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F O R M 1 0 - K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
++++++++++++++++++++++++++++++++
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
Common Stock, par value New York Stock Exchange
$.20 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Warrants to Purchase Shares of Common Stock
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by reference in
PART III of this Form 10-K or any amendment to this Form 10-K. X
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 15, 1995 - $44,446,596
Number of Shares of Common Stock
Outstanding on March 15, 1995 - 20,933,190
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 3, 1995 are incorporated by
reference in Part III.
Exhibit Index - See Page 66
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . 15
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . 16
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . 16
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . 17
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations. . . . . . . . . . . . . . . . . . . 17
Item 8. Financial Statements and Supplementary Data. . . . . . . . . . . 25
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . 55
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . 55
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . 56
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . 57
Item 13. Certain Relationships and Related Transactions . . . . . . . . . 57
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . 58
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1994
PART I
Item 1. Business and Item 2. Properties
- -----------------------------------------
GENERAL
The Company, through its wholly owned subsidiaries, is engaged in the
land contract drilling of oil and natural gas wells, the development,
acquisition and production of oil and natural gas properties and the
marketing of natural gas. The Company operates primarily in the Anadarko
and Arkoma Basins, which cover portions of Oklahoma, Texas, Kansas and
Arkansas and has additional producing properties located in other states,
including but not limited to, New Mexico, Louisiana, North Dakota,
Colorado, Wyoming, Montana, Alabama and Mississippi.
The Company was originally incorporated in Oklahoma in 1963 as Unit
Drilling Company. In 1979 it became a publicly held Delaware corporation
and changed its name to Unit Drilling and Exploration Company ("UDE") to
more accurately reflect the importance of its oil and natural gas business.
In September 1986, pursuant to a merger and exchange offer, the Company
acquired all of the assets and assumed all of the liabilities of UDE and
six oil and gas limited partnerships for which UDE was the general partner,
in exchange for shares of the Company's common stock (the "Exchange
Offer").
The Company's principal executive offices are maintained at 1000
Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number
(918) 493-7700. As used herein, the term "Company" refers to Unit Corpo-
ration and at times Unit Corporation and/or one or more of its subsidiaries
with respect to periods from and after the Exchange Offer and to UDE with
respect to periods prior thereto.
OIL AND NATURAL GAS OPERATIONS
In 1979, the Company began to acquire oil and natural gas properties
to diversify its source of revenues which had previously been derived from
contract drilling. The development, production and sale of oil and natural
gas together with the acquisition of producing properties now constitutes a
major portion of the Company's operations as conducted through its wholly
owned subsidiaries, Unit Petroleum Company and Roundup Resources, Inc.
As of December 31, 1994, the Company had 4,308 Mbbls and 93,360 MMcf
of estimated proved oil and natural gas reserves, respectively. The
Company's producing oil and natural gas interests, undeveloped leaseholds
and related assets are located primarily in Oklahoma, Texas, Louisiana and
New Mexico and to a lesser extent in Arkansas, North Dakota, Colorado, Wyo-
ming, Montana, Alabama, Mississippi and Canada. As of December 31, 1994,
1
the Company had an interest in a total of 1,764 wells in the United States
of which it served as the operator of 418. The Company also had an
interest in 61 wells located in Canada. The majority of the Company's
development and exploration prospects are generated by its technical staff.
When the Company is the operator of a property, it generally employs its
own drilling rigs and the Company's own engineering staff supervises the
drilling operation.
The Company intends to continue the growth in its oil and natural gas
operations utilizing funds generated from operations and its bank revolving
line of credit.
Well and Leasehold Data. The Company's oil and natural gas explora-
tion and development drilling activities and the number of wells in which
the Company had an interest which were producing or capable of producing
were as follows for the periods indicated:
Year Ended December 31,
Wells drilled: 1994 1993 1992
- -------------- Gross Net Gross Net Gross Net
Exploratory: ------ ------ ------ ------ ------ ------
Oil.............. - - - - - -
Natural gas...... 1 .98 1 1.00 - -
Dry.............. 2 .80 1 0.10 - -
------ ------ ------ ------ ------ ------
Total 3 1.78 2 1.10 - -
====== ====== ====== ====== ====== ======
Development:
Oil.............. 5 5.00 12 11.98 2 2.00
Natural gas...... 40 13.46 25 11.12 15 5.38
Dry.............. 12 7.26 8 4.29 6 1.48
------ ------ ------ ------ ------ ------
Total 57 25.72 45 27.39 23 8.86
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
- ------------------------------------------------------------
Oil - USA........ 675 177.68 337 162.09 329 130.70
Oil - Canada..... - - - - - -
Gas - USA........ 1,089 179.99 709 141.76 715 132.03
Gas - Canada..... 61 1.53 61 1.53 56 1.40
------ ------ ------ ------ ------ ------
Total 1,825 359.20 1,107 305.38 1,100 264.13
====== ====== ====== ====== ====== ======
2
The following table summarizes the Company's acreage as of the end of each
of the years indicated:
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
------- ------- ------- -------
1994
----
USA 340,241 100,732 21,514 11,540
Canada 31,360 784 - -
------- ------- ------- -------
Total 371,601 101,516 21,514 11,540
======= ======= ======= =======
1993
----
USA 246,115 86,013 28,738 18,021
Canada 31,360 784 - -
------- ------- ------- -------
Total 277,475 86,797 28,738 18,021
======= ======= ======= =======
1992
----
USA 228,363 86,144 36,169 18,736
Canada 31,360 784 - -
------- ------- ------- -------
Total 259,723 86,928 36,169 18,736
======= ======= ======= =======
3
Price and Production Data. The average sales price, oil and natural
gas production volumes and average production cost per equivalent barrel (6
thousand cubic feet (Mcf) of natural gas = 1 barrel (Bbl) of oil) of
production, experienced by the Company, for the periods indicated were as
follows:
Year Ended December 31,
1994 1993 1992
-------- -------- --------
Average sales price per barrel
of oil produced:
USA $ 15.13 $ 16.73 $ 19.52
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 1.86 $ 2.07 $ 2.15
Canada $ 1.27 $ 0.96 $ 0.93
Oil production (Mbbls):
USA 406 397 375
Canada - - -
-------- -------- --------
Total 406 397 375
======== ======== ========
Natural gas production (MMcf):
USA 9,606 7,435 6,730
Canada 53 70 80
-------- -------- --------
Total 9,659 7,505 6,810
======== ======== ========
Average production expense per
equivalent barrel:
USA $ 3.49 $ 3.93 $ 4.11
Canada $ 2.19 $ 1.28 $ 0.76
Reserves. The following table sets forth the estimated proved
developed and undeveloped oil and natural gas reserves of the Company at
the end of each of the years indicated:
Year Ended December 31,
1994 1993 1992
------- ------- -------
Oil (Mbbls):
USA 4,308 3,304 3,308
Canada - - -
------- ------- -------
Total 4,308 3,304 3,308
======= ======= =======
Natural gas (Mmcf):
USA 92,566 71,379 63,761
Canada 794 861 931
------- ------- -------
Total 93,360 72,240 64,692
======= ======= =======
Further information relating to oil and natural gas operations is
presented in Notes 1, 2, 4, 9, 10 and 12 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
5
LAND CONTRACT DRILLING OPERATIONS
Unit Drilling Company, a wholly owned subsidiary of the Company,
engages in the land drilling of oil and natural gas wells for a wide range
of customers. A land drilling rig consists, in part, of engines, drawworks
or hoists, derrick or mast, pumps to circulate the drilling fluid, blowout
preventers and drill pipe. An active maintenance and replacement program
during the life of a drilling rig permits upgrading of components on an
individual basis. Over the life of a typical rig, due to the normal wear
and tear of operating up to 24 hours a day, several of the major
components, such as engines, mud pumps and drill pipe, are replaced or
rebuilt on a periodic basis as required, while other components, such as
the substructure, mast and drawworks, can be utilized for extended periods
of time with proper maintenance. The Company also owns additional
equipment used in the operation of its rigs, including large air compres-
sors, trucks and other support equipment.
The Company owns and operates 25 drilling rigs with drilling capa-
bilities primarily in the 6,000 to 20,000 foot depth range. Historically,
all of these drilling rigs were located in the Anadarko and Arkoma Basins
of Oklahoma, Kansas, Arkansas and Texas. In 1994, the Company moved two
20,000 feet depth range rigs to the South Texas basin region thereby
expanding the Company's market area for its contract drilling services. A
third rig was moved under contract to the South Texas basin early in 1995.
In the Anadarko and Arkoma Basins the Company's primary focus is on the
utilization of its medium depth rigs which have a depth range of 8,000 to
14,000 feet. These medium depth rigs are suited to the contract drilling
currently undertaken by operators in these two basins.
At present, the Company does not have a shortage of drill pipe or
other equipment. However, as certain grades of drill pipe start to reach
the end of their useful life there is no assurance that sufficient supplies
of such equipment will be readily available. In addition, given the
general decline experienced in the land contract drilling industry over the
past number of years, the Company's ability to utilize its full complement
of drilling rigs, should economic conditions improve rapidly in the future,
will be restricted due to a lack of equipment and qualified labor not only
within the Company but in the industry as a whole.
5
The following table sets forth for each of the periods indicated
certain data concerning the Company's contract drilling operations:
Year Ended December 31,
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Number of rigs owned at end of period 25 25 26 26 27
Average number of rigs utilized(1) 9.5 8.0 5.5 9.1 12.6
Number of wells drilled 95 84 56 92 106
Total footage drilled (feet in 1000's) 1027 788 527 736 991
- -------------------
(1) Utilization rates are based on a 365-day year. A rig is
considered utilized when it is operating or being moved, assembled or
dismantled under contract.
As of March 15, 1995, 6 of the Company's 25 drilling rigs were oper-
ating under contract.
The following table sets forth, as of March 15, 1995, the type and
approximate depth capability of the Company's drilling rigs:
Depth
Capability
Type (feet)
---- ----------
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
Gardner Denver 800. . . . . . . . . . . . 15,000
Brewster N-55 . . . . . . . . . . . . . . 12,000
Gardner Denver 700. . . . . . . . . . . . 15,000
BDW 800-M1. . . . . . . . . . . . . . . . 15,000
Gardner Denver 700. . . . . . . . . . . . 15,000
Mid-Continent 914-C . . . . . . . . . . . 20,000
U-15 Unit Rig . . . . . . . . . . . . . . 11,000
Brewster N-75 . . . . . . . . . . . . . . 15,000
Gardner Denver 500. . . . . . . . . . . . 12,000
Gardner Denver 700. . . . . . . . . . . . 15,000
Gardner Denver 700. . . . . . . . . . . . 15,000
Gardner Denver 700. . . . . . . . . . . . 15,000
National 75 . . . . . . . . . . . . . . . 15,000
Brewster N-75 . . . . . . . . . . . . . . 15,000
BDW 1350-M. . . . . . . . . . . . . . . . 20,000
SU-15 North Texas Machine . . . . . . . . 12,000
SU-15 North Texas Machine . . . . . . . . 12,000
National 110-E. . . . . . . . . . . . . . 20,000
Continental Emsco C-1-E . . . . . . . . . 20,000
Gardner Denver 1500-E . . . . . . . . . . 25,000
For the past several years, the Company's contract drilling services
have encountered significant competition due to depressed levels of
6
activity in contract drilling as oil and natural gas prices remained below
economic levels needed to encourage domestic exploration. While drilling
operations of the Company showed continued improvement in 1994, this
competition will, for the foreseeable future, continue to adversely affect
the Company's drilling operations.
Drilling Contracts. Most of the Company's drilling contracts are
obtained through competitive bidding. Generally, the contracts are for a
single well with the terms and rates varying depending upon the nature and
duration of the work, the equipment and services supplied and other
matters. The contracts obligate the Company to pay certain operating
expenses, including wages of drilling personnel, maintenance expenses and
incidental rig supplies and equipment. Usually, the contracts are subject
to termination by the customer on short notice upon payment of a fee. The
Company generally indemnifies its customers against certain types of claims
by the Company's employees and claims arising from surface pollution caused
by spills of fuel, lubricants and other solvents within the control of the
Company. Such customers generally indemnify the Company against claims
arising from other surface and subsurface pollution other than claims
resulting from the Company's gross negligence.
The contracts may provide for compensation to the Company on a day
rate, footage or turnkey basis with additional compensation for special
risks and unusual conditions. Under daywork contracts, the Company
provides the drilling rig with the required personnel to the operator who
supervises the drilling of the contracted well. Compensation to the
Company is based on a negotiated rate per day as the rig is utilized.
Footage contracts usually require the Company to bear some of the drilling
costs in addition to providing the rig. The Company is compensated on a
rate per foot drilled basis upon completion of the well. Under turnkey
contracts, the Company contracts to drill a well to a specified depth and
provides most of the equipment and services required. The Company bears
the risk of drilling the well to the contract depth and is compensated when
the contract provisions have been satisfied.
Turnkey drilling operations, in particular, might result in losses if
the Company underestimates the costs of drilling a well or if unforeseen
events occur. Because the proportion of turnkey drilling is currently
dictated by market conditions and the desires of customers using the
Company's services, the Company is unable to predict whether the portion of
drilling conducted on a turnkey basis will increase or decrease in the
future. During the year ended December 31, 1994 turnkey revenue
represented approximately 19% of the Company's contract drilling revenues.
To date, the Company has not experienced significant losses in performing
turnkey contracts.
Customers. During the last 3 years, approximately 8 customers have
regularly used the Company for drilling operations. During the fiscal year
ended December 31, 1994, 10 contract drilling customers accounted for
approximately 10% of the Company's revenues. In addition, approximately 2%
of the Company's revenues for the year ended December 31, 1994, were
generated by drilling on oil and natural gas properties of which the
Company was the operator (including properties owned by limited partner-
7
ships for which the Company acted as general partner). Such drilling was
pursuant to contracts containing terms and conditions comparable to those
contained in the Company's customary drilling contracts with non-affiliated
operators.
Further information relating to contract drilling operations is
presented in Notes 1 and 10 of Notes to Consolidated Financial Statements
set forth in Item 8 hereof.
NATURAL GAS MARKETING, GATHERING AND PROCESSING
The Company, through its wholly owned subsidiary, Mountain Front
Pipeline Company ("Mountain Front"), is engaged in marketing natural gas
from wells located primarily in Oklahoma and Texas and to a lesser extent
in Arkansas, Kansas, Louisiana, Mississippi and New Mexico. Natural gas
purchased from 5 customers during 1994 accounted for 32% of the Company's
marketing activity. The Company owns 8 natural gas gathering systems. The
Company also owns an interest in 2 natural gas processing plants located in
Oklahoma and Mississippi and 44 natural gas compressors.
Revenues and expenses from the Company's natural gas marketing,
gathering and processing activities for the periods indicated were as
follows:
Year Ended December 31,
1994 1993 1992
------- ------- -------
(In thousands)
Natural gas marketing and
gathering revenue $43,725 $31,624 $21,341
Natural gas processing revenue $ 82 $ 181 $ 514
Other revenue $ 364 $ 299 $ 115
Natural gas marketing
and processing expense $43,897 $32,325 $22,627
Mountain Front, while achieving substantial growth in revenues in
recent years, has not, in the opinion of management, achieved the size
necessary to reach desired levels of profitability. Consequently, the
Company is currently negotiating to effect a business combination between
Mountain Front's marketing operations and a third party. The combination,
if completed, would leave the Company with a minority interest in the
resulting larger entity. Such a combination would not adversely affect the
operations of the Company's drilling and oil and natural gas exploration
segments or the profitability of the Company as a whole, although it would
result in a significant reduction in the Company's total revenues and
associated costs.
Further information related to natural gas marketing, gathering and
processing is presented in Note 10 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
8
MARKETING OF OIL AND NATURAL GAS PRODUCTION
The Company's revenue and profitability are substantially dependent
upon prevailing prices for natural gas and crude oil. These prices vary
based on factors beyond the control of the Company, including the extent of
domestic production and importation of crude oil and natural gas, the
proximity and capacity of oil and natural gas pipelines, the marketing of
competitive fuels, general fluctuations in the supply and demand for oil
and natural gas, the effect of federal and state regulation of production,
refining, transportation and sales, the use and allocation of oil and
natural gas and their substitute fuels and general national and worldwide
economic conditions. In addition, natural gas spot prices received by the
Company are influenced by weather conditions impacting the continental
United States.
The Company's oil and condensate production is sold at or near the
Company's wells under short-term purchase contracts at prevailing prices in
accordance with arrangements which are customary in the oil industry. The
Company's natural gas production is sold at the wellhead to intrastate and
interstate pipelines as well as independent marketing firms under contracts
with original terms ranging from one month to 20 years. Most of these
contracts contain provisions for readjustment of price, termination and
other terms which are customary in the industry.
The worldwide supply of oil has been largely dependent upon rates of
production of foreign reserves. Although the demand for oil has slightly
increased in the United States, imports of foreign oil continue to in-
crease. Future domestic oil prices will depend largely upon the actions of
foreign producers with respect to rates of production and it is virtually
impossible to predict what actions those producers will take in the future.
Prices may also be affected by political and other factors relating to the
Middle East. In view of the many uncertainties affecting the supply and
demand for oil and natural gas the Company is unable to predict future oil
and natural gas prices or the overall effect, if any, that a decline in
demand or oversupply of such products would have on the Company.
COMPETITION
All lines of business in which the Company engages are highly com-
petitive. Competition in land contract drilling traditionally involves
such factors as price, efficiency, condition of equipment, availability of
labor and equipment, reputation and customer relations. Some of the
Company's competitors in the land contract drilling business are sub-
stantially larger than the Company and have appreciably greater financial
and other resources. As a result of the decrease in demand for land
contract drilling services, a surplus of drilling rigs currently exists.
Accordingly, the competitive environment within which the Company's
drilling operations presently operates is uncertain and extremely price
oriented.
The Company's oil and natural gas operations and the Company's natural
gas marketing operations, likewise encounter strong competition from major
oil companies, independent operators, marketers, pipelines and others.
9
Many of these competitors have appreciably greater financial, technical and
other resources and are more experienced in the exploration for and
production of oil and natural gas and the marketing of natural gas than the
Company.
OIL AND NATURAL GAS PROGRAMS
The Company currently serves as a general partner to 5 oil and gas
limited partnerships and 6 employee oil and gas limited partnerships. The
employee partnerships acquire an interest ranging from 5% to 15% of the
Company's interest in most oil and natural gas drilling activities and pur-
chases of producing oil and natural gas properties participated in by the
Company. The limited partners in the employee partnerships are either
employees or directors of the Company or its subsidiaries. Prior to
December 31, 1993, the Company was the general partner of seven additional
employee limited partnerships. However, pursuant to the terms of an
agreement and plan of merger these seven limited partnerships were
consolidated into one new employee limited partnership effective December
31, 1993.
Under the terms of the partnership agreements of each limited part-
nership, the general partner, which in each case is Unit Petroleum Company,
has broad discretionary authority to manage the business and operations of
the partnership, including the authority to make decisions on such matters
as the partnership's participation in a drilling location or a property
acquisition, the partnership's expenditure of funds and the distribution of
funds to partners. Because the business activities of the limited partners
on the one hand, and the general partner on the other hand, are not the
same, conflicts of interest will exist and it is not possible to eliminate
entirely such conflicts. Additionally, conflicts of interest may arise
where the Company is the operator of an oil and natural gas well and also
provides contract drilling services. Although the Company has no formal
procedures for resolving such conflicts, the Company believes it fulfills
its responsibility to each contracting party and complies fully with the
terms of the agreements which regulate such conflicts.
Depending upon a number of factors, including the performance of the
drilling programs and general economic and capital market conditions, the
Company may form additional drilling and/or producing property acquisition
programs in the future.
EMPLOYEES
As of February 28, 1995, the Company had approximately 205 employees
in its land contract drilling operations, 46 employees in its oil and natu-
ral gas operations, 9 employees in natural gas marketing and processing and
23 in its general corporate area. None of the Company's employees are
represented by a union or labor organization nor have the Company's
operations ever been interrupted by a strike or work stoppage. The Company
considers relations with its employees to be satisfactory.
10
OPERATING AND OTHER RISKS
The Company's land contract drilling, oil and natural gas operations
and natural gas processing facilities are subject to a variety of oil field
hazards such as fire, explosion, blowouts, cratering and oil spills or
certain other types of possible surface and subsurface pollution, any of
which can cause personal injury and loss of life and severely damage or
destroy equipment, suspend drilling operations and cause substantial damage
to surrounding areas or property of others. As protection against some,
but not all, of these operating hazards, the Company maintains broad
insurance coverage, including all-risk physical damage, employer's
liability and comprehensive general liability. In all states in which the
Company operates except Oklahoma, the Company maintains worker's
compensation insurance for losses exceeding $50,000. In Oklahoma, starting
in August 1991, the Company elected to become self insured. In
consideration therewith, the Company purchased an excess liability
reinsurance policy. The Company believes that to the extent reasonably
practicable such insurance coverages are adequate. The Company's insurance
policies do not, however, provide protection against revenue losses
incurred by reason of business interruptions caused by the destruction or
damage of major items of equipment nor certain types of hazards such as
specific types of environmental pollution claims. In view of the
difficulties which may be encountered in renewing such insurance at
reasonable rates, no assurance can be given that the Company will be able
to maintain the amount of insurance coverage which it considers adequate at
reasonable rates. Moreover, loss of or serious damage to any of the
Company's equipment, although adequately covered by insurance, could have
an adverse effect upon the Company's earning capacity.
The Company's oil and natural gas operations are also subject to all
of the risks and hazards typically associated with the search for and
production of oil and natural gas. These include the necessity of ex-
pending large sums of money for the location and acquisition of properties
and for drilling exploratory wells. In such exploratory work, many
failures and losses may occur before any accumulation of oil or natural gas
is found. If oil or natural gas is encountered, there is no assurance that
it will be capable of being produced or will be in quantities sufficient to
warrant development or that it can be satisfactorily marketed. The
Company's future natural gas and crude oil revenues and production, and
therefore cash flow and income, are highly dependent upon the Company's
level of success in acquiring or finding additional reserves. Without
continuing reserve additions through exploration or acquisitions, the
Company's reserves and production will decline over the long-term.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which the Company
conducts activities impose restrictions on the drilling, production and
sale of oil and natural gas, which often include requirements relating to
well spacing, waste prevention, production limitations, pollution preven-
tion and clean-up, obtaining drilling permits and similar matters. The
following discussion summarizes, in part, the regulations of the United
11
States oil and natural gas industry and is not intended to constitute a
complete discussion of the many statutes, rules, regulations and
governmental orders to which the Company's operations may be subject.
The Company's activities are subject to existing federal and state
laws and regulations governing environmental quality and pollution control.
Various states and governmental agencies are considering, and some have
adopted, laws and regulations regarding environmental control which could
adversely affect the business of the Company. Such laws and regulations
may substantially increase the costs of doing business and may prevent or
delay the commencement or continuation of given operations. Compliance
with such legislation and regulations, together with any penalties
resulting from noncompliance therewith, will increase the cost of oil and
natural gas drilling, development, production and processing. In the
opinion of the Company's management, its operations to date comply in all
material respects with applicable environmental legislation and regula-
tions; however, in view of the many uncertainties with respect to the
current controls, including their duration, interpretation and possible
modification, the Company can not predict the overall effect of such
controls on its operations.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Wellhead Decontrol Act") became effective. Under the Wellhead Decontrol
Act, all remaining price and non-price controls of first sales under the
NGA and NGPA were removed effective January 1, 1993. Prices for
deregulated categories of natural gas fluctuate in response to market
pressures which currently favor purchasers and disfavor producers. As a
result of the deregulation of a greater proportion of the domestic United
States natural gas market and an increase in the availability of natural
gas transportation, a competitive trading market for natural gas has
developed.
During the past several years, the Federal Energy Regulatory
Commission ("FERC") has adopted several regulations designed to accomplish
a more competitive, less regulated market for natural gas. These
regulations have materially affected the market for natural gas. The major
elements of several of these initiatives remain subject to appellate
review.
One of the initiatives FERC adopted was order 636. In brief, the
primary requirements of Order 636 are as follows: pipelines must separate
their sales and transportation services; pipelines must provide open access
transportation services that are equal in quality for all natural gas
suppliers and must provide access to storage on an open access contract
basis; pipelines that provide firm sales service on May 18, 1992 must offer
a "no-notice" firm transportation service under which firm shippers may
receive delivery of natural gas on demand up to their firm entitlement
without incurring daily balancing and scheduling penalties; pipelines must
provide all shippers with equal and timely access to information relevant
to the availability of their open access transportation services; open
access pipelines must allow firm transportation customers to downstream
pipelines to acquire capacity on upstream pipelines held by downstream
pipelines; pipelines must implement a capacity releasing program so that
12
firm shippers can release unwanted capacity to those desiring capacity
(which program replaces previous "capacity brokering" and "buy-sell"
programs); existing bundled firm sales entitlement are converted to
unbundled firm sales entitlement and to unbundled firm transportation
rights on the effective date of a particular pipeline's blanket sales
certificate; and pipeline transportation rights must be developed under the
Straight Fixed Variable (SFV) method of cost classification, allocation and
rate design unless the FERC permits the pipeline to use some other method.
The FERC will not permit a pipeline to change the new resulting rates until
the FERC accepts the pipeline's formal restructuring plans.
In essence, the goal of Order 636 is to make a pipeline's position as
natural gas merchant indistinguishable from that of a non-pipeline
supplier. It, therefore, pushes the point or sale of natural gas by
pipelines upstream, perhaps all the way to the wellhead. Order 636 also
requires pipelines to give firm transportation customers flexibility with
respect to receipt and delivery points (except that a firm shipper's choice
of delivery point cannot be downstream of the existing primary delivery
point) and to allow "no-notice" service (which means that natural gas is
available not only simultaneously but also without prior nomination, with
the only limitation being the customer's daily contract demand) if the
pipeline offered no-notice city-gate sales service on May 18, 1992. Thus,
this separation of pipelines' sales and transportation allows non-pipeline
sellers to acquire firm downstream transportation rights and thus to offer
buyers what is effectively a bundled city-gate sales service and it permits
each customer to assemble a package of services that serves its individual
requirements. But it also makes more difficult the coordination of natural
gas supply and transportation. A corollary to these changes is that all
pipelines will be permitted to sell natural gas at market-based rates.
The results of these changes may be the increased availability of firm
transportation and the reduction of interruptible transportation, with a
corresponding reduction in the rates for off-peak and interruptible
transportation. However, due to the still evolutionary nature of Order 636
and its implementation, it is not possible to project the overall potential
impact on transportation rates for natural gas or market prices of natural
gas.
The future interpretation and application by FERC of these rules and
its broad authority, or of the state and local regulations by the relevant
agencies, could affect the terms and availability of transportation
services for transportation of natural gas to customers and the prices at
which natural gas can be sold by the Company.
Additional proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by
the FERC and Congress will continue. Sales of petroleum liquids by the
Company are not currently regulated and are made at market prices; however,
the FERC is considering a proposal that could increase transportation rates
for petroleum liquids. A number of legislative proposals have also been
introduced in Congress and the state legislatures of various states, that,
13
if enacted, would significantly affect the petroleum industry. Such
proposals involve, among other things, the imposition of land and use
controls and certain measures designed to prevent petroleum companies from
acquiring assets in other energy areas. In addition, there is always the
possibility that if market conditions change dramatically in favor of oil
and natural gas producers that some new form of "windfall profits" or
severance tax may be proposed and imposed upon oil or natural gas. At the
present time it is impossible to predict which proposals, if any, will
actually be enacted by Congress or the various state legislatures. The
Company believes that it is complying with all orders and regulations
applicable to its operations. However, in view of the many uncertainties
with respect to the current controls, including their duration and possible
modification together with any new proposals that may be enacted, the
Company cannot predict the overall effect, if any, of such controls on
Company operations.
Certain states in which the Company operates control production from
wells through regulations establishing the spacing of wells, limiting the
number of days in a given month during which a well can produce and
otherwise limiting the rate of allowable production.
As noted above, the Company's operations are subject to numerous
federal and state laws and regulations regarding the control of
contamination of the environment. These laws and regulations may require
the acquisition of a permit before or after drilling commences, prohibit
drilling activities on certain lands lying within wilderness areas or where
pollution arises and impose substantial liabilities for pollution resulting
from drilling operations, particularly operations in offshore waters or on
submerged lands.
A past, present, or future release or threatened release of a
hazardous substance into the air, water, or ground by the Company or as a
result of disposal practices may subject the Company to liability under the
Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), the Resource Conservation Recovery Act ("RCRA"), the
Clean Water Act, and/or similar state laws, and any regulations promulgated
pursuant thereto. Under CERCLA and similar laws, the Company may be fully
liable for the cleanup costs of a release of hazardous substances even
though it contributed to only part of the release. While liability under
CERCLA and similar laws may be limited under certain circumstances, the
limits are so high that the maximum liability would likely have a
significant adverse effect on the Company. In certain circumstances, the
Company may have liability for releases of hazardous substances by previous
owners of Company properties. CERCLA currently excludes petroleum from its
definition of "hazardous substances." However, Congress may delete this
exclusion for petroleum, in which case the Company would be required to
manage its petroleum production and wastes from its exploration and
production activities as CERCLA hazardous substances. In addition, RCRA
classifies certain oil field wastes as "non-hazardous." Congress may
delete this exemption for oilfield waste, in which case the Company would
have to manage much of its oilfield waste as hazardous. Additionally, the
discharge or substantial threat of a discharge of oil by the Company into
United States waters or onto an adjoining shoreline may subject the Company
14
to liability under the Oil Pollution Act of 1990 and similar state laws.
While liability under the Oil Pollution Act of 1990 is limited under
certain circumstances, the maximum liability under those limits would still
likely have a significant adverse effect on the Company.
Violation of environmental legislation and regulations may result in
the imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the abatement of the conditions,
or suspension of the activities, giving rise to the violation. The Company
believes that the Company has complied with all orders and regulations
applicable to its operations. However, in view of many uncertainties with
respect to the current controls, including their duration and possible
modification, the Company cannot predict the overall effect of such
controls on such operations. Similarly, the Company cannot predict what
future environmental laws may be enacted or regulations may be promulgated
and what, if any, impact they would have on operations.
Item 3. Legal Proceeding
- -------------------------
The Company is a party to a settlement agreement dated January 31,
1991 with a natural gas purchaser which superseded a settlement agreement
entered into during March of 1988. Under the agreements the purchaser made
certain prepayments to the Company for natural gas to be delivered to the
purchaser in the future. As of December 31, 1994, this prepayment balance
for natural gas yet to be delivered was $3.7 million. The Company has
learned that the Oklahoma Tax Commission (the "Commission"), based on four
assessments, one in 1988, one in 1992 and two in 1994, is seeking to hold
the purchaser liable for certain taxes, interests and penalties that the
Commission contends are due and owing with respect to the prepayment
amounts made by the purchaser under the agreements on the grounds that the
prepayments are solely attributable to the settlement of past claims for
take-or-pay obligations. To date, the Company is not a party to the
Commission's proceedings, but may in the future, seek to intervene in these
proceedings. The purchaser has denied the claims made by the Commission
and is contesting the assessments. The purchaser and the Commission have
settled the 1988 assessment for approximately $51,000 and the remaining
three assessments have been consolidated and set for a hearing before an
administrative law judge on or before May 10, 1995. The purchaser has
notified the Company of the proceedings and has indicated its intention to
assert claims against the Company to recover the amount it paid in
settlement of the 1988 assessment (including its attorney fees) as well as
any amounts it might have to pay by virtue of the remaining assessments.
The Company is aware that the purchaser has made such claims against other
companies which also received prepayments from the purchaser, although the
type of agreements and the facts involved in those cases are not known by
the Company. At this time, the Company is unable to determine what the
outcome of the remaining Commission's proceedings will be, the amount of
taxes, if any, plus interest and penalties that may ultimately be assessed
against the purchaser and the claims, if any, that the purchaser might seek
to assert against the Company in the event an unfavorable result is
incurred by the purchaser. The Company has advised the purchaser that it
believes the responsibility for the payment of the taxes, interest and
15
penalty sought by the Commission, should it be ultimately determined that
any such amounts are in fact owed, is the responsibility of the purchaser
and not the Company.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
should result in judgments which would have a material adverse effect on
the Company.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted to the security holders during the fourth
quarter of the Company's calendar year ended December 31, 1994.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 21, 1995, the Company had 3,512 holders of record of
its common stock. The Company has not paid any cash dividends on shares of
its common stock since its organization and currently intends to continue
its policy of retaining earnings, if any, from the Company's operations.
The Company is prohibited, by certain loan agreement provisions, from
declaring and paying dividends (other than stock dividends) during any
fiscal year in excess of 25 percent of its consolidated net income of the
preceding fiscal year. The table below reflects the high and low sales
prices per share of the Company's common stock as reported by the New York
Stock Exchange, Inc. for the period indicated:
1994 1993
QUARTER High Low High Low
------- ------ ------ ------ ------
First $3 1/2 $2 5/8 $3 1/4 $1 5/8
Second $3 1/4 $2 3/4 $4 3/8 $2 3/4
Third $3 1/2 $2 5/8 $4 3/4 $3 1/4
Fourth $3 7/8 $2 5/8 $4 3/4 $2 5/8
16
Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
1994 1993 1992 1991 1990
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $87,958 $70,941 $55,827 $69,652 $61,904
======= ======= ======= ======= =======
Income Before
Income Taxes $ 4,814 $ 3,892 $ 1,102(1)$ 4,436 $ 830
======= ======= ======= ======= =======
Net Income $ 4,794 $ 3,871 $ 1,087(1)$ 4,341 $ 830
======= ======= ======= ======= =======
Net Income Per
Common Share $.23 $.19 $.05(1) $.21 $.04
==== ==== ==== ==== ====
Total Assets $112,421 $95,762 $88,710 $92,086 $86,286
======== ======= ======= ======= =======
Long-Term Debt $ 37,824 $25,919 $22,298 $23,153 $19,929
======== ======= ======= ======= =======
Long-Term Portion
of Natural Gas
Purchaser Prepayments $ 2,149 $ 4,417 $ 5,924 $ 7,626 $ 9,481
======== ======= ======= ======= =======
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
======== ======= ======= ======= =======
___________
(1) Includes a $1.5 million provision for litigation
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1994, 1993 and 1992 activity.
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------------------------------------------------------------------------
Results of Operations
- ---------------------
Financial Condition and Liquidity
On December 12, 1994, the Company amended its credit agreement (as
amended the "Agreement"), in part to provide funds for the December 15,
1994 closing of a producing oil and natural gas property acquisition from
two subsidiaries of Patrick Petroleum Company (collectively "Patrick").
The acquisition consisted of producing properties, located in Alabama,
Louisiana, Mississippi, New Mexico, Oklahoma and Texas and related accounts
receivable and certain related assumed liabilities for a net cost of $13.2
million. The Agreement provides for a total commitment of $50 million,
consisting of a revolving credit facility through January 1, 1997 and a
term loan thereafter, maturing on January 1, 2001. Borrowings under the
17
revolving credit facility are limited to a borrowing base which is subject
to a semi-annual redetermination. The latest borrowing base determination
indicated $42 million of the commitment is available to the Company.
Certain covenants of the Agreement were also amended. The Company must
maintain consolidated net worth of at least $45 million, a modified current
ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the
Agreement, to consolidated tangible net worth not greater than 1 to 1 and a
ratio of total liabilities, as defined in the Agreement, to consolidated
tangible net worth not greater than 1.25 to 1. In addition, working
capital provided by operations, as defined in the Agreement, cannot be less
than $13 million in any year. At December 31, 1994, borrowings under the
Agreement totalled $37.3 million. At February 21, 1995, borrowings under
the Agreement totalled $37.0 million with $2.7 million available for future
borrowings. The interest rate on the bank debt was 8.5 and 9 percent at
December 31, 1994 and February 21, 1995, respectively. A commitment fee of
1/2 of 1 percent is charged for any unused portion of the borrowing base.
Shareholders' equity at December 31, 1994 was $52.6 million, making
the Company's ratio of long-term debt-to-equity .72 to 1. The Company's
primary source of liquidity and capital resources in the near- and long-term
will consist of cash flow from operating activities and available
borrowings under the Company's Agreement. Net cash provided by operating
activities in 1994 was $13.2 million as compared to $9.9 million in 1993.
The Company's capital expenditures during 1994 were $27 million. The
majority of the capital expenditures, $25.1 million, were made in the
Company's oil and natural gas operations with $11.5 million and $13.1
million used for exploration and development drilling and producing
property acquisitions, respectively. Capital expenditures made by the
Company's contract drilling operations were approximately $1.1 million in
1994 and principally consisted of improvements to large rig components
which benefit current and future years. The Company's rigs are composed of
large components some of which, on a rotational basis, are required to be
overhauled to assure proper performance. Such capital expenditures will
continue in future years. Additional expenditures may be required in 1995
for drill pipe as certain grades of the Company's drill pipe are reaching
the end of their useful life.
Late in December 1994, Unit agreed to acquire producing oil and
natural gas properties for a purchase price of $2,125,000. This
acquisition has an effective date of January 1, 1995 and includes ten
natural gas wells located in Lipscomb County, Texas.
During the first half of 1995, the Company plans to pay down a portion
of its long-term debt while continuing its developmental drilling on a
limited basis. The Company's capital expenditures are discretionary and
directed toward increasing reserves and future growth. Current operations
should not be adversely affected by any inability to obtain funds outside
of the Company's current loan agreement. The decision to acquire or drill
on oil and natural gas properties at any given time depends on market
conditions, potential return on investment, future drilling potential and
the availability of opportunities to obtain financing given the
circumstances involved, thus providing the Company with a large degree of
18
flexibility in incurring such costs. Depending, in part, on commodity
pricing, the Company plans to spend approximately $16 million on its
capital expenditure program in 1995.
The Company has 2.873 million warrants outstanding. The warrants
entitle the holders to purchase one share of common stock at a price of
$4.375 per share. The warrants, subject to certain restrictions, are
callable by the Company, in whole or in part, at $.50 per warrant. A
Second Amendment to the Warrant Agreement between the Company and the
Warrant Agent, dated May 9, 1994, extended the term of the warrants to
August 30, 1996.
The Company continued to receive monthly payments on behalf of itself
and other parties (collectively the "Committed Interest") from a natural
gas purchaser pursuant to a settlement agreement (the "Settlement
Agreement"). As a result of the Settlement Agreement, the December 31,
1994 prepayment balance of $3.7 million paid by the purchaser for natural
gas not taken (the "Prepayment Balance") is subject to recoupment in
volumes of natural gas through a period ending on the earlier of recoupment
or December 31, 1997 (the "Recoupment Period"). Additionally, the purchaser
is obligated to make monthly payments on behalf of the Committed Interest
based on their share of the natural gas deliverability of the wells subject
to the Settlement Agreement, up to a maximum of $211,000 or a minimum of
$110,000 per month for the year 1995. Both the maximum and minimum monthly
payments decline annually through the Recoupment Period. If natural gas is
taken during a month, the value of such natural gas is credited toward the
monthly amount the purchaser is required to pay. In the event the
purchaser takes volumes of natural gas valued in excess of its monthly
payment obligations, the value taken in excess is applied to reduce any
then outstanding Prepayment Balance. The Company currently believes that
sufficient natural gas deliverability is available to enable the Committed
Interest to receive substantially all of the maximum monthly payments
during 1995. At the end of the Recoupment Period, the Settlement Agreement
and the natural gas purchase contracts which are subject to the Settlement
Agreement will terminate. If the Prepayment Balance is not fully recouped
in natural gas by December 31, 1997 then the unrecouped portion is subject
to cash repayment, limited to a maximum of $3 million, payable in equal
annual installments over a five year period. Under the Settlement
Agreement, the purchaser is entitled to make a monthly determination of the
volumes to be purchased from the wells subject to the Settlement Agreement.
During 1993, the Company, in accordance with the terms of the Settlement
Agreement, elected to deliver natural gas at approximately 80 percent of
the deliverability of the wells subject to the Settlement Agreement.
During 1994 natural gas delivered was again reduced to approximately 75
percent of the deliverability of the wells subject to the Settlement
Agreement. However, because these month-to-month determinations, up to
certain maximum levels, are made by the purchaser, the Company is unable to
predict with certainty future natural gas sales from these wells. In
addition, future revenues to be received by the Company would be impacted
by the failure of the purchaser to meet its obligations, financially or
otherwise, under the terms of the Settlement Agreement or by the ability of
the wells to maintain certain projected deliverability requirements. In
the event the wells are unable to maintain such deliverability, the monthly
19
payments to be received by the Company under the Settlement Agreement would
be decreased. The price per Mcf under the Settlement Agreement is
substantially higher than current spot market prices. The impact of the
higher price received under the Settlement Agreement increased pre-tax
income by approximately $1.8, $1.9 and $2.8 million in 1994, 1993 and 1992,
respectively.
Oil prices received by the Company in 1994 ranged from an average of
$12.53 in February to $17.78 in July and averaged $15.73 in December. The
Company's average price for oil received in 1994 was $15.13. Average
natural gas prices received by the Company have gradually declined since
the first quarter of 1994, and December's average price of $1.52 per Mcf
was 32 percent less than the average natural gas price of $2.24 received by
the Company in March 1994. Oil prices received early in the first quarter
of 1995 were 3 percent higher than average prices received by the Company
at December 31, 1994 while spot prices for natural gas dropped 17 percent
from the December 31, 1994 price. Oil prices within the industry remain
largely dependent upon world market developments for crude oil. Prices for
natural gas are influenced by weather conditions and supply imbalances,
particularly in the domestic market, and by world wide oil price levels.
The large drop in spot market natural gas prices had a significant adverse
effect on the value of the Company's reserves at year end 1994 and could
cause the Company to reduce the carrying value of its oil and natural gas
properties in 1995 (see Note 12 of Notes to Consolidated Financial
Statements). Likewise, declines in natural gas or oil prices could
adversely effect the semi-annual borrowing base determination under the
Company's current credit agreement since this determination is, for the
most part, calculated on the value of the Company's oil and natural gas
reserves.
The Company's ability to utilize its full complement of drilling rigs,
should economic conditions improve in the future, will be restricted due to
the lack of qualified labor and certain supporting equipment not only
within the Company but in the industry as a whole. The Company's ability
to utilize its drilling rigs at any given time is dependent on a number of
factors, including but not limited to, the price of both oil and natural
gas, the availability of labor and the Company's ability to supply the type
of equipment required. The Company's management expects that these factors
will continue to influence the Company's rig utilization during 1995.
In the third quarter of 1994, the Company's Board of Directors
authorized the Company to purchase up to 1,000,000 shares of the Company's
outstanding common stock on the open market. At December 31, 1994 25,100
shares had been repurchased at prices ranging from $2 5/8 to $3 3/8 per
share.
The Company's wholly owned natural gas marketing subsidiary, Mountain
Front Pipeline Company, while achieving substantial growth in revenues in
recent years, has not achieved the size necessary to reach desired levels
of profitability. Consequently, the Company is currently negotiating to
effect a business combination between Mountain Front Pipeline Company's
marketing operations and a third party. The combination, if completed,
would leave the Company with a minority interest in the resulting larger
20
entity. Such a combination would not adversely affect the operations of
the Company's drilling and oil and natural gas exploration segments or the
profitability of the Company as a whole, although it would result in a
significant reduction in the Company's total revenues and associated costs.
Effects of Inflation
The effects of inflation on the Company's current operations have been
minimal due to low inflation rates. However, the impact of inflation on
the Company in the future will depend on the relative increase, if any, the
Company may realize in its rig rates and the selling price of its oil and
natural gas. If industry activity increases substantially, shortages in
support equipment such as drill pipe, third party services and qualified
labor would occur resulting in corresponding increases in material and
labor costs. These market conditions may limit the Company's ability to
realize improvements in operating profits.
Results of Operations
1994 versus 1993
- ----------------
Net income for 1994 was $4,794,000, compared with $3,871,000 in 1993.
The increase in net income was achieved through improved operating results
in the Company's contract drilling and natural gas marketing operations and
also from a net gain of $742,000 recognized in conjunction with the sale of
one of the Company's gas gathering systems. Total revenues were
$87,958,000 in 1994 and $70,941,000 in 1993.
Oil and natural gas revenues increased 8 percent due to a 29 percent
increase in natural gas production and a 2 percent increase in oil
production between 1994 and 1993. Average natural gas and oil prices
received by the Company both decreased 10 percent and partially offset the
increases in production. Average natural gas prices received by the
Company declined due to a 14 percent reduction in average spot market
prices received by the Company coupled with a 14 percent reduction in
volumes produced from certain wells included under a settlement agreement
which contains provisions for prices which are higher than current spot
market prices. Approximately 92 percent of the Company's natural gas
production was sold under spot market prices in 1994 as compared with 88
percent in 1993.
In 1994, revenues from contract drilling operations increased by 16
percent as average rig utilization increased from 8 rigs in 1993 to 9.5
rigs in 1994. Daywork revenues represented 58 percent of total drilling
revenues in 1994 as opposed to 47 percent in 1993. Turnkey and footage
contracts typically provide for higher revenues since a greater portion of
the expense of drilling the well is born by the drilling contractor.
In July 1994, the Company moved one of its rigs under a multi-well
contract to the South Texas Basin creating a new operating region for the
Company to market its drilling services. In November, the Company moved a
21
second rig under contract into the region and a third rig was moved under
contract in February 1995.
The Company's marketing and natural gas processing revenues increased
38 percent as the marketing operation moved 53 percent higher volumes in
1994 while experiencing a 15 percent decrease in prices.
Operating margins (revenues less operating costs) were either slightly
improved or unchanged for all segments on the Company's operations when
comparing 1994 with 1993. Operating margins for the Company's oil and
natural gas operations were unchanged due primarily to increased production
offset by the decrease in average prices received for natural gas. Total
operating costs from oil and natural gas operations increased 9 percent as
the Company increased production from reserves added primarily through
development drilling in 1993 and 1994.
Operating margins for contract drilling improved from 10 percent in
1993 to 12 percent in 1994. Increased rig utilization helped provide
greater revenue in relation to fixed costs. Total operating costs for
contract drilling were up 12 percent in 1994 versus 1993 due to the
increased utilization.
Natural gas marketing and processing operating margins improved from a
negative 1 percent in 1993 to a positive 1 percent in 1994. Increased
volumes marketed in 1994 helped to improve the Company's ability to cover
its fixed overhead. Total natural gas marketing and processing expense
increased 36 percent due to increased volumes marketed between the
comparative periods.
Contract drilling depreciation increased 19 percent in response to
increased rig utilization. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 18 percent as the
Company increased its equivalent barrels of production by 22 percent. The
Company's average DD&A rate per equivalent barrel dropped from $4.13 in
1993 to $4.08 in 1994.
General and administrative expense increased 8 percent as certain
employee and reporting costs increased between the comparative years. This
increase is expected to continue in 1995 as the Company continues to expand
its area of operation. Interest expense increased 25 percent as the
average interest rate on the Company's outstanding bank debt increased from
6 percent in 1993 to 7.15 percent in 1994. Outstanding bank debt was $12.4
million higher at December 31, 1994 when compared with December 31, 1993
due to the financing of the December 15, 1994 Patrick acquisition
previously discussed.
1993 versus 1992
- ----------------
Net income for 1993 was $3,871,000, compared with $1,087,000 in 1992.
The increase in 1993 resulted primarily from improved operating results
associated with the contract drilling segment. Additionally net income for
22
1992 was negatively impacted by a $1.5 million provision for certain
litigation.
Total revenues were $70,941,000 in 1993 and $55,827,000 in 1992. Oil
and natural gas revenues increased 3 percent due to a 10 percent increase
in natural gas production and a 6 percent increase in oil production
between 1993 and 1992. Average natural gas and oil prices received by the
Company decreased 4 and 14 percent, respectively, and partially offset the
increases in production. Although spot market natural gas prices
increased, the Company's natural gas price was negatively impacted by a 26
percent reduction in volumes produced from certain wells included under a
settlement agreement which contains provisions for prices which are higher
than current spot market prices. Approximately 88 percent of the Company's
natural gas production was sold under spot market prices in 1993 as
compared with 83 percent in 1992.
Higher spot market natural gas prices had a positive effect on the
Company's contract drilling operations. Revenues from contract drilling
operations increased 51 percent as utilization went from 21 percent in 1992
to 31 percent in 1993. Rising spot market natural gas prices encouraged
domestic operators to increase their focus on drilling new wells as opposed
to acquiring producing properties as in previous years. To a lesser
extent, the increase in drilling revenues resulted from higher rates per
day for daywork drilling and a greater portion of the Company's contract
drilling being performed under turnkey and footage contracts. Turnkey and
footage contracts typically provide for higher revenues since a greater
portion of the expense of drilling the well is born by the drilling
contractor. Daywork revenues represented 47 percent of total drilling
revenues in 1993 as opposed to 51 percent in 1992.
The Company's marketing and natural gas processing revenues increased
46 percent as the marketing operations began moving higher volumes in 1993
after experiencing reduced volumes in 1992 which were associated with the
change in focus of its marketing activity toward an end user market. The
Company had previously marketed its natural gas primarily to broker and
commodity markets.
Increased revenues were complemented by improved operating margins
(revenues less operating costs) in 1993 versus 1992 from both contract
drilling and natural gas marketing and processing. Operating margins for
the Company's oil and natural gas operations declined from 68 percent to 66
percent due primarily to the decrease in average prices received for oil
and natural gas. Total operating costs from oil and natural gas operations
increased 7 percent as the Company increased production from reserves added
primarily through developmental drilling in 1993 and from producing
property acquisitions in 1992.
Operating margins for contract drilling showed significant improvement
as they moved from a negative 2 percent in 1992 to a positive 10 percent in
1993. This increase was a result of a reduction in fixed overhead expense
made by the Company during the last six months of 1992, reduced worker's
compensation expense and increased rig utilization and dayrates which
provided greater revenue to cover fixed costs. Total operating costs for
23
contract drilling were up 34 percent in 1993 versus 1992 due to the
increased utilization.
Natural gas marketing and processing operating margins improved from a
negative 3 percent in 1992 to a negative 1 percent in 1993. Increased
volumes marketed in 1993 helped to improve the Company's ability to cover
its fixed overhead. Total natural gas marketing and processing expense
increased 43 percent due to the increased volumes marketed between the
comparative periods.
Contract drilling depreciation increased 33 percent in response to
increased rig utilization and a $160,000 write down in value of components
previously utilized on one of the Company's rigs which was retired at
December 31, 1993. Depreciation, depletion and amortization ("DD&A") of
oil and natural gas properties decreased 2 percent as the Company's average
DD&A rate per equivalent barrel dropped from $4.67 per equivalent barrel in
1992 to $4.13 per equivalent barrel in 1993. The effect of the decreased
rate was partially offset by increased production volumes between the
comparative periods.
General and administrative expense increased 6 percent, primarily due
to increased payroll, employee benefits and office related expenses.
Interest expense decreased 19 percent as interest rates remained stable and
the Company's average debt outstanding for the year of 1993 remained below
the average debt outstanding in 1992.
24
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
ASSETS 1994 1993
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 2,749 $ 3,756
Short-term investments - 41
Accounts receivable (less allowance for
doubtful accounts of $289 and $411) 16,369 14,099
Materials and supplies 1,498 1,424
Prepaid expenses and other 1,222 736
--------- ---------
Total current assets 21,838 20,056
--------- ---------
Property and Equipment:
Drilling equipment 75,746 75,528
Oil and natural gas properties, on the full
cost method 157,393 132,704
Transportation equipment 3,341 2,851
Other 7,925 8,541
--------- ---------
244,405 219,624
Less accumulated depreciation, depletion,
amortization and impairment 153,862 144,099
--------- ---------
Net property and equipment 90,543 75,525
--------- ---------
Other Assets 40 181
--------- ---------
Total Assets $112,421 $ 95,762
========= =========
The accompanying notes are an integral part of the
consolidated financial statements
25
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY 1994 1993
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term debt $ 496 $ 481
Current portion of natural gas
purchaser prepayments (Note 4) 1,580 1,170
Accounts payable 14,593 14,008
Accrued liabilities 3,014 1,983
Contract advances 158 10
---------- ----------
Total current liabilities 19,841 17,652
---------- ----------
Natural Gas Purchaser Prepayments (Note 4) 2,149 4,417
---------- ----------
Long-Term Debt 37,824 25,919
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value, 5,000,000
shares authorized, none issued - -
Common stock, $.20 par value, 40,000,000
shares authorized, 20,910,190 and
20,861,505 shares issued, respectively 4,182 4,172
Capital in excess of par value 50,086 49,977
Accumulated deficit (1,581) (6,375)
Treasury stock, at cost (25,100 shares) (80) -
---------- ----------
Total shareholders' equity 52,607 47,774
---------- ----------
Total Liabilities and Shareholders' Equity $ 112,421 $ 95,762
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
26
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
1994 1993 1992
-------- -------- --------
(In thousands except per share amounts)
Revenues:
Contract drilling $16,952 $14,676 $ 9,732
Oil and natural gas 26,001 24,073 23,464
Natural gas marketing
and processing 44,171 32,104 21,970
Other 834 88 661
-------- -------- --------
Total revenues 87,958 70,941 55,827
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 14,909 13,269 9,901
Depreciation and impairment 2,030 1,713 1,284
Oil and natural gas:
Operating costs 8,799 8,098 7,538
Depreciation, depletion
and amortization 8,281 7,018 7,128
Natural gas marketing
and processing 43,897 32,325 22,627
General and administrative 3,574 3,302 3,114
Interest 1,654 1,324 1,633
Provision for litigation - - 1,500
-------- -------- --------
Total expenses 83,144 67,049 54,725
-------- -------- --------
Income Before Income Taxes 4,814 3,892 1,102
Income Tax Expense 20 21 15
-------- -------- --------
Net Income $ 4,794 $ 3,871 $ 1,087
======== ======== ========
Net Income Per Common Share $ .23 $ .19 $ .05
======== ======== ========
Weighted Average Shares Outstanding 20,900 20,860 20,781
(Both Primary and Fully Diluted) ======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
27
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1992, 1993 and 1994
Capital
In Excess Treasury
Common Of Par Accumulated
Stock Value Deficit Stock Total
-------- -------- --------- -------- --------
(In thousands)
Balances,
January 1, 1992 $ 4,143 $49,733 $(11,333) $ - $42,543
Net income - - 1,087 - 1,087
Activity in employee
compensation plans
(67,755 shares) 14 108 - - 122
-------- -------- --------- -------- --------
Balances,
December 31, 1992 4,157 49,841 (10,246) - 43,752
Net income - - 3,871 - 3,871
Activity in employee
compensation plans
(78,706 shares) 15 136 - - 151
-------- -------- --------- -------- --------
Balances,
December 31, 1993 4,172 49,977 (6,375) - 47,774
Net income - - 4,794 - 4,794
Activity in employee
compensation plans
(48,685 shares) 10 109 - - 119
Purchase of treasury
stock (25,100
shares) - - - (80) (80)
-------- -------- --------- -------- --------
Balances,
December 31, 1994 $ 4,182 $50,086 $ (1,581) $ (80) $52,607
======== ======== ========= ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
28
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1994 1993 1992
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities:
Net income $ 4,794 $ 3,871 $ 1,087
Adjustments to reconcile net income
to net cash provided by
operating activities:
Depreciation, depletion,
amortization and impairment 10,774 9,256 8,772
Gain on disposition of assets (813) (49) (463)
Employee stock compensation plans 119 151 122
Bad debt expense - - 200
Provision for litigation - - 1,500
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (939) (1,257) 2,493
Materials and supplies (74) (99) 121
Prepaid expenses and other (486) 83 191
Accounts payable 735 634 (747)
Accrued liabilities 760 (947) (151)
Contract advances 148 8 (876)
Natural gas purchaser prepayments (1,858) (1,743) (2,319)
-------- -------- --------
Net cash provided
by operating activities 13,160 9,908 9,930
-------- -------- --------
The accompanying notes are an integral part of the
consolidated financial statements
29
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
1994 1993 1992
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions) $(28,227) $(11,946) $(10,768)
Proceeds from disposition of assets 2,038 709 1,146
Decrease in short-term investments 41 664 170
(Acquisition) disposition
of other assets 141 (45) 60
--------- --------- ---------
Net cash used in
investing activities (26,007) (10,618) (9,392)
Cash Flows From Financing Activities:
Borrowings under line of credit 63,700 43,400 23,900
Payments under line of credit (51,300) (40,600) (24,700)
Proceeds from notes payable
and other long-term debt - 911 710
Payments on notes payable and
other long-term debt (480) (367) (80)
Acquisition of treasury stock (80) - -
--------- --------- ---------
Net cash provided by
(used in) financing
activities 11,840 3,344 (170)
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents (1,007) 2,634 368
Cash and Cash Equivalents,
Beginning of Year 3,756 1,122 754
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 2,749 $ 3,756 $ 1,122
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 1,548 $ 1,326 $ 1,673
Income taxes $ 2 $ 2 $ 63
The accompanying notes are an integral part of the
consolidated financial statements
30
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Principles of Consolidation
The consolidated financial statements include the accounts of Unit
Corporation and its directly and indirectly wholly owned subsidiaries (the
"Company"). The Company's investment in limited partnerships is accounted
for on the proportionate consolidation method, whereby its share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Drilling Contracts
The Company accounts for "footage" and "turnkey" drilling contracts,
in which the Company assumes the risks associated with drilling the well,
under the completed-contract method and for "daywork" drilling contracts
under the percentage-of-completion method. The entire amount of the loss,
if any, is recorded when the loss is determinable.
The costs of uncompleted drilling contracts include expenses incurred
to date on "footage" or "turnkey" drilling contracts which are still in
process.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and
all investments with original maturities at date of purchase of three
months or less which are readily convertible into known amounts of cash.
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated
useful lives, including a minimum provision of 20 percent of the active
rate when the equipment is idle. At December 31, 1993, one of the
Company's rigs was retired and certain components of the rig were written
down by $160,000 to their estimated market value. The Company uses the
composite method of depreciation for drill pipe and collars and calculates
the depreciation by footage actually drilled compared to total estimated
remaining footage. Depreciation of other property and equipment is comput-
ed using the straight-line method over the estimated useful lives of the
assets ranging from 3 to 15 years.
When property and equipment components are disposed of, the cost and
the related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For dispo-
31
sitions of drill pipe and drill collars, an average cost for the
appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and
development activities on the full cost method of accounting prescribed by
the Securities and Exchange Commission ("SEC"). Accordingly, all produc-
tive and non-productive costs incurred in connection with the acquisition,
exploration and development of oil and natural gas reserves are capitalized
and amortized on a composite units-of-production method based on proved oil
and natural gas reserves. The Company's determination of its oil and
natural gas reserves are reviewed annually by independent petroleum
engineers. The average composite rates used for depreciation, depletion and
amortization ("DD&A") were $4.08, $4.13 and $4.67 per equivalent barrel in
1994, 1993 and 1992, respectively. The Company's calculation of DD&A
includes estimated future expenditures to be incurred in developing proved
reserves and estimated dismantlement and abandonment costs, net of
estimated salvage values. In the event the unamortized cost of oil and
natural gas properties being amortized exceeds the full cost ceiling, as
defined by the SEC, the excess is charged to expense in the period during
which such excess occurs.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties
in which the Company has an interest or on properties in which a part-
nership, of which the Company is a general partner, has an interest.
Accordingly, in 1994 the Company recorded $14,000 of contract drilling
profits as a reduction of the carrying value of its oil and natural gas
properties rather than including these profits in current operations. No
contract drilling profits were realized on such interests in 1993 and 1992.
Limited Partnerships
The Company, through its wholly owned subsidiary, Unit Petroleum
Company, is a general partner in eleven oil and natural gas limited part-
nerships sold privately and publicly. Certain of the Company's officers
and directors own interests in some of these partnerships. Their interests
were acquired generally on the same basis as other outside investors.
Prior to December 31, 1993, the Company also was general partner of seven
additional employee limited partnerships. However, pursuant to the terms
of an agreement and plan of merger, these seven limited partnerships were
consolidated into one new employee limited partnership effective December
31, 1993.
The Company shares in partnership revenues and costs in accordance
with formulas prescribed in each limited partnership agreement. The
32
partnerships also reimburse the Company for certain administrative costs
incurred on behalf of the partnerships.
Income Taxes
Income taxes are accounted for in accordance with Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes". SFAS No. 109 requires the measurement of deferred tax assets for
deductible temporary differences and operating loss carryforwards, and of
deferred tax liabilities for taxable temporary differences. Measurement of
current and deferred tax liabilities and assets is based on provisions of
enacted tax law; the effects of future changes in tax laws or rates are not
included in the measurement. Deferred tax assets primarily result from net
operating loss carryforwards, and deferred tax liabilities result from the
recognition of depreciation, depletion and amortization in different
periods for financial reporting and tax purposes. Valuation allowances are
established where necessary to reduce deferred tax assets to the amount
expected to be realized. Income tax expense is the tax payable for the
year and the change during that year in deferred tax assets and
liabilities.
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales.
This method allows for recognition of revenue which may be more or less
than the Company's share of pro-rata production from certain wells. Based
upon the Company's 1994 average spot market natural gas price of $1.65 per
Mcf, the Company estimates its balancing position to be approximately $5.5
million on under-produced properties and approximately $3.1 million on
over-produced properties.
The Company's policy is to expense its pro-rata share of lease oper-
ating costs from all wells as incurred. Such expenses relating to the
Company's balancing position on wells on which the Company has imbalances
are not material.
Financial Instruments and Concentrations of Credit Risk
At December 31, 1994, the Company had natural gas price swaps, related
to its marketing of natural gas, which qualify as hedges of the Company's
future purchase and sales commitments. Gains or losses on these swaps are
recognized in the consolidated statement of operations and included in
operating cash flows in the same period as the associated sale of natural
gas occurs. At December 31, 1994, the Company had price swap agreements
for 380,000 Mcf totaling $525,000 related to purchase commitments and
358,000 Mcf totaling $694,000 related to sales commitments for the period
of January through March of 1995.
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
credit risk is considered by management to be limited due to the large
33
number of customers comprising the Company's customer base. The Company
had one customer in its natural gas marketing operation at December 31,
1993, with an accounts receivable balance of $4.1 million which was
subsequently paid in January 1994. In addition, at December 31, 1994 and
1993, the Company had a concentration of cash of $2.3 and $3.4 million,
respectively, with one bank.
RECLASSIFICATIONS
Certain reclassifications have been made in the 1992 and 1993
consolidated financial statements to conform them to classifications used
in 1994.
NOTE 2 - PRODUCING PROPERTY ACQUISITION
- ---------------------------------------
On December 15, 1994, Unit Petroleum Company, a wholly owned
subsidiary of Unit Corporation, acquired interests in approximately 700 oil
and natural gas wells located primarily in Oklahoma, Texas, New Mexico and
Louisiana. Financing for the transaction was provided under the Company's
bank credit agreement. The acquisition is summarized as follows:
Current assets net of current liabilities $ 976,000
Producing oil and natural gas properties 12,261,000
-----------
Net assets acquired $13,237,000
===========
Unaudited summary pro forma results of operations for the Company,
reflecting the above described acquisition as if it had occurred at the
beginning of the years ended December 31, 1994 and December 31, 1993, are
as follows, respectively; revenues, $94,373,000 and $79,807,000; net
income, $5,068,000 and $7,259,000; and net income per common share, $.24
and $.35. The pro forma results of operations are not necessarily
indicative of the actual results of operations that would have occurred had
the purchase actually been made at the beginning of the respective periods
nor of the results which may occur in the future.
NOTE 3 - WARRANTS
- -----------------
In 1987, the Company issued 2.873 million units, consisting of three
shares of the Company's common stock and one warrant, at a price of $10.375
per unit. Each warrant entitles the holder to purchase one share of the
Company's common stock at a price of $4.375 anytime prior to the warrant's
expiration on August 30, 1996. The warrants, subject to certain
restrictions, are callable by the Company, in whole or in part, at $.50 per
warrant. As of December 31, 1994 no warrants have been exercised.
34
NOTE 4 - NATURAL GAS PURCHASER PREPAYMENTS
- -------------------------------------------
In March 1988, the Company entered into a settlement agreement with a
natural gas purchaser. During early 1991, the Company and the natural gas
purchaser superseded the original agreement with a new settlement agreement
effective retroactively to January 1, 1991. Under these settlement
agreements, the Company has a prepayment balance of $3.7 million at
December 31, 1994 representing proceeds received from the purchaser as
prepayment for natural gas. This amount is net of natural gas recouped and
net of certain amounts disbursed to other owners (such owners, collectively
with the Company are referred to as the "Committed Interest") for their
proportionate share of the prepayments. The December 31, 1994 prepayment
balance is subject to recoupment in volumes of natural gas for a period
ending the earlier of recoupment or December 31, 1997 (the "Recoupment
Period"). Additionally, the purchaser is obligated to make monthly
payments on behalf of the Committed Interest in an amount calculated as a
percentage of the Committed Interest's share of the deliverability of the
wells subject to the settlement agreement, up to a maximum of $211,000 or a
minimum of $110,000 per month for the year 1995. Both the maximum and
minimum monthly payments decline annually through the Recoupment Period.
At December 31, 1997, the Committed Interest's prepayment balance, if any,
that has not been fully recouped in natural gas is subject to a cash
repayment limited to a maximum of $3 million to be made in equal payments
over a five year period. The prepayment amounts subject to recoupment from
future production by the purchaser are being recorded as liabilities and
are reflected in revenues as recoupment occurs. The portion of the prepay-
ments that are estimated to be recouped in the next twelve months has been
included in current liabilities. At the end of the Recoupment Period, the
terms of the settlement agreement and the natural gas purchase contracts
which are subject to the settlement agreement will terminate.
NOTE 5 - LONG-TERM DEBT
- ------------------------
Long-term debt consisted of the following as of December 31, 1994 and
1993:
1994 1993
--------- ---------
Revolving credit and term loan, (In thousands)
with interest at December 31,
1994 and 1993 of 8.5%
and 6%, respectively $ 37,300 $ 24,900
Other 1,020 1,500
--------- ---------
38,320 26,400
Less current portion 496 481
--------- ---------
Total long-term debt $ 37,824 $ 25,919
========= =========
35
At December 31, 1994, the Company's credit agreement ("Agreement")
provided for a total loan commitment of $50 million consisting of a revolv-
ing credit facility through January 1, 1997 and a term loan thereafter,
maturing on January 1, 2001. Borrowings under the Agreement are limited to
a semi-annual borrowing base computation which as of December 31, 1994 is
$42 million.
The principal of the revolving credit facility is due in 48 equal
monthly payments commencing February 1, 1997 and continuing on the first
day of each month thereafter through maturity. The outstanding principal
amount of the revolving credit facility which is less than or equal to the
loan value of the mineral interest then in effect shall bear interest at
the Chase Manhattan Bank, N.A. prime rate ("Prime Rate") and that portion
of the outstanding balance exceeding such loan value shall bear interest at
the Prime Rate plus 1 and 1/2 percent through January 1, 1997. Subsequent to
January 1, 1997 and continuing through January 1, 2001, the portion of the
outstanding amount under the Agreement which is less than or equal to the
loan value of the mineral interests then in effect shall bear interest at
the Prime Rate plus 1/4 of 1 percent and any portion of the outstanding
principal balance exceeding such loan value shall bear interest equal to
the Prime Rate plus 1 and 1/2 percent. The Agreement also provides for a
commitment fee of 1/2 of 1 percent of the unused portion of the borrowing
base. Virtually all of the Company's drilling rigs are collateral for such
indebtedness and the balance of the Company's assets are subject to a
negative pledge.
The Agreement includes prohibitions against (i) the payment of divi-
dends (other than stock dividends) during any fiscal year in excess of 25
percent of the consolidated net income of the Company during the preceding
fiscal year, (ii) the incurrence by the Company or any of its subsidiaries
of additional debt with certain very limited exceptions and (iii) the
creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any property of the Company or any of its
subsidiaries, except in favor of its banks. The Agreement also requires
that the Company maintain consolidated net worth of at least $45 million, a
modified current ratio of not less than 1 to 1, a ratio of long-term debt,
as defined in the Agreement, to consolidated tangible net worth not greater
than 1 to 1 and a ratio of total liabilities, as defined in the Agreement,
to consolidated tangible net worth not greater than 1.25 to 1. In
addition, working capital provided by operations, as defined in the
Agreement, cannot be less than $13 million in any year.
Estimated annual principal payments under the terms of all long-term
debt from 1995 through 1999 are $496,000, $200,000, $200,000, $8,671,000
and $9,325,000.
36
NOTE 6 - INCOME TAXES
- ---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income, to the Company's effective income
tax expense is as follows:
1994 1993 1992
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 1,637 $ 1,323 $ 375
Tax benefit of net operating
loss carryforward (1,652) (1,308) (396)
Alternative minimum tax - - 2
State income tax 6 1 7
Other 29 5 27
-------- -------- --------
Income tax expense $ 20 $ 21 $ 15
======== ======== ========
Deferred tax assets and liabilities are comprised of the following at
December 31, 1994 and 1993:
1994 1993
-------- --------
Deferred tax assets: (In thousands)
Allowance for losses $ 521 $ 580
Gas purchaser prepayments - 149
Net operating loss carryforwards 18,190 18,118
Statutory depletion carryforward 2,500 2,500
Investment tax credit carryforward 3,530 3,530
-------- --------
Gross deferred tax assets 24,741 24,877
-------- --------
Deferred tax liabilities:
Depreciation, depletion and amortization 18,318 16,659
-------- --------
Gross deferred tax liabilities 18,318 16,659
-------- --------
Net deferred tax asset 6,423 8,218
Valuation allowance 6,423 8,218
-------- --------
$ - $ -
======== ========
The net deferred tax asset valuation allowance reflects that the tax
carryforwards above may not be utilized before the expiration dates as
itemized below due in part to the effects of anticipated future exploratory
and development drilling costs.
At December 31, 1994, the Company has net operating loss carryforwards
for regular tax purposes of approximately $47,868,000 and net operating
loss carryforwards for alternative minimum tax purposes of approximately
37
$38,260,000 which expire in various amounts from 1999 to 2007. The Company
has investment tax credit carryforwards of approximately $3,530,000 which
expire from 1995 to 2000. In addition, a statutory depletion carryforward
of approximately $6,579,000 is available to reduce future taxable income,
subject to statutory limitations. Statutory depletion may be carried
forward indefinitely.
In 1987, the Company completed an equity offering which constituted an
ownership change as that term is used in the Internal Revenue Code. As a
result of the ownership change, the amount of taxable income in future
years which may be offset by the Company's net operating loss carryovers
prior to the ownership change is limited. Tax losses of $45,950,000 at
December 31, 1994 are not subject to these limitations. The remaining tax
net operating loss carryforward will become available for utilization by
the Company at a rate of $3,500,000 per year. Similar limitations apply to
investment tax credits.
NOTE 7 - BENEFIT AND COMPENSATION PLANS
- ---------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common
stock were authorized for issuance under the Plan. Under the terms of the
Plan, bonuses may be granted to employees in either cash or stock or a
combination thereof, and are payable in a lump sum or in annual in-
stallments subject to certain restrictions. The Company issued 38,354 and
50,788 shares under the Plan in 1993 and 1992, respectively. No shares
were issued under the Plan in 1994.
The Company has a Stock Option Plan which provides for the granting of
options for up to 1,000,000 shares of common stock to officers and
employees. The plan permits the issuance of qualified or nonqualified
stock options. Stock options granted in 1986 became exercisable at the
rate of 20 percent per year through 1990. Options granted subsequent to
1986 become exercisable at the rate of 20 percent per year one year after
being granted.
38
Activity pertaining to the Stock Option Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES -----------------------------
--------- PER SHARE AGGREGATE
Outstanding at -----------------------------
January 1, 1992 752,000 $1.50 to 3.375 $1,476,995
Granted 10,000 1.875 18,750
Cancelled (10,000) 2.37 to 2.875 (26,225)
--------- -------------- ----------
Outstanding at
December 31, 1992 752,000 1.50 to 3.375 1,469,520
Granted 89,000 2.75 244,750
Exercised (12,000) 1.50 to 2.37 (19,740)
--------- -------------- -----------
Outstanding at
December 31, 1993 829,000 1.50 to 3.375 1,694,530
Granted 102,500 3.00 307,500
Exercised (16,000) 1.50 to 2.37 (24,870)
--------- -------------- -----------
Outstanding at
December 31, 1994 915,500 $1.50 to 3.375 $ 1,977,160
========= ============== ===========
Options for 676,400, 610,500 and 556,400 shares were exercisable at
prices ranging from $1.50 to $3.375 at December 31, 1994, 1993 and 1992,
respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued or delivered upon exercise of the
stock options. On the first business day following each annual meeting of
stockholders of the Company, each person who is then a member of the Board
of Directors of the Company and who is not then an employee of the Company
or any of its subsidiaries will be granted an option to purchase 2,500
shares of common stock. The option price for each stock option is the fair
market value of the common stock on the date the stock options are granted.
No stock options may be exercised during the first six months of its term
except in case of death and no stock options are exercisable after ten
years from the date of grant.
39
Activity pertaining to the Directors' Plan is as follows:
NUMBER
OF OPTION PRICE
SHARES --------------------------
------- PER SHARE AGGREGATE
1992: -------------- ---------
Granted 10,000 $ 1.75 $ 17,500
------- -------------- ---------
Outstanding at
December 31, 1992 10,000 1.75 17,500
Granted 10,000 3.75 37,500
------- -------------- ---------
Outstanding at
December 31, 1993 20,000 1.75 to 3.75 55,000
Granted 10,000 2.875 28,750
------- -------------- ---------
Outstanding at
December 31, 1994 30,000(1) $1.75 to 3.75 $ 83,750
======= ============== =========
- -------------
(1) All 30,000 options were exercisable at December 31, 1994.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in
full or on a partial basis. The Company made discretionary contributions
under the plan of 32,685, 28,352 and 16,967 shares of common stock and
recognized expense of $130,000, $162,000 and $33,000 in 1994, 1993 and
1992, respectively.
Effective March 1, 1993, the Company adopted a salary deferral plan
("Deferral Plan"). The Deferral Plan allows participants to defer the
recognition of salary for income tax purposes until actual distribution of
benefits which occurs at either termination of employment, death or certain
defined unforeseeable emergency hardships. Funds set aside in a trust to
satisfy the Company's obligation under the Deferral Plan at December 31,
1994 and 1993 totaled $108,000 and $41,000, respectively. The Company
recognizes payroll expense and records a deferred liability at the time of
deferral.
NOTE 8 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through
1994, with a subsidiary of the Company serving as General Partner. The
Partnerships were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as co-general
partner with the Company in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with the Company in most drilling operations and most producing property
40
acquisitions commenced by the Company for its own account during the period
from the formation of the Partnership through December 31 of each year.
Pursuant to the terms of an agreement and plan of merger, seven limited
partnerships, in which the Company was general partner, were consolidated
into one new employee limited partnership effective December 31, 1993.
Amounts received in the following years ended December 31 from both
public and private Partnerships for which the Company is a general partner
are as follows:
1994 1993 1992
-------- -------- --------
(In thousands)
Contract drilling $ 53 $ 60 $ 38
Well supervision and other fees $ 226 $ 278 $ 277
General and administrative
expense reimbursement $ 209 $ 231 $ 294
A subsidiary of the Company paid the Partnerships, for which the
Company or a subsidiary is the general partner, $38,000, $65,000 and
$58,000 during the years ended December 31, 1994, 1993 and 1992,
respectively, for purchases of natural gas production.
During 1993 and 1992, the Company received legal services from a law
firm of which one of the Company's directors was a partner. Total payments
to the law firm during 1993 and 1992 were $164,000 and $130,000,
respectively. The Company did not receive such services from the law firm
in 1994.
During 1994, a bank owned by one of the Company's Directors became a
participant in the Company's loan agreement. The bank's total pro rata
share of the Company's line of credit is not to exceed $1.5 million.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
- --------------------------------------
The Company is currently negotiating a new operating lease agreement
to remain in its current office space until February 1, 2000. Future
minimum rental payments under the proposed terms of the lease would be
approximately $205,000, $224,000, $244,000, $246,000 and $246,000 in 1995,
1996, 1997, 1998 and 1999, respectively. Total rent expense incurred by
the Company was $210,000, $208,000 and $205,000 in 1994, 1993 and 1992,
respectively.
The Company had letters of credit totaling $835,600 outstanding at
December 31, 1994.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership agreements along with the employee oil and gas
limited partnerships require, upon the election of a limited partner, that
the Company repurchase the limited partner's interest at amounts to be
determined by appraisal in the future. Such repurchases in any one year
are limited to 20 percent of the units outstanding. The Company made
41
repurchases of $38,000, $56,000 and $70,000 in 1994, 1993 and 1992,
respectively, for such limited partner's interest.
The Company is a party to a settlement agreement dated January 31,
1991 with a natural gas purchaser which superseded a settlement agreement
entered into during March of 1988. Under the agreements the purchaser made
certain prepayments to the Company for natural gas to be delivered to the
purchaser in the future. As of December 31, 1994, this prepayment balance
for natural gas yet to be delivered was $3.7 million. The Company has
learned that the Oklahoma Tax Commission (the "Commission"), based on four
assessments, one in 1988, one in 1992 and two in 1994, is seeking to hold
the purchaser liable for certain taxes, interests and penalties that the
Commission contends are due and owing with respect to the prepayment
amounts made by the purchaser under the agreements on the grounds that the
prepayments are solely attributable to the settlement of past claims for
take-or-pay obligations. To date, the Company is not a party to the
Commission's proceedings, but may in the future, seek to intervene in these
proceedings. The purchaser has denied the claims made by the Commission
and is contesting the assessments. The purchaser and the Commission have
settled the 1988 assessment for approximately $51,000 and the remaining
three assessments have been consolidated and set for a hearing before an
administrative law judge on or before May 10, 1995. The purchaser has
notified the Company of the proceedings and has indicated its intention to
assert claims against the Company to recover the amount it paid in
settlement of the 1988 assessment (including its attorney fees) as well as
any amounts it might have to pay by virtue of the remaining assessments.
The Company is aware that the purchaser has made such claims against other
companies which also received prepayments from the purchaser, although the
type of agreements and the facts involved in those cases are not known by
the Company. At this time, the Company is unable to determine what the
outcome of the remaining Commission's proceedings will be, the amount of
taxes, if any, plus interest and penalties that may ultimately be assessed
against the purchaser and the claims, if any, that the purchaser might seek
to assert against the Company in the event an unfavorable result is
incurred by the purchaser. The Company has advised the purchaser that it
believes the responsibility for the payment of the taxes, interest and
penalty sought by the Commission, should it be ultimately determined that
any such amounts are in fact owed, is the responsibility of the purchaser
and not the Company.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
should result in judgements which would have a material adverse effect on
the Company.
42
NOTE 10 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
The Company operates in the United States in three industry segments
which are contract drilling, oil and natural gas exploration and production
and natural gas marketing and processing. The Company also has natural gas
production in Canada which is not significant. Selected financial
information by industry segment is as follows:
Depreciation,
Depletion,
Operating Amortization
Operating Profit Total Capital and Impairment
Revenues (Loss)(1) Assets(2) Expenditures Expense
---------- -------- --------- ---------- ----------
(In thousands)
Year ended December 31, 1994:
Drilling $ 16,952 $ 13 $ 14,771 $ 1,115 $ 2,030
Oil and natural gas 26,001 8,921 83,082 25,110 8,281
Natural gas marketing
and processing 44,171 274 10,619 56 331
---------- -------- --------- ---------- ----------
87,124 $ 9,208 108,472 26,281 10,642
Other 834 ======== 3,949 708 132
---------- --------- ---------- ----------
Total $ 87,958 $112,421 $ 26,989 $ 10,774
========== ========= ========== ==========
Year ended December 31, 1993:
Drilling $ 14,676 $ (306) $ 15,738 $ 936 $ 1,713
Oil and natural gas 24,073 8,957 64,845 11,422 7,018
Natural gas marketing
and processing 32,104 (221) 10,099 1,049 418
---------- -------- --------- ---------- ----------
70,853 $ 8,430 90,682 13,407 9,149
Other 88 ======== 5,080 323 107
---------- --------- ---------- ----------
Total $ 70,941 $ 95,762 $ 13,730 $ 9,256
========== ========= ========== ==========
Year ended December 31, 1992:
Drilling $ 9,732 $(1,453) $ 16,382 $ 266 $ 1,284
Oil and natural gas 23,464 8,798 61,694 7,951 7,128
Natural gas marketing
and processing 21,970 (657) 7,628 541 250
---------- -------- --------- ---------- ----------
55,166 $ 6,688 85,704 8,758 8,662
Other 661 ======== 3,006 137 110
---------- --------- ---------- ----------
Total $ 55,827 $ 88,710 $ 8,895 $ 8,772
========== ========= ========== ==========
- ---------------------
(1) Operating profit is total operating revenues, less operating expenses,
depreciation, depletion, amortization and impairment and does not include
non-operating revenues, general corporate expenses, interest expense,
income taxes or provision for litigation.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements and
furniture and equipment.
43
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1994 and 1993 is as
follows:
Three Months Ended
-------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- ----------- ----------
(In thousands except per share amounts)
Year ended December 31, 1994:
Revenues $ 23,005 $ 19,926 $ 21,166 (2) $ 23,861
========= ========= ========= =========
Gross Profit(1) $ 2,396 $ 2,726 $ 2,090 $ 1,996
========= ========= ========= =========
Income before
income taxes $ 1,215 $ 1,430 $ 1,595 (2) $ 574
========= ========= ========= =========
Net income $ 1,211 $ 1,425 $ 1,590 (2) $ 568
========= ========= ========= =========
Net income per
common share $ .06 $ .07 $ .07 (2) $ .03
========= ========= ========= =========
Year ended December 31, 1993:
Revenues $ 15,574 $ 17,881 $ 16,935 $ 20,551
========= ========= ========= =========
Gross Profit(1) $ 2,357 $ 1,982 $ 1,920 $ 2,171
========= ========= ========= =========
Income before
income taxes $ 1,163 $ 884 $ 890 $ 955
========= ========= ========= =========
Net income $ 1,156 $ 878 $ 886 $ 951
========= ========= ========= =========
Net income per
common share $ 0.06 $ 0.04 $ 0.04 $ 0.05
========= ========= ========= =========
- -------------
(1) Gross Profit excludes other revenues, general and administrative
expense and interest expense.
(2) Includes $742,000 net gain on sale of natural gas gathering system.
44
NOTE 12 - OIL AND NATURAL GAS INFORMATION (UNAUDITED)
- -----------------------------------------------------
The capitalized costs at year end and costs incurred during the year
were as follows:
USA Canada Total
--------- -------- --------
(In thousands)
1994:
Capitalized costs:
Proved properties $ 154,688 $ 455 $155,143
Unproved properties 2,250 - 2,250
--------- -------- --------
156,938 455 157,393
Less accumulated depreciation,
depletion, amortization
and impairment 81,583 368 81,951
--------- -------- --------
Net capitalized costs $ 75,355 $ 87 $ 75,422
========= ======== ========
Cost incurred:
Unproved properties $ 460 $ - $ 460
Producing properties 13,108 - 13,108
Exploration 1,825 - 1,825
Development 9,716 1 9,717
--------- -------- --------
Total costs incurred $ 25,109 $ 1 $ 25,110
========= ======== ========
1993:
Capitalized costs:
Proved properties $ 129,612 $ 454 $130,066
Unproved properties 2,638 - 2,638
--------- -------- --------
132,250 454 132,704
Less accumulated depreciation,
depletion, amortization
and impairment 73,419 314 73,733
--------- -------- --------
Net capitalized costs $ 58,831 $ 140 $ 58,971
========= ======== ========
Cost incurred:
Unproved properties $ 732 $ - $ 732
Producing properties 1,241 - 1,241
Exploration 1,359 - 1,359
Development 8,084 6 8,090
--------- -------- --------
Total costs incurred $ 11,416 $ 6 $ 11,422
========= ======== ========
45
USA Canada Total
--------- -------- --------
1992: (In thousands)
Capitalized costs:
Proved properties $ 117,721 $ 448 $ 118,169
Unproved properties 3,680 - 3,680
--------- -------- --------
121,401 448 121,849
Less accumulated depreciation,
depletion, amortization
and impairment 66,544 233 66,777
--------- -------- --------
Net capitalized costs $ 54,857 $ 215 $ 55,072
========= ======== ========
Cost incurred:
Unproved properties $ 504 $ - $ 504
Producing properties 3,629 - 3,629
Exploration 900 - 900
Development 2,918 - 2,918
--------- -------- --------
Total costs incurred $ 7,951 $ - $ 7,951
========= ======== ========
The results of operations before income taxes for producing activities
are provided below. Due to the Company's utilization of net operating loss
carryforwards, income taxes are not significant and have not been included.
USA Canada Total
--------- -------- --------
(In thousands)
1994:
Revenues $ 23,964 $ 67 $24,031
Production costs 7,011 19 7,030
Depreciation, depletion
and amortization 8,165 53 8,218
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing
costs) $ 8,788 $ (5) $ 8,783
======== ======== ========
46
USA Canada Total
--------- -------- --------
(In thousands)
1993:
Revenues $ 22,040 $ 67 $22,107
Production costs 6,439 15 6,454
Depreciation, depletion
and amortization 6,875 81 6,956
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing costs) $ 8,726 $ (29) $ 8,697
======== ======== ========
1992:
Revenues $21,816 $ 75 $21,891
Production costs 6,159 10 6,169
Depreciation, depletion
and amortization 6,961 94 7,055
--------- -------- --------
Results of operations for
producing activities
before income taxes
(excluding corporate
overhead and financing costs) $ 8,696 $ (29) $ 8,667
======== ======== ========
47
Estimated quantities of proved developed oil and natural gas reserves
and changes in net quantities of proved developed and undeveloped oil and
natural gas reserves were as follows:
USA Canada Total
----------------- ------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------ ----- ------- --------
1994: (In thousands)
Proved developed and
undeveloped reserves:
Beginning of year 3,304 71,379 - 861 3,304 72,240
Revision of previous
estimates (97) (571) - (14) (97) (585)
Extensions, discoveries
and other additions 601 17,426 - - 601 17,426
Purchases of minerals
in place 910 14,075 - - 910 14,075
Sales of minerals in place (4) (137) - - (4) (137)
Production (406) (9,606) - (53) (406) (9,659)
------- -------- ----- ----- ------- --------
End of Year 4,308 92,566 - 794 4,308 93,360
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year
End of year
1993:
Proved developed and
undeveloped reserves:
Beginning of year 3,308 63,761 - 931 3,308 64,692
Revision of previous
estimates (132) 4,662 - - (132) 4,662
Extensions, discoveries
and other additions 549 9,169 - - 549 9,169
Purchases of minerals
in place 18 1,369 - - 18 1,369
Sales of minerals in place (42) (147) - - (42) (147)
Production (397) (7,435) - (70) (397) (7,505)
------- -------- ----- ----- ------- --------
End of Year 3,304 71,379 - 861 3,304 72,240
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,245 58,809 - 468 3,245 59,277
End of year 3,187 65,395 - 426 3,187 65,821
48
USA Canada Total
----------------- ------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------ ------ ------- --------
1992:
Proved developed and
undeveloped reserves:
Beginning of year 2,943 52,853 - 964 2,943 53,817
Revision of previous
estimates 235 7,679 - 47 235 7,726
Extensions, discoveries
and other additions 190 1,655 - - 190 1,655
Purchases of minerals
in place 316 8,327 - - 316 8,327
Sales of minerals in place (1) (23) - - (1) (23)
Production (375) (6,730) - (80) (375) (6,810)
------- -------- ----- ----- ------- --------
End of Year 3,308 63,761 - 931 3,308 64,692
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 2,778 44,936 - 499 2,278 45,435
End of year 3,245 58,809 - 468 3,245 59,277
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made
in connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's
reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog-
ical and engineering data, appear with reasonable certainty to be recov-
erable in the future from known oil and natural gas reservoirs under exist-
ing economic and operating conditions. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods. Proved undeveloped reserves are
those reserves which are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expendi-
ture is required.
Estimates of oil and natural gas reserves require extensive judgments
of reservoir engineering data as explained above. Assigning monetary
values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. Indeed the uncertainties inherent in the
disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves. The information set forth herein is therefore
subjective and, since judgments are involved, may not be comparable to
estimates submitted by other oil and natural gas producers. In addition,
since prices and costs do not remain static and no price or cost escala-
tions or de-escalations have been considered, the results are not neces-
sarily indicative of the estimated fair market value of estimated proved
reserves nor of estimated future cash flows.
49
The standardized measure of discounted future net cash flows ("SMOG")
was calculated using year-end prices and costs, and year-end statutory tax
rates, adjusted for permanent differences, that relate to existing proved
oil and natural gas reserves. SMOG as of December 31 is as follows:
USA Canada Total
--------- -------- --------
1994: (In thousands)
Future cash flows $234,171 $ 1,255 $235,426
Future production and
development costs 105,876 311 106,187
Future income tax expenses 20,161 524 20,685
--------- -------- --------
Future net cash flows 108,134 420 108,554
10% annual discount for
estimated timing of cash flows 30,116 170 30,286
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 78,018 $ 250 $ 78,268
========= ======== =========
1993:
Future cash flows $214,800 $ 861 $215,661
Future production and
development costs 90,177 229 90,406
Future income tax expenses 17,097 244 17,341
--------- -------- --------
Future net cash flows 107,526 388 107,914
10% annual discount for
estimated timing of cash flows 34,374 157 34,531
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 73,152 $ 231 $ 73,383
======== ======== ========
1992
Future cash flows $208,964 $ 931 $209,895
Future production and
development costs 86,417 361 86,778
Future income tax expenses 19,634 194 19,828
--------- -------- --------
Future net cash flows 102,913 376 103,289
10% annual discount for
estimated timing of cash flows 32,653 120 32,773
--------- -------- --------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 70,260 $ 256 $ 70,516
======== ======== ========
50
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1994:
Sales and transfers of oil and
natural gas produced,
net of production costs $(16,953) $ (48) $(17,001)
Net changes in prices and
production costs (14,941) 206 (14,735)
Revisions in quantity estimates
and changes in production timing (482) (5) (487)
Extensions, discoveries and improved
recovery, less related costs 17,050 - 17,050
Purchases of minerals in place 13,426 - 13,426
Sales of minerals in place (138) - (138)
Accretion of discount 7,915 35 7,950
Net change in income taxes (457) (177) (634)
Other - net (554) 8 (546)
--------- -------- ---------
Net change 4,866 19 4,885
Beginning of year 73,152 231 73,383
--------- -------- ---------
End of year $ 78,018 $ 250 $ 78,268
========= ======== =========
1993:
Sales and transfers of oil and
natural gas produced,
net of production costs $(15,359) $ (52) $(15,411)
Net changes in prices and
production costs (4,997) 73 (4,924)
Revisions in quantity estimates
and changes in production timing 483 (70) 413
Extensions, discoveries and improved
recovery, less related costs 12,886 - 12,886
Purchases of minerals in place 1,440 - 1,440
Sales of minerals in place (284) - (284)
Accretion of discount 7,619 36 7,655
Net change in income taxes (74) (8) (82)
Other - net 1,178 (4) 1,174
--------- -------- --------
Net change 2,892 (25) 2,867
Beginning of year 70,260 256 70,516
--------- -------- --------
End of year $ 73,152 $ 231 $ 73,383
========= ======== =========
51
USA Canada Total
--------- -------- --------
(In Thousands)
1992:
Sales and transfers of oil
and natural gas produced,
net of production costs $(14,693) $ (65) $(14,758)
Net changes in prices and
production costs (1,081) (117) (1,198)
Revisions in quantity estimates
and changes in production timing 4,113 2 4,115
Extensions, discoveries and improved
recovery, less related costs 3,677 - 3,677
Purchases of minerals in place 9,488 - 9,488
Sales of minerals in place (47) - (47)
Accretion of discount 6,602 49 6,651
Net change in income taxes (2,870) 95 (2,775)
Other - net 2,104 5 2,109
--------- -------- ---------
Net change 7,293 (31) 7,262
Beginning of year 62,967 287 63,254
--------- -------- ---------
End of year $ 70,260 $ 256 $ 70,516
========= ======== =========
The Company's SMOG and changes therein were determined in accordance
with Statement of Financial Accounting Standards No. 69. Certain infor-
mation concerning the assumptions used in computing SMOG and their inherent
limitations are discussed below. Management believes such information is
essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those
reserves nor their present worth. Assigning monetary values to the reserve
quantity estimation process does not reduce the subjective and ever-changing
nature of such reserve estimates. Additional subjectivity occurs
when determining present values because the rate of producing the reserves
must be estimated. In addition to errors inherent in predicting the
future, variations from the expected production rate could result from
factors outside of management's control, such as unintentional delays in
development, environmental concerns or changes in prices or regulatory
controls. Also, the reserve valuation assumes that all reserves will be
disposed of by production. However, other factors such as the sale of
reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided
by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of
existing economic conditions.
52
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates to the future pretax net cash flows relating
to proved oil and natural gas reserves less the tax basis of the Company's
properties. The future income tax expenses also give effect to permanent
differences and tax credits and allowances relating to the Company's proved
oil and natural gas reserves.
Care should be exercised in the use and interpretation of the above
data. As production occurs over the next several years, the results shown
may be significantly different as changes in production performance,
petroleum prices and costs are likely to occur.
As disclosed in Note 4, the Company is receiving payments from a
natural gas purchaser which are subject to recoupment from future natural
gas production. The amounts received will be reflected in revenues and the
reserves and future net cash flows will be reduced as recoupment occurs.
Subsequent to December 31, 1994, the natural gas industry experienced
a significant downturn in natural gas prices. The Company's reserves were
determined at December 31, 1994 using a natural gas price of approximately
$1.70 per Mcf for natural gas not subject to long-term contracts. At
February 21, 1995, the natural gas prices received by the Company fell to
approximately $1.41 per Mcf for natural gas not subject to long-term
contracts. This decrease in natural gas prices would have had a
significant effect on the SMOG value of the Company's reserves at December
31, 1994 and would have resulted in a provision to reduce the carrying
value of oil and natural gas properties of approximately $3.5 million.
REPORT OF INDEPENDENT ACCOUNTANTS
53
The Shareholders and Board of Directors
Unit Corporation
We have audited the accompanying consolidated balance sheets of Unit
Corporation and subsidiaries as of December 31, 1994 and 1993 and the
related consolidated statements of operations, changes in shareholders'
equity and cash flows and the related financial statement schedule for each
of the three years in the period ended December 31, 1994. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Unit
Corporation and subsidiaries as of December 31, 1994 and 1993, and the con-
solidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation
to the basic financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
February 22, 1995
54
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure.
- --------------------
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
- ------------------------------------------------------------
The table below and accompanying footnotes set forth certain infor-
mation concerning each executive officer of the Company. Unless otherwise
indicated, each has served in the positions set forth for more than five
years. Executive officers are elected for a term of one year. There are
no family relationships between any of the persons named.
NAME AGE POSITION
- ---------------- --- ----------------------------------------
King P. Kirchner 67 Chairman of the Board, Chief Executive
Officer and Director
John G. Nikkel 60 President, Chief Operating Officer and
Director
Earle Lamborn 60 Senior Vice President, Drilling and
Director
Philip M. Keeley 53 Senior Vice President, Exploration and
Production
Larry D. Pinkston 40 Vice President, Treasurer and Chief
Financial Officer
Mark E. Schell 37 General Counsel and Secretary
________
Mr. Kirchner, a co-founder of the Company, has been the Chairman of
the Board and a director since 1963 and was President until November 1983.
Mr. Kirchner is a Registered Professional Engineer within the State of
Oklahoma, having received degrees in Mechanical Engineering from Oklahoma
State University and in Petroleum Engineering from the University of
Oklahoma.
Mr. Nikkel joined the Company in 1983 as its President and a director.
From 1976 until January 1982 when he co-founded Nike Exploration Company,
Mr. Nikkel was an officer and director of Cotton Petroleum Corporation,
serving as the President of that Company from 1979 until his departure.
Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production
Company for 18 years, last serving as Division Geologist for Amoco's Denver
Division. Mr. Nikkel presently serves as President and a director of Nike
55
Exploration Company. Mr. Nikkel received a Bachelor of Science degree in
Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 40
years, joining the Company's predecessor in 1952 prior to it becoming a
publicly-held corporation. He was elected Vice President, Drilling in 1973
and to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice
President, Exploration and Production. Prior to that time, Mr. Keeley co-
founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and
serves as Executive Vice President and a director of that company. From
1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation,
serving first as Manager of Land and from 1979 as Vice President and a
director. Before joining Cotton, Mr. Keeley was employed for four years by
Apexco, Inc. as Manager of Land and prior thereto he was employed by
Texaco, Inc. for nine years. He received a Bachelor of Arts degree in
Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as
Corporate Budget Director and Assistant Controller prior to being appointed
as Controller in February 1985. He has been Treasurer since December 1986
and was elected to the position of Vice President and Chief Financial
Officer in May 1989. He holds a Bachelor of Science Degree in Accounting
from East Central University of Oklahoma and is a Certified Public
Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and
General Counsel. From 1979 until joining the Company, Mr. Schell was
Counsel, Vice President and a member of the Board of Directors of C & S
Exploration, Inc. He received a Bachelor of Science degree in Political
Science from Arizona State University and his Juris Doctorate degree from
the University of Tulsa Law School.
The balance of the information required in this Item 10 is incorpo-
rated by reference to the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1995
annual meeting of stockholders.
Item 11. Executive Compensation
- ---------------------------------
Information required by this item is incorporated by reference to the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1995 annual meeting of
stockholders.
56
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
Information required by this item is incorporated by reference to the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1995 annual meeting of
stockholders.
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Information required by this item is incorporated by reference to the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1995 annual meeting of
stockholders.
57
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements:
---------------------
Included in Part II of this report:
Consolidated Balance Sheets as of December 31, 1994 and 1993
Consolidated Statements of Operations for the years ended December
31, 1994, 1993 and 1992
Consolidated Statements of Changes in Shareholders' Equity for the
years ended December 31, 1994, 1993 and 1992
Consolidated Statements of Cash Flows for the years ended December
31, 1994, 1993 and 1992
Notes to Consolidated Financial Statements
Report of Independent Accountants
2. Financial Statement Schedules:
------------------------------
Included in Part IV of this report for the years ended December 31,
1994, 1993 and 1992:
Schedule VIII - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under
which they are required or because the required information is included
in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers
assigned such exhibits in the Exhibit Table of Item 601 of Regulation
S-K.
3. Exhibits:
--------
2 Certificate of Ownership and Merger of the Company and Unit
Drilling Co., dated February 22, 1979 (filed as an Exhibit to
the Company's Registration Statement No. 2-63702, which is
incorporated herein by reference).
3.1.1 Certificate of Incorporation (filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated
July 21, 1988 (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December
31, 1989, which is incorporated herein by reference).
58
3.1.3 Restated Certificate of Incorporation of Unit Corporation
dated February 2, 1994 (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
3.2.1 By-Laws (filed as Exhibit 3.5 to the Company's Registration
Statement of Form S-4 as S.E.C. File No. 33-7848, which is
incorporated herein by reference).
3.2.2 Amended and Restated By-Laws, dated June 29, 1988 (filed as an
Exhibit to the Company's Annual Report under cover of Form 10-K for
the year ended December 31, 1989, which is incorporated
herein by reference).
4.2.1 Form of Warrant Agreement between the Company and the Warrant
Agent (filed as Exhibit 4.1 to the Company's Registration
statement on Form S-2 as S.E.C. File No. 33-16116, which is
incorporated herein by reference).
4.2.2 Form of Warrant (filed as Exhibit 4.3 to the Company's
Registration Statement of Form S-2 as S.E.C. File No. 33-16116, which
is incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.2 on Form
S-2 as S.E.C. File No. 33-16116, which is incorporated herein
by reference).
4.2.4 First Amendment to Warrant Agreement (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1992, which is incorporated herein
by reference).
4.2.5 Second Amendment to Warrant Agreement (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1994, which is incorporated herein
by reference).
10.1.14 Amended and Restated Credit Agreement dated as of January 17,
1992 by and between Unit Corporation and Bank of Oklahoma
N.A., F&M Bank and Trust Company, Fourth National Bank of
Tulsa and Western National Bank of Tulsa (filed as an Exhibit
to the Company's Annual Report under cover of Form 10-K for
the year ended December 31, 1991, which is incorporated herein
by reference).
10.1.16 First Amendment to Amended and Restated Credit Agreement dated
as of May 1, 1992, by and between Unit Corporation and Bank of
Oklahoma, N.A., F&M Bank and Trust Company, Fourth National
Bank of Tulsa, and Western National Bank of Tulsa (filed as an
Exhibit to the Company's Quarterly Report under cover of Form
10-Q for the quarter ended June 30, 1992, which is
incorporated herein by reference).
59
10.1.17 Second Amendment to Amended and Restated Credit Agreement,
dated March 3, 1993 and effective as of March 1, 1993, by and
between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank
and Trust Company, Fourth National Bank of Tulsa, and Western
National Bank of Tulsa (filed as an Exhibit to the Company's
Quarterly Report under cover of Form 10-Q for the quarter
ended March 31, 1993, which is incorporated herein by
reference).
10.1.18 Third Amendment to Amended and Restated Credit Agreement
effective as of March 31, 1994, by and between Unit
Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust
Company, Bank IV, Oklahoma, N.A. and American National Bank
and Trust Company of Shawnee (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the
quarter ended March 31, 1994, which is incorporated herein by
reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement
dated as of December 12, 1994, by and between Unit Corporation
and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank
IV, Oklahoma, N.A. and American National Bank and Trust
Company of Shawnee (filed as an Exhibit in Form 8-K dated
December 15, 1994, which is incorporated herein by reference).
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership
(filed as Exhibit I to Unit Drilling and Exploration Company's
Registration Statement on Form S-1 as S.E.C. File No. 2-66347,
which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership
(filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's
Registration Statement Form S-1 as S.E.C. File No. 2-92582,
which is incorporated herein by reference).
10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited
Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil
and Gas Program's Registration Statement of Form S-1 as S.E.C.
File No. 2-89678, which is incorporated herein by reference).
10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 3.1 to Unit 1985
Employee Oil and Gas Limited Partnership's Registration
Statement on Form S-1 as S.E.C. File No. 2-95068, which is
incorporated herein by reference).
10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 10.11 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
60
10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1990, which is incorporated herein by reference).
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1991, which is incorporated herein by reference).
10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as
Exhibit 10.16 to the Company's Registration Statement on Form
S-4 as S.E.C. File No. 33-7848, which is incorporated herein
by reference).
10.2.22* The Company's Stock Option Plan (filed on the Company's
Registration Statement of Form S-8 as S.E.C. File No. 33-44103,
which is incorporated herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan
(filed on Form S-8 as S.E.C. File No. 33-49724, which is
incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed on Form S-8 as
S.E.C. File No. 33-53542, which is incorporated herein by
reference).
61
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1993,
which is incorporated herein by reference).
10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to
the Company's Annual Report under cover of Form 10-K for the
year ended December 31, 1993, which is incorporated herein by
reference).
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed herewith).
10.3.4 Director and Officers Insurance and Company Reimbursement
Policy (filed as an Exhibit to the Company's Quarterly Report
under cover of Form 10-Q for the quarter ended March 31, 1993,
which is incorporated herein by reference).
10.5 Acquisition and Development Agreement, dated September 26,
1991, between Registrant and Municipal Energy Agency of
Nebraska (filed on Form 8-K dated September 30, 1991, which is
incorporated herein by reference).
10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco
Exploration, Inc. and Aleco Production Company (as "Seller")
and Unit Petroleum Company (a "Buyer") and Helmerich & Payne,
Inc. (a "Buyer") (filed on Form 8-K dated May 21, 1992, which
is incorporated herein by reference).
10.7 Asset Purchase Agreement, dated as of November 28, 1994,
between the Registrant and Patrick Petroleum Corp of Michigan
and American National Petroleum Company (filed as an Exhibit
in Form 8-K dated December 15, 1994, which is incorporated
herein by reference).
22.1 Subsidiaries of the Registrant (filed herewith).
24.1 Consent of Independent Accountants (filed herewith).
27 Financial Data Schedules (filed herewith).
* Indicates a management contract or compensatory plan identified
pursuant to the requirements of Item 14 of Form 10-K.
62
(b) Reports on Form 8-K:
On December 28, 1994 (as amended by Form 8-K/A filed February
24, 1995), the Company filed a report on Form 8-K under Item 2
and Item 5 reporting the purchase of certain oil and natural
gas wells located in Oklahoma, Texas, New Mexico and Louisiana
from Patrick Petroleum Corp of Michigan and American National
Petroleum Company and the amending of the Company's credit
agreement.
63
Schedule VIII
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance
Balance at charged to Deductions at
beginning costs & & net end of
Description of period expenses write-offs period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1994 $ 411 $ - $ 122 $ 289
======== ======== ======== ========
Year ended
December 31, 1993 $ 376 $ - $ (35) $ 411
======== ======== ======== ========
Year ended
December 31, 1992 $ 170 $ 200 $ (6) $ 376
======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance at Balance at
beginning end of
Description of period Additions Deductions period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1994 $ 8,218 $ - $ 1,795 $ 6,423
======== ======== ======== ========
Year ended
December 31, 1993 $ 12,245 $ - $ 4,027 $ 8,218
======== ======== ======== ========
Year ended
December 31, 1992 $ 12,905(1) $ - $ 660 $ 12,245
======== ======== ======== ========
___________
(1) Represents initial valuation allowance recorded at the date of
adoption of Statement of Financial Accounting Standard No. 109.
64
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 21, 1995 By: /s/ John G. Nikkel
-------------- ---------------------------
JOHN G. NIKKEL
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on the 21st day of March, 1995.
Name Title
/s/ King P. Kirchner
- ------------------------------- Chairman of the Board and Chief
KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel
- ------------------------------- President and Chief Operating
JOHN G. NIKKEL Officer, Director
/s/ Earle Lamborn
- ------------------------------- Senior Vice President, Drilling,
EARLE LAMBORN Director
/s/ Larry D. Pinkston
- ------------------------------- Vice President, Chief Financial
LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz
- ------------------------------- Controller
STANLEY W. BELITZ
/s/ Don Bodard
- ------------------------------- Director
DON BODARD
/s/ Don Cook
- ------------------------------- Director
DON COOK
/s/ William B. Morgan
- ------------------------------- Director
WILLIAM B. MORGAN
/s/ John S. Zink
- ------------------------------- Director
JOHN S. ZINK
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
65
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
------- ----------------------------------------------- -----
10.2.28 Unit 1995 Employee Oil and Gas Limited
Partnership Agreement of
Limited Partnership.
22.1 Subsidiaries of the Registrant.
24.1 Consent of Independent Accountants.
27 Financial Data Schedule
66