periods. The
availability of transportation under Order 500 greatly expanded the free trading
market for natural gas, including the establishment of an active and viable spot
market.
Subsequently, in Order 636 the FERC focused on whether the resulting
regulatory structure provided all gas sellers with the same regulatory
opportunity to compete for gas purchasers. It decided that the form
of bundled pipeline services (gas sales and transportation) was unduly
discriminatory and anticompetitive. Pipeline Service Obligations and Revisions
to Regulations Governing Self-Implementing Transportation; and Regulation of
Natural Gas Pipelines After Wellhead Decontrol, Order No. 636, 57 Fed. Reg.
13,267 (Apr. 16, 1992), III FERC Stats. & Regs. Preambles Paragraph 30,939, at
30,406; Regulations of Natural Gas Pipelines After Partial Wellhead Decontrol,
and Order Denying Rehearing in Part, Granting Rehearing in Part, and Clarifying
Order No. 636, Order No. 636-A, 57 Fed. Reg. 36,128 (Aug. 12, 1992), III FERC
Stats. & Regs. Preambles Paragraph 30,950; Regulation of Natural Gas Pipelines
After Partial Wellhead Decontrol; Regulation of Natural Gas Pipelines After
Partial Wellhead Decontrol; Order Denying Rehearing and Clarifying Order Nos.
636 and 636-A, Order No. 636-B, 57 Fed. Reg. 57,911 (Dec. 8, 1992).
Among other things, Order 636 required each interstate pipeline company to
"unbundle" its traditional wholesale services and create and make available on
an open and nondiscriminatory basis numerous constituent services (such as
gathering services, storage services, firm and interruptible transportation
services, and stand-by sales services) and to adopt a new rate making
methodology (Straight Fixed Variable) to determine appropriate rates for those
services. To the extent the pipeline company or its sales affiliate makes gas
sales as a merchant in the future, it will do so in direct competition with all
other sellers pursuant to private contracts; however, pipeline companies have or
will become "transporters only." Order 636 also allows pipeline companies to
act as agents for their customers in arranging the transportation of gas
purchased from any supplier, including the pipeline itself, and to charge a
negotiated fee for such agency services. The FERC required each pipeline
company to develop the specific terms of service in individual proceedings and
to submit for approval by FERC a compliance filing which set forth the pipeline
company's new, detailed procedures.
On October 29, 1996, the United States Court of Appeals for the District of
Columbia Circuit denied petitions for rehearing of its earlier decision, United
Distribution Companies v. FERC, 88 F. 3d 1105, 1191 (D.C. Cir. 1996), in which
the D.C. Circuit upheld most of Order 636 ("In its broad contours and in most of
its specifics we uphold Order No. 636"). However, the Court remanded to the
FERC for further explanation the provisions pertaining to (1) restriction of
entitlement to receive no-service to those customers who received bundled firm-
sales service on May 18, 1992; (2) the twenty-year term-matching cap for the
right-of-first refusal mechanism; (3) two aspects of the straight fixed variable
(SFV) rate design mitigation measures; and (4) why, in light of Order 500 and
the general cost-spreading principles of Order 636, pipelines can pass through
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all their gas supply realignment (GSR) transition costs to customers and why
interruptible-transportation customers should bear 10% of GSR costs. On
February 27, 1997 FERC issued its final rule addressing the issues remanded by
the D.C. Circuit. Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation Under Part 284 and Regulation of
National Pipelines After Partial Wellhead Decontrol, 62 Fed. Reg. 10204 (Mar. 6,
1997). FERC reaffirmed its prior position with respect to the SFV rate design
and exempting pipelines from sharing in GSR costs. It modified its regulation
with respect to the other issues, including (i) changing the selection of a
twenty-year matching term for the right of first refusal and instead adopting a
five-year matching term and (ii) reversing the requirement that pipelines
allocate 10% of GSR costs to interruptible customers and requiring that
pipelines propose the percentage that interruptible customers will bear based on
the individual circumstances present on each pipeline. In addition, some of the
individual pipeline restructurings arising from Order 636 are the subject of
pending appeals, either before the FERC or in the courts.
In essence, the goal of Order 636 is to make a pipeline's position as gas
merchant indistinguishable from that of a non-pipeline supplier. It, therefore,
pushes the point of sale of gas by pipelines upstream, perhaps all the way to
the wellhead. Order 636 also requires pipelines to give firm transportation
customers flexibility with respect to receipt and delivery points (except that a
firm shipper's choice of delivery point cannot be downstream of the existing
primary delivery point) and to allow "no-notice" service (which means that gas
is available not only simultaneously but also without prior nomination, with the
only limitation being the customer's daily contract demand) if the pipeline
offered no-notice city-gate sales service on May 18, 1992. Thus, this
separation of pipelines' sales and transportation allows non-pipeline sellers to
acquire firm downstream transportation rights and thus to offer buyers what is
effectively a bundled city-gate sales service and it permits each customer to
assemble a package of services that serves its individual requirements. But
it also makes more difficult the coordination of gas supply and transportation.
The results of these changes could increase the marketability of natural
gas and place the burden of obtaining supplies of natural gas for local
distribution systems directly on distributors who would no longer be able to
rely on the aggregation of supplies by the interstate pipelines. Such
distributors may return to longer term contracts with suppliers who can assure a
secure supply of natural gas. A return to longer term contracts and the
attendant decrease in gas available for the spot market could improve gas
prices. The primary beneficiaries of these changes should be gas marketers and
the producers who are able to demonstrate the availability of an assured long-
term supply of natural gas to local distribution purchasers and to large end
users. However, due to the still evolutionary nature of Order 636 and its
implementation, it is not possible at this time to project the impact Order 636
will have on the Partnership's ability to sell gas directly into gas markets
previously served by the gas pipelines.
As a corollary to Order 636, FERC issued Order 547, which is a blanket
certificate of public convenience and necessity pursuant to Section 7 of the NGA
that authorizes any person who is not an interstate pipeline or an affiliate
thereof to make sales for resale at negotiated rates in interstate commerce of
any category of gas that is subject to the Commission's NGA jurisdiction.
(There are certain requirements which must be met before an affiliated marketer
of an interstate pipeline can avail itself of this certification.) Regulations
Governing Blanket Marketer Sales Certificates, Order No. 547, 57 Fed. Reg.
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57,952 (Dec. 8, 1992) (to be codified at 18 C.F.R. Sections 284.401 - .402).
The blanket certificates were effective January 7, 1993, and do not require any
further application by a person. The goal of Order 457, in conjunction with
Orders 636, 636-A and 636-B, is to provide all merchants of natural gas a "level
playing field" so that gas merchants who are not interstate pipelines are on an
equal footing with interstate pipeline merchants who are afforded blanket sales
certificates pursuant to Order 636.
The FERC has also begun to allow individual companies to depart from cost-
of-service regulation and set market-based rates if they can show they lack
significant market power or have mitigated market power. See, e.g., Richmond
Gas Storage Systems, 59 FERC Paragraph 61,316 (1992); El Paso Natural Gas
Company, 4 FERC Paragraph 61,316, reh'g granted and denied in part, 56 FERC
Paragraph 61,290 (1990); Transcontinental Gas Pipe Line Corp., 53 FERC Paragraph
61,446, reh'g granted and denied in part, 57 FERC Paragraph 61,345 (1991).
Since the FERC has stated that "[w]here companies have market power, market-
based rates are not appropriate," in order to "enhance productive efficiency in
non-competitive markets," the FERC issued a rule allowing pipelines (and
electric utilities) "to propose incentive rate mechanisms as alternatives to
traditional cost-of-service regulations." Incentive Ratemaking for Interstate
Natural Gas Pipelines, Oil Pipelines, and Electric Utilities; Policy Statement
on Incentive Regulation, 57 Fed. Reg. 55,231 (Nov. 24, 1992). The FERC has
established five specific regulatory standards for implementing specific
incentive mechanisms: they should (1) be prospective, (2) be voluntary, (3) be
understandable, (4) result in quantifiable benefits to consumers including an
upper limit on the risk to consumers that the incentive rates would be higher
than rates they would have paid under traditional regulation, and (5)
demonstrate how they maintain or enhance incentives to improve the quality of
service.
Other regulatory actions have included elimination of minimum take and
minimum bill provisions of pipeline sales tariffs (Order 380) and authorization
of automatic abandonment authority upon expiration or termination of the
underlying contracts (Order 490). The latter order is currently before the
United States Court of Appeals for the Sixth Circuit. FERC has also provided
several forms of "blanket" certificates authorizing sales of gas with pregranted
abandonment.
In addition, in Order 451, FERC established an alternative maximum lawful
price for certain NGPA Section 104 and 106 gas produced from wells drilled prior
to 1975 (so-called "old gas") which otherwise would be subject to lower ceiling
prices. FERC provided, however, that the higher price could be collected
only where the parties amended the contract or pursuant to complicated "good
faith negotiation" rules which permit purchasers facing requests for increased
prices to seek reduction of certain higher prices and authorize abandonment of
both the higher cost and lower cost supplies if agreement cannot be reached.
After the Fifth Circuit vacated Order 451 as an invalid exercise of FERC's
authority, the United States Supreme Court reversed that decision and upheld the
entirety of Order 451.
The issuance of Order 636 and its future interpretation, as well as the
future interpretation and application by FERC of all of the above rules and its
broad authority, or of the state and local regulations by the relevant agencies,
could affect the terms and availability of transportation services for
transportation of natural gas to customers and the prices at which gas can be
sold on behalf of the Partnership. For instance, as a result of Order 636, more
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interstate pipeline companies have begun divesting their gathering systems,
either to unregulated affiliates or to third persons, a practice which could
result in separate, and higher, rates for gathering a producer's natural gas.
In proceedings during mid and late 1994 allowing various interstate natural gas
companies' spindowns or spinoffs of gathering facilities, the FERC held that,
except in limited circumstances of abuse, it generally lacks jurisdiction over a
pipeline's gathering affiliates, which neither transport natural gas in
interstate commerce nor sell gas in interstate commerce for resale. However,
pipelines spinning down gathering systems have to include two Order No. 497
standards of conduct in their tariffs: nondiscriminatory access to
transportation for all sources of supply and no tying of pipeline transportation
service to any service by the pipeline's gathering affiliate. In addition, if
unable to reach a mutually acceptable gathering contract with a present user of
the gathering facilities, the FERC required that the pipeline must offer a two-
year "default contract" to existing users of the gathering facilities. However,
on appeal, while the United States Court of Appeals for the District of Columbia
upheld the FERC's allowing the spinning down of gathering facilities to a non-
regulated affiliate, in Conoco Inc. v. FERC, 90 F.3d 536, 552-53 (D.C. Cir.
1996) the D.C. Circuit remanded the FERC's default contract mechanism. On
February 18, 1997 the United States Supreme Court denied a petition to review
the D. C. Circuit's decision. As a result of FERC's action, states are now
enacting or considering statutory and/or regulatory provisions to regulate
gathering systems. Consequently, the General Partner cannot reliably predict at
this time how regulation will ultimately impact Partnership Revenue.
Oil Price Regulation
With respect to oil pipeline rates subject to the FERC's jurisdiction under
the Interstate Commerce Act, in October 1993 the FERC issued Order 561 to
implement the requirements of Title XVIII of the Energy Policy Act of 1992.
Order 561 established an indexing system, effective January 1, 1995, under which
many oil pipelines are able to readily change their rates to track changes in
the Producer Price Index for Finished Goods (PPI-FG), minus one percent. This
index established ceiling levels for rates. Order 561 also permits cost-of-
service proceedings to establish just and reasonable rates. The Order does not
alter the right of a pipeline to seek FERC authorization to charge market rates.
However, until the FERC makes the finding that the pipeline does not exercise
significant market power, the pipeline's rates cannot exceed the applicable
index ceiling level or a level justified by the pipeline's cost of service.
State Regulation of Oil and Gas Production
Most states in which the Partnership may conduct oil and gas activities
regulate the production and sale of oil and natural gas. Those states generally
impose requirements or restrictions for obtaining drilling permits, the method
of developing new fields, the spacing and operation of wells and the prevention
of waste of oil and gas resources. In addition, most states regulate the rate
of production and may establish maximum daily production allowable from both oil
and gas wells on a market demand or conservation basis. Until recently there
has been no limit on allowable daily production on the basis of market demand,
although at some locations production continues to be regulated for conservation
or market purposes. In 1992 Oklahoma and Texas imposed additional limitations
on gas production to more closely track market demand. The General Partner
cannot predict whether any state regulatory agency may issue additional
allowable reductions which may adversely affect the Partnership's ability to
produce its gas reserves.
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Legislative and Regulatory Production and Pricing Proposals
A number of legislative and regulatory proposals continually are advanced
which, if put into effect, could have an impact on the petroleum industry. The
various proposals involve, among other things, an oil import fee, restructuring
how oil pipeline rates are determined and implemented reducing production
allowables, providing purchasers with "market-out" options in existing and
future gas purchase contracts, eliminating or limiting the operation of take-or-
pay clauses, eliminating or limiting the operation of "indefinite price
escalator clauses" (e.g., pricing provisions which allow prices to escalate by
means of reference to prices being paid by other purchasers of natural gas or
prices for competing fuels), and state regulation of gathering systems.
Proposals concerning these and other matters have been and will be made by
members of the President's office, Congress, regulatory agencies and special
interest groups. The General Partner cannot predict what legislation or
regulatory changes, if any, may result from such proposals or any effect
therefrom on the Partnership.
The effect of these regulations could be to decrease allowable production
on Partnership Properties and thereby to decrease Partnership Revenues.
However, by decreasing the amount of natural gas available in the market, such
regulations could also have the effect of increasing prices of natural gas,
although there can be no assurance that any such increase will occur. There can
also be no assurance that the proposed regulations described above will be
adopted or that they will be adopted upon the terms set forth above.
Additionally, such proposals, if adopted, are likely to be challenged in the
courts and there can be no assurance as to the outcome of any such challenge.
Production and Environmental Regulation
Certain states in which the Partnership may drill and own productive
properties control production from wells through regulations establishing the
spacing of wells, limiting the number of days in a given month during which a
well can produce and otherwise limiting the rate of allowable production.
In addition, the federal government and various state governments have
adopted laws and regulations regarding protection of the environment. These
laws and regulations may require the acquisition of a permit before or after
drilling commences, impose requirements that increase the cost of operations,
prohibit drilling activities on certain lands lying within wilderness areas or
other environmentally sensitive areas and impose substantial liabilities for
pollution resulting from drilling operations, particularly operations in
offshore waters or on submerged lands.
A past, present, or future release or threatened release of a hazardous
substance into the air, water, or ground by the Partnership or as a result of
disposal practices may subject the Partnership to liability under the
Comprehensive Environmental Response, Compensation and Liability Act, as amended
("CERCLA"), the Resource Conservation Recovery Act ("RCRA"), the Clean Water
Act, and/or similar state laws, and any regulations promulgated pursuant
thereto. Under CERCLA and similar laws, the Partnership may be fully liable for
the cleanup costs of a release of hazardous substances even though it
contributed to only part of the release. While liability under CERCLA and
similar laws may be limited under certain circumstances, typically the limits
are so high that the maximum liability would likely have a significant adverse
effect on the Partnership. In certain circumstances, the Partnership may have
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liability for releases of hazardous substances by previous owners of Partnership
Properties. Additionally, the discharge or substantial threat of a discharge of
oil by the Partnership into United States waters or onto an adjoining shoreline
may subject the Partnership to liability under the Oil Pollution Act of 1990 and
similar state laws. While liability under the Oil Pollution Act of 1990 is
limited under certain circumstances, the maximum liability under those limits
would still likely have a significant adverse effect on the Partnership. The
Partnership's operations generally will be covered by the insurance carried by
the General Partner or UNIT, if any. However, there can be no assurance that
such insurance coverage will always be in force or that, if in force, it will
adequately cover any losses or liability the Partnership may incur.
Violation of environmental legislation and regulations may result in the
imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the removal, remediation and abatement
of the conditions, or suspension of the activities, giving rise to the
violation. The General Partner believes that the Partnership will comply with
all orders and regulations applicable to its operations. However, in view of
the many uncertainties with respect to the current controls, including their
duration and possible modification, the General Partner cannot predict the
overall effect of such controls on such operations. Similarly, the General
Partner cannot predict what future environmental laws may be enacted or
regulations may be promulgated and what, if any, impact they would have on
operations or Partnership Revenue.
SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT
The business and affairs of the Partnership and the respective rights and
obligations of the Partners will be governed by the Agreement. The following is
a summary of certain pertinent provisions of the Agreement which have not been
as fully discussed elsewhere in this Memorandum but does not purport to be a
complete description of all relevant terms and provisions of the Agreement and
is qualified in its entirety by express reference to the Agreement. Each
prospective subscriber should carefully review the entire Agreement.
Partnership Distributions
The General Partner will make quarterly determinations of the Partnership's
cash position. If it determines that excess cash is available for distribution,
it will be distributed to the Partners in the same proportions that Partnership
Revenue has been allocated to them after giving effect to previous distributions
and to portions of such revenues theretofore used or expected to be thereafter
used to pay costs incurred in conducting Partnership operations or to repay
Partnership borrowings. It is expected that no cash distributions will be made
earlier than the first quarter of 2000. 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.
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The Partnership will terminate automatically on December 31, 2029 unless
prior thereto the General Partner or Limited Partners holding a majority of the
outstanding Units elect to terminate the Partnership as of an earlier date.
Upon termination of the Partnership, the debts, liabilities and obligations of
the Partnership will be paid and the Partnership's oil and gas properties and
any tangible equipment, materials or other personal property may be sold for
cash. The cash received will be used to make certain adjusting payments
to the Partners (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -
Termination"). Any remaining cash and properties will then be distributed to
the Partners in proportion to and to the extent of any remaining balances in the
Partners' capital accounts and then in undivided percentage interests to the
Partners in the same proportions that Partnership Revenues are being shared at
the time of such termination (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT
- - Termination").
Deposit and Use of Funds
Until required in the conduct of the Partnership's business, Partnership
funds, including, but not limited to, the Capital Contributions, Partnership
Revenue and proceeds of borrowings by the Partnership, will be deposited, with
or without interest, in one or more bank accounts of the Partnership in a bank
or banks to be selected by the General Partner or invested in short-term United
States government securities, money market funds, bank certificates of deposit
or commercial paper rated as "A1" or "P1" as the General Partner, in its sole
discretion, deems advisable. Any interest or other income generated by such
deposits or investments will be for the Partnership's account. Except for
Capital Contributions, Partnership funds from any of the various sources
mentioned above may be commingled with funds of the General Partner and may
be used, expended and distributed as authorized by the terms and provisions of
the Agreement. The General Partner will be entitled to prompt reimbursement of
expenses it incurs on behalf of the Partnership.
Power and Authority
In managing the business and affairs of the Partnership, the General
Partner is authorized to take such action as it considers appropriate and in the
best interests of the Partnership (see Section 10.1 of the Agreement). The
General Partner is authorized to engage legal counsel and otherwise to act with
respect to Service audits, assessments and administrative and judicial
proceedings as it deems in the best interests of the Partnership and pursuant to
the provisions of the Code.
The General Partner is granted a broad power of attorney authorizing it to
execute certain documents required in connection with the organization,
qualification, continuance, modification and termination of the Partnership on
behalf of the Limited Partners (see Sections 1.5 and 1.6 of the Agreement).
Certain actions, such as an assignment for the benefit of its creditors or a
sale of substantially all of the Partnership Properties, except in connection
with the termination, roll-up or consolidation of the Partnership, cannot be
taken by the General Partner without the consent of a majority in interest of
the Limited Partners and the receipt of an opinion of counsel as described under
"Assignments by the General Partner" below (see Sections 10.15 and 12.1 of the
Agreement).
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The Agreement provides that the General Partner will either conduct the
Partnership's drilling and production operations and operate each Partnership
Well or arrange for a third party operator to conduct such operations. The
General Partner will, on behalf of the Partnership, enter into an appropriate
operating agreement with the other owners of properties to be developed by the
Partnership authorizing either the General Partner or a third party operator to
conduct such operations. The Partnership Agreement further provides that the
Partnership will take such action in connection with operations pursuant to such
operating agreements as the General Partner, in its sole discretion, deems
appropriate and in the best interests of the Partnership, and the decision of
the General Partner with respect thereto will be binding upon the Partnership.
Rollup or Consolidation of the Partnership
Two years or more after the Partnership has completed substantially all of
its property acquisition, drilling and development operations, the General
Partner may, without the vote, consent or approval of the Limited Partners,
cause all or substantially all of the oil and gas properties and other assets of
the Partnership to be sold, assigned or transferred to, or the Partnership
merged or consolidated with, another partnership or a corporation, trust or
other entity for the purpose of combining the assets of two or more of the oil
and gas partnerships formed for investment or participation by employees,
directors and/or consultants of UNIT or any of its subsidiaries; provided,
however, that the valuation of the oil and gas properties and other assets of
all such participating partnerships for purposes of such transfer or combination
shall be made on a consistent basis and in a manner which the General Partner
and UNIT believe is fair and equitable to the Limited Partners. As a
consequence of any such transfer or combination, the Partnership will be
dissolved and terminated and the Limited Partners shall receive partnership
interests, stock or other equity interests in the transferee or resulting
entity. See "RISK FACTORS - Investment Risks - Roll-Up or Consolidation of the
Partnership."
Limited Liability
Under the Act, a limited partner is not generally liable for partnership
obligations unless he or she takes part in the control of the business. The
Agreement provides that the Limited Partners cannot bind or commit the
Partnership or take part in the control of its business or management of its
affairs, and that the Limited Partners will not be personally liable for any
debts or losses of the Partnership. However, the amounts contributed to the
Partnership by the Limited Partners and the Limited Partners' interests in
Partnership assets, including amounts of undistributed Partnership Revenue
allocable to the Limited Partners, will be subject to the claims of creditors of
the Partnership. A Limited Partner (or his or her estate) will be obligated to
contribute cash to the Partnership, even if the Limited Partner is unable to do
so because of death, disability or any other reason, for:
(1) any unpaid contribution which the Limited Partner agreed to make to
the Partnership; and
(2) any return, in whole or in part, of the Limited Partner's contribution
to the extent necessary to discharge Partnership liabilities to all
creditors who extended credit or whose claims arose before such return.
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Liability of a Limited Partner is limited by the Act to one year for any
return of his or her contribution not in violation of the Partnership Agreement
or such Act and six years on any return of his or her contribution in violation
of the Partnership Agreement or such Act. A partner is deemed to have received
a return of his or her contribution to the extent that a distribution to him or
her reduces his or her share of the fair value of the net assets of the
Partnership below the value of his or her contribution which has not been
distributed to him or her. How this provision applies to a partnership whose
primary assets are producing oil and gas properties or other depleting assets is
not entirely clear. The Agreement provides that for the purposes of this
provision, the value of a Limited Partner's contribution which has not been
distributed to him or her at any point in time will be the Limited Partner's
Percentage of the stated capital of the Partnership allocated to the Limited
Partners as reflected in its financial statements as of such point in time.
Maintenance of limited liability of the Limited Partners in other
jurisdictions in which the Partnership may operate may require compliance with
certain legal requirements of those jurisdictions. In such jurisdictions, the
General Partner shall cause the Partnership to operate in such a manner as it,
on the advice of responsible counsel, deems appropriate to avoid unlimited
liability for the Limited Partners (see Sections 1.5, 12.1 and 12.2 of the
Agreement). After the termination of the Partnership, any distribution of
Partnership Properties to the Limited Partners would result in their having
unlimited liability with respect to such properties.
Although the Partnership will, with certain limited exceptions, serve as a
co-general partner of any drilling or income programs formed by UNIT or UPC in
1999 (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 Partnership, such transfer or assignment would not violate, or cause the
offering of the Units to be violative of, such act or applicable state
securities laws, including investor suitability standards thereunder. Because
of the structure and anticipated operation of the Partnership, Rule 144 under
the Securities Act of 1933 will not be available to Limited Partners in
connection with any such sales.
Assignees. An assignee of a Limited Partner does not automatically become
a Substituted Limited Partner, but has the right to receive the same share of
Partnership Revenue and distributions thereof to which the assignor Limited
Partner would have been entitled. A Limited Partner who assigns his or her
Partnership interest ceases to be a Limited Partner, except that until a
Substituted Limited Partner is admitted in his or her place, the assignor
retains the statutory rights of an assignor of a Limited Partner's interest
under the partnership laws of the State of Oklahoma. The assignee of a
Partnership interest who does not become a Substituted Limited Partner and
desires to make a further assignment of such interest is subject to all of the
restrictions on transferability of Partnership interests described herein and in
the Partnership Agreement.
In the event of the death, incapacity or bankruptcy of a Limited Partner,
his or her legal representatives will have all the rights of a Limited Partner
only for the purpose of settling or liquidating his or her estate and such power
as the decedent, incompetent or bankrupt Limited Partner possessed to assign all
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or any part of his or her interest in the Partnership and to join with such
assignee in satisfying conditions precedent to such assignee's becoming a
Substituted Limited Partner.
A purported sale, assignment or transfer of a Limited Partner's interest
will be recognized by the Partnership when it has received written notice of
such sale or assignment in form satisfactory to the General Partner, signed by
both parties, containing the purchaser's or assignee's acceptance of the terms
of the Agreement and a representation by the parties that the sale or assignment
was lawful. Such sale or assignment will be recognized as of the date of such
notice, except that if such date is more than 30 days prior to the time of
filing, such sale or assignment will be recognized as of the time the notice was
filed with the Partnership. Distributions of Partnership Revenue will be made
only to those persons who were record owners of Units on the day any such
distribution is made (see "RISK FACTORS - Tax Related Risks - Disproportionate
Tax Liability upon Transfer").
Substituted Limited Partners. No Limited Partner has the right to
substitute an assignee as a Limited Partner in his or her place. The General
Partner, however, has the right in its sole discretion to permit such assignee
to become a Substituted Limited Partner and any such permission by the General
Partner is binding and conclusive without the consent or approval of any Limited
Partner. Any Substituted Limited Partner must, as a condition to receiving any
interest of the Limited Partner, agree in writing to be bound by the terms and
conditions of the Partnership Agreement, pay or agree to pay the costs and
expenses incurred by the Partnership in taking the actions necessary in
connection with his or her substitution as a Limited Partner and satisfy the
other conditions specified in Article XIII of the Partnership Agreement.
Assignments by the General Partner. The General Partner may not sell,
assign, transfer or otherwise dispose of its interest in the Partnership except
with the prior consent of a majority in interest of the Limited Partners,
provided that no such consent is required if the sale, assignment or transfer is
pursuant to a bona fide merger, other corporate reorganization or complete
liquidation, sale of substantially all of the General Partner's assets (provided
the purchasers agree to assume the duties and obligations of the General
Partner) or any sale or transfer to UNIT or any affiliate of UNIT. Any consent
of the Limited Partners will not be effective without an opinion of counsel to
the Partnership or an order or judgment of a court of competent jurisdiction to
the effect that the exercise of such right will not be deemed to evidence that
the Limited Partners are taking part in the management of the Partnership's
business and affairs and will not result in a loss of any Limited Partner's
limited liability or cause the Partnership to be classified as an association
taxable as a corporation for federal income tax purposes (see Section 12.1 of
the Agreement). Any transferee of the General Partner's interest may become a
substitute General Partner by assuming and agreeing to perform all of the duties
and obligations of a General Partner under the Agreement. In such event, the
transferring General Partner, upon making a proper accounting to the substitute
General Partner, will be relieved of any further duties or obligations with
respect to any future Partnership operations.
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
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Partner's compensation or otherwise materially and adversely affecting the
interests of either the Limited Partners or the General Partner must be approved
by all Limited Partners if their interests would be adversely affected thereby
or by the General Partner if its interest would be adversely affected thereby.
The Limited Partners have no right to propose amendments to the Agreement.
Voting Rights
Under the Agreement, the Limited Partners will have very limited rights to
vote on any Partnership matters. Except for certain special amendments referred
to under "Amendments" above, matters submitted to the Limited Partners for
determination will be determined by the affirmative vote of Limited Partners
holding a majority of the outstanding Units. Units held by the General Partner
may be voted by it.
Generally, Limited Partners owning more than 50% of the outstanding Units
of the Partnership may, without the necessity of concurrence by the General
Partner, vote to:
. Approve the execution or delivery of any assignment for the benefit
of the Partnership's creditors;
. Approve the sale or disposal of all or substantially all of the
Partnership's assets, except pursuant to (i) a rollup or
consolidation of the Partnership (see "Rollup or Consolidation of the
Partnership" above) or (ii) termination (see "Termination" below);
. Approve the General Partner's sale, assignment, transfer or disposal
of its interest in the Partnership, unless such sale, assignment or
transfer is pursuant to (i) a merger or other corporate
reorganization, or liquidation or sale of substantially all of its
assets, and the purchaser agrees to assume the duties and obligations
of the General Partner, or (ii) any sale to UNIT or its affiliates;
. Terminate and dissolve the Partnership; or
. Approve any amendments to the Agreement which may be proposed by the
General Partner;
provided, however, any approvals, consents or elections of the Limited Partners
will not become effective unless prior to the exercise thereof the General
Partner is furnished with an opinion of counsel for the Partnership, or an order
or judgment of any court of competent jurisdiction, that the exercise of such
rights:
. Will not be deemed to evidence that the Limited Partners are taking
part in the control or management of the Partnership's business
affairs;
. Will not result in the loss of any Limited Partner's limited
liability under the Act; and
. Will not result in the Partnership being classified as an association
taxable as a corporation for federal income tax purposes.
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Exculpation and Indemnification of the General Partner
Pursuant to the Agreement, neither the General Partner or any affiliate
thereof will have any liability to the Partnership or to any Partners therein
for any loss suffered by the Partnership or such Partner that arises out of any
action or inaction of the General Partner or any affiliate thereof if the
General Partner or affiliate thereof in good faith determined that such course
of conduct was in the best interest of the Partnership, the General Partner or
affiliate was acting on behalf of or performing services for the Partnership,
such liability or loss was not the result of gross negligence or wilful
misconduct by the General Partner or affiliates thereof, and payments arising
from such indemnification or agreement to hold harmless are receivable only out
of the tangible net assets of the Partnership.
Termination
The Partnership will terminate automatically on December 31, 2029. In
addition, upon the dissolution (other than pursuant to a merger, or other
corporate reorganization or sale), bankruptcy, legal disability or
withdrawal of the General Partner, the Partnership shall immediately be
dissolved and terminated. The Act provides, however, that the Limited Partners
may elect to reform and reconstitute themselves as a limited partnership within
90 days after such dissolution under the provisions in the Partnership Agreement
or under any other terms. The Partnership may terminate sooner if a majority in
interest of the Limited Partners or the General Partner elects to dissolve and
terminate the Partnership as of an earlier date. Such right to accelerate
termination of the Partnership by the Limited Partners will not be available
unless prior to any exercise thereof the Limited Partners proposing such
termination obtain and furnish to the General Partner an opinion, order
or judgment in the form referred to above under "Transferability of Interests -
Assignments by the General Partner." The withdrawal, expulsion, dissolution,
death, legal disability, bankruptcy or insolvency of any Limited Partner will
not effect a dissolution or termination of the Partnership. In the event of an
election to terminate the Partnership prior to expiration of its stated terms,
90 days' prior written notice must be given to all Partners specifying the
termination date which must be the last day of a calendar month following such
90 day period unless an earlier date is approved by Limited Partners holding a
majority of the outstanding Units.
When the Partnership is terminated, there will be an accounting with
respect to its assets, liabilities and accounts. The Partnership's physical
property and its oil and gas properties may be sold for cash. Except in the
case of an election by the General Partner to terminate the Partnership before
the tenth anniversary of the Effective Date, Partnership Properties may be sold
to the General Partner or any of its affiliates for their fair market value as
determined in good faith by the General Partner.
Upon termination, all of the Partnership's debts, liabilities and
obligations, including expenses incurred in connection with the termination and
the sale or distribution of Partnership assets, will be paid. All Partnership
borrowings will be paid in full. When the specified payments have all been
made, the remaining cash and properties of the Partnership, if any, will be
distributed to the Partners as set forth under "Partnership Distributions" above
(see Section 16.4 of the Agreement). Such distribution will result in the
Limited Partners' having unlimited liability with respect to any Partnership
Properties distributed to them.
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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, 3700 First Place Tower,
Tulsa, Oklahoma, has acted as special counsel ("Counsel") to the General Partner
in connection with certain aspects of this offering. Counsel has assisted in
the preparation of the Agreement and this Memorandum. In connection with the
preparation of this Memorandum, Counsel has relied entirely upon information
submitted to it by the General Partner. Certain of this information has been
verified by Counsel in the course of its representation, but no systematic
effort has been made to verify all of the material information contained herein,
and much of such information is not subject to independent verification. In
addition, Counsel has made no independent investigation of the financial
information concerning the General Partner. Further, while passing on certain
legal matters, Counsel has not passed on the investment merits nor is it
qualified to do so. Because substantial portions of the information contained
in this Memorandum have not been independently verified, each investor must make
whatever independent inquiries the investor or his or her advisors deem
necessary or desirable to verify or confirm the statements made herein.
GLOSSARY
As used herein and in the Agreement, the following terms and phrases will
have the meanings indicated.
(a) "Additional Assessments" are amounts required to be contributed by the
Limited Partners to the Partnership upon a call therefor by the General Partner
in the manner described under "ADDITIONAL FINANCING - Additional Assessments."
(b) An "affiliate" of another person is (1) any person directly or
indirectly owning, controlling or holding with power to vote 10% or more of the
outstanding voting securities of such other person; (2) any person 10% or more
of whose outstanding voting securities are directly or indirectly owned,
controlled, or held 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
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includes the amounts contributed to the Partnership or paid by the General
Partner or by any Limited Partner whose Units are purchased by the General
Partner pursuant to Section 4.2 of the Agreement because of a default by such
Limited Partner in the payment of an Installment or pursuant to Article XV of
the Agreement, including payments made by deductions from the salary of
such Limited Partner.
(f) The "Capital Subscription" of a Limited Partner or his or her assignee
(including the General Partner where Units are transferred pursuant to Section
4.2 of the Agreement) is the amount specified in the Subscription Agreement
executed by such Limited Partner for payment by him or her to the capital of the
Partnership in accordance with the provisions of the Agreement, reduced by the
amounts thereof from which the Limited Partners have been released by the
General Partner of their obligation to pay.
(g) A "Development Well" means a well intended to be drilled within the
proved areas of a known oil or gas reservoir to the depth of a stratigraphic
horizon known to be productive.
(h) "Director" refers to the duly elected directors of UNIT as well as all
honorary directors and consultants to the Board of Directors of UNIT.
(i) "Drilling Costs" are those costs incurred in drilling, testing,
completing and equipping a well to the point that it proves to be dry and is
abandoned or is ready to commence commercial production of oil or gas therefrom.
(j) "Effective Date" refers to the date on which the certificate
evidencing formation of the Partnership is filed with the Secretary of State of
the State of Oklahoma as required by the Act (54 Okla. Stat. 1991, Section 309).
(k) An "Exploratory Well" means a well drilled to find production in an
unproven area, to find a new reservoir in a field previously found to be
productive or to extend greatly the limits of a known reservoir.
(l) A "farm-out" is an agreement whereby the owner of an oil and gas
property agrees to assign such property, usually retaining some interest therein
such as an overriding royalty, a production payment, a net profits interest or a
carried working interest, subject in most cases, however, to the drilling of one
or more wells or other performance by the prospective assignee as a condition
of the assignment.
(m) The "General Partner's Minimum Capital Contribution" is that amount
equal to the total of (i) all Partnership costs and expenses charged to its
account from the time of the formation of the Partnership through December 31,
1999, 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, 1999, if any, minus (iii) the amount, if any, of the
unexpended Aggregate Subscription at December 31, 1999.
(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
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March 15, 1999, June 15, 1999, September 15, 1999 and December 15, 1999,
respectively, or (ii) if an employee so elects, through equal deductions
from 1999 salary commencing immediately after formation of the Partnership.
(p) "Leasehold Acquisition Costs" with respect to properties, if any,
acquired by the Partnership from non-affiliated parties mean the actual costs to
the Partnership of and in acquiring the properties, and, with respect to
properties acquired by the Partnership from the General Partner, UNIT or its
affiliates are, without duplication, the sum of:
(1) the prices paid by the General Partner, UNIT or its affiliates in
acquiring an oil and gas property, including purchase option fees and
charges, bonuses and penalties, if any;
(2) title insurance or examination costs, broker's commissions, filing
fees, recording costs, transfer taxes, if any, and like charges
incurred in connection with the acquisition of such property;
(3) a pro rata portion of the actual, necessary and reasonable expenses of
the General Partner, UNIT or its affiliates for seismic and
geophysical services;
(4) rentals, shut-in royalties and ad valorem taxes paid by the General
Partner, UNIT or its affiliates with respect to such property to the
date of its transfer to the Partnership;
(5) interest and points actually incurred on funds used by the General
Partner, UNIT or its affiliates to acquire or maintain such property;
and
(6) such portion of the General Partner's, UNIT or its affiliates'
reasonable, necessary and actual expenses for geological, engineering,
drafting, accounting, legal and other like services allocated to the
acquisition, operations and maintenance of the property in accordance
with generally accepted industry practices, except for expenses in
connection with the past drilling of wells which are not producers of
sufficient quantities of oil or gas to make commercially reasonable
their continued operations, and provided that the costs and expenses
enumerated in (4), (5) and (6) above with respect to any particular
property shall have been incurred not more than thirty-six (36) months
prior to the acquisition of such property by the Partnership.
In the event a fractional undivided interest in a property is sold or
transferred by the General Partner, UNIT or any affiliate to an unaffiliated
third party for an amount in excess of that portion of the original cost of the
property attributable to the transferred interest, the amount of such excess
shall not reduce or be offset against the amount of the Leasehold Acquisition
Costs attributable to any interest in the same property which is transferred to
the Partnership.
(q) "Limited Partners" are those persons who acquire Units in the
Partnership upon its formation and those transferees of Units who are accepted
as Substituted Limited Partners. The General Partner may also be a Limited
Partner if it subscribes for Units or if it subsequently acquires Units by (i)
the exercise by a Limited Partner of his or her right of presentment; (ii) a
purchase by the General Partner of the Units of a Limited Partner who defaults
in the payment of an Installment; or (iii) any other assignment or transfer.
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(r) The "Limited Partners' Percentage" is that percentage determined by
dividing the amount of the Aggregate Subscription by the total of (i) the
General Partner's Minimum Capital Contribution plus (ii) the Aggregate
Subscription.
(s) "Normal Retirement" means retirement under the terms of a pension or
similar retirement plan adopted by the General Partner, UNIT or any subsidiary
with whom a Limited Partner is employed as in effect at the time of retirement.
(t) "Oil and gas properties" are oil and gas leasehold working interests,
fee interests, mineral interests, royalty interests, overriding royalty
interests, production payments, options or rights to lease or acquire such
interests, geophysical exploration permits and any tangible or intangible
properties or other rights incident thereto, whether real, personal or mixed.
(u) "Operating Expenses" are expenditures made and costs incurred in
producing and marketing oil or gas from completed wells, including, in addition
to labor, fuel, repairs, hauling, material, supplies, utility charges and other
costs incident to or necessary for the maintenance or operation of such wells or
the marketing of production therefrom, ad valorem, severance and other
such taxes (other than windfall profit taxes), insurance and casualty loss
expense and compensation to well operators or others for services rendered in
conducting such operations.
(v) The General Partner and the Limited Partners are sometimes
collectively referred to as the "Partners."
(w) "Partnership Agreement" and "Agreement" refer to the Agreement of
Limited Partnership attached as Exhibit A to this Private Offering Memorandum.
(x) The "Partnership Properties" are oil and gas properties or interests
therein acquired by the Partnership or properties acquired by any partnership or
joint venture in which the Partnership is a partner or joint venturer, whether
acquired by purchase, option exercise or otherwise.
(y) "Partnership Revenue" refers to the Partnership's gross revenues from
all sources, including interest income, proceeds from sales of production, the
Partnership's share of revenues from partnerships or joint ventures of which it
is a member, sales or other dispositions of Partnership Properties or other
Partnership assets, provided that contributions to Partnership capital by the
Partners and the proceeds of any Partnership borrowings are specifically
excluded and dry-hole and bottom-hole contributions shall be treated as
reductions of the costs giving rise to the right to receive such contributions.
(z) "Partnership Wells" are any and all of the oil and gas wells in which
the Partnership has an interest, either directly or indirectly through any other
partnership or joint venture.
(aa) "Productive properties" are oil and gas properties that have been
tested by drilling and determined to be capable of producing oil or gas in
commercial quantities.
(bb) A "spacing unit" is a drilling and spacing, production or similar unit
established by any regulatory body with jurisdiction, or in the absence of such
a regulatory body or action thereby, the acreage attributable to wells drilled
under the normal spacing pattern in such area or if no such spacing unit is
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designated, in keeping with generally accepted industry practices, or the
largest of such units in the event of multiple objective formations.
(cc) "Special Production and Marketing Costs" are costs and expenses that
are not normally and customarily incurred in connection with drilling, producing
and marketing operations, including without limitation, costs incurred in
constructing compressor plants, gasoline plants, gas gathering systems, natural
gas processing plants, pipeline systems and salt water disposal systems and
costs incurred in installing pressure maintenance and secondary or tertiary
production projects.
(dd) "Subscription Agreement" refers to the form of Limited Partner
Subscription Agreement and Suitability Statement attached as Attachment I to the
Partnership Agreement.
(ee) A "Substituted Limited Partner" is a transferee, donee, heir, legatee
or other recipient of all or any portion of a Limited Partner's interest in the
Partnership with respect to whom all conditions and consents required to become
a Substituted Limited Partner under Article XIII of the Partnership Agreement
have been satisfied and given.
(ff) A "Unit" is a preformation unit of limited partnership interest of a
Limited Partner in the Partnership representing a Capital Subscription of One
Thousand Dollars ($1,000).
FINANCIAL STATEMENTS
On January 1, 1988 all of the oil and natural gas properties previously
owned by Unit Drilling and Exploration Company ("UDEC") and UNIT were
transferred into Sunshine Development Company through a contribution of capital.
Included in the transfer were all interests previously owned by UDEC in numerous
General and Limited Partnerships sponsored by UDEC. Effective February 1, 1988,
Sunshine Development Company, a wholly owned subsidiary of UDEC, pursuant to an
"Amended and Restated Certificate of Incorporation" was renamed Unit Petroleum
Company and became a wholly owned subsidiary of UNIT.
Unit Petroleum Company functions as the operating entity for all oil and
natural gas exploration and production activities including operating any
partnerships for UNIT.
The consolidated balance sheet of Unit Petroleum Company at October 31,
1998 is unaudited and includes all adjustments which UNIT considers necessary
for a fair presentation of the financial position of Unit Petroleum Company at
October 31, 1998.
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Unit Petroleum Company and Subsidiary
Consolidated Balance Sheet
(In Thousands)
October 31,
1998
-----------
(Unaudited)
Assets
------
Current Assets:
Cash and cash equivalents $ 376
Accounts receivable 6,959
Materials and supplies, at lower of cost or market 3,237
Other 180
--------
Total current assets 10,752
--------
Property and Equipment:
Oil and natural gas properties, on the full cost method 267,658
Other 376
--------
268,034
Less accumulated depreciation, depletion,
amortization and impairment 128,636
--------
Net property and equipment 139,398
--------
Other Assets 19
--------
Total Assets $150,169
========
Liabilities and Shareholders' Equity
------------------------------------
Current Liabilities:
Current portion of natural gas purchaser prepayments $ 440
Accounts payable 4,262
Amount Payable to parent 60,961
Contract advances 4
Accrued liabilities 1,031
--------
Total current liabilities 66,698
--------
Long-Term Portion of Natural Gas Purchaser Prepayment 1,319
--------
Shareholders' Equity:
Common stock, $1.00 per value, 500 shares
authorized and outstanding 1
Capital in excess of par value 31,486
Retained earnings 50,665
--------
Total shareholders' Equity 82,152
--------
Total Liabilities and Shareholders' Equity $150,169
========
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EXHIBIT A
UNIT 1999 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP
AGREEMENT OF LIMITED PARTNERSHIP
A-1
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INDEX
ARTICLE I
Formation of Limited Partnership . . . . . . . . . . . . . . . .4
ARTICLE II
Definitions. . . . . . . . . . . . . . . . . . . . . . . . . . .5
ARTICLE III
Purposes and Powers of the Partnership . . . . . . . . . . . . .9
ARTICLE IV
Partner Capital Contributions. . . . . . . . . . . . . . . . . 12
ARTICLE V
Deposit and Use of Capital Contributions and
Other Partnership Funds. . . . . . . . . . . . . . . . . . . . 13
ARTICLE VI
Sharing of Costs, Capital Accounts and
Allocation of Charges and Income . . . . . . . . . . . . . . . 15
ARTICLE VII
Fiscal Year, Accountings and Reports . . . . . . . . . . . . . 20
ARTICLE VIII
Tax Returns and Elections. . . . . . . . . . . . . . . . . . . 21
ARTICLE IX
Distributions. . . . . . . . . . . . . . . . . . . . . . . . . 21
ARTICLE X
Rights, Duties and Obligations of the General Partner. . . . . 21
ARTICLE XI
Compensation and Reimbursements. . . . . . . . . . . . . . . . 27
ARTICLE XII
Rights and Obligations of Limited Partners . . . . . . . . . . 28
ARTICLE XIII
Transferability of Limited Partner's Interest. . . . . . . . . 29
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ARTICLE XIV
Assignments by the General Partner . . . . . . . . . . . . . . 31
ARTICLE XV
Limited Partners' Right of Presentment . . . . . . . . . . . . 32
ARTICLE XVI
Termination and Dissolution of Partnership . . . . . . . . . . 34
ARTICLE XVII
Notices. . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
ARTICLE XVIII
Amendments . . . . . . . . . . . . . . . . . . . . . . . . . . 36
ARTICLE XIX
General Provisions . . . . . . . . . . . . . . . . . . . . . . 37
ATTACHMENT I Limited Partner Subscription Agreement
and Suitability Statement. . . . . . . . . . . . . .I-1
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UNIT 1999 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 1999
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,
2029, unless sooner terminated pursuant to any provisions of this Agreement.
A-4
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1.5 The parties hereto will execute such certificates and other documents,
and the General Partner will file, record and publish such certificates and
documents, as may be necessary or appropriate to comply with the requirements
for the formation and operation of a limited partnership under the Act and as
the General Partner, upon advice of counsel, deems necessary or appropriate
to comply with requirements of applicable laws governing the formation and
operations of a limited partnership (or a partnership in which special partners
have a limited liability) in all other jurisdictions where the Partnership
desires to conduct business, including, but not limited to, filings under the
Fictitious Name Act, Assumed Name Act or similar law in effect in the counties,
parishes and other governmental jurisdictions in which the Partnership conducts
business. The General Partner shall not be required to deliver or mail a copy
of the certificate of limited partnership or any amendments thereto filed
pursuant to the Act to the Limited Partners.
1.6 Each Limited Partner by his or her execution of a counterpart of the
Subscription Agreement irrevocably constitutes and appoints the General Partner
such Limited Partner's true and lawful attorney and agent, with full power and
authority in such Limited Partner's name, place and stead, to execute, sign,
acknowledge, swear to, deliver, file and record in the appropriate public
offices (i) all certificates or other instruments (including, without
limitation, counterparts of this Agreement) and amendments thereto which the
General Partner deems appropriate to qualify or continue the Partnership as a
limited partnership (or a partnership in which special partners have limited
liability) in the jurisdictions in which the Partnership conducts business; (ii)
all instruments and amendments thereto which the General Partner deems
appropriate to reflect any change or modification of this Agreement, the
admission of additional or substitute Partners in accordance with the terms of
this Agreement, the release or waiver of the Limited Partners from the
obligation to pay in one or more of the installments of their Capital
Subscriptions pursuant to Section 4.2 below and the termination of the
Partnership and the cancellation of the certificate of limited partnership;
(iii) all conveyances and other instruments which the General Partner deems
appropriate to evidence and reflect any sales or transfers, including sales or
transfers upon or in connection with the dissolution and termination of the
Partnership; and (iv) all consents to transfers of Partnership interests, to the
admission of substitute or additional Partners or to the withdrawal or reduction
of any Partner's invested capital, to the extent that such actions are
authorized by the terms of this Agreement. The Power of Attorney granted herein
is irrevocable and is a power coupled with an interest and will survive the
death, disability, dissolution, bankruptcy, insolvency or incapacity of a
Limited Partner.
ARTICLE II
Definitions
2.1 Whenever used in this Agreement the following terms will have the
meanings described below:
(a) The "Additional Assessments" of the Limited Partners are those
amounts, if any, which they are required to pay into the capital of the
Partnership pursuant to Section 5.3 of this Agreement.
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(b) An "affiliate" of another person is (1) any person directly or
indirectly owning, controlling or holding with power to vote 10% or more of
the outstanding voting securities of such other person; (2) any person 10%
or more of whose outstanding voting securities are directly or indirectly
owned, controlled, or held with power to vote, by such other person; (3)
any person directly or indirectly controlling, controlled by, or under
common control with such other person; (4) any officer, director, trustee
or partner of such other person; and (5) if such other person is an
officer, director, trustee or partner, any company for which such person
acts in any such capacity.
(c) The "Aggregate Subscription" is the sum of the Capital
Subscriptions of all Limited Partners.
(d) The "Capital Contribution" of a Limited Partner is the amount of
the Capital Subscription actually paid in by him or her, or by any
predecessor in interest, to the capital of the Partnership, including any
payments made by deductions from salary. The "Capital Contribution" of the
General Partner includes the amounts contributed to the Partnership or
paid by the General Partner or by any Limited Partner whose Units are
purchased by the General Partner including purchases pursuant to Section
4.2 of this Agreement because of a default by such Limited Partner in the
payment of a subscription installment or pursuant to Article XV of this
Agreement, including payments made by deductions from the salary of such
Limited Partner.
(e) The "Capital Subscription" of a Limited Partner or his or her
assignee (including the General Partner where Units are transferred
pursuant to Section 4.2 of this Agreement) is the amount specified in the
Subscription Agreement executed by such Limited Partner for payment by him
or her to the capital of the Partnership in accordance with the provisions
of this Agreement, reduced by the amount thereof from which the Limited
Partner has been released by the General Partner of his or her obligation
to pay pursuant to Section 4.2 hereof.
(f) "Drilling Costs" are those costs incurred in drilling, testing,
completing and equipping a Partnership Well to the point that it proves to
be dry and is abandoned or is ready to commence commercial production of
oil or gas therefrom.
(g) "Effective Date" refers to the date on which the certificate
evidencing formation of the Partnership is filed with the Secretary of
State of the State of Oklahoma as required by the Act (54 Okla. Stat. 1991,
Section 309).
(h) A "farm-out" is an agreement whereby the owner of an oil and gas
property agrees to assign such property, usually retaining some interest
therein such as an overriding royalty, a production payment, a net profits
interest or a carried working interest, subject in most cases, however, to
the drilling of one or more wells or other performance by the prospective
assignee as a condition of the assignment.
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(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, 1999, 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, 1999, minus (iii) the amount, if
any, of the unexpended Aggregate Subscription at December 31, 1999.
(j) The "General Partner's Percentage" is that percentage determined
by dividing the amount of the General Partner's Minimum Capital
Contribution by the total of (i) the General Partner's Minimum Capital
Contribution plus (ii) the Aggregate Subscription.
(k) "Leasehold Acquisition Costs" with respect to properties, if any,
acquired by the Partnership from non-affiliated parties mean the actual
costs to the Partnership of and in acquiring the properties, and, with
respect to properties acquired by the Partnership from the General Partner,
UNIT or its affiliates, are, without duplication, the sum of: (1) the
prices paid by the General Partner, UNIT or its affiliates in acquiring an
oil and gas property, including purchase option fees and charges, bonuses
and penalties, if any; (2) title insurance or examination costs, broker's
commissions, filing fees, recording costs, transfer taxes, if any, and like
charges incurred in connection with the acquisition of such property; (3) a
pro rata portion of the actual, necessary and reasonable expenses of the
General Partner, UNIT or its affiliates for seismic and geophysical
services; (4) rentals, shut-in royalties and ad valorem taxes paid by the
General Partner, UNIT or its affiliates with respect to such property to
the date of its transfer to the Partnership; (5) interest and points
actually incurred on funds used by the General Partner, UNIT or its
affiliates to acquire or maintain such property; and (6) such portion of
the General Partner's, UNIT's or its affiliates' reasonable, necessary and
actual expenses for geological, engineering, drafting, accounting, legal
and other like services allocated to the acquisition, operations and
maintenance of the property in accordance with generally accepted industry
practices, except for expenses in connection with the past drilling of
wells which are not producers of sufficient quantities of oil or gas
to make commercially reasonable their continued operations, and provided
that the costs and expenses enumerated in (4), (5) and (6) above with
respect to any particular property shall have been incurred not more than
thirty-six (36) months prior to the acquisition of such property by the
Partnership. In the event a fractional undivided interest in a property is
sold or transferred by the General Partner, UNIT or any affiliate to an
unaffiliated third party for an amount in excess of that portion of the
original cost of the property attributable to the transferred interest, the
amount of such excess shall not reduce or be offset against the amount of
the Leasehold Acquisition Costs attributable to any interest in the same
property which is transferred to the Partnership.
(l) "Limited Partners" are those persons who acquire Units in the
Partnership upon its formation and those transferees of Units who are
accepted as Substituted Limited Partners. The General Partner may also be
a Limited Partner if it subscribes for Units or if it subsequently acquires
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Units by (i) the exercise by a Limited Partner of his or her right of
presentment; (ii) a purchase by the General Partner of the Units of a
Limited Partner who defaults in the payment of any subscription
installment; or (iii) any other assignment or transfer.
(m) The "Limited Partners' Percentage" is that percentage determined
by dividing the amount of the Aggregate Subscription by the total of (i)
the General Partner's Minimum Capital Contribution plus (ii) the Aggregate
Subscription.
(n) "Normal Retirement" means retirement under the provision of a
pension or similar retirement plan adopted by the General Partner, UNIT or
any subsidiary with whom a Limited Partner is employed as in effect at the
time of the employee's retirement.
(o) "Oil and gas properties" are oil and gas leasehold working
interests, fee interests, mineral interests, royalty interests, overriding
royalty interests, production payments, options or rights to lease or
acquire such interests, geophysical exploration permits and any tangible or
intangible properties or other rights incident thereto, whether real,
personal or mixed.
(p) "Operating Expenses" are expenditures made and costs incurred in
producing and marketing oil or gas from completed wells, including, in
addition to labor, fuel, repairs, hauling, material, supplies, utility
charges and other costs incident to or necessary for the maintenance or
operation of such wells or the marketing of production therefrom, ad
valorem, severance and other such taxes (other than windfall profit taxes),
insurance and casualty loss expense and compensation to well operators or
others for services rendered in conducting such operations.
(q) The General Partner and the Limited Partners are sometimes
collectively referred to as the "Partners".
(r) The "Partnership Properties" are oil and gas properties or
interests therein acquired by the Partnership or properties acquired by any
partnership or joint venture in which the Partnership is a partner or joint
venturer, whether acquired by purchase, option exercise or otherwise.
(s) "Partnership Revenue" refers to the Partnership's gross revenues
from all sources, including interest income, proceeds from sales of
production, the Partnership's share of revenues from partnerships or joint
ventures of which it is a member, sales or other dispositions of
Partnership Properties or other Partnership assets, provided that
contributions to Partnership capital by the Partners and the proceeds of
any Partnership borrowings are specifically excluded and dry-hole and
bottom-hole contributions shall be treated as reductions of the costs
giving rise to the right to receive such contributions.
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(t) "Partnership Wells" are any and all of the oil and gas wells in
which the Partnership has an interest, either directly or indirectly
through any other partnership or joint venture.
(u) "Productive properties" are oil and gas properties that have been
tested by drilling and determined to be capable of producing oil or gas in
commercial quantities.
(v) "Special Production and Marketing Costs" are costs and expenses
that are not normally and customarily incurred in connection with drilling,
producing and marketing operations, including without limitation, costs
incurred in constructing compressor plants, gasoline plants, gas gathering
systems, natural gas processing plants, pipeline systems and salt water
disposal systems and costs incurred in installing pressure maintenance and
secondary or tertiary production projects.
(w) "Subscription Agreement" refers to the form of Limited Partner
Subscription Agreement and Suitability Statement attached as Attachment I
to this Agreement.
(x) A "Substituted Limited Partner" is a transferee, donee, heir,
legatee or other recipient of all or any portion of a Limited Partner's
interest in the Partnership with respect to whom all conditions and
consents required to become a Substituted Limited Partner under Article
XIII have been satisfied and given.
(y) A "Unit" is a preformation unit of limited partnership interest
of a Limited Partner in the Partnership representing a Capital Subscription
of One Thousand Dollars ($1,000).
ARTICLE III
Purposes and Powers of the Partnership
3.1 The purposes of the Partnership will be to acquire productive oil and
gas properties and to explore for, produce, treat, transport and market oil, gas
or both, or products derived therefrom, anywhere in the United States. It is
contemplated that all or most of the Partnership's operations will be conducted
as part of the operations of the General Partner and its affiliates, but the
Partnership may engage in operations on its own or in conjunction with
unaffiliated third parties. In accomplishing such purposes the Partnership may:
(a) acquire oil and gas properties, either alone or in conjunction
with other parties;
(b) conduct geological and geophysical investigations, including,
without limitation, seismic exploration, core drilling and other means and
methods of exploration;
(c) drill, equip, complete, rework, reequip, recomplete, plug back,
deepen, plug and abandon Partnership Wells as the General Partner deems
advisable;
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(d) acquire and dispose of tangible lease and well equipment for use
or used in connection with Partnership Wells;
(e) employ or retain such personnel and obtain such legal,
accounting, geological, geophysical, engineering and other professional
services and advice as the General Partner may deem advisable in the course
of the Partnership's operations under this Agreement;
(f) either pay or elect not to pay delay rentals or shut-in royalties
on Partnership Properties as appropriate in the judgment of the General
Partner, it being understood that the General Partner will not be liable
for failure to make correct or timely payments of delay rentals or shut-in
royalties if such failure was due to any reason other than gross negligence
or lack of good faith;
(g) make or give dry-hole or bottom-hole or other contributions of
oil and gas properties, money or both, to encourage drilling by others in
the vicinity of or on Partnership Properties;
(h) negotiate for and accept dry-hole, bottom-hole or other
contributions of oil and gas properties, cash or both, as consideration for
the drilling of a Partnership Well, with oil and gas properties so
acquired, if any, to become Partnership Properties;
(i) pay all ad valorem taxes levied or assessed against the
Partnership Properties, all taxes upon or measured by the production of oil
or gas or other hydrocarbons therefrom, and all other taxes (other than
income taxes) directly relating to operations conducted under this
Agreement;
(j) enter into and operate pursuant to operating agreements with
respect to Partnership Properties naming either the General Partner, any of
its affiliates or a third party as operator, or enter into partnership
agreements with third parties whereby the Partnership may be either a
general or a limited partner (including any partnerships formed or
sponsored by the General Partner or in which the General Partner may also
be a partner), which operating or partnership agreements shall contain such
terms, provisions and conditions as the General Partner deems appropriate;
(k) execute all documents or instruments of any kind which the
General Partner deems appropriate for carrying out the purposes of the
Partnership, including, without limitation, unitization agreements,
gasoline plant contracts, recycling agreements and agreements relating to
pressure maintenance and secondary or tertiary production projects;
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(l) purchase and establish inventories of equipment and material
required or expected to be required in connection with its operations;
(m) contract or enter into agreements with unaffiliated third
parties, the General Partner or its affiliates for the performance of
services and the purchase and sale of material, equipment, supplies and
property, both real and personal, provided, however, that any such
contracts or agreements with the General Partner or any of its affiliates
shall, except as otherwise provided herein, provide for prices, fees,
rates, charges or other compensation which are not greater than those
available from, being paid to or charged by unaffiliated third
parties dealing at arm's length in the same or a similar geographic area
for the same or comparable services, material, equipment, supplies or
property;
(n) conduct operations either alone or as a joint venturer, co-
tenant, partner or in any other manner of participation with third persons
and to enter into agreements and contracts setting forth the terms and
provisions of such participation;
(o) borrow money from banks and other lending institutions for
Partnership purposes and pledge Partnership Properties (including
production therefrom) for the repayment of such loans, it being understood
that no bank or other lending institution to which the General Partner
makes application for a loan will be required to inquire as to the purposes
for which such loan is sought, and as between the Partnership and such bank
or lending institution it will be conclusively presumed that the proceeds
of such loan are to be and will be used for purposes authorized under the
terms of this Agreement;
(p) hold Partnership Properties in its own name or in the name of the
General Partner, UNIT or any affiliate or any other party as nominee for
the Partnership;
(q) sell, relinquish, release, farm-out, abandon or otherwise dispose
of Partnership Properties, including undeveloped, productive and condemned
properties;
(r) produce, treat, transport and market oil and gas and execute
division orders, contracts for the marketing or sale of oil, gas or other
hydrocarbons and other marketing agreements;
(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.
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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, 1999, June 15, 1999,
September 15, 1999, and December 15, 1999, respectively, or (ii) by employees so
electing, through equal deductions from 1999 salary paid to the employee by the
General Partner, UNIT or its subsidiaries commencing immediately after the
Effective Date. Notwithstanding the foregoing, if in the judgment of the
General Partner, the entire amount of the Aggregate Subscription is not required
for purposes of conducting the business, operations and affairs of the
Partnership, the General Partner may, at its sole option, elect to release
the Limited Partners from the obligation to pay in one or more of the
installments of their Capital Subscriptions. If Units are acquired by a
corporation or other entity, the beneficial owners of the interests therein
shall be jointly and severally liable for the payment of the Capital
Subscription. If an employee or director who has subscribed for Units (either
directly or through a corporation or other entity) ceases to be employed by or a
director of the General Partner, UNIT or any of its subsidiaries for any reason
other than death, disability or Normal Retirement prior to the time the
full amount of his or her Capital Subscription is paid, then the due date for
any unpaid amount shall be accelerated so that the full amount of his or her
unpaid Capital Subscription shall be due and payable on the effective date of
such termination. The Capital Subscriptions shall be legally binding
obligations of the Limited Partners and any past due amounts shall bear interest
at the annual rate equal to two (2) percentage points in excess of the prime
rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank,
as announced and in effect from time to time, until paid. Further, in the event
a Limited Partner fails to pay any installment when due, the General Partner,
at its sole option and discretion, may elect to purchase the Units of such
defaulting Limited Partner at a price equal to the total amount of the Capital
Contributions actually paid into the Partnership by such defaulting Limited
Partner, less the amount of any Partnership distributions that may have been
received by him or her. Such option may be exercised by the General Partner by
written notice to the Limited Partner at any time after the date that the unpaid
installment was due and shall be deemed exercised when the amount of the
purchase price is first tendered to the defaulting Limited Partner. The General
Partner may, in its discretion, accept payments of delinquent installments but
shall not be required to do so. In the event that the General Partner elects to
purchase the Units of a defaulting Limited Partner, it shall pay into the
Partnership the amount of the delinquent installment (excluding any interest
that may have accrued thereon) and shall pay each additional installment, if
any, payable with respect to such Units as it becomes due. By virtue of such
purchase, the General Partner shall be allocated all Partnership Revenues and be
charged with all Partnership costs and expenses attributable to such Units
otherwise allocable or chargeable to the defaulting Limited Partner to the
extent provided in Section 13.9.
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4.3 If the Partnership requires funds to conduct Partnership operations
during the period between any of the installments due as set forth in Section
4.2 above, then, notwithstanding the provisions of Section 5.4 below, the
General Partner shall advance funds to the Partnership in an amount equal to the
funds then required to conduct such operations but in no event more than the
total amount of the Aggregate Subscription remaining unpaid. With respect to
any such advances, the General Partner shall receive no interest thereon and no
financing charges will be levied by the General Partner in connection therewith.
The General Partner shall be repaid out of the Capital Subscription installments
thereafter paid into the capital of the Partnership when due.
4.4 Additional Assessments required by the General Partner pursuant to
Section 5.3 of this Agreement will be payable in cash on such date as the
General Partner may set in its written notice, but in no event will such
assessments be due earlier than thirty (30) days after the date of mailing of
the notice. Notice of the General Partner's call for Additional Assessments
shall specify the amount required, the manner in which the additional funds will
be expended, the date on which such amounts are payable, and the consequences of
non-payment. The General Partner will not be required to accept late payments
of such amounts, but it may in its discretion do so.
4.5 The General Partner will contribute to the capital of the Partnership
amounts equal to the total of all costs paid by the Partnership that are charged
to the General Partner's account as such costs are incurred.
ARTICLE V
Deposit and Use of Capital Contributions and
Other Partnership Funds
5.1 Until required in the conduct of the Partnership's business,
Partnership funds, including, but not limited to, Capital Contributions,
Partnership Revenue and proceeds of borrowings by the Partnership, will be
deposited, with or without interest, in one or more bank accounts of the
Partnership in a bank or banks selected by the General Partner or invested in
short-term United States government securities, money market funds, bank
certificates of deposit or commercial paper rated as "A1" or "P1" as the General
Partner, in its sole discretion, deems advisable. Any interest or other income
generated by such deposits or investments will be for the Partnership's account.
Except for Capital Contributions, Partnership funds from any of the various
sources mentioned above may be commingled with other Partnership funds and with
the funds of the General Partner and may be withdrawn, expended and distributed
as authorized by the terms and provisions of this Agreement.
5.2 The Capital Contributions of the Limited Partners will be expended for
costs incurred by the Partnership that, in accordance with the terms of this
Agreement, are properly chargeable to the Limited Partners' accounts.
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5.3 After the General Partner's Minimum Capital Contribution has been
fully expended, if the Aggregate Subscription has all been fully expended or
committed and additional funds are required in order to pay Drilling Costs,
Special Production and Marketing Costs or Leasehold Acquisition Costs of
productive properties which are chargeable to the Limited Partners, the General
Partner may, but shall not be required to, make one or more calls for Additional
Assessments from Limited Partners pursuant to Section 4.4; provided, however,
that the aggregate amount of Additional Assessments called of the Limited
Partners may not exceed $100 per Unit. The Limited Partners who do not respond
will participate in production, if any, obtained from the aggregate Additional
Assessments paid into the Partnership. However, the amount of the unpaid
Additional Assessment shall bear interest at the annual rate equal to two (2)
percentage points in excess of the prime rate of interest of Bank of Oklahoma,
N.A., Tulsa, Oklahoma, or successor bank, as announced and in effect from time
to time, until paid. The Partnership will have a lien on the defaulting Limited
Partner's interest in the Partnership and the General Partner may apply
Partnership Revenue otherwise available for distribution to the defaulting
Limited Partner until an amount equal to the unpaid Additional Assessment and
interest is received. Furthermore, the General Partner may satisfy such lien by
proceeding with legal action to enforce the lien and the defaulting Limited
Partner shall pay all expenses of collection, including interest, court costs
and a reasonable attorney's fee.
5.4 After the General Partner's Minimum Capital Contribution has been
fully expended, the General Partner may cause the Partnership to borrow funds
for the purpose of paying Drilling Costs, Special Production and Marketing Costs
or Leasehold Acquisition Costs of productive properties, which borrowings may be
secured by interests in the Partnership Properties and will be repaid, including
interest accruing thereon, out of Partnership Revenue allocable to the accounts
of the Partners on whose behalf the proceeds of such borrowings are expended.
The General Partner may, but is not required to, advance funds to the
Partnership for the same purposes for which Partnership borrowings are
authorized by this Section 5.4. With respect to any such advances, the General
Partner shall receive interest in an amount equal to the lesser of the interest
which would be charged to the Partnership by unrelated banks on comparable loans
for the same purpose or the General Partner's interest cost with respect to such
loan, where it borrows the same. No financing charges will be levied by the
General Partner in connection with any such loan. If Partnership borrowings
secured by interests in the Partnership Properties and repayable out of
Partnership Revenue cannot be arranged on a basis which, in the opinion of the
General Partner, is fair and reasonable, and the entire sum required to pay
costs of the type referred to above is not available from Partnership Revenue,
the Partnership may elect not to drill or participate in the drilling of a
well or the General Partner may dispose of the Partnership Properties upon which
such operations were to be conducted by sale (subject to any other applicable
provisions of this Agreement), farmout 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.
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5.6 With respect to any Partnership activity and subject to the
restrictions set forth in Sections 5.3 and 5.4 above, it shall be in the sole
discretion of the General Partner whether to call for Additional Assessments,
arrange for borrowings on behalf of the Partners, utilize Partnership Revenue or
sell (subject to any other applicable provisions of this Agreement), farm-out or
abandon Partnership Properties.
5.7 The Partnership Properties and production therefrom may be pledged,
mortgaged or otherwise encumbered as security for borrowings by the Partnership
authorized by Section 5.4 above, provided that the holder of indebtedness
arising by virtue of such borrowings may not have or acquire, at any time as a
result of making any such loans, any direct or indirect interest in the profits,
capital or property of the Partnership other than as a secured creditor.
ARTICLE VI
Sharing of Costs, Capital Accounts and
Allocation of Charges and Income
6.1 All costs of organizing the Partnership and offering Units therein
will be paid by the General Partner. All costs incurred in the offering and
syndication of any drilling or income program formed by UPC or UNIT and its
affiliates during 1999 in which the Partnership participates as a co-general
partner will also be paid by the General Partner.
6.2 All other Partnership costs and expenses will be charged 99% to the
accounts of the Limited Partners and 1% to the account of the General Partner
until such time as the Aggregate Subscription has been fully expended.
Thereafter and until the General Partner's Minimum Capital Contribution has been
fully expended, all of such costs and expenses will be charged to the General
Partner. After the General Partner's Minimum Capital Contribution has been
fully expended, such costs and expenses will be charged to the respective
accounts of the General Partner and the Limited Partners on the basis of their
respective Percentages.
6.3 All Partnership Revenues will be allocated between the General Partner
and the Limited Partners on the basis of their respective Percentages.
6.4 Partnership costs, expenses and Revenues which are charged and
allocated to the Limited Partners shall be charged and allocated to their
respective accounts in the proportion the Units of each Limited Partner bear to
the total number of outstanding Units.
6.5 Capital accounts shall be established and maintained for each Partner
in accordance with tax accounting principles and with valid regulations issued
by the U.S. Treasury Department under subsection 704(b) (the "704 Regulations")
of the Internal Revenue Code of 1986, as amended (the "Code"). To the extent
that tax accounting principles and the 704 Regulations may conflict, the latter
shall control. In connection with the establishment and maintenance of such
capital accounts, the following provisions shall apply:
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(a) Each Partner's capital account shall be (i) increased by the
amount of money contributed by him or her to the Partnership, the fair
market value of property contributed by him or her to the Partnership (net
of liabilities securing such contributed property that the Partnership is
considered to assume or take subject to under section 752 of the Code) and
allocations to him or her of Partnership income and gain (except to the
extent such income or gain has previously been reflected in his or her
capital account by adjustments thereto) and (ii) decreased by the amount of
money distributed to him or her by the Partnership, the fair market value
of property distributed to him or her by the Partnership (net of
liabilities securing such distributed property that such Partner is
considered to assume or take subject to under section 752 of the Code) and
allocations to him or her of Partnership loss, deduction (except to the
extent such loss or deduction has previously been reflected in his or her
capital account by adjustments thereto) and expenditures described in
section 705(a)(2)(B) of the Code.
(b) In the event Partnership Property is distributed to a Partner,
then, before the capital account of such Partner is adjusted as required by
subsection (a) of this Section 6.5, the capital accounts of the Partners
shall be adjusted to reflect the manner in which the unrealized income,
gain, loss and deduction inherent in such property (that has not been
reflected in such capital accounts previously) would be allocated among the
Partners if there were a taxable disposition of such property for its fair
market value on the date of distribution.
(c) If, pursuant to this Agreement, Partnership Property is reflected
on the books of the Partnership at a book value that differs from the
adjusted tax basis of such property, then the Partners' capital accounts
shall be adjusted in accordance with the 704 Regulations for allocations to
the Partners of depreciation, depletion, amortization, and gain or loss, as
computed for book purposes, with respect to such property.
(d) The Partners' capital accounts shall be adjusted for depletion
and gain or loss with respect to the Partnership's oil or gas properties in
whichever of the following manners the General Partner determines is in the
best interests of the Partners:
(i) the Partners' capital accounts shall be reduced by a
simulated depletion allowance computed on each oil or gas property
using either the cost depletion method or the percentage depletion
method (without regard to the limitations under the Code which could
apply to less than all Partners); provided, however, that the choice
between the cost depletion method and the simulated depletion method
shall be made on a property-by-property basis in the first taxable
year of the Partnership for which such choice is relevant for an oil
or gas property, and such choice shall be binding for all Partnership
taxable years during which such oil or gas property is held by the
Partnership. Such reductions for depletion shall not exceed the
aggregate adjusted basis allocated to the Partners with respect to
such oil or gas property. Such reductions for depletion shall be
allocated among the Partners' capital accounts in the same proportions
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as the adjusted basis in the particular property is allocated to each
Partner. Upon the taxable disposition of an oil or gas property by
the Partnership, the Partnership's simulated gain or loss shall be
determined by subtracting its simulated adjusted basis (aggregate
adjusted tax basis of the Partners less simulated depletion
allowances) in such property from the amount realized on such
disposition and the Partners' capital accounts shall be increased or
reduced, as the case may be, by the amount of the simulated gain or
loss on such disposition in proportion to the Partners' allocable
shares of the total amount realized on such disposition, or
(ii) the Partnership shall reduce the capital account of each
Partner in an amount equal to such Partner's depletion allowance with
respect to each oil or gas property of the Partnership (for the
Partner's taxable year that ends within the Partnership's taxable
year), but such reductions for depletion shall not exceed the adjusted
basis allocated to such Partner with respect to such property. Upon
the taxable disposition of an oil or gas property by the Partnership,
the capital account of each Partner shall be reduced or increased, as
the case may be, by the amount of the difference between such
Partner's allocable share of the total amount realized on such
disposition and such Partner's remaining adjusted tax basis in such
property.
(e) For purposes of determining the capital account balance of any
Partner as of the end of any Partnership taxable year for purposes of
Subsection 6.6(f) hereof, such Partner's capital account shall be reduced
by:
(i) adjustments that, as of the end of such year, reasonably are
expected to be made to such Partner's capital account pursuant to
paragraph (b)(2)(iv)(k) of the 704 Regulations for depletion
allowances with respect to oil and gas properties of the Partnership,
(ii) allocations of loss and deduction that, as of the end of
such year, reasonably are expected to be made to such Partner pursuant
to Code section 704(e)(2), Code section 706(d), and paragraph
(b)(2)(ii) of section 1.751-1 of regulations promulgated under the
Code, and
(iii) distributions that, as of the end of such year, reasonably
are expected to be made to such Partner to the extent they exceed
offsetting increases to such Partner's capital account that reasonably
are expected to occur during (or prior to) the partnership taxable
years in which such distributions reasonably are expected to be made.
6.6 With respect to the various allocations of Partnership income, gain,
loss, deduction and credit for federal income tax purposes, it is hereby agreed
as follows:
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(a) To the extent permitted by law, all charges, deductions and
losses shall be allocated for federal income tax purposes in the same
manner as the costs in respect of which such charges, deductions and losses
are charged to the respective accounts of the Partners. The Partners
bearing the costs shall be entitled to the deductions (including, without
limitation, cost recovery allowances, depreciation and cost depletion) and
credits that are attributable to such costs.
(b) The Partnership shall allocate to each Partner his or her portion
of the adjusted basis in each depletable Partnership Property as required
by Section 613A(c)(7)(D) of the Code based upon the interest of said
Partner in the capital of the Partnership as of the time of the acquisition
of such Partnership Property. To the extent permitted by the Code, such
allocation shall be based upon said Partner's interest (i) in the
Partnership capital used to acquire the property, or (ii) in the adjusted
basis of the property if it is contributed to the Partnership. If such
allocation of basis is not permitted under the Code, then basis will be
allocated in the permissible manner which the General Partner deems will
most closely achieve the result intended above.
(c) Partnership Revenue shall be allocated for federal income tax
purposes in the same manner as it is allocated to the respective accounts
of the Partners pursuant to Sections 6.3 and 6.4 above.
(d) Depreciation or cost recovery allowance recapture and recapture
of intangible drilling and development costs, if any, due as a result of
sales or dispositions of assets shall be allocated in the same proportion
that the depreciation, cost recovery allowances or intangible drilling and
development costs being recaptured were allocated.
(e) Notwithstanding anything to the contrary stated herein,
(i) there shall be allocated first to other Limited Partners and
then to the General Partner any item of loss, deduction, credit or
allowance that, but for this Subsection 6.6(e), would have been
allocated to any Limited Partner that is not obligated to restore any
deficit balance in such Limited Partner's capital account and
would have thereupon caused or increased a deficit balance in such
Limited Partner's capital account as of the end of the Partnership's
taxable year to which such allocation related (after taking into
consideration the numbered items specified in Subsection 6.5(e)
hereof);
(ii) any Limited Partner that is not obligated to restore any
deficit balance in such Limited Partner's capital account who
unexpectedly receives an adjustment, allocation or distribution
specified in Subsection 6.5(e) hereof shall be allocated items of
income and gain in an amount and manner sufficient to eliminate such
deficit balance as quickly as possible; and
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(iii) in the event any allocations of loss, deduction, credit or
allowance are made to a Limited Partner or the General Partner
pursuant to clause (i) of this Subsection 6.6(e), then such Limited
Partner and/or the General Partner shall be subsequently allocated all
items of income and gain pro rata as they were allocated the item(s)
of loss, deduction, credit or allowance under such clause (i) until
the aggregate amount of such allocations of income and gain is equal
to the aggregate amount of any such allocations of loss, deduction,
credit or allowance allocated to such Partner(s) pursuant to clause
(i) of this Subsection 6.6(e).
(f) Notwithstanding any other provision of this Agreement, if, under
any provision of this Agreement, the capital account of any Partner is
adjusted to reflect the difference between the basis to the Partnership of
Partnership Property and such property's fair market value, then all items
of income, gain, loss and deduction with respect to such property shall be
allocated among the Partners so as to take account of the variation between
the basis of such property and its fair market value at the time of the
adjustment to such Partner's capital account in accordance with the
requirements of subsection 704(c) of the Code, or in the same manner as
provided under subsection 704(c) of the Code.
6.7 Notwithstanding anything to the contrary that may be expressed or
implied in this Agreement, the interest of the General Partner in each material
item of Partnership income, gain, loss, deduction or credit shall be equal to at
least one percent of each such item at all times during the existence of the
Partnership. In determining the General Partner's interest in such items, Units
owned by the General Partner shall not be taken into account.
6.8 Except as provided in subsections (a) through (d) of this Section 6.8,
in the case of a change in a Partner's interest in the Partnership during a
taxable year of the Partnership, all Partnership income, gain, loss, deduction
or credit allocable to the Partners shall be allocated to the persons who were
Partners during the period to which such item is attributable in accordance with
the Partners' interests in the Partnership during such period regardless of when
such item is paid or received by the Partnership.
(a) With respect to certain "allocable cash basis items" (as such
term is defined in the Code) of Partnership Revenue, gain, loss, deduction
or credit, if, during any taxable year of the Partnership there is change
in any Partner's interest in the Partnership, then, except to the extent
provided in regulations prescribed under Section 706 of the Code, each
Partner's allocable share of any "allocable cash basis item" shall be
determined by (i) assigning the appropriate portion of each such item to
each day in the period to which it is attributable, and (ii) allocating the
portion assigned to any such day among the Partners in proportion to their
interests in the Partnership at the close of such day.
(b) If, by adhering to the method of allocation described in the
immediately preceding subsection of this Section 6.8, a portion of any
"allocable cash basis item" is attributable to any period before the
beginning of the Partnership taxable year in which such item is received or
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paid, such portion shall be (i) assigned to the first day of the taxable
year in which it is received or paid, and (ii) allocated among the persons
who were Partners in the Partnership during the period to which such
portion is attributable in accordance with their interests in the
Partnership during such period.
(c) If any portion of any "allocable cash basis item" paid or
received by the Partnership in a taxable year is attributable to a period
after the close of that taxable year, such portion shall be (i) assigned to
the last day of the taxable year in which it is paid or received, and (ii)
allocated among the persons who are Partners in proportion to their
interests in the Partnership at the close of such day.
(d) If any deduction is allocated to a person with respect to an
"allocable cash basis item" attributable to a period before the beginning
of the Partnership taxable year and such person is not a Partner of the
Partnership on the first day of the Partnership taxable year, such
deduction shall be capitalized by the Partnership and treated in the manner
provided for in Section 755 of the Code.
ARTICLE VII
Fiscal Year, Accountings and Reports
7.1 Unless the Code requires otherwise, the fiscal year of the Partnership
will be the calendar year and the books of the Partnership will be kept in
accordance with usual and customary accounting practices on the accrual method.
7.2 Within sixty (60) days after the end of each quarter of each
Partnership fiscal year, each person who was a Limited Partner during such
period will be furnished a report setting forth the source and disposition of
Partnership funds during the quarter.
7.3 Not later than the end of the fiscal year in which all Partnership
Wells are drilled and completed, and sufficient production history has been
obtained on Partnership Wells to evaluate properly the reserves attributable
thereto, the General Partner will make an evaluation of Partnership Properties
as of the last day of such fiscal year. The report shall include an estimate of
the total oil and gas proven reserves of the Partnership and the dollar value
thereof and the value of the Limited Partner's interest in such reserve value.
It shall also contain an estimate of the present worth of the reserves. Each
Limited Partner will receive a summary statement of such report reflecting the
Limited Partners' interest in such reserve value.
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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 conducting Partnership operations or to
repay borrowings theretofore or expected to be thereafter obtained by the
Partnership. Within forty-five (45) days after the end of each calendar
quarter, the General Partner will determine the amount of cash available for
distribution to the Limited Partners and will distribute such amount, if any, as
promptly thereafter as reasonably possible. Distributions of cash to the
General Partner may be at any time the General Partner determines there is cash
available therefor. The General Partner's determination of the cash available
for distribution will be conclusive and binding upon all Partners. All
Partnership funds distributed to the Limited Partners shall be distributed to
the persons who were record holders of Units on the day on which the
distribution is made.
ARTICLE X
Rights, Duties and Obligations of the General Partner
10.1 Subject to the limitations of this Agreement, the General Partner will
have full, exclusive and complete discretion in the management and control of
the business of the Partnership and will make all decisions affecting its
business and affairs or the Partnership Properties. The General Partner will
have, subject to the provisions of this Article X, full power and authority to
take any action described in Article III above and execute and deliver in the
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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 1999 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, 1999 or the
Effective Date through December 31, 1999 (except for wells, if any, (i) drilled
outside of the 48 contiguous United States; (ii) drilled as part of secondary or
tertiary recovery operations which were in existence prior to the formation of
the Partnership; (iii) drilled by third parties under farm-out or similar
arrangements with the General Partner or UNIT or whereby the General Partner or
UNIT may be entitled to an overriding royalty, reversionary or other similar
interest in the production from such wells but is not obligated to pay any of
the Drilling Costs thereof; (iv) acquired by UNIT or the General Partner
through the acquisition by UNIT or the General Partner of, or merger of UNIT or
the General Partner with, other companies; or (v) with respect to which the
General Partner does not believe that the potential economic return therefrom
justifies the costs of participation by the Partnership).
10.4 The General Partner, UNIT or any affiliate thereof will transfer to
the Partnership interests in oil and gas properties comprising the spacing unit
on which a Partnership Well is located or is to be drilled for the separate
account of the Partnership, provided that no broker's commissions or fees of a
similar nature will be paid in connection with any such transfer and the
consideration paid by the Partnership will be equal to the Leasehold Acquisition
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Costs of the property so transferred. If the size of a spacing unit on which a
Partnership Well is located is ever reduced or increased well density is
permitted thereon, the Partnership will not be entitled to any reimbursement
or recoupment of any portion of the Leasehold Acquisition Costs paid with
respect thereto notwithstanding the provisions of Section 10.7 below.
10.5 With respect to certain transactions involving Partnership Properties,
it is hereby agreed as follows:
(a) A sale, transfer or conveyance by the General Partner or any
affiliate of less than its entire interest in such property is prohibited
unless (i) the interest retained by the General Partner or its affiliate is
a proportionate working interest, (ii) the respective obligations of the
General Partner or its affiliate and the Partnership are substantially the
same proportionately as those of the General Partner or its affiliate at
the time it acquired the property and (iii) the Partnership's interest in
revenues will not be less than the proportionate interest therein of the
General Partner or its affiliate when it acquired the property. The
General Partner or its affiliate may retain the remaining interest for its
own account or it may sell, transfer, farm-out or otherwise convey all or a
portion of such remaining interest to non-affiliated industry members. In
connection with any such sale, transfer, farm-out or other conveyance of
such interest to non-affiliated industry members, which may occur either
before or after the transfer of the interests in the same properties to the
Partnership, the General Partner or its affiliate may realize a profit on
the interests or may be carried to some extent with respect to its cost
obligations in connection with any drilling on such properties and any such
profit or interest will be strictly for the account of the General Partner
and the Partnership will have no claim with respect thereto.
(b) The General Partner or its affiliates may not retain any
overrides or other burdens on property conveyed to the Partnership (other
than overriding royalty interests granted to geologists and other persons
employed or retained by the General Partner or its affiliates).
10.6 The General Partner will cause the Partnership Properties to be
acquired in accordance with the customs of the oil and gas industry in the area.
The Partnership will be required to do only such title work with respect to its
oil and gas properties as the General Partner in its sole judgment deems
appropriate in light of the area, any applicable drilling or expiration dates
and any other material factors.
10.7 Partnership Properties shall be transferred to the Partnership after
the decision to acquire a productive property or the commitment to drill a
Partnership Well thereon has been made. The Partnership shall acquire interests
in only those properties of the General Partner or UNIT which comprise the
spacing unit on which the Partnership Well is drilled or on which a producing
Partnership Well is located. If a spacing unit on which a Partnership Well is
drilled or located is ever reduced, or any subsequent well in which the
Partnership has no interest is drilled thereon, the Partnership will have no
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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 1999 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 1999 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 1999 or is drilled by a drilling or income program of which the
Partnership is a partner.
10.8 The General Partner, UNIT or its affiliates will either conduct the
Partnership's drilling and production operations and operate each Partnership
Well or arrange for a third party operator to conduct such operations. The
General Partner will, on behalf of the Partnership, enter into appropriate
operating agreements with other owners of Partnership Wells authorizing the
General Partner, its affiliates or a third party operator to conduct such
operations. The Partnership will take such action in connection with operations
pursuant to said operating agreements as the General Partner, in its sole
discretion, deems appropriate and in the best interests of the Partnership,
and the decision of the General Partner with respect thereto will be binding
upon the Partnership.
10.9 The General Partner will cause the Partnership to plug and abandon its
dry holes and abandoned wells in accordance with rules and regulations of the
governmental regulatory body having jurisdiction.
10.10 The General Partner may pool or unitize Partnership Properties with
other oil and gas properties when such pooling or unitization is required by a
governmental regulatory body, when well spacing as determined by any such body
requires such pooling or unitization, or when, in the General Partner's opinion,
such pooling or unitization is in the best interests of the Partnership.
10.11 The General Partner will have authority to make and enter into
contracts for the sale of the Partnership's share of oil or gas production from
Partnership Wells, including contracts for the sale of such production to the
General Partner, UNIT or its affiliates; provided, however, that the production
purchased by the General Partner, UNIT or any of its affiliates will be for
prices which are not less than the highest posted price (in the case of crude
oil production) or prevailing price (in the case of natural gas production) in
the same field or area.
10.12 The General Partner will use its best efforts to procure and maintain
for the Partnership, and at its expense, such insurance coverage with
responsible companies as may be reasonably available for such premium costs as
would not be considered to be unreasonably high or prohibitive with respect to
each item of coverage and as the General Partner considers necessary for
the protection of the Partnership and the Partners. The coverage will be in
such amounts and will cover such risks as the General Partner believes warranted
by the operations conducted hereunder. Such risks may include but will not
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necessarily be limited to public liability and automobile liability, each
covering bodily injury, death and property damage, workmen's compensation and
employer's liability insurance and blowout and control of well insurance.
10.13 In order to conduct properly the business of the Partnership, and in
order to keep the Partners properly informed, the General Partner will:
(a) maintain adequate records and files identifying the Partnership
Properties and containing all pertinent information in regard thereto that
is obtained or developed pursuant to this Agreement;
(b) maintain a complete and accurate record of the acquisition and
disposition of each Partnership Property;
(c) maintain appropriate books and records reflecting the
Partnership's revenue and expense and each Partner's participation therein;
(d) maintain a capital account for each Partner with appropriate
records as necessary in order to reflect each Partner's interest in the
Partnership and furnish required tax information; and
(e) keep the Limited Partners informed by means of written reports on
the acquisition of Partnership Properties and the progress of the business
and operations of the Partnership, which reports will be rendered semi-
annually and at such more frequent intervals during the progress of
Partnership operations as the General Partner deems appropriate.
10.14 The General Partner, UNIT and the officers, directors, employees and
affiliates thereof may own, purchase or otherwise acquire and deal in oil and
gas properties, drill wells, conduct operations and otherwise engage in any
aspect of the oil and gas business, either for their own accounts or for the
accounts of others. Each Limited Partner hereby agrees that engaging in any
activity permitted by this Section 10.14 will not be considered a breach of any
duty that the General Partner, UNIT or the officers, directors, employees and
affiliates thereof may have to the Partnership or the Limited Partners, and that
the Partnership and the Limited Partners will not have any interest in any
properties acquired or profits which may be realized with respect to any such
activity.
10.15 Subject to Section 12.1, without the prior consent of Limited
Partners holding a majority of the outstanding Units, the General Partner will
not (i) make, execute or deliver any assignment for the benefit of the
Partnership's creditors; or (ii) contract to sell all or substantially all
of the Partnership Properties (except as permitted by Sections 10.23 and
16.4(b)).
10.16 In contracting for services to and insurance coverage for the
Partnership and its activities and operations, and in acquiring material,
equipment and personal property on behalf of the Partnership, the General
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Partner will use its best efforts to obtain such services, insurance, material,
equipment and personal property at prices no less favorable than those normally
charged in the same or in comparable geographic areas by non-affiliated persons
or companies dealing at arm's length. No rebates, concessions or compensation
of a similar nature will be paid to the General Partner by the person or company
supplying such services, insurance, material, equipment and personal property.
10.17 The General Partner, UNIT or its affiliates are authorized to provide
equipment, materials and services to the Partnership in connection with the
conduct of its operations, provided, that the terms of any contracts between the
Partnership and the General Partner, UNIT or any affiliates, or the officers,
directors, employees and affiliates thereof must be no less favorable to the
Partnership than those of comparable contracts entered into, and will be at
prices not in excess of those charged in the same geographical area by non-
affiliated persons or companies dealing at arm's length. Any such contracts for
services must be in writing precisely describing the services to be rendered and
all compensation to be paid.
10.18 The General Partner may cause the Partnership to hold Partnership
Properties in the Partnership's name, or in the name of the General Partner,
UNIT, any affiliates thereof or some third party as nominee for the Partnership.
If record title to a Partnership Property is to be held permanently in the name
of a nominee, such nominee arrangement will be evidenced and documented by a
nominee agreement identifying the Partnership Properties so held and disclaiming
any beneficial interest therein by the nominee.
10.19 The General Partner will be generally liable for the debts and
obligations of the Partnership, provided that any claims against the Partnership
shall be satisfied first out of the assets of the Partnership and only
thereafter out of the separate assets of the General Partner.
10.20 The Partnership may not make any loans to the General Partner, UNIT
or any of its affiliates.
10.21 The General Partner will use its best efforts at all times to
maintain its net worth at a level that is sufficient to insure that the
Partnership will be classified for federal income tax purposes as a partnership,
rather than as an association taxable as a corporation, on account of the
net worth of the General Partner.
10.22 The Tax Matters Partner designated in Section 8.1 above is authorized
to engage legal counsel and accountants and to incur expense on behalf of the
Partnership in contesting, challenging and defending against any audits,
assessments and administrative or judicial proceedings conducted or participated
in by the Internal Revenue Service with respect to the Partnership's operations
and affairs.
10.23 At any time two years or more after the Partnership has completed
substantially all of its property acquisition, drilling and development
operations, the General Partner may, without the vote, consent or approval of
the Limited Partners, cause all or substantially all of the oil and gas
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properties and other assets of the Partnership to be sold, assigned or
transferred to, or the Partnership merged or consolidated with, another
partnership or a corporation, trust or other entity for the purpose of combining
the assets of two or more of the oil and gas partnerships formed for investment
or participation by employees, directors and/or consultants of UNIT or any of
its subsidiaries; provided, however, that the valuation of the oil and gas
properties and other assets of all such participating partnerships for purposes
of such transfer or combination shall be made on a consistent basis and in a
manner which the General Partner and UNIT believe is fair and equitable to the
Limited Partners. As a consequence of any such transfer or combination, the
Partnership shall be dissolved and terminated pursuant to Article XVI hereof and
the Limited Partners shall receive partnership interests, stock or other equity
interests in the transferee or resulting entity.
ARTICLE XI
Compensation and Reimbursements
11.1 For the General Partner's services performed as operator of productive
Partnership Wells located on Partnership Properties and as operator during the
drilling of Partnership Wells, the Partnership will compensate the General
Partner at rates no higher than those normally charged in the same or a
comparable geographic area by non-affiliated persons or companies dealing at
arm's length. The General Partner will not receive compensation for such
services performed in connection with the operation of Partnership Wells
operated by third party operators, but such third party operators will be
compensated as provided in the operating agreements in effect with respect
to such wells and the Partnership will pay its proportionate share of such
compensation.
11.2 The General Partner will be reimbursed by the Partnership out of
Partnership Revenues for that portion of its general and administrative overhead
expense that is attributable to its conduct of the actual and necessary
business, affairs and operations of the Partnership. The General Partner's
general and administrative overhead expenses will be determined in accordance
with industry practices. The allocable costs and expenses will include all
customary and routine legal, accounting, geological, engineering, travel, office
rent, telephone, secretarial, salaries, data processing, word processing and
other incidental reasonable expenses necessary to the conduct of the
Partnership's business and generated by the General Partner or allocated to it
by UNIT, but will not include filing fees, commissions, professional fees,
printing costs and other expenses incurred in forming the Partnership or
offering interests therein. Also excluded will be any general and
administrative overhead expense of the General Partner or UNIT which may be
attributable to its services as an operator of Partnership Wells for which it
receives compensation pursuant to Section 11.1 above. The portion of the
General Partner's general and administrative overhead expense to be
reimbursed by the Partnership with respect to any particular period will be
determined by allocating to the Partnership that portion of the General
Partner's total general and administrative overhead expense incurred during such
period which is equal to the ratio of the Partnership's total expenditures
compared to the total expenditures by the General Partner for its own account.
The portion of such general and administrative overhead expense reimbursement
which is charged to the Limited Partners may not exceed an amount equal to 3% of
the Aggregate Subscription during the first 12 months of the Partnership's
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operations, and in each succeeding twelve-month period, the lesser of
(a) 2% of the Aggregate Subscription and (b) 10% of the total Partnership
Revenue realized in such twelve-month period. Administrative expenses incurred
directly by the Partnership, or incurred by the General Partner on behalf of the
Partnership and reimbursable to the General Partner, such as legal, accounting,
auditing, reporting, engineering, mailing and other such fees, costs and
expenses are not to be deemed a part of the general and administrative expense
of the General Partner which is to be reimbursed pursuant to this Section 11.2
and the amounts thereof will not be subject to the limitations described in the
preceding sentence.
ARTICLE XII
Rights and Obligations of Limited Partners
12.1 The Limited Partners, in their capacity as such, cannot transact any
business for the Partnership or take part in the control of its business or
management of its affairs. Limited Partners will have no power to execute any
agreements on behalf of, or otherwise bind or commit, the Partnership. They may
give consents and approvals as herein provided and exercise the rights and
powers granted to them in this Agreement, it being understood that the exercise
of such rights and powers will be deemed to be matters affecting the basic
structure of the Partnership and not the exercise of control over its business;
provided, however, that exercise of any of the rights and powers granted to the
Limited Partners in Sections 10.15, 12.3, 14.1, 16.1 and 18.1 will not be
authorized or effective unless prior to the exercise thereof the General Partner
is furnished an opinion of counsel for the Partnership or an order or judgment
of any court of competent jurisdiction to the effect that the exercise of such
rights or powers (i) will not be deemed to evidence that the Limited Partners
are taking part in the control of or management of the Partnership's business
and affairs, (ii) will not result in the loss of any Limited Partner's limited
liability and (iii) will not result in the Partnership being classified as an
association taxable as a corporation for federal income tax purposes.
12.2 The Limited Partners will not be personally liable for any debts or
losses of the Partnership. Except as otherwise specifically provided herein, no
Partner will be responsible for losses of any other Partners.
12.3 Except as otherwise provided in this Agreement, no Limited Partner
will be entitled to the return of his contribution. Distributions of
Partnership assets pursuant to this Agreement may be considered and treated as
returns of contributions if so designated by law or, subject to Section 12.1, by
agreement of the General Partner and Limited Partners holding a majority of the
outstanding Units. The value of a Limited Partner's undistributed contribution
determined for the purposes of Section 39 of the Act at any point in time shall
be his or her percentage of the amount of the Partnership's stated capital
allocated to the Limited Partners as reflected in the financial statements
of the Partnership as of such point in time. No Partner will receive any
interest on his or her contributions and no Partner will have any priority over
any other Partner as to the return of contributions.
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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
(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.
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13.4 If a Limited Partner dies, his or her executor, administrator or
trustee, or, if he or she is adjudicated incompetent, his or her committee,
guardian or conservator, or, if he or she becomes bankrupt, the trustee or
receiver of his or her estate, shall have all the rights of a Limited Partner
for the purpose of settling or managing his or her estate and such power as the
deceased, incapacitated or bankrupt Limited Partner possessed to assign all or
any part of his or her interest and to join with such assignee in satisfying
conditions precedent to such assignee's becoming a Substituted Limited
Partner.
13.5 The Partnership shall not recognize for any purpose any purported
sale, assignment or transfer of all or any fraction of the interest of a Limited
Partner in the Partnership, unless the provisions of Section 13.1 shall have
been complied with and there shall have been filed with the Partnership a
written and dated notification of such sale, assignment or transfer in form
satisfactory to the General Partner, executed and acknowledged by both the
seller, assignor or transferor and the purchaser, assignee or transferee and
such notification (i) contains the acceptance by the purchaser, assignee or
transferee of all of the terms and provisions of this Agreement and (ii)
represents that such sale, assignment or transfer was made in accordance with
all applicable laws and regulations. Any sale, assignment or transfer shall be
recognized by the Partnership as effective on the date of such notification if
the date of such notification is within thirty (30) days of the date on which
such notification is filed with the Partnership, and otherwise shall be
recognized as effective on the date such notification is filed with the
Partnership.
13.6 Any Limited Partner who shall assign all of his or her interest in the
Partnership shall cease to be a Limited Partner, except that, unless and until a
Substituted Limited Partner is admitted in his or her stead, such assigning
Limited Partner shall retain the statutory rights of the assignor of a Limited
Partner's interest under the Act.
13.7 A person who is the assignee of all or any fraction of the interest of
a Limited Partner, but does not become a Substituted Limited Partner and desires
to make a further assignment of such interest, shall be subject to all the
provisions of this Article XIII to the same extent and in the same manner as any
Limited Partner desiring to make an assignment of his or her interest.
13.8 No Limited Partner shall have the right to substitute a purchaser,
assignee, transferee, donee, heir, legatee, distributee or other recipient of
all or any portion of such Limited Partner's interest in the Partnership as a
Limited Partner in his or her place. Any such purchaser, assignee, transferee,
donee, legatee, distributee or other recipient of an interest in the Partnership
shall be admitted to the Partnership as a Substituted Limited Partner only with
the consent of the General Partner, which consent shall be granted or withheld
in the sole and absolute discretion of the General Partner and may be
arbitrarily withheld, and only by an amendment to this Agreement or the
certificate of limited partnership duly executed and recorded in the proper
records of each jurisdiction in which the Partnership owns mineral interests and
filed in the proper records of the State of Oklahoma. Any such consent by the
General Partner shall be binding and conclusive without the consent of any
Limited Partners and may be evidenced by the execution of the General
Partner of an amendment to this Agreement or the certificate of limited
partnership, evidencing the admission of such person as a Substituted Limited
Partner.
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<PAGE>
13.9 No person shall become a Substituted Limited Partner until such person
shall have:
(a) become a party to, and adopted all of the terms and conditions
of, this Agreement;
(b) if such person is a corporation, partnership or trust, provided
the General Partner with evidence satisfactory to counsel for the
Partnership of such person's authority to become a Limited Partner under
the terms and provisions of this Agreement; and
(c) paid or agreed to pay the costs and expenses incurred by the
Partnership in connection with such person's becoming a Limited Partner.
Provided, however, that for the purpose of allocating Partnership Revenue, costs
and expenses, a person shall be treated as having become, and as appearing in
the records of the Partnership as, a Substituted Limited Partner on such date as
the sale, assignment or transfer was recognized by the Partnership pursuant to
Section 13.5.
13.10 By his or her execution of his or her Subscription Agreement, each
Limited Partner represents and warrants to the General Partner and to the
Partnership that his or her acquisition of his or her interest in the
Partnership is made as principal for his or her own account for investment
purposes only and not with a view to the resale or distribution of such
interest. Each Limited Partner agrees that he or she will not sell, assign or
otherwise transfer his or her interest in the Partnership or any fraction
thereof unless such interest has been registered under the Securities Act of
1933, as amended, or such sale, assignment or transfer is exempt from such
registration and, in any event, he or she will not so sell, assign or otherwise
transfer his or her interest or any fraction thereof to any person who does not
similarly represent, warrant and agree.
ARTICLE XIV
Assignments by the General Partner
14.1 The General Partner may not sell, assign, transfer or otherwise
dispose of its interest in the Partnership except with the prior consent,
subject to Section 12.1, of Limited Partners holding a majority of the
outstanding Units; provided that a sale, assignment or transfer may be effective
without such consent if pursuant to a bona fide merger, any other corporate
reorganization or a complete liquidation, pursuant to a sale of all or
substantially all of the General Partner's assets (provided the purchasers of
such assets agree to assume the duties and obligations of the General
Partner) or a sale or transfer to UNIT or any affiliates of UNIT. If the
Limited Partners' consent to a proposed transfer is required, the General
Partner will, concurrently with the request for such consent, give the Limited
Partners written notice identifying the interest to be transferred, the date
on which the transfer is to be effective, the proposed transferee and the
substitute General Partner, if any.
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<PAGE>
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, 2000, each Limited Partner will have the option,
subject to the terms and conditions set forth in this Article XV, to require the
General Partner to purchase all (but not less than all) of his or her Units,
provided that the option may not be exercised after the date of any notice that
will effect a dissolution and termination of the Partnership pursuant to Article
XVI below. Any such exercise shall be effected by written notice thereof
delivered to the General Partner.
15.2 Sales of Limited Partners' Units pursuant to this Article XV will be
effective, and the purchase price for such interests will be determined, as of
the close of business on the last day of the calendar year in which the Limited
Partner's notice exercising his or her option is given, or, at the General
Partner's election, as of 7:00 o'clock A.M. on the following day.
15.3 The purchase price to be paid for the Units of any Limited Partner who
exercises the option granted in this Article XV will be determined in the
following manner. First, future gross revenues expected to be derived from the
production and sale of the proved reserves attributable to Partnership
Properties will be estimated, as of the end of the calendar year in which
presentment is made, by the independent engineering firm preparing a report on
the reserves of the Partnership, or if no such firm is preparing a report as of
the end of the calendar year in which the option is exercised, then by the
General Partner. Next, future net revenues will be calculated by deducting
anticipated expenses (including Operating Expenses and other costs that will be
incurred in producing and marketing such reserves and any gross production,
excise, or other taxes, other than federal income taxes, based on the oil and
gas production of the Partnership or sales thereof) from estimated future gross
revenues. The estimates of price and cost escalations to be used in such
calculations will be those of such independent engineering firm or the General
Partner, whichever is making the determination. Then the present worth of the
future net revenues will be calculated by discounting the estimated future net
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<PAGE>
revenues at that rate per annum which is one (1) percentage point higher than
the prime rate of interest being charged by Bank of Oklahoma, N.A., Tulsa,
Oklahoma, or any successor bank, as such prime rate of interest is announced by
said bank as of the date such reserves are estimated. This amount will be
reduced by an additional 25% to take into account the uncertainties attendant to
the production and sale of oil and gas reserves and other unforeseen
contingencies. Estimated salvage value of tangible equipment installed on the
Partnership Wells and costs of plugging and abandoning the productive
Partnership Wells, both discounted at the aforementioned rate from the expected
date of abandonment, will be considered, and Partnership Properties, if any,
which do not have proved reserves attributable to them but which have not been
condemned will be valued at the lower of cost or their then current market value
as determined by the aforementioned independent petroleum engineering firm or
General Partner, as the case may be. The Partnership's cash on hand, prepaid
expenses, accounts receivable (less a reasonable reserve for doubtful accounts)
and the market value of its other assets as determined by the General Partner
will be added to the value of the Partnership Properties thus determined, and
the Partnership's debts, obligations and other liabilities will be deducted, to
arrive at the Partnership's net asset value for purposes of this Section 15.3.
The price to be paid for the Limited Partner's interest will be his or her
proportionate share of such net asset value less 75% of the amount of any
Partnership distributions received by him or her which are attributable to sales
of Partnership production since the date as of which the Partnership's proved
reserves are estimated.
15.4 Within one hundred twenty (120) days after the end of any calendar
year in which a Limited Partner exercises his or her option to require purchase
of his or her Units as provided in this Article XV, the General Partner will
furnish to such Limited Partner a statement showing the price to be paid for his
or her Units and evidencing that such price has been determined in accordance
with the provisions of Section 15.3 above. The statement will show which
portion of the proposed purchase price is represented by the value of the proved
reserves and by each of the other classes of Partnership assets and liabilities
attributable to the account of the Limited Partner. The Limited Partner will
then have thirty (30) days to confirm, by further notice to the General Partner,
his or her intention to sell his or her Units to the General Partner. If the
Limited Partner timely confirms his or her intention to sell, the sale will be
consummated and the price paid in cash within ten (10) days after such
confirmation. The General Partner will not be obligated to purchase (i) any
Units pursuant to such right if such purchase, when added to the total of all
other sales, exchanges, transfers or assignments of the Units within the
preceding 12 months, would result in the Partnership being considered to have
terminated within the meaning of Section 708 of the Code or would cause the
Partnership to lose its status as a partnership for federal income tax purposes,
or (ii) in any one calendar year more than 20% of the Units in the Partnership
then outstanding. If less than all of the Units tendered are purchased, the
interests purchased will be selected by lot. The Limited Partners whose
tendered Units were rejected by reason of the foregoing limitation shall be
entitled to priority in the following year. Contemporaneously with the closing
of any such sale, the Limited Partner will execute such certificates or other
documents and perform such acts as the General Partner deems necessary to effect
the sale and transfer of the liquidating Limited Partner's Units to the General
Partner and to preserve the limited liability status of the Partnership under
the laws of the jurisdictions in which it is doing business.
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<PAGE>
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, 2029,
unless prior thereto, subject to Section 12.1 above, the General Partner or
Limited Partners holding a majority of the outstanding Units elect to terminate
the Partnership as of an earlier date. In the event of such earlier
termination, ninety (90) days' written notice will be given to all other
Partners. The termination date will be specified in such notice and must be the
last day of any calendar month following expiration of the ninety (90) day
period unless an earlier date is approved by Limited Partners holding a majority
of the outstanding Units.
16.2 Upon the dissolution (other than pursuant to a merger or other
corporate reorganization), bankruptcy, legal disability or withdrawal of the
General Partner (other than pursuant to Section 14.1 above), the Partnership
shall immediately be dissolved and terminated; provided, however, that nothing
in this Agreement shall impair, restrict or limit the rights and powers of the
Partners under the laws of the State of Oklahoma and any other jurisdiction in
which the Partnership is doing business to reform and reconstitute themselves as
a limited partnership within ninety (90) days following the dissolution of the
Partnership either under provisions identical to those set forth herein or under
any other provisions. The withdrawal, expulsion, dissolution, death, legal
disability, bankruptcy or insolvency of any Limited Partner will not effect a
dissolution or termination of the Partnership.
16.3 Upon termination of the Partnership by action of the Limited Partners
pursuant to Section 16.1 hereof or as a result of an event under Section 16.2
hereof, a party designated by the Limited Partners holding a majority of the
outstanding Units will act as Liquidating Trustee. In any other case, the
General Partner will act as Liquidating Trustee.
16.4 As soon as possible after December 31, 2029, 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;
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<PAGE>
(c) The Liquidating Trustee shall:
(i) pay all of the Partnership's debts, liabilities and
obligations to its creditors, including the General Partner; and
(ii) pay all expenses incurred in connection with the
termination, liquidation and dissolution of the Partnership and
distribution of its assets as herein provided;
(d) The Liquidating Trustee shall ascertain the fair market value by
appraisal or other reasonable means of all assets of the Partnership
remaining unsold, and each Partner's capital account shall be charged or
credited, as the case may be, as if such property had been sold at such
fair market value and the gain or loss realized thereby had been allocated
to and among the Partners in accordance with Article VI hereof; and
(e) On or as soon as practicable after the effective date of the
termination, all remaining cash and any other properties and assets of the
Partnership not sold pursuant to the preceding subsections of this Section
16.4 will be distributed to the Partners (i) in proportion to and to the
extent of any remaining balances in the Partners' capital accounts and then
(ii) in undivided interests to the Partners in the same proportions that
Partnership Revenues are being shared at the time of such termination,
provided, that:
(i) the various interests distributed to the respective Partners
will be distributed subject to such liens, encumbrances, restrictions,
contracts, operating agreements, obligations, commitments or
undertakings as existed with respect to such interests at the time
they were acquired by the Partnership or were subsequently created or
entered into by the Partnership;
(ii) if interests in the Partnership Wells that are not subject
to any operating agreement are to be distributed, the Partners will,
concurrently with the distribution, enter into standard form operating
agreements covering the subsequent operation of each such well which
will, if the termination is effected pursuant to Section 16.1 above,
be in a form satisfactory to the General Partner and will name the
General Partner or its designee as operator; and
(iii) no Partner shall be distributed an interest in any asset
if the distribution would result in a deficit balance or increase the
deficit balance in its capital account (after making the adjustments
referred to in this Section 16.4 relating to distributions in kind).
A-35
<PAGE>
16.5 If the General Partner has a deficit balance in its capital account
following the distribution(s) provided for in Section 16.4(e) above, as
determined after taking into account all adjustments to its capital account for
the taxable year of the Partnership during which such distribution occurs, it
shall restore the amount of such deficit balance to the Partnership within
ninety (90) days and such amount shall be distributed to the other Partners in
accordance with their positive capital account balances.
16.6 Notwithstanding anything to the contrary in this Agreement, upon the
dissolution and termination of the Partnership, the General Partner will
contribute to the Partnership the lesser of: (a) the deficit balance in its
capital account; or (b) the excess of 1.01 percent of the total Capital
Contributions of the Limited Partners over the capital previously contributed by
the General Partner.
ARTICLE XVII
Notices
17.1 All notices, consents, requests, demands, offers, reports and other
communications required or permitted shall be deemed to be given or made when
personally delivered to the party entitled thereto, or when sent by United
States mail in a sealed envelope, with postage prepaid, addressed, if to the
General Partner, to 1000 Kensington Tower I, 7130 South Lewis Avenue, P. O.
Box 702500, Tulsa, Oklahoma 74136, and, if to a Limited Partner, to the address
set forth below such Limited Partner's signature on the counterpart of the
Subscription Agreement that he or she originally executed and delivered to the
General Partner. The General Partner may change its address by giving notice to
all Limited Partners. Limited Partners may change their address by giving
notice to the General Partner.
ARTICLE XVIII
Amendments
18.1 Limited Partners do not have the right to propose amendments to this
Agreement. The General Partner may propose an amendment or amendments to this
Agreement by mailing to the Limited Partners a notice describing the proposed
amendment and a form to be returned by the Limited Partners indicating whether
they oppose or approve of its adoption. Such notice will include the text of
the proposed amendment, which will have been approved in advance by counsel for
the Partnership. If, within sixty (60) days, or such shorter period as may be
designated by the General Partner, after any notice proposing an amendment or
amendments to this Agreement has been mailed, Limited Partners holding a
majority of the outstanding Units have properly executed and returned the form
indicating that they approve of and consent to adoption of the proposed
amendment, such amendment will become effective as of the date specified in such
notice, provided that no amendment which alters the allocations specified in
Article VI above, changes the compensation and reimbursement provisions set
forth in Article XI above or is otherwise materially adverse to the interests of
the Limited Partners will become effective unless approved by all Limited
Partners. If an amendment does become effective, all Partners will promptly
evidence such effectiveness by executing such certificates and other instruments
as the General Partner may deem necessary or appropriate under the laws of the
jurisdictions in which the Partnership is then doing business in order to
reflect the amendment.
A-36
<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 _____ day of _______________, 1999 but effective as of the Effective Date.
"General Partner"
UNIT PETROLEUM COMPANY
Attest:
By______________________________ By_________________________________
Mark E. Schell, Secretary John G. Nikkel, President
(CORPORATE SEAL)
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<PAGE>
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
State or Province Percentage
Subsidiary of Incorporation Owned
- ------------------------------------- ----------------- ----------
Unit Drilling and Exploration Company Delaware 100%
Mountain Front Pipeline Company, Inc. Oklahoma 100%
Unit Drilling Company (1) Oklahoma 100%
Unit Petroleum Company (2) Oklahoma 100%
Petroleum Supply Company Oklahoma 100%
Unit Energy Canada, Inc. Alberta 100%
- -------------
(1) Unit Drilling Company owns 100% of one subsidiary which in turn owns
100% of two subsidiaries. The name and country of incorporation of the
companies are:
Unit Drilling Company International Cayman Islands
Perforaciones Leasing Ltd. Cayman Islands
Rig Leasing International Cayman Islands
(2) Unit Petroleum Company owns 100% of one subsidiary corporation,
namely:
Unit Texas Company Oklahoma
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Unit Corporation on Form S-8 (File No.'s 33-19652, 33-44103, 33-49724,
33-64323 and 33-53542) and Form S-3 (File No. 333-42341) of our report
dated February 23, 1999, on our audits of the consolidated financial
statements and financial statement schedule of Unit Corporation as of
December 31, 1998 and 1997, and for the years ended December 31, 1998, 1997
and 1996, which report is included in this Annual Report on Form 10-K.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 18, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
The schedule contains summary financial information extracted from the
Consolidated Financial Statements of Unit Corporation and Subsidiaries
under cover of Form 10-K for December 31, 1998 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-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 446
<SECURITIES> 0
<RECEIVABLES> 13,423
<ALLOWANCES> 274
<INVENTORY> 3,298
<CURRENT-ASSETS> 19,543
<PP&E> 405,043
<DEPRECIATION> 207,883
<TOTAL-ASSETS> 223,064
<CURRENT-LIABILITIES> 17,990
<BONDS> 0
0
0
<COMMON> 5,113
<OTHER-SE> 106,177
<TOTAL-LIABILITY-AND-EQUITY> 223,064
<SALES> 0
<TOTAL-REVENUES> 93,337
<CGS> 0
<TOTAL-COSTS> 79,892
<OTHER-EXPENSES> 4,891
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,815
<INCOME-PRETAX> 3,739
<INCOME-TAX> 1,493
<INCOME-CONTINUING> 2,246
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,246
<EPS-PRIMARY> .09
<EPS-DILUTED> .09
</TABLE>
