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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, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
++++++++++++++++++++++++++++++++
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange
Common Stock, par value on which registered
$.20 per share New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in PART III of this
Form 10-K or any amendment to this Form 10-K.
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 17, 1999 - $143,274,719
Number of Shares of Common Stock
Outstanding on March 17, 1999 - 26,653,341
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting
of Stockholders to be held May 5, 1999 are incorporated by reference in Part
III.
Exhibit Index - See Page 77
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . 18
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . 18
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . 19
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . . 21
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . 29
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . 67
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . . 67
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . 68
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . . 68
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . 69
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . 69
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1998
PART I
Item 1. Business and Item 2. Properties
- -----------------------------------------
GENERAL
The Company, through its wholly owned subsidiaries, is engaged in the
land contract drilling of oil and natural gas wells and the development,
acquisition and production of oil and natural gas properties. The
Company's primary exploration and production operations are conducted in
the Anadarko and Arkoma Basins, which cover portions of Oklahoma, Texas,
Kansas and Arkansas, with additional operations located in the South Texas
Basin. Additional producing properties are located in other states,
including, but not limited to, New Mexico, Louisiana, North Dakota,
Colorado, Wyoming, Montana, Alabama, Mississippi, Arkansas, Illinois and
Nebraska as well as in Canada. The Company's contract drilling operations
are primarily located in the Oklahoma and Texas areas of the Anadarko and
Arkoma Basins with additional operations in the Permian and South Texas
Basins.
The Company was originally incorporated in Oklahoma in 1963 as Unit
Drilling Company. In 1979 it became a publicly held Delaware corporation
and changed its name to Unit Drilling and Exploration Company ("UDE") to
more accurately reflect the importance of its oil and natural gas business.
In September 1986, pursuant to a merger and exchange offer, the Company
acquired all of the assets and assumed all of the liabilities of UDE and
six oil and gas limited partnerships for which UDE was the general partner,
in exchange for shares of the Company's common stock (the "Exchange
Offer").
The Company's principal executive offices are maintained at 1000
Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number
(918) 493-7700. The Company also has regional offices in Moore and
Woodward, Oklahoma and Booker and Houston, Texas. When used in this
report, the term "Company" refers to Unit Corporation and at times Unit
Corporation and/or one or more of its subsidiaries with respect to periods
from and after the Exchange Offer and to UDE with respect to periods prior
thereto.
OIL AND NATURAL GAS OPERATIONS
In 1979, the Company began to develop its exploration and production
operations to diversify its source of revenues which, up to that time, were
derived from its contract drilling. Today, the Company conducts the
development, production and sale of oil and natural gas together with the
acquisition of producing properties through its wholly owned subsidiary,
Unit Petroleum Company.
As of December 31, 1998, the Company had 3,245 Mbbls and 161,318 MMcf
of estimated proved oil and natural gas reserves, respectively. The
Company's producing oil and natural gas interests, undeveloped leaseholds
1
and related assets are located primarily in Oklahoma, Texas, Louisiana and
New Mexico and to a lesser extent in Arkansas, North Dakota, Colorado, Wyo-
ming, Montana, Alabama, Mississippi, Arkansas, Illinois, Nebraska and
Canada. As of December 31, 1998, the Company had an interest in a total of
2,499 wells in the United States and served as the operator of 524 wells.
The Company also had an interest in 64 wells located in Canada. The
majority of the Company's development and exploration prospects are
generated by its technical staff. When the Company is the operator of a
property, it generally employs its own drilling rigs and the Company's own
engineering staff supervises the drilling operation.
The Company intends to continue the growth in its oil and natural gas
operations utilizing funds generated from operations and its bank revolving
line of credit.
Well and Leasehold Data. The Company's oil and natural gas explora-
tion and development drilling activities and the number of wells in which
the Company had an interest, which were producing or capable of producing,
were as follows for the periods indicated:
Year Ended December 31,
-------------------------------------------------
1998 1997 1996
Wells drilled: Gross Net Gross Net Gross Net
- -------------- ------ ------ ------ ------ ------ ------
Exploratory:
Oil.............. - - - - - -
Natural gas...... - - - - - -
Dry.............. 1 .26 - - - -
------ ------ ------ ------ ------ ------
Total 1 .26 - - - -
====== ====== ====== ====== ====== ======
Development:
Oil.............. 4 .44 10 4.84 10 8.35
Natural gas...... 52 19.26 57 23.85 55 19.46
Dry.............. 21 10.62 15 9.27 7 4.26
------ ------ ------ ------ ------ ------
Total 77 30.32 82 37.96 72 32.07
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
- ------------------------------------------------------------
Oil - USA........ 726 196.64 684 197.67 717 197.71
Oil - Canada..... - - - - - -
Gas - USA........ 1,773 286.73 1,545 260.40 1,530 242.09
Gas - Canada..... 64 1.60 64 1.60 64 1.60
------ ------ ------ ------ ------ ------
Total 2,563 484.97 2,293 459.67 2,311 441.40
====== ====== ====== ====== ====== ======
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
------- ------- ------- -------
1998
----
USA 569,076 130,440 52,958 35,371
Canada 39,040 976 22,763 22,763
------- ------- ------- -------
Total 608,116 131,416 75,721 58,134
======= ======= ======= =======
1997
----
USA 432,824 118,926 37,844 26,116
Canada 39,040 976 18,970 18,970
------- ------- ------- -------
Total 471,864 119,902 56,814 45,086
======= ======= ======= =======
1996
----
USA 455,713 115,326 29,245 19,124
Canada 39,040 976 - -
------- ------- ------- -------
Total 494,753 116,302 29,245 19,124
======= ======= ======= =======
3
Price and Production Data. The Company's average sales price, oil and
natural gas production volumes and average production cost per equivalent
Mcf (1 barrel (Bbl) of oil = 6 thousand cubic feet (Mcf) of natural gas) of
production for the periods indicated were as follows:
Year Ended December 31,
----------------------------------
1998 1997 1996
-------- -------- --------
Average sales price per barrel
of oil produced:
USA $ 12.81 $ 19.19 $ 20.40
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 1.90 $ 2.43 $ 2.21
Canada $ 1.46 $ .93 $ 1.18
Oil production (Mbbls):
USA 443 493 579
Canada - - -
-------- -------- --------
Total 443 493 579
======== ======== ========
Natural gas production (MMcf):
USA 16,427 13,742 12,974
Canada 38 74 51
-------- -------- --------
Total 16,465 13,816 13,025
======== ======== ========
Average production expense per
equivalent Mcf:
USA $ .61 $ .64 $ 0.68
Canada $ .54 $ .33 $ 0.27
Reserves. The following table sets forth the estimated proved
developed and undeveloped oil and natural gas reserves of the Company at
the end of each of the years indicated:
Year Ended December 31,
---------------------------------
1998 1997 1996
------- ------- -------
Oil (Mbbls):
USA 3,245 4,131 5,204
Canada - - -
------- ------- -------
Total 3,245 4,131 5,204
======= ======= =======
Natural gas (MMcf):
USA 160,795 144,661 128,408
Canada 523 723 753
------- ------- -------
Total 161,318 145,384 129,161
======= ======= =======
4
Further information relating to oil and natural gas operations is
presented in Notes 1,5,12 and 14 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
LAND CONTRACT DRILLING OPERATIONS
Unit Drilling Company, a wholly owned subsidiary of the Company, is
engaged in the land drilling of oil and natural gas wells for a wide range
of customers. A land drilling rig consists, in part, of engines, drawworks
or hoists, derrick or mast, substructure, pumps to circulate the drilling
fluid, blowout preventers and drill pipe. An active maintenance and
replacement program during the life of a drilling rig permits upgrading of
components on an individual basis. Over the life of a typical rig, due to
the normal wear and tear of operating 24 hours a day, several of the major
components, such as engines, mud pumps and drill pipe, are replaced or
rebuilt on a periodic basis as required, while other components, such as
the substructure, mast and drawworks, can be utilized for extended periods
of time with proper maintenance. The Company also owns additional
equipment used in the operation of its rigs, including large air compres-
sors, trucks and other support equipment.
On November 20, 1997, the Company acquired Hickman Drilling Company,
an Oklahoma corporation pursuant to an Agreement and Plan of Merger ("the
Merger Agreement"), dated November 20, 1997 entered into by and between the
Company, the Company's wholly owned subsidiary Unit Drilling Company,
Hickman Drilling Company and all of the holders of the outstanding capital
stock of Hickman Drilling Company (the "Selling Stockholders"). Under the
terms of this acquisition, the Selling Stockholders received, in aggregate,
1,300,000 shares of Common Stock and promissory notes in the aggregate
principal amount of $5,000,000 payable in five equal annual installments
commencing January 2, 1999. The acquisition included nine land contract
drilling rigs with depth capacities ranging from 9,500 to 17,000 feet,
spare drilling equipment and approximately $2.1 million in working capital.
As part of the acquisition the Company retained Hickman Drilling Company's
Woodward, Oklahoma corporate office as a regional office for its contract
drilling operations. In December 1997, the Company also purchased a Mid-
Continent U-36A, 650 horsepower rig with a 13,000 feet depth capacity and
spare components from two additional rigs for a total consideration of
$1 million, of which $200,000 was paid at closing and the balance is to be
paid over a period ending no later than three years. The balance is to be
paid out monthly with the monthly amount to be calculated on the basis of a
predetermined daily rate multiplied by the number of days in such month
that the acquired rig is employed for the account of the seller, all as
more fully specified in the acquisition agreement. If the balance of the
purchase price has not been fully paid at the end of three years the
remaining amount is to be paid in cash to the seller.
5
With the acquisitions noted above, the Company's drilling rig fleet
expanded to 34 rigs with depth capacities ranging from 7,000 to 25,000
feet. At December 31, 1998, 29 of the Company's rigs were located in the
Anadarko and Arkoma Basins of Oklahoma and Texas while five of its larger
horsepower rigs were located in South Texas. In the Anadarko and Arkoma
Basins the Company's primary focus is on the utilization of its medium
depth rigs which have a depth range of 8,000 to 14,000 feet. These medium
depth rigs are suited to the contract drilling currently undertaken by
operators in these two basins.
At present, the Company does not have a shortage of drilling rig
related equipment. During 1996 and through 1997, the Company increased
its drill pipe acquisitions since certain grades of drill pipe were in high
demand, due to increased rig utilization. However, at any given time, the
Company's ability to utilize its full complement of drilling rigs is
dependent upon the availability of qualified labor, drilling supplies and
equipment as well as demand. Should industry conditions improve rapidly,
there is no assurance that sufficient supplies of drill pipe, other
drilling equipment and qualified labor will be readily available, not only
within the Company, but in the industry as a whole.
The following table sets forth, for each of the periods indicated,
certain data concerning the Company's contract drilling operations:
Year Ended December 31,
---------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Number of operational rigs owned
at end of period 34 34(1) 24 22 25
Average number of rigs utilized (2) 22.9 19.2 14.7 10.9 9.5
Number of wells drilled 198 167 130 111 95
Total footage drilled (feet in 1000's) 2,203 1,736 1,468 1,196 1,027
- -------------------
(1) Includes 10 rigs acquired in the fourth quarter of 1997.
(2) Utilization rates are based on a 365-day year. A rig is
considered utilized when it is operating or being moved,
assembled or dismantled under contract.
As of February 23, 1999, 22 of the Company's 34 drilling rigs were
operating under contract.
6
The following table sets forth, as of February 23, 1999, the type and
approximate depth capability of each of the Company's drilling rigs:
Approximate
Depth
Capability
Rig# Type (feet)
---- ---- ----------
1 U-15 Unit Rig 11,000
2 BDW 650 13,000
3 BDW 650 13,500
4 U-15 Unit Rig 11,000
5 U-15 Unit Rig 11,000
6 BDW 800 15,000
7 U-15 Unit Rig 11,000
8 Gardner Denver 800 15,000
9 BDW 800 16,000
10 BDW 450T 9,500
11 Gardner Denver 700 15,000
12 BDW 800-M1 15,000
14 Gardner Denver 700 15,000
15 Mid-Continent 914-C 20,000
16 U-15 Unit Rig 11,000
17 Brewster N-75A 15,000
18 BDW 650 12,000
19 Gardner Denver 500 12,000
20 Gardner Denver 700 15,000
21 Gardner Denver 700 15,000
22 BDW 800 15,000
23 Gardner Denver 700M 15,000
24 Gardner Denver 700M 15,000
25 Gardner Denver 700 15,000
29 Brewster N-75A 15,000
30 BDW 1350-M 20,000
31 SU-15 North Texas Machine 12,000
32 Brewster N-75 15,000
34 National 110-UE 20,000
35 Continental Emsco C-1-E 20,000
36 Gardner Denver 1500-E 25,000
37 Mid-Continent 914-EC 20,000
38 Mid-Continent 1220-E 25,000
39 U-36-A 13,000
During the previous decade, the Company's contract drilling services
encountered significant competition due to depressed levels of activity in
contract drilling. In the last 6 months of 1996 and throughout 1997 and
the first three quarters of 1998, the Company's drilling operation showed
significant improvements in rig utilization. However, in late 1998, the
Company and the industry as a whole experienced a significant reduction in
demand. The Company anticipates that competition within the industry will,
for the foreseeable future, continue to adversely affect the Company.
Drilling Contracts. Most of the Company's drilling contracts are
obtained through competitive bidding. Generally, the contracts are for a
single well with the terms and rates varying depending upon the nature and
duration of the work, the equipment and services supplied and other
7
matters. The contracts obligate the Company to pay certain operating
expenses, including wages of drilling personnel, maintenance expenses and
incidental rig supplies and equipment. Usually, the contracts are subject
to termination by the customer on short notice upon payment of a fee. The
Company generally indemnifies its customers against certain types of claims
by the Company's employees and claims arising from surface pollution caused
by spills of fuel, lubricants and other solvents within the control of the
Company. Such customers generally indemnify the Company against claims
arising from other surface and subsurface pollution other than claims
resulting from the Company's gross negligence.
The contracts may provide for compensation to the Company on a day
rate, footage or turnkey basis with additional compensation for special
risks and unusual conditions. Under daywork contracts, the Company
provides the drilling rig with the required personnel to the operator who
supervises the drilling of the contracted well. Compensation to the
Company is based on a negotiated rate per day as the rig is utilized.
Footage contracts usually require the Company to bear some of the drilling
costs in addition to providing the rig. The Company is compensated on a
rate per foot drilled basis upon completion of the well. Under turnkey
contracts, the Company contracts to drill a well to a specified depth and
provides most of the equipment and services required. The Company bears
the risk of drilling the well to the contract depth and is compensated when
the contract provisions have been satisfied.
Turnkey drilling operations, in particular, might result in losses if
the Company underestimates the costs of drilling a well or if unforeseen
events occur. To date, the Company has not experienced significant losses
in performing turnkey contracts. For 1998, turnkey revenue represented
approximately 15 percent of the Company's contract drilling revenues.
Because the proportion of turnkey drilling is currently dictated by market
conditions and the desires of customers using the Company's services, the
Company is unable to predict whether the portion of drilling conducted on a
turnkey basis will increase or decrease in the future.
Customers. During the fiscal year ended December 31, 1998, 10
contract drilling customers accounted for approximately 24 percent of the
Company's total revenues and approximately 5 percent of the Company's total
revenues were generated by drilling on oil and natural gas properties of
which the Company was the operator (including properties owned by limited
partnerships for which the Company acted as general partner). Such drill-
ing was pursuant to contracts containing terms and conditions comparable to
those contained in the Company's customary drilling contracts with non-
affiliated operators.
Further information relating to contract drilling operations is
presented in Notes 1, 2 and 12 of Notes to Consolidated Financial State-
ments set forth in Item 8 hereof.
8
VOLATILE NATURE OF THE COMPANY'S OIL AND NATURAL GAS MARKETS;
FLUCTUATIONS IN PRICES
The Company's revenue and profitability are substantially dependent
upon prevailing prices for natural gas and crude oil. Oil and natural gas
prices have historically been volatile and are expected by the Company to
continue to be volatile in the future. These prices vary based on factors
beyond the control of the Company, including the extent of domestic produc-
tion and importation of crude oil and natural gas, the proximity and
capacity of oil and natural gas pipelines, costs of gathering natural gas,
the marketing of competitive fuels, general fluctuations in the supply and
demand for oil and natural gas, the effect of federal and state regulation
of production, refining, transportation and sales, the use and allocation
of oil and natural gas and their substitute fuels and general national and
worldwide economic conditions. In addition, natural gas spot prices
received by the Company are influenced by weather conditions impacting the
continental United States.
The Company's oil and condensate production is sold at or near the
Company's wells under purchase contracts at prevailing prices in accordance
with arrangements which are customary in the oil industry. The Company's
natural gas production is sold to intrastate and interstate pipelines as
well as to independent marketing firms under contracts with original terms
ranging from one month to several years. Most of these contracts contain
provisions for readjustment of price, termination and other terms which are
customary in the industry.
The worldwide supply of oil has been largely dependent upon rates of
production of foreign reserves. Although the demand for oil has increased
in the United States, imports of foreign oil continue to increase. Future
domestic oil prices will depend largely upon the actions of foreign
producers with respect to rates of production and it is virtually
impossible to predict what actions those producers will take in the future.
Prices may also be affected by political, social and other factors relating
to the Middle East. In view of the many uncertainties affecting the supply
and demand for oil and natural gas, the Company is unable to predict future
oil and natural gas prices or the overall effect, if any, that a decline in
demand or oversupply of such products would have on the Company.
COMPETITION
All lines of business in which the Company engages are highly com-
petitive. Competition in land contract drilling traditionally involves
such factors as price, efficiency, condition of equipment, availability of
labor and equipment, reputation and customer relations. Some of the
Company's competitors in the land contract drilling business are sub-
stantially larger than the Company and have appreciably greater financial
and other resources. As a result of the decrease in demand for land
contract drilling services over the past decade, a surplus of certain types
of drilling rigs currently exists within the industry while inventories of
certain components such as specific grades of drill pipe have been depleted
from continued use. Accordingly, the competitive environment within which
the Company's drilling operations presently operates is uncertain and
extremely price oriented.
9
The Company's oil and natural gas operations likewise encounter strong
competition from major oil companies, independent operators, and others.
Many of these competitors have appreciably greater financial, technical and
other resources and are more experienced in the exploration for and
production of oil and natural gas than the Company.
OIL AND NATURAL GAS PROGRAMS
The Company currently serves as a general partner to 4 oil and gas
limited partnerships and 10 employee oil and gas limited partnerships. The
employee partnerships acquire an interest fixed annually, ranging from 5%
to 15% of the Company's interest, in most oil and natural gas drilling
activities and purchases of producing oil and natural gas properties
participated in by the Company. The limited partners in the employee
partnerships are either employees or directors of the Company or its sub-
sidiaries.
Under the terms of the partnership agreements of each limited part-
nership, the general partner, which in each case is Unit Petroleum Company,
has broad discretionary authority to manage the business and operations of
the partnership, including the authority to make decisions on such matters
as the partnership's participation in a drilling location or a property
acquisition, the partnership's expenditure of funds and the distribution of
funds to partners. Because the business activities of the limited partners
on the one hand, and the general partner on the other hand, are not the
same, conflicts of interest will exist and it is not possible to eliminate
entirely such conflicts. Additionally, conflicts of interest may arise
where the Company is the operator of an oil and natural gas well and also
provides contract drilling services. Although the Company has no formal
procedures for resolving such conflicts, the Company believes it fulfills
its responsibility to each contracting party and complies fully with the
terms of the agreements which regulate such conflicts.
EMPLOYEES
As of February 23, 1999, the Company had approximately 453 employees
in its land contract drilling operations, 47 employees in its oil and natu-
ral gas operations and 44 in its general corporate area. None of the
Company's employees are represented by a union or labor organization nor
have the Company's operations ever been interrupted by a strike or work
stoppage. The Company considers relations with its employees to be
satisfactory.
OPERATING AND OTHER RISKS
The Company's land contract drilling and oil and natural gas
operations are subject to a variety of oil field hazards such as fire,
explosion, blowouts, cratering and oil spills or certain other types of
possible surface and subsurface pollution, any of which can cause personal
injury and loss of life and severely damage or destroy equipment, suspend
drilling operations and cause substantial damage to surrounding areas or
property of others. As protection against some, but not all, of these
operating hazards, the Company maintains broad insurance coverage,
including all-risk physical damage, employer's liability and comprehensive
general liability. In all states in which the Company operates except
Oklahoma, the Company maintains a large deductible worker's compensation
10
policy that insures for losses exceeding $200,000. In Oklahoma, starting
in August 1991, the Company elected to become self insured. In
consideration therewith, the Company purchased an excess liability
reinsurance policy to insure losses exceeding $250,000. The Company
believes that to the extent reasonably practicable such insurance coverages
are adequate. The Company's insurance policies do not, however, provide
protection against revenue losses incurred by reason of business inter-
ruptions caused by the destruction or damage of major items of equipment
nor certain types of hazards such as specific types of environmental
pollution claims. In view of the difficulties which may be encountered in
renewing such insurance at reasonable rates, no assurance can be given that
the Company will be able to maintain the amount of insurance coverage which
it considers adequate at reasonable rates. Moreover, loss of or serious
damage to any of the Company's equipment, although adequately covered by
insurance, could have an adverse effect upon the Company's earning
capacity.
The Company's oil and natural gas operations are also subject to all
of the risks and hazards typically associated with the search for and
production of oil and natural gas. These include the necessity of ex-
pending large sums of money for the location and acquisition of properties
and for drilling exploratory wells. In such exploratory work, many
failures and losses may occur before any accumulation of oil or natural gas
may be found. If oil or natural gas is encountered, there is no assurance
that it will be capable of being produced or will be in quantities
sufficient to warrant development or that it can be satisfactorily mar-
keted. The Company's future natural gas and crude oil revenues and
production, and therefore cash flow and income, are highly dependent upon
the Company's level of success in acquiring or finding additional reserves.
Without continuing reserve additions through exploration or acquisitions,
the Company's reserves and production will decline.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which the Company
conducts activities impose restrictions on the drilling, production and
sale of oil and natural gas, which often include requirements relating to
well spacing, waste prevention, production limitations, pollution preven-
tion and clean-up, obtaining drilling permits and similar matters. The
following discussion summarizes, in part, the regulations of the United
States oil and natural gas industry and is not intended to constitute a
complete discussion of the many statutes, rules, regulations and
governmental orders to which the Company's operations may be subject.
The Company's activities are subject to existing federal and state
laws and regulations governing environmental quality and pollution control.
Various states and governmental agencies are considering, and some have
adopted, laws and regulations regarding environmental control which could
adversely affect the business of the Company. Such laws and regulations
may substantially increase the costs of doing business and may prevent or
delay the commencement or continuation of given operations. Compliance
with such legislation and regulations, together with any penalties
resulting from noncompliance therewith, will increase the cost of oil and
natural gas drilling, development, production and processing. In the
opinion of the Company's management, its operations to date comply in all
11
material respects with applicable environmental legislation and regula-
tions; however, in view of the many uncertainties with respect to the
current controls, including their duration, interpretation and possible
modification, the Company can not predict the overall effect of such
controls on its operations.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Wellhead Decontrol Act") became effective. Under the Wellhead Decontrol
Act, all remaining price and non-price controls of first sales under the
NGA and NGPA were removed effective January 1, 1993. Prices for deregulated
categories of natural gas fluctuate in response to market pressures which
currently favor purchasers and disfavor producers. As a result of the
deregulation of a greater proportion of the domestic United States natural
gas market and an increase in the availability of natural gas
transportation, a competitive trading market for natural gas has developed.
During the past several years, the Federal Energy Regulatory
Commission ("FERC") has adopted several regulations designed to accomplish
a more competitive, less regulated market for natural gas. These
regulations have materially affected the market for natural gas. The major
elements of several of these initiatives remain subject to appellate
review.
One of the initiatives FERC adopted was order 636. In brief, the
primary requirements of Order 636 are as follows: pipelines must separate
their sales and transportation services; pipelines must provide open access
transportation services that are equal in quality for all natural gas
suppliers and must provide access to storage on an open access contract
basis; pipelines that provide firm sales service on May 18, 1992 must offer
a "no-notice" firm transportation service under which firm shippers may
receive delivery of natural gas on demand up to their firm entitlement
without incurring daily balancing and scheduling penalties; pipelines must
provide all shippers with equal and timely access to information relevant
to the availability of their open access transportation services; open
access pipelines must allow firm transportation customers to downstream
pipelines to acquire capacity on upstream pipelines held by downstream
pipelines; pipelines must implement a capacity releasing program so that
firm shippers can release unwanted capacity to those desiring capacity
(which program replaces previous "capacity brokering" and "buy-sell"
programs); existing bundled firm sales entitlement are converted to
unbundled firm sales entitlement and to unbundled firm transportation
rights on the effective date of a particular pipeline's blanket sales
certificate; and pipeline transportation rights must be developed under the
Straight Fixed Variable (SFV) method of cost classification, allocation and
rate design unless the FERC permits the pipeline to use some other method.
The FERC will not permit a pipeline to change the new resulting rates until
the FERC accepts the pipeline's formal restructuring plans.
In essence, the goal of Order 636 is to make a pipeline's position as
natural gas merchant indistinguishable from that of a non-pipeline
supplier. It, therefore, pushes the point of sale of natural gas by
pipelines upstream, perhaps all the way to the wellhead. Order 636 also
requires pipelines to give firm transportation customers flexibility with
respect to receipt and delivery points (except that a firm shipper's choice
of delivery point cannot be downstream of the existing primary delivery
point) and to allow "no-notice" service (which means that natural gas is
12
available not only simultaneously but also without prior nomination, with
the only limitation being the customer's daily contract demand) if the
pipeline offered no-notice city-gate sales service on May 18, 1992. Thus,
this separation of pipelines' sales and transportation allows non-pipeline
sellers to acquire firm downstream transportation rights and thus to offer
buyers what is effectively a bundled city-gate sales service and it permits
each customer to assemble a package of services that serves its individual
requirements. But it also makes more difficult the coordination of natural
gas supply and transportation. A corollary to these changes is that all
pipelines will be permitted to sell natural gas at market-based rates.
The results of these changes may be the increased availability of firm
transportation and the reduction of interruptible transportation, with a
corresponding reduction in the rates for off-peak and interruptible
transportation. Due to the continuing evolutionary nature of Order 636 and
its implementation, it is not possible to project the overall potential
impact on transportation rates for natural gas or market prices of natural
gas.
The future interpretation and application by FERC of these rules and
its broad authority, or of the state and local regulations by the relevant
agencies, could affect the terms and availability of transportation
services for transportation of natural gas to customers and the prices at
which natural gas can be sold by the Company. For instance, as a result of
Order 636, more interstate pipeline companies have begun divesting their
gathering systems, either to unregulated affiliates or to third persons, a
practice which could result in separate, and higher, rates for gathering a
producer's natural gas. In proceedings during mid and late 1994 allowing
various interstate natural gas companies' spindowns or spinoffs of
gathering facilities, the FERC held that, except in limited circumstances
of abuse, it generally lacks jurisdiction over a pipeline's gathering
affiliates, which neither transport natural gas in interstate commerce nor
sell gas in interstate commerce for resale. However, pipelines spinning
down gathering systems have to include two Order No. 497 standards of
conduct in their tariffs: nondiscriminatory access to transportation for
all sources of supply and no tying of pipeline transportation service to
any service by the pipeline's gathering affiliate. In addition, if unable
to reach a mutually acceptable gathering contract with a present user of
the gathering facilities, the FERC required that the pipeline must offer a
two-year "default contract" to existing users of the gathering facilities.
However, on appeal, while the United States Court of Appeals for the
District of Columbia upheld the FERC's allowing the spinning down of
gathering facilities to a non-regulated affiliate, in Conoco Inc. v. FERC,
90 F.3d 536, 552-53 (D.C. Cir. 1996)the D.C. Circuit remanded the FERC's
default contract mechanism. On February 18, 1997, the United States
Supreme Court denied review of the D.C. Circuit's decision.
Additional proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by
the FERC and Congress will continue. Sales of petroleum liquids by the
Company are not currently regulated and are made at market prices; however,
the FERC is considering a proposal that could increase transportation rates
for petroleum liquids. A number of legislative proposals have also been
introduced in Congress and the state legislatures of various states, that,
13
if enacted, would significantly affect the petroleum industry. Such
proposals involve, among other things, the imposition of land and use
controls and certain measures designed to prevent petroleum companies from
acquiring assets in other energy areas. In addition, there is always the
possibility that if market conditions change dramatically in favor of oil
and natural gas producers that some new form of "windfall profits" or
severance tax may be proposed and imposed upon oil or natural gas. At the
present time it is impossible to predict which proposals, if any, will
actually be enacted by Congress or the various state legislatures. The
Company believes that it is complying with all orders and regulations
applicable to its operations. However, in view of the many uncertainties
with respect to the current controls, including their duration and possible
modification together with any new proposals that may be enacted, the
Company cannot predict the overall effect, if any, of such controls on
Company operations.
Certain states in which the Company operates control production from
wells through regulations establishing the spacing of wells, limiting the
number of days in a given month during which a well can produce and
otherwise controlling the rate of allowable production.
As noted above, the Company's operations are subject to numerous
federal and state laws and regulations regarding the control of
contamination of the environment. These laws and regulations may require
the acquisition of a permit before or after drilling commences, prohibit
drilling activities on certain lands lying within wilderness areas or where
pollution arises and impose substantial liabilities for pollution resulting
from drilling operations, particularly operations in offshore waters or on
submerged lands.
A past, present, or future release or threatened release of a
hazardous substance into the air, water, or ground by the Company or as a
result of disposal practices may subject the Company to liability under the
Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), the Resource Conservation Recovery Act ("RCRA"), the
Clean Water Act, and/or similar state laws, and any regulations promulgated
pursuant thereto. Under CERCLA and similar laws, the Company may be fully
liable for the cleanup costs of a release of hazardous substances even
though it contributed to only part of the release. While liability under
CERCLA and similar laws may be limited under certain circumstances, the
limits are so high that the maximum liability would likely have a
significant adverse effect on the Company. In certain circumstances, the
Company may have liability for releases of hazardous substances by previous
owners of Company properties. CERCLA currently excludes petroleum from its
definition of "hazardous substances." However, Congress may delete this
exclusion for petroleum, in which case the Company would be required to
manage its petroleum production and wastes from its exploration and
production activities as CERCLA hazardous substances. In addition, RCRA
classifies certain oil field wastes as "non-hazardous." Congress may
delete this exemption for oilfield waste, in which case the Company would
have to manage much of its oilfield waste as hazardous. Additionally, the
discharge or substantial threat of a discharge of oil by the Company into
United States waters or onto an adjoining shoreline may subject the Company
to liability under the Oil Pollution Act of 1990 and similar state laws.
While liability under the Oil Pollution Act of 1990 is limited under
certain circumstances, the maximum liability under those limits would still
likely have a significant adverse effect on the Company.
14
Violation of environmental legislation and regulations may result in
the imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the abatement of the conditions,
or suspension of the activities, giving rise to the violation. The Company
believes that the Company has complied with all orders and regulations
applicable to its operations. However, in view of many uncertainties with
respect to the current controls, including their duration and possible
modification, the Company cannot predict the overall effect of such
controls on such operations. Similarly, the Company cannot predict what
future environmental laws may be enacted or regulations may be promulgated
and what, if any, impact they would have on operations.
SAFE HARBOR STATEMENT OF FURTHER ACTIVITY
In the normal course of its business, the Company, in an effort to
help keep its shareholders and the public informed about the Company's
operations, may, from time to time, issue certain statements, either in
writing or orally, that contain or may contain forward looking information.
Generally, these statements relate to projections involving the anticipated
revenues to be received from the Company's oil and natural gas production
or drilling operations, the utilization rate of its drilling rigs, growth
of its oil and natural gas reserves, well performance, and the Company's
anticipated debt.
Statements in this Annual Report on Form 10-K under the captions
"Business" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations", as well as oral statements that may be made by
the Company or by officers, directors or employees of the Company acting on
the Company's behalf, that are not historical facts constitute "forward-
looking statements" within the meaning of the Private Securities Litigation
Reform Act of 1995. Words such as "believes", "anticipates" and similar
expressions, although not inclusive, identify forward-looking statements.
Such forward-looking statements are subject to a number of factors that may
tend to influence the accuracy of the statements and the projections upon
which the statements are based. As noted elsewhere in this report, all
phases of the Company's operations are subject to a number of influences
outside the control of the Company, any one of which, or a combination of
which, could materially affect the results of the Company's operations.
All future written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any forward looking statements made
by the Company, the following discussion outlines certain factors that in
the future could cause the Company's consolidated results for 1999 and
beyond to differ materially from those that may be set forth in any such
forward-looking statement made by or on behalf of the Company.
15
Commodity Prices
The prices received by the Company for its oil and natural gas
production have a direct impact on the Company's revenues, profitability
and cash flow as well as its ability to meet its projected financial and
operational goals. The prices for natural gas and crude oil are heavily
dependent on a number of factors beyond the control of the Company,
including, but not limited to, the demand for oil and/or natural gas;
current weather conditions in the continental United States which can
greatly influence the demand for natural gas at any given time as well as
the price to be received for such gas; and the ability of current
distribution systems in the United States to effectively meet the demand
for oil and or natural gas at any given time, particularly in times of peak
demand which may result due to adverse weather conditions. Oil prices are
extremely sensitive to foreign influences that may be based on political,
social or economic underpinnings, any one of which could have an immediate
and significant effect on the price and supply of oil. In addition, prices
of both natural gas and oil are becoming more and more influenced by
trading on the commodities markets which, at times, has tended to increase
the volatility associated with these prices resulting at times in large
difference in such prices even on a month to month basis. All these
factors, especially when coupled with the fact that much of the Company's
product prices are determined on a month to month basis, can, and at times
do, lead to wide fluctuations in the prices received by the Company.
Based upon the results of operations for the year ended December
31, 1998, the Company estimates that a change of $0.10/Mcf in the average
price of natural gas and a change of $1.00/Bbl in the price of crude oil
throughout such period would have resulted in approximate changes in net
income before income taxes of $1,541,000 and $414,000, respectively. During
1998, substantially all of the natural gas and crude oil volume of the
Company were sold at market responsive prices.
Customer Demand
Demand for the Company's drilling services is dependent almost entirely on
the needs of third parties. Based on past history, such parties' requirements
are subject to a number of factors, independent of any subjective factors, that
directly impact the demand for the Company's drilling rigs. These include the
funds available to such companies to carry out their drilling operations during
any given time period which, in turn, are often subject to downward revision
based on decreases in the then current prices of oil and natural gas. Many of
the Company's customers are small to mid-size oil and natural gas companies
whose drilling budgets tend to be susceptible to the influences of current price
fluctuations. Other factors that affect the Company's ability to work its
drilling rigs are the weather, which can, under adverse circumstances, delay or
even cause a project to be abandoned by an operator, the competition faced by
the Company in securing the award of a drilling contract in a given area, the
experience and recognition of the Company in a new market area, and the
availability of labor to run the Company's drilling rigs.
16
Uncertainty Of Oil And Natural Gas Reserves And Well Performance
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Estimating quantities of proved reserves is imprecise. Such estimates are
based upon certain assumptions pertaining to future production levels,
future natural gas and crude oil prices, timing and amount of development
expenditures and future operating costs, using currently available
geologic, engineering and economic data, some or all of which may prove to
be incorrect over time. As a result of changes in these assumptions that
will occur in the future, and based upon further production history,
results of future exploration and development activities, future natural
gas and crude oil prices and other factors, the reported quantity of
reserves may be subject to upward or downward revision.
In addition to the foregoing, projections regarding the potential
production and reserve capabilities of newly drilled and/ or completed
wells are subject to additional uncertainties that may significantly
influence such projections. Such wells have a very limited production
history, if any, on which to base future forecasts of their capabilities.
Since an established rate of production is a primary factor used by
reservoir engineers to forecast oil and natural gas reserves as well as a
well's production rate, the lack of this information decreases the
Company's ability to accurately project such information. In addition,
there are inherent risks in both the drilling and completion phases of a
new well which could cause a well bore to be prematurely abandoned due
either to the loss of the well bore in the physical sense or due to the
costs associated with operational problems which could render further
operations uneconomical.
Debt and Bank Borrowing
The amount of the Company's existing debt as well as its future debt
is, to a large extent, a function of the costs associated with the projects
undertaken by the Company at any given time and the cash flow received by
the Company. Generally, the costs incurred by the Company in its normal
operations are those associated with the drilling of oil and natural gas
wells, the acquisition of producing properties, and the costs associated
with the maintenance of its drilling rig fleet. To some extent, these
costs, particularly the first two items, are discretionary and the Company
maintains a degree of control regarding the timing and/ or the need to
incur the same. However, in some cases, unforseen circumstances may arise,
such as in the case of an unanticipated opportunity to acquire a large
producing property package or the need to replace a costly rig component
due to an unexpected loss, which could force the Company to incur increased
debt above that which it had expected or forecast. Likewise, for many of
the reasons mentioned above, the Company's cash flow may not be sufficient
to cover its current cash requirements which would then require the Company
to increase its debt either through bank borrowings or otherwise.
17
International Operations and Risks
Currently all of the Company's contract land drilling operations are
conducted within the continental United States. Should, however, the
Company at some point in the future undertake international drilling
operations, such operations would be subject to a number of risks including
foreign exchange restrictions, currency fluctuations, foreign taxation,
changing political conditions and foreign and domestic policies,
expropriation, nationalization, nullification, modification or
renegotiation of contracts, war and civil disturbances or other risks that
may limit or disrupt markets. In addition, the Company would incur certain
additional costs in establishing and running such operations.
Item 3. Legal Proceedings
- --------------------------
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
should result in judgments which would have a material adverse effect on
the Company.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted to the security holders during the fourth
quarter of the Company's calendar year ended December 31, 1998.
18
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 23, 1999, the Company had 2,543 holders of record of
its common stock the only form of stock issued as of that date. The
Company has not paid any cash dividends on shares of its common stock since
its organization and currently intends to continue its policy of retaining
earnings from the Company's operations. The Company is prohibited, by
certain loan agreement provisions, from declaring and paying dividends
(other than stock dividends) during any fiscal year in excess of 25 percent
of its consolidated net income of the preceding fiscal year, and only if
working capital provided from operations during said year is equal to or
greater than 175 percent of current maturities of long-term debt at the end
of such year. The table below reflects the high and low sales prices per
share of the Company's common stock as reported by the New York Stock
Exchange, Inc. for the period indicated:
1998 1997
-------------------- --------------------
QUARTER High Low High Low
------- --------- --------- --------- ---------
First $ 9 13/16 $ 6 7/16 $12 1/4 $ 7 1/2
Second $ 9 7/8 $ 5 1/2 $11 7/8 $ 7 7/8
Third $ 6 5/16 $ 3 3/4 $15 3/8 $ 9 5/8
Fourth $ 6 15/16 $ 3 5/8 $15 13/16 $ 8 7/16
19
Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
---------------------------------------------------
1998 1997 1996 1995 1994
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $93,337 $91,864 $72,070 $53,074 $43,895
======= ======= ======= ======= =======
Income From Continuing
Operations $ 2,246 $11,124 $ 8,333 $ 3,751 (1) $ 4,628 (2)
======= ======= ======= ======= =======
Net Income $ 2,246 $11,124 $ 8,333 $ 3,999 (1) $ 4,794 (2)
======= ======= ======= ======= =======
Basic Earnings Per
Common Share:
Continuing Operations $.09 $.46 $.37 $.18 (1) $.22 (2)
Discontinued Operation - - - .01 .01
---- ---- ---- ---- ----
Net Income $.09 $.46 $.37 $.19 (1) $.23 (2)
==== ==== ==== ==== ====
Diluted Earnings Per
Common Share:
Continuing Operations $.09 $.45 $.37 $.18 (1) $.22 (2)
Discontinued Operation - - - .01 .01 (2)
---- ---- ---- ---- ----
Net Income $.09 $.45 $.37 $.19 (1) $.23
==== ==== ==== ==== ====
Total Assets $223,064 $202,497 $137,993 $110,922 $103,933
======== ======== ======== ======== ========
Long-Term Debt $ 72,900 $ 54,100 $ 40,600 $ 41,100 $ 37,300
======== ======== ======== ======== ========
Other Long-Term
Liabilities $ 2,301 $ 2,279 $ 2,276 $ 2,109 $ 2,673
======== ======== ======== ======== ========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
======== ======== ======== ======== ========
___________
(1) Includes a $635,000 gain on compressor sale, a $850,000 gain from
settlement of litigation and a net $530,000 deferred tax benefit.
(2) Includes a $742,000 gain on sale of a natural gas gathering
system.
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1998, 1997 and 1996 activity.
20
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------------------------------------------------------------------------
Results of Operations
- ---------------------
Financial Condition and Liquidity
- ---------------------------------
The Company's loan agreement ("Loan Agreement"), provides for a total
facility of $100 million, consisting of a revolving credit facility through
May 1, 2002 and a term loan thereafter, maturing on May 1, 2005. Borrowings
under the revolving credit facility are limited to a borrowing value which
is subject to a semi-annual redetermination. As of the latest borrowing
value determination, $85 million of the commitment is available to the
Company. The Loan Agreement contains certain covenants which require the
Company to maintain consolidated tangible net worth of at least $75
million, a current ratio of not less than 1 to 1, a ratio of long-term
debt, as defined in the Loan Agreement, to consolidated tangible net worth
not greater than 1.2 to 1 and a ratio of total liabilities, as defined in
the Loan Agreement, to consolidated tangible net worth not greater than
1.65 to 1. In addition, working capital provided by operations, as defined
in the Loan Agreement, cannot be less than $18 million in any year. At
December 31, 1998, borrowings under the Loan Agreement totaled $68.9
million. At February 23, 1999, borrowings under the Loan Agreement totaled
$71.0 million with $11.4 million available for future borrowings. The
interest rate on the bank debt was 6.27 and 6.31 percent at December 31,
1998 and February 23, 1999, respectively. At the Company's election, any
portion of the debt outstanding may be fixed at the London Interbank
Offered Rate ("Libor Rate"), as adjusted per the Loan Agreement depending
on the level of debt as a percentage of the total borrowing base, for 30,
60, 90 or 180 days with the remainder of the outstanding debt subject to
the Chase Manhattan Bank, N. A. prime rate ("Chase Prime Rate"). During
any Libor Rate funding period, the Company may not pay in part or in whole
the outstanding principal balance of the note to which such Libor Rate
option applies. At both December 31, 1998 and February 23, 1999, $63.0
million of borrowings were subject to the Libor Rate as adjusted. A
commitment fee of 3/8 of 1 percent is charged for any unused portion of the
borrowing base.
Shareholders' equity at December 31, 1998 was $111.3 million, making
the Company's ratio of long-term debt-to-equity .66 to 1. The Company's
primary source of liquidity and capital resources in the near- and long-
term will consist of cash flow from operating activities and available
borrowings under the Loan Agreement. Net cash provided by operating
activities in 1998 was $33.5 million as compared to $34.4 million in 1997.
At December 31, 1998 and January 31, 1999, the Company had working capital
of $1.6 million and $1.0 million, respectively.
The Company's capital expenditures during 1998 were $50.1 million.
The Company's oil and natural gas operations had capital expenditures of
$38.4 million, with $24.9 million and $9.0 million used for exploration and
development drilling and producing property acquisitions, respectively.
Capital expenditures made by the Company's contract drilling operations
were $11.5 million in 1998. Drilling capital expenditures in 1998 were for
drill pipe and collars, the refurbishment of one drilling rig previously
stacked and major overhauls on large rig components of drilling rigs in
21
service. The Company's drilling rigs are composed of large components some
of which, on a rotational basis, are required to be overhauled to assure
continued proper performance. Such capital expenditures will continue in
future years with approximately $2.5 million projected for 1999.
During 1999, the Company's oil and natural gas exploration subsidiary
plans to continue its developmental drilling program. However, lower spot
market natural gas prices in the fourth quarter of 1998 have increased the
potential availability of economical producing property acquisitions and,
as a result, a larger portion of the Company's capital expenditure budget
may be shifted to producing property acquisitions in 1999. The majority of
the Company's capital expenditures are discretionary and primarily directed
toward increasing reserves and future growth. Current operations are not
dependent on the Company's ability to obtain funds outside of the Company's
Loan Agreement. The decision to acquire or drill on oil and natural gas
properties at any given time depends on market conditions, potential return
on investment, future drilling potential and the availability of
opportunities to obtain financing given the circumstances involved, thus
providing the Company with a large degree of flexibility in incurring such
costs. Depending, in part, on commodity pricing, the Company plans to
spend approximately $20 million on its exploration capital expenditure
program in 1999.
On November 20, 1997, the Company acquired Hickman Drilling Company,
pursuant to an Agreement and Plan of Merger ("the Merger Agreement"),
entered into by and between the Company, Hickman Drilling Company and all
of the holders of the outstanding capital stock of Hickman Drilling Company
(the "Selling Stockholders"). Under the terms of this acquisition, the
Selling Stockholders received, in aggregate, 1,300,000 shares of Common
Stock and promissory notes in the aggregate principal amount of $5,000,000
payable in five equal annual installments commencing January 2, 1999. The
acquisition included nine land contract drilling rigs with depth capacities
ranging from 9,500 to 17,000 feet, spare drilling equipment and
approximately $2.1 million in working capital. The notes bear interest at
the Chase Prime Rate which at both December 31, 1998 and February 23, 1999
was 7.75 percent. In December 1997, the Company also purchased a Mid-
Continent U-36-A, 650 horsepower rig with a 13,000 feet depth capacity and
spare components from two additional rigs for a total consideration of $1
million, of which $200,000 was paid at closing and the balance is being
paid out over a period ending no later than three years after the
acquisition date. The balance is paid out monthly with the monthly amount
calculated on the basis of a predetermined daily rate multiplied by the
number of days in such month that the acquired rig is employed for the
account of the seller, all as more fully specified in the acquisition
agreement. If the balance of the purchase price has not been fully paid at
the end of three years the remaining amount is to be paid in cash to the
seller. At December 31, 1998, the balance remaining under this purchase
agreement was $331,000.
In March of 1998, a Vice President of South America Drilling
Operations was hired to facilitate the Company's efforts to expand its
contract drilling operations outside the continental United States,
specifically into areas of South America. Drilling markets in South
America have the potential to provide higher profit margins and higher
profit contributions, with longer term multi-year contracts which could
also provide a leveling effect on drilling rig utilization. The Company
22
has not previously conducted international contract drilling operations,
but it anticipates that such operations would involve a number of
additional political, economic, currency, tax and other risks and costs not
generally encountered in its domestic operations. To date, the Company has
not entered into any contracts for international work.
Prior to December 31, 1997, the Company received monthly payments on
behalf of itself and other parties (collectively the "Committed Interest")
from a natural gas purchaser pursuant to a settlement agreement (the
"Settlement Agreement"). The monthly payments paid by the purchaser for
natural gas not taken (the "Prepayment Balance") were subject to recoupment
in volumes of natural gas through a period ending on the earlier of
recoupment or December 31, 1997 (the "Recoupment Period"). At December 31,
1997, the Settlement Agreement and the natural gas purchase contracts which
were subject to the Settlement Agreement terminated. As a result of the
Settlement Agreement, the December 31, 1997 Prepayment Balance of $2.2
million became payable in equal annual payments over a five year period.
The first payment of $441,000 was due and paid on June 1, 1998. The price
per Mcf under the Settlement Agreement was substantially higher than
current spot market prices. The impact of the higher price received under
the Settlement Agreement increased pre-tax income approximately $540,000
and $650,000 in 1997 and 1996, respectively. The natural gas previously
subject to the Settlement Agreement is now being sold at spot market prices
consistent with primarily all of the rest of the natural gas sold by the
Company.
Oil and natural gas prices received by the Company were volatile
throughout 1998. Average oil prices received by the Company in December
1998, as compared to January 1998, dropped by 35 percent. Average natural
gas prices in December 1998, as compared to January 1998, were one percent
higher after recovering from a 20 percent decrease in August and September
of 1998. The Company's average price received for oil during 1998 was
$12.81 and the average natural gas price was $1.90. Average oil prices and
natural gas spot prices received in February 1999 were up 5 percent for oil
and down 16 percent for natural gas, when compared with December 31, 1998
average prices. The large drop in natural gas prices in February 1999 had
a significant impact to the value of the Company's natural gas reserves as
reported at December 31, 1998. If this lower natural gas price had
occurred at year-end 1998, it would have caused the Company to reduce the
carrying value of its natural gas properties by approximately $22.0 million
before taxes. If prices do not recover from this February level and
depending on other variables, the Company will record a provision to reduce
the carrying value of oil and natural gas properties in the first quarter
of 1999. Oil prices within the industry remain largely dependent upon
world market developments for crude oil. Prices for natural gas are
influenced by weather conditions and supply imbalances, particularly in the
domestic market, and by world wide oil price levels. Declines in natural
gas or oil prices could also adversely effect the Company operationally by,
for example, adversely impacting future demand for its drilling rigs or
financially by reducing the price received for its oil and natural gas
sales and also by adversely effecting the semi-annual borrowing value
determination under the Company's Loan Agreement since this determination
is calculated on the value of the Company's oil and natural gas reserves.
23
At December 31, 1998, the Company did not have any hedge against the
fluctuation in the price of oil and natural gas nor did the Company
maintain any forward or future contracts relating to the production of its
oil and natural gas. In the first quarter of 1999, the Company initiated
swap transactions to help manage its exposure to commodity price risk in
the month to month sale of natural gas. These transactions cover
approximately 20 percent of the Company's daily production and cover the
period from March 1, 1999 to June 30, 1999. These activities have been
designated as hedging activities by the Company and will be accounted for
as such. Increases (decreases) in the fair value of these instruments will
generally offset increases (decreases) in the spot market prices of natural
gas. Implicit gains or losses, resulting from changes in the fair value of
hedges which have not yet been settled, are not recognized to the extent
that they relate to changes in the spot price of anticipated natural gas
sales. Gains or losses arising from hedge transactions are recorded in
sales in the month of the hedged transaction.
As a result of the depressed condition existing in the contract
drilling industry over much of the past decade, the Company's ability to
fully utilize its complement of drilling rigs during portions of 1997 and
1998 when there was a rapid increase in drilling activity was limited due
to the lack of qualified labor and certain support equipment not only
within the Company, but in the industry as a whole. The Company's ability
to utilize its drilling rigs at any given time is dependent on a number of
factors, including but not limited to, the price of both oil and natural
gas, the availability of labor and the Company's ability to supply the type
of equipment required. Although the Company currently does not have a
shortage of rig labor or support equipment, the Company's management
expects that these factors will continue to influence the Company's rig
utilization especially if demand should rapidly increase.
In the third quarter of 1994, the Company's Board of Directors
authorized the Company to purchase up to 1,000,000 shares of the Company's
outstanding common stock on the open market. Since that time, 160,100
shares have been repurchased at prices ranging from $2.50 to $9.69 per
share. During the first quarters of 1998, 1997 and 1996, 19,863, 23,892
and 44,686 of the purchased shares, respectively, were reissued as the
Company's matching contribution to its 401(k) Employee Thrift Plan. At
December 31, 1998, 25,000 treasury shares were held by the Company.
Year 2000 Statement
- -------------------
The Company has initiated a comprehensive assessment of its
information technology ("IT") and non-information technology ("non-IT")
systems to try and ensure that such systems will be Year 2000 compliant.
The Year 2000 problem exists because many existing computer programs use
only the last two digits to define the year. Therefore, these computer
programs do not recognize years that begin with a "20" and assume that all
years begin with a "19". If not corrected many computer applications could
fail or create erroneous results which could cause disruption of operations
not only for the Company but also for its customers and suppliers, so the
Company has also initiated an assessment of its customers' and suppliers'
efforts to become year 2000 compliant.
24
Evaluation of the Company's IT systems began in house during 1997.
The Company's IT systems consist mainly of office computers, related
computer programs and mangement financial information software. The
Company believes nearly all of the Company's hardware is Year 2000
compliant and approximately 20 percent of its related computer programs and
software are Year 2000 compliant. The Company has expended approximately
$92,000 and estimates it will expend an additional $40,000 to bring the
remaining systems compliant by the end of the second quarter of 1999.
The Company's non-IT systems consist of office equipment and other
systems associated with its oil and natural gas properties and its drilling
rigs. The Company began assessing these non-IT systems and the associated
cost during the fourth quarter of 1998. The assessment and replacement of
equipment, if any, should be completed by the end of the second quarter of
1999. The Company anticipates that the cost associated with non-IT systems
will be minimal.
During the third quarter of 1998, the Company issued questionnaires to
its key suppliers and customers to assess their preparation for Year 2000
compliance. The Company received responses from 41 percent of these
entities. Approximately 90 percent of the responses indicated that these
entities are aware of and are in the process of resolving their Year 2000
issues. During the first quarter of 1999, the Company will issue second
request questionnaires to those key suppliers and customers who did not
respond to the questionnaires issued during the third quarter of 1998.
Upon the return of the second request questionnaires from these non-
affiliated entities, the Company will review their responses and will begin
the process of assessing the preparedness of these entities.
As noted, the Company currently anticipates that all of its internal
systems and equipment will be Year 2000 compliant by the end of the second
quarter of 1999 and that the associated costs will not have a material
adverse effect on the Company's results of operations and financial
condition. However, the failure to properly assess or timely implement a
material Year 2000 problem could result in a disruption in the Company's
normal business activities or operations. Such failures, depending on the
extent and nature, could materially and adversely effect the Company's
operations and financial condition. As a result, the Company will continue
to evaluate its Year 2000 exposure, both internally and externally. Since
a portion of the Company's overall evaluation of its Year 2000 readiness
will, of necessity, be based on the information to be supplied by and the
readiness of the Company's key suppliers and customers, the Company cannot
currently determine the impact, if any, such third parties will have on the
Company's Year 2000 exposure. As noted, the Company intends to evaluate
this information as, if and when it is made available to it. To date, the
Company has not developed a contingency plan.
25
Effects of Inflation
- ---------------------
The effects of inflation on the Company's operations in previous years
have been minimal due to low inflation rates. However, during third and
fourth quarters of 1996 and throughout 1997 as drilling rig day rates and
drilling rig utilization increased, the impact of inflation intensified as
the availability of related equipment, third party services and qualified
labor decreased. In 1998, the impact of inflation was reduced as oil and
natural gas prices became depressed. The impact on the Company in the
future will depend on the relative increase, if any, the Company may
realize in its drilling rig rates and the selling price of its oil and
natural gas. If industry activity suddenly increases substantially,
shortages in support equipment such as drill pipe, third party services and
qualified labor will occur resulting in additional corresponding increases
in material and labor costs. These market conditions may limit the
Company's ability to realize improvements in operating profits.
Results of Operations
- ---------------------
1998 versus 1997
- ----------------
Net income for 1998 was $2,246,000, compared with $11,124,000 in 1997.
Increases in the number of rigs utilized and increased natural gas
production were more than offset by substantial decreases in the average
price received for both oil and natural gas and to a lesser extent from
reduced oil production and contract drilling day rates.
Oil and natural gas revenues decreased 13 percent in 1998 due to a 21
percent and 33 percent decrease in average natural gas and oil prices
received, respectively along with a 10 percent reduction in oil production.
These decreases were partially offset by a 19 percent increase in natural
gas production. Oil production declined from 1997 levels due to the
Company's emphasis over the past three years in drilling development wells
which focused on replacing and increasing natural gas reserves. Average
natural gas spot market prices received by the Company decreased 20
percent. The natural gas previously subject to the Settlement Agreement,
which ended at December 31, 1997 and contained provisions for prices higher
than current spot market prices, is now being sold at spot market prices
consistent with the rest of the natural gas sold by the Company. The
impact of higher prices received under the Settlement Agreement increased
pre-tax income by approximately $540,000 in 1997.
In 1998, revenues from contract drilling operations increased by 16
percent as average rig utilization increased from 19.2 rigs operating in
1997 to 22.9 rigs operating in 1998. Daywork revenues per rig per day
decreased 3 percent between the comparative years. During the first three
quarters of 1998, the Company's monthly rig utilization consistently
remained at or above 23 rigs with daywork revenue per rig per day declining
by 8 percent from the January 1998 rate. In the fourth quarter utilization
dropped 27 percent from the previous quarter and dayrates decreased another
6 percent from the previous quarter. Total daywork revenues represented 64
percent of total drilling revenues in 1998 and 72 percent in 1997. Turnkey
and footage contracts typically provide for higher revenues since a greater
portion of the expense of drilling the well is born by the drilling
contractor.
26
Operating margins (revenues less operating costs) for the Company's
oil and natural gas operations were 64 percent in 1998 compared to 71
percent in 1997. Decreased operating margins resulted primarily from the
decrease in average natural gas and oil prices received by the Company
between the two years. Total operating costs were 9 percent higher in 1998
compared to 1997 as the Company continues to add producing properties.
Operating margins for contract drilling decreased from 21 percent in
1997 to 18 percent in 1998. Margins in 1998 were lower primarily due to
decreases in both daily rig rates and utilization in the fourth quarter of
1998. Total operating costs for contract drilling were up 20 percent in
1998 versus 1997 due to increased drilling rig utilization and costs
associated with the November 1997 Hickman Acquisition.
Contract drilling depreciation increased 37 percent in response to
increased rig utilization and additional drilling capital expenditures
throughout 1997 and 1998. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 27 percent as the
Company increased its equivalent barrels of production by 14 percent and
the Company's average DD&A rate per equivalent barrel increased 11 percent
to $4.99 in 1998.
General and administrative expenses increased 6 percent as certain
employee costs increased. Interest expense increased 65 percent as the
Company's average outstanding debt increased 65 percent during 1998. The
average interest rate decreased from 7.28 percent in 1997 to 7.11 percent
in 1998.
1997 versus 1996
- ----------------
Net income for 1997 was $11,124,000, compared with $8,333,000 in 1996.
Increases in rig utilization, contract drilling day rates, average natural
gas prices received and natural gas production from new wells drilled
during the year all combined to produce the increase in 1997 net income.
Oil and natural gas revenues increased 6 percent in 1997 due to a 6
percent and 10 percent increase in natural gas production and average
natural gas prices received, respectively. These increases were partially
offset by a 15 percent decline in oil production and a 6 percent decrease
in average oil prices received by the Company in 1997. Oil production
declined from 1996 levels due to the Company's emphasis over the past two
years in drilling development wells which focused on replacing and
increasing natural gas reserves. Average natural gas spot market prices
received by the Company increased 11 percent while volumes produced from
certain wells included under the Settlement Agreement, which ended at
December 31, 1997 and contained provisions for prices higher than current
spot market prices, dropped 7 percent. The impact of higher prices
received under the Settlement Agreement increased pre-tax income by
approximately $540,000 and $650,000 in 1997 and 1996, respectively.
In 1997, revenues from contract drilling operations increased by 60
percent as average rig utilization increased from 14.7 rigs operating in
1996 to 19.2 rigs operating in 1997, and daywork revenues per rig per day
increased 22 percent. During the first three quarters of 1997, the
Company's monthly rig utilization consistently remained above 18 rigs with
27
daywork revenue per rig per day steadily climbing by 15 percent. In October
utilization dropped slightly below 18 rigs before the Company acquired 9
rigs through the Hickman acquisition in late November 1997 and another rig
in December 1997, raising the Company's rig count to 34 rigs and its
utilization in December to 26.2 rigs. Daywork revenue per rig per day
continued to rise in the fourth quarter, but the Company's average dayrate
declined 9 percent in December compared to November since the acquired
rigs, due to their depth capabilities, earned lower dayrates. Total daywork
revenues represented 72 percent of total drilling revenues in 1997 and 68
percent in 1996. Turnkey and footage contracts typically provide for higher
revenues since a greater portion of the expense of drilling the well is
born by the drilling contractor.
Operating margins (revenues less operating costs) for the Company's
oil and natural gas operations were 71 percent in 1997 compared to 69
percent in 1996. Increased operating margins resulted primarily from the
increase in natural gas production and the increase in natural gas prices
received by the Company between the two years. Total operating costs were
2 percent lower in 1997 compared to 1996.
Operating margins for contract drilling increased from 16 percent in
1996 to 21 percent in 1997. Margins in 1997 improved due to increases in
daily rig rates and utilization. Total operating costs for contract
drilling were up 50 percent in 1997 versus 1996 due to increased drilling
rig utilization.
Contract drilling depreciation increased 43 percent in response to
increased rig utilization and additional drilling capital expenditures
throughout 1997. Depreciation, depletion and amortization ("DD&A") of oil
and natural gas properties increased 17 percent as the Company increased
its equivalent barrels of production by 2 percent and the Company's average
DD&A rate per equivalent barrel increased 15 percent to $4.49 in 1997.
General and administrative expenses increased 12 percent as certain
employee costs and outside services increased. Interest expense decreased 8
percent as the average interest rate on the Company's outstanding bank debt
decreased from 7.69 percent in 1996 to 7.27 percent in 1997. Average bank
debt also decreased 4 percent during 1997.
Prior to 1996, the Company's effective income tax rate was
significantly impacted by its net operating loss carryforwards. As of
December 31, 1995, the Company's net operating loss and statutory depletion
carryforwards were fully recognized for financial reporting purposes;
therefore, the Company's effective income tax rate in 1996 and 1997
increased to approximately the statutory rate.
28
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
-------------------------
ASSETS 1998 1997
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 446 $ 458
Accounts receivable (less allowance for
doubtful accounts of $274 and $354) 13,149 19,813
Materials and supplies 3,298 3,535
Prepaid expenses and other 2,650 2,206
---------- ----------
Total current assets 19,543 26,012
---------- ----------
Property and Equipment:
Drilling equipment 123,258 119,155
Oil and natural gas properties, on the full
cost method 271,960 233,659
Transportation equipment 2,955 2,825
Other 6,870 6,948
---------- ----------
405,043 362,587
Less accumulated depreciation, depletion,
amortization and impairment 207,883 192,613
---------- ----------
Net property and equipment 197,160 169,974
---------- ----------
Other Assets 6,361 6,511
---------- ----------
Total Assets $ 223,064 $ 202,497
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
29
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
-------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY 1998 1997
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,801 $ 727
Accounts payable 8,517 11,112
Accrued liabilities 7,362 7,762
Contract advances 310 92
---------- ----------
Total current liabilities 17,990 19,693
---------- ----------
Other Long-Term Liabilities (Note 5) 2,301 2,279
---------- ----------
Long-Term Debt 72,900 54,100
---------- ----------
Deferred Income Taxes 18,583 17,560
---------- ----------
Commitments and Contingencies (Note 11)
Shareholders' Equity:
Preferred stock, $1.00 par value, 5,000,000
shares authorized, none issued - -
Common stock, $.20 par value, 40,000,000
shares authorized, 25,563,165 and
25,514,836 shares issued, respectively 5,113 5,103
Capital in excess of par value 82,187 82,043
Retained earnings 24,121 21,875
Treasury stock, at cost (25,000 and
19,863 shares, respectively) (131) (156)
---------- ----------
Total shareholders' equity 111,290 108,865
---------- ----------
Total Liabilities and Shareholders' Equity $ 223,064 $ 202,497
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
30
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
----------------------------------
1998 1997 1996
-------- -------- --------
(In thousands except per share amounts)
Revenues:
Contract drilling $53,528 $46,199 $28,819
Oil and natural gas 39,703 45,581 43,013
Other 106 84 238
-------- -------- --------
Total revenues 93,337 91,864 72,070
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 43,729 36,419 24,259
Depreciation 5,766 4,216 2,944
Oil and natural gas:
Operating costs 14,328 13,201 13,409
Depreciation, depletion
and amortization 16,069 12,625 10,807
General and administrative 4,891 4,621 4,122
Interest 4,815 2,921 3,162
-------- -------- --------
Total expenses 89,598 74,003 58,703
-------- -------- --------
Income Before Income Taxes 3,739 17,861 13,367
-------- -------- --------
Income Tax Expense:
Current 139 118 4
Deferred 1,354 6,619 5,030
-------- -------- --------
Total income taxes 1,493 6,737 5,034
-------- -------- --------
Net Income $ 2,246 $11,124 $ 8,333
======== ======== ========
Net Income Per Common Share:
Basic $ .09 $ .46 $ .37
======== ======== ========
Diluted $ .09 $ .45 $ .37
======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
31
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1996, 1997 and 1998
Capital
In Excess
Common Of Par Retained Treasury
Stock Value Earnings Stock Total
-------- -------- --------- -------- ---------
(In thousands)
Balances,
January 1, 1996 $ 4,195 $50,181 $ 2,418 $ (188) $ 56,606
Net income - - 8,333 - 8,333
Activity in employee
compensation plans
(321,667 shares) 64 615 - 123 802
Issuance of stock on
exercise of
warrants
(2,859,555 shares) 572 11,939 - - 12,511
Purchase of treasury
stock (5,000
shares) - - - (42) (42)
-------- -------- --------- -------- ---------
Balances,
December 31, 1996 4,831 62,735 10,751 (107) 78,210
Net income - - 11,124 - 11,124
Activity in employee
compensation plans
(57,524 shares) 12 718 - 89 819
Issuance of stock
for acquisition
(1,300,000 shares) 260 18,590 - - 18,850
Purchase of treasury
stock
(15,000 shares) - - - (138) (138)
-------- -------- --------- -------- ---------
Balances,
December 31, 1997 5,103 82,043 21,875 (156) 108,865
Net income - - 2,246 - 2,246
Activity in employee
compensation plans
(48,329 shares) 10 144 - 156 310
Purchase of treasury
stock
(25,000 shares) - - - (131) (131)
-------- -------- --------- -------- ---------
Balances,
December 31, 1998 $ 5,113 $82,187 $ 24,121 $ (131) $111,290
======== ======== ========= ======== =========
The accompanying notes are an integral part of the
consolidated financial statements
32
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
Cash Flows From Operating Activities:
Net Income $ 2,246 $ 11,124 $ 8,333
Adjustments to reconcile net
income to net cash provided
(used) by operating activities:
Depreciation, depletion, and
amortization 22,186 17,199 14,079
Loss (gain) on disposition
of assets 17 (94) (185)
Employee stock compensation plans 561 244 214
Bad debt expense - 250 -
Deferred tax expense (benefit) 1,354 6,619 5,030
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 6,664 (1,762) (5,444)
Materials and supplies 237 (1,233) (254)
Prepaid expenses and other (444) (211) (418)
Accounts payable 948 2,062 (2,288)
Accrued liabilities (27) 1,430 540
Contract advances 218 (1,208) 890
Other liabilities (447) (70) 167
--------- --------- ---------
Net cash provided
by operating activities 33,513 34,350 20,664
--------- --------- ---------
The accompanying notes are an integral part of the
consolidated financial statements
33
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions) $(53,654) $(45,115) $(34,111)
Cash received on acquisition
of drilling company (Note 2) - 1,611 -
Proceeds from disposition of
property and equipment 964 792 1,009
(Acquisition) disposition
of other assets- (93) (314) 215
--------- --------- ---------
Net cash used in
investing activities (52,783) (43,026) (32,887)
--------- --------- ---------
Cash Flows From Financing Activities:
Borrowings under line of credit 52,700 34,400 31,500
Payments under line of credit (32,900) (25,900) (32,000)
Net payments on notes payable
and other long-term debt (470) - (20)
Proceeds from sale of common stock 59 225 12,798
Acquisition of treasury stock (131) (138) (42)
--------- --------- ---------
Net cash provided by
financing activities 19,258 8,587 12,236
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents (12) (89) 13
Cash and Cash Equivalents,
Beginning of Year 458 547 534
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 446 $ 458 $ 547
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 4,064 $ 2,910 $ 3,189
Income taxes $ 507 $ 102 $ 63
The accompanying notes are an integral part of the
consolidated financial statements
34
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Principles of Consolidation
The consolidated financial statements include the accounts of Unit
Corporation and its directly and indirectly wholly owned subsidiaries (the
"Company"). The Company's investment in limited partnerships is accounted
for on the proportionate consolidation method, whereby its share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business
The Company is engaged in the development, acquisition and production
of oil and natural gas properties and the land contract drilling of oil and
natural gas wells primarily in the Anadarko, Arkoma and South Texas Basins.
These basins are located in Oklahoma, Texas, Kansas and Arkansas.
Additional producing properties are located in Canada and other states,
including New Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana,
Alabama, Mississippi, Arkansas, Illinois and Nebraska. At December 31,
1998, the Company has an interest in 2,563 wells and served as operator of
524 of those wells. Land contract drilling of oil and natural gas wells is
performed for a wide range of customers using the drilling rigs owned and
operated by the Company. In 1998, 31 of the Company's 34 rigs were in
operation.
Drilling Contracts
The Company recognizes revenues generated from "daywork" drilling
contracts as the services are performed, which is similar to the percentage
of completion method. For all contracts under which the Company bears the
risk of completion of the wells ("footage" and "turnkey" drilling
contracts), revenues and expenses are recognized using the completed
contract method. The duration of all three types of contracts range
typically from 20 to 90 days. The entire amount of the loss, if any, is
recorded when the loss is determinable.
The costs of uncompleted drilling contracts include expenses incurred
to date on "footage" or "turnkey" drilling contracts which are still in
process and are included in other current assets.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and
all investments with maturities at date of purchase of three months or less
which are readily convertible into known amounts of cash.
35
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated
useful lives, including a minimum provision of 20 percent of the active
rate when the equipment is idle. The Company uses the composite method of
depreciation for drill pipe and collars and calculates the depreciation by
footage actually drilled compared to total estimated remaining footage.
Depreciation of other property and equipment is computed using the
straight-line method over the estimated useful lives of the assets ranging
from 3 to 15 years.
Realization of the carrying value of the Company's property and
equipment is reviewed for possible impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable.
Assets are determined to be impaired if a forecast of undiscounted
estimated future net operating cash flows directly related to the asset
including disposal value if any, is less than the carrying amount of the
asset. If any asset is determined to be impaired, the loss is measured as
the amount by which the carrying amount of the asset exceeds its fair
value. An estimate of fair value is based on the best information
available, including prices for similar assets. Changes in such estimates
could cause the Company to reduce the carrying value of its property and
equipment.
When property and equipment components are disposed of, the cost and
the related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For
dispositions of drill pipe and drill collars, an average cost for the
appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.
Goodwill
Goodwill represents the excess of the cost of the acquisition of
Hickman Drilling Company over the fair value of the net assets acquired and
is being amortized on the straight-line method over 25 years. Goodwill is
evaluated periodically for impairment, when it appears an impairment may
have occurred, based on the estimated undiscounted future cash flow of the
acquired entity. Net goodwill reported in other assets at December 31,
1998 and 1997 was $5,818,000 and $6,061,000, respectively with accumulated
amortization at December 31, 1998 and 1997 of $264,000 and $20,000,
respectively.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and
development activities on the full cost method of accounting prescribed by
the Securities and Exchange Commission ("SEC"). Accordingly, all
productive and non-productive costs incurred in connection with the
acquisition, exploration and development of oil and natural gas reserves
are capitalized and amortized on a composite units-of-production method
based on proved oil and natural gas reserves. The Company's determination
of its oil and natural gas reserves are reviewed annually by independent
36
petroleum engineers. The average composite rates used for depreciation,
depletion and amortization ("DD&A") were $4.99, $4.49 and $3.90 per
equivalent barrel in 1998, 1997 and 1996, respectively. The Company's
calculation of DD&A includes estimated future expenditures to be incurred
in developing proved reserves and estimated dismantlement and abandonment
costs, net of estimated salvage values. In the event the unamortized cost
of oil and natural gas properties being amortized exceeds the full cost
ceiling, as defined by the SEC, the excess is charged to expense in the
period during which such excess occurs. The full cost ceiling is based
principally on the estimated future discounted net cash flows from the
Company's oil and natural gas properties. As discussed in Note 14, such
estimates are imprecise. Changes in these estimates or declines in oil and
natural gas prices could cause the Company in the near-term to reduce the
carrying value of its oil and natural gas properties.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties
in which the Company has an interest or on properties in which a
partnership, of which the Company is a general partner, has an interest.
Accordingly, in 1998 and 1997 the Company recorded $437,000 and $314,000 of
contract drilling profits, respectively, as a reduction of the carrying
value of its oil and natural gas properties rather than including these
profits in current operations. No contract drilling profits were realized
on such interests in 1996.
Limited Partnerships
The Company's wholly owned subsidiary, Unit Petroleum Company, is a
general partner in fourteen oil and natural gas limited partnerships sold
privately and publicly. Certain of the Company's officers, directors and
employees own interests in most of these partnerships.
The Company shares in partnership revenues and costs in accordance with
formulas prescribed in each limited partnership agreement. The
partnerships also reimburse the Company for certain administrative costs
incurred on behalf of the partnerships.
Income Taxes
Measurement of current and deferred income tax liabilities and assets
is based on provisions of enacted tax law; the effects of future changes in
tax laws or rates are not included in the measurement. Valuation
allowances are established where necessary to reduce deferred tax assets to
the amount expected to be realized. Income tax expense is the tax payable
for the year and the change during that year in deferred tax assets and
liabilities.
37
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales.
This method allows for recognition of revenue which may be more or less
than the Company's share of pro-rata production from certain wells. Based
upon the Company's 1998 average spot market natural gas price of $1.90 per
Mcf, the Company estimates its balancing position to be approximately $4.6
million on under-produced properties and approximately $2.8 million on
over-produced properties.
The Company's policy is to expense its pro-rata share of lease
operating costs from all wells as incurred. Such expenses relating to the
Company's balancing position on wells in which the Company has imbalances
are not material.
Stock Based Compensation
The Company applies APB Opinion 25 in accounting for its stock option
plans. Under this standard, no compensation expense is recognized for
grants of options which include an exercise price equal to or greater than
the market price of the stock on the date of grant. Accordingly, based on
the Company's grants in 1998, 1997 and 1996 no compensation expense has
been recognized. As provided by Financial Accounting Standard No. 123
"Accounting for Stock-Based Compensation," the Company has disclosed the
pro forma effects of recording compensation for such option grants based on
fair value in Note 8 to the financial statements.
Self Insurance
The Company utilizes self insurance programs for employee group health
and worker's compensation. Self insurance costs are accrued based upon the
aggregate of estimated liabilities for reported claims and claims incurred
but not yet reported.
Financial Instruments and Concentrations of Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
credit risk is considered by management to be limited due to the large
number of customers comprising the Company's customer base. In addition,
at December 31, 1998 and 1997, the Company had a concentration of cash of
$1.5 million and $0.3 million, respectively, with one bank.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
38
Earnings Per Share
In the fourth quarter of 1997, the Company adopted Financial
Accounting Standards Board Statement of Financial Accounting Standards No.
128, Earnings Per Share ("FAS 128"). Earnings per share amounts for all
previous periods presented give effect to the application of FAS 128.
Impact of Financial Accounting Pronouncements
On June 15, 1998, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities (FAS 133). FAS 133 is
effective for all fiscal quarters of fiscal years beginning after June 15,
1999 (January 1, 2000 for the Company). FAS 133 requires that all
derivative instruments be recorded on the balance sheet at their fair
value. Changes in the fair value of derivatives are recorded each period
in current earnings or other comprehensive income, depending on whether a
derivative is designated as part of a hedge transaction and, if it is, the
type of hedge transaction. Management of the Company anticipates that, due
to its limited use of derivative instruments, the adoption of FAS 133 will
not have a significant effect on the Company's results of operations or its
financial position.
NOTE 2 - ACQUISITION OF DRILLING COMPANY
- ----------------------------------------
On November 20, 1997, the Company acquired Hickman Drilling Company.
The selling stockholders of Hickman Drilling Company received, in the
aggregate, 1,300,000 shares of common stock valued at $18,850,000 and
promissory notes of $5,000,000 to be paid in five equal annual installments
commencing January 2, 1999. The acquisition has been accounted for as a
purchase and the results of Hickman Drilling Company have been included in
the accompanying consolidated financial statements since the date of
acquisition. The acquisition is summarized as follows:
(In thousands)
Current assets net of current liabilities $ 2,072
Property and equipment 23,187
Goodwill 6,081
Deferred tax liability - long-term (7,490)
---------
Total acquisition $ 23,850
=========
39
NOTE 3 - EARNINGS PER SHARE
- ---------------------------
The following data shows the amounts used in computing earnings per
share.
For the Year Ended
December 31, 1998
--------------------------------------
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ----------- ----------
Basic earnings per common
share $ 2,246,000 25,544,000 $ 0.09
==========
Effect of dilutive
stock options - 340,000
----------- -----------
Diluted earnings per common
share $ 2,246,000 25,884,000 $ 0.09
=========== =========== ==========
For the Year Ended
December 31, 1997
-------------------------------------
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ----------- ----------
Basic earnings per common
share $11,124,000 24,327,000 $ 0.46
==========
Effect of dilutive
stock options - 380,000
----------- -----------
Diluted earnings per common
share $11,124,000 24,707,000 $ 0.45
=========== =========== ==========
40
For the Year Ended
December 31, 1996
--------------------------------------
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ----------- ----------
Basic earnings per common
share $ 8,333,000 22,463,000 $ 0.37
==========
Effect of dilutive
stock options - 302,000
----------- -----------
Diluted earnings per common
share $ 8,333,000 22,765,000 $ 0.37
=========== =========== ==========
The following options and their average exercise prices were not included
in the computation of diluted earnings per share because the option
exercise prices were greater than the average market price on common shares
for the years ended December 31,:
1998 1997 1996
----------- ---------- ----------
Options 191,000 2,500 161,500
=========== ========== ==========
Average exercise price $ 8.60 $ 11.32 $ 8.60
=========== ========== ==========
NOTE 4 - WARRANTS
- -----------------
In 1987, the Company issued 2.873 million Units, consisting of three
shares of the Company's common stock and one warrant, at a price of $10.375
per Unit. Each warrant entitled the holder to purchase one share of the
Company's common stock at a price of $4.375. Prior to the warrants
expiration on August 30, 1996, 2.86 million warrants were exercised
providing $12.5 million in additional capital to the Company.
41
NOTE 5 - OTHER LONG-TERM LIABILITIES
- ------------------------------------
Other long-term liabilities consisted of the following as of December
31, 1998 and 1997:
1998 1997
--------- ---------
(In thousands)
Natural gas purchaser prepayment $ 1,759 $ 2,206
Separation benefit plan 1,012 -
Rig acquisition 331 800
--------- ---------
3,102 3,006
Less current portion 801 727
--------- ---------
$ 2,301 $ 2,279
========= =========
In March 1988, the Company entered into a settlement agreement with a
natural gas purchaser. During early 1991, the Company and the natural gas
purchaser superseded the original agreement with a new settlement agreement
effective retroactively to January 1, 1991. Under these settlement
agreements ("Settlement Agreement"), the Company has a prepayment balance
of $1.8 million at December 31, 1998 representing proceeds received from
the purchaser as prepayment for natural gas. This amount is net of natural
gas recouped and net of certain amounts disbursed to other owners (such
owners, collectively with the Company are referred to as the "Committed
Interest") for their proportionate share of the prepayments. At December
31, 1997, the Settlement Agreement and the natural gas purchase contracts
which were subject to the Settlement Agreement terminated. The December
31, 1997 Prepayment Balance of $2.2 million became payable in equal annual
payments over a five year period. The first payment of $441,000 was due
and paid on June 1, 1998.
The Company has other long-term liabilities of $1,343,000, consisting
of $331,000 from the December 9, 1997 acquisition of a Mid-Continent U-36-
A, 650 horsepower rig plus additional spare rig equipment and $1,012,000
from the liability accrued for the Company's Separation Benefit Plan. The
debt for rig equipment is payable over a maximum of three years from the
closing date of the acquisition.
42
NOTE 6 - LONG-TERM DEBT
- ------------------------
Long-term debt consisted of the following as of December 31, 1998 and
1997:
1998 1997
--------- ---------
(In thousands)
Revolving credit and term loan,
with interest at December 31,
1998 and 1997 of 6.3 percent
and 7.3 percent, respectively $ 68,900 $ 49,100
Notes payable for Hickman
Drilling Company acquisition
with interest at December 31,
1998 and 1997 of 7.8 percent
and 8.5 percent, respectively 5,000 5,000
--------- ---------
73,900 54,100
Less current portion 1,000 -
--------- ---------
Total long-term debt $ 72,900 $ 54,100
========= =========
At December 31, 1998, the Company's loan agreement ("Loan Agreement")
provided for a total loan commitment of $100 million consisting of a
revolving credit facility through May 1, 2002 and a term loan thereafter,
maturing on May 1, 2005. Borrowings under the Loan Agreement are limited
to a borrowing value which as of December 31, 1998 was $85 million. The
Loan Value under the revolving credit facility is subject to a semi-annual
redetermination calculated as the sum of a percentage of the discounted
future value of the Company's oil and natural gas reserves, as determined
by the banks, plus the greater of (i) 50 percent of the appraised value of
the Company's contract drilling rigs or (ii) two times the previous 12
months cash flow from the contract drilling rigs, limited in either case to
$20 million. Any declines in commodity prices would adversely impact the
determination of the borrowing value.
Borrowings under the revolving credit facility bear interest at the
Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London
Interbank Offered Rates ("Libor Rate") plus .75 to 1.25 percent depending
on the level of debt as a percentage of the total borrowing base.
Subsequent to May 1, 2002, borrowings under the Loan Agreement bear
interest at the Prime Rate plus .25 percent or the Libor rate plus 1.0 to
1.5 percent depending on the level of debt as a percentage of the total
borrowing base.
43
At the Company's election, any portion of the debt outstanding may be
fixed at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate
funding period the Company may not pay in part or in whole the outstanding
principal balance of the note to which such Libor Rate option applies.
Borrowings under the Prime Rate option may be paid anytime in part or in
whole without premium or penalty.
The Company paid an origination fee of $85,000 at inception of the
Loan Agreement and a facility fee of 3/8 of one percent is charged for any
unused portion of the borrowing value. Virtually all of the Company's
drilling rigs are collateral for such indebtedness and the balance of the
Company's assets are subject to a negative pledge.
The Loan Agreement includes prohibitions against (i) the payment of
dividends (other than stock dividends) during any fiscal year in excess of
25 percent of the consolidated net income of the Company during the
preceding fiscal year, and only if working capital provided from operations
during said year is equal to or greater than 175 percent of current
maturities of long-term debt at the end of such year, (ii) the incurrence
by the Company or any of its subsidiaries of additional debt with certain
very limited exceptions and (iii) the creation or existence of mortgages or
liens, other than those in the ordinary course of business, on any property
of the Company or any of its subsidiaries, except in favor of its banks.
The Loan Agreement also requires that the Company maintain consolidated net
worth of at least $75 million, a current ratio of not less than 1 to 1, a
ratio of long-term debt, as defined in the Loan Agreement, to consolidated
tangible net worth not greater than 1.2 to 1 and a ratio of total
liabilities, as defined in the Loan Agreement, to consolidated tangible net
worth not greater than 1.65 to 1. In addition, working capital provided by
operations, as defined in the Loan Agreement, cannot be less than $18
million in any year.
In November 1997, the Company completed its acquisition of Hickman
Drilling Company. In association with this acquisition, the Company issued
an aggregate of $5.0 million in promissory notes payable in five equal
annual installments commencing January 2, 1999, with interest at the Prime
Rate.
Estimated annual principal payments under the terms of all long-term
liabilities and debt from 1999 through 2003 are $1,801,000, $1,484,000,
$1,440,000, $14,837,000 and $23,967,000. Based on the borrowing rates
currently available to the Company for debt with similar terms and
maturities, long-term debt at December 31, 1998 approximates its fair
value.
44
NOTE 7 - INCOME TAXES
- ---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income to the Company's effective income
tax expense is as follows:
1998 1997 1996
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 1,271 $ 6,073 $ 4,545
State income tax, net of federal 150 733 499
Goodwill and other 72 (69) (10)
-------- -------- --------
Income tax expense (benefit) $ 1,493 $ 6,737 $ 5,034
======== ======== ========
Deferred tax assets and liabilities are comprised of the following at
December 31, 1998 and 1997:
1998 1997
--------- ---------
(In thousands)
Deferred tax assets:
Allowance for losses $ 1,680 $ 1,348
Net operating loss carryforwards 12,541 15,819
Statutory depletion carryforward 2,260 2,260
Investment tax credit carryforward 530 1,552
Alternative minimum tax credit
carryforward 431 167
--------- ---------
Gross deferred tax assets 17,442 21,146
Valuation allowance (530) (1,552)
Deferred tax liability-
Depreciation, depletion and amortization (35,495) (37,154)
--------- ---------
Net deferred tax liability $(18,583) $(17,560)
========= =========
The deferred tax asset valuation allowance reflects that the
investment tax credit carryforwards may not be utilized before the
expiration dates due in part to the effects of anticipated future
exploratory and development drilling costs. The reduction in the valuation
allowance was the result of the expiration of investment tax credit
carryforwards in 1998.
45
Realization of the deferred tax asset is dependent on generating
sufficient taxable income prior to expiration of loss carryforwards.
Although realization is not assured, management believes it is more likely
than not that the deferred tax asset will be realized. The amount of the
deferred tax asset considered realizable, however, could be reduced in the
near-term if estimates of future taxable income during the carryforward
period are reduced.
At December 31, 1998, the Company has net operating loss carryforwards
for regular tax purposes of approximately $33,003,000 and net operating
loss carryforwards for alternative minimum tax purposes of approximately
$19,953,000 which expire in various amounts from 2000 to 2011. The Company
has investment tax credit carryforwards of approximately $530,000 which
expire from 1999 to 2000. In addition, a statutory depletion carryforward
of approximately $5,948,000, which may be carried forward indefinitely, is
available to reduce future taxable income, subject to statutory
limitations.
NOTE 8 - EMPLOYEE BENEFIT AND COMPENSATION PLANS
- ------------------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common
stock were authorized for issuance under the Plan. On May 3, 1995, the
Company's shareholders approved and amended the Plan to increase by 250,000
shares the aggregate number of shares of common stock that could be issued
under the Plan. Under the terms of the Plan, bonuses may be granted to
employees in either cash or stock or a combination thereof, and are payable
in a lump sum or in annual installments subject to certain restrictions.
No shares were issued under the Plan in 1998, 1997 or 1996.
On December 22, 1998, the Board of Directors approved a stock bonus of
87,376 shares of common stock to be issued on January 4, 1999 for payment
of the Company's year end bonuses.
The Company also has a Stock Option Plan which provides for the
granting of options for up to 1,500,000 shares of common stock to officers
and employees. The plan permits the issuance of qualified or nonqualified
stock options. Options granted become exercisable at the rate of 20
percent per year one year after being granted and expire after ten years
from the original grant date. The exercise price for options granted to
date was based on the fair market value on the date of the grant.
46
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
--------- --------
Outstanding at
January 1, 1996 865,600 $ 2.23
Granted 149,500 8.75
Exercised (371,200) 1.59
Canceled (7,100) 2.92
--------- --------
Outstanding at
December 31, 1996 636,800 4.13
Granted 24,000 9.00
Exercised (56,440) 2.71
Canceled (30,200) 7.89
--------- --------
Outstanding at
December 31, 1997 574,160 4.28
Granted 226,000 3.96
Exercised (21,300) 2.71
Canceled (10,500) 7.05
--------- --------
Outstanding at
December 31, 1998 768,360 $ 4.19
========= ========
OUTSTANDING OPTIONS
--------------------------------------
WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE
EXERCISE OF REMAINING EXERCISE
PRICES SHARES CONTRACTUAL LIFE PRICE
----------------------------------------------------------
$ 2.37 - $ 4.00 614,860 5.7 years $3.07
$ 7.25 - $11.32 153,500 8.1 years $8.67
EXERCISABLE OPTIONS
-----------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
-----------------------------------------
$ 2.37 - $ 4.00 374,660 $2.68
$ 8.00 - $11.32 52,000 $8.76
Options for 427,000, 383,000 and 375,000 shares were exercisable with
weighted average exercise prices of $3.42, $3.01 and $2.64 at December 31,
1998, 1997 and 1996, respectively.
47
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued upon exercise of the stock options.
On the first business day following each annual meeting of stockholders of
the Company, each person who is then a member of the Board of Directors of
the Company and who is not then an employee of the Company or any of its
subsidiaries will be granted an option to purchase 2,500 shares of common
stock. The option price for each stock option is the fair market value of
the common stock on the date the stock options are granted. No stock
options may be exercised during the first six months of its term except in
case of death and no stock options are exercisable after ten years from the
date of grant.
Activity pertaining to the Directors' Plan is as
follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
-------- --------
Outstanding at
January 1, 1996 42,500 $ 2.96
Granted 12,500 6.88
-------- --------
Outstanding at
December 31, 1996 55,000 3.85
Granted 12,500 8.94
Exercised (7,500) 2.67
-------- --------
Outstanding at
December 31, 1997 60,000 5.06
Granted 12,500 9.00
-------- --------
Outstanding at
December 31, 1998 72,500 $ 5.74
======== ========
OUTSTANDING AND
EXERCISABLE OPTIONS
---------------------------------------
WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE
EXERCISE OF REMAINING EXERCISE
PRICES SHARES CONTRACTUAL LIFE PRICE
----------------------------------------------------------
$ 1.75 - $ 3.75 35,000 4.9 years $ 3.03
$ 6.87 - $ 9.00 37,500 8.3 years $ 8.28
48
The Company applies APB Opinion 25 in accounting for its Stock Option
Plan and Non-Employee Director's Stock Option Plan. Accordingly, based on
the nature of the Company's grants of options, no compensation cost has
been recognized in 1998, 1997 and 1996. Had compensation been determined
on the basis of fair value pursuant to FASB Statement No. 123, net income
and earnings per share would have been reduced as follows:
1998 1997 1996
------- ------- -------
Net Income (In thousands):
As reported $ 2,246 $11,124 $ 8,333
======= ======= =======
Pro forma $ 1,933 $10,748 $ 8,244
======= ======= =======
Basic Earnings per Share:
As reported $ .09 $ .46 $ .37
======= ======= =======
Pro forma $ .08 $ .44 $ .37
======= ======= =======
Diluted Earnings per Share:
As reported $ .09 $ .45 $ .36
======= ======= =======
Pro forma $ .07 $ .43 $ .36
======= ======= =======
The fair value of each option granted is estimated using the Black-
Scholes model. The Company's stock volatility was 0.53, 0.52 and 0.51 in
1998, 1997 and 1996, respectively, based on previous stock performance.
Dividend yield was estimated to remain at zero with a risk free interest
rate of 4.95, 5.80 and 6.55 percent in 1998, 1997 and 1996, respectively.
Expected life ranged from 1 to 10 years based on prior experience depending
on the vesting periods involved and the make up of participating employees.
The aggregate fair value of options granted during 1998, 1997 and 1996
under the Stock Option Plan were $527,000, $136,000 and $753,000,
respectively, and under the Non-Employee Stock Option Plan were $71,000,
$74,000 and $56,000, respectively.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in
full or on a partial basis. The Company made discretionary contributions
under the plan of 46,892, 23,892 and 44,686 shares of common stock and
recognized expense of $536,000, $329,000 and $268,000 in 1998, 1997 and
1996, respectively.
49
The Company provides a salary deferral plan ("Deferral Plan") which
allows participants to defer the recognition of salary for income tax
purposes until actual distribution of benefits which occurs at either
termination of employment, death or certain defined unforeseeable emergency
hardships. Funds set aside in a trust to satisfy the Company's obligation
under the Deferral Plan at December 31, 1998 and 1997 totaled $1,035,000
and $752,000, respectively. The Company recognizes payroll expense and
records a liability at the time of deferral.
Effective January 1, 1997, the Company adopted a separation benefit
plan ("Separation Plan"). The Separation Plan allows eligible employees
whose employment with the Company is involuntarily terminated or, in the
case of an employee who has completed 20 years of service, voluntarily or
involuntarily terminated, to receive benefits equivalent to 4 week's salary
for every whole year of service completed with the Company up to a maximum
of 104 weeks. Benefits received under the Separation Plan will be reduced
by the amount of any other benefits received from other disability or
severance plans which may be in effect during the payment period. To
receive payments the recipient must waive any claims against the Company
in exchange for receiving the separation benefits. On October 28, 1997,
the Company adopted a Separation Benefit Plan for Senior Management
("Senior Plan"). The Senior Plan provides certain officers and key
executives of the Company with benefits generally equivalent to the
Separation Plan. The Compensation Committee of the Board of Directors has
absolute discretion in the selection of the individuals covered in this
plan. The Company recognized expense of $577,000 and $466,000 in 1998 and
1997, respectively, for benefits associated with anticipated payments from
both separation plans.
NOTE 9 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through
1998, with a subsidiary of the Company serving as General Partner. The
Partnerships were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as co-general
partner with the Company in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with the Company in most drilling operations and most producing property
acquisitions commenced by the Company for its own account during the period
from the formation of the Partnership through December 31 of each year.
Amounts received in the years ended December 31 from both public and
private Partnerships for which the Company is a general partner are as
follows:
1998 1997 1996
-------- -------- --------
(In thousands)
Contract drilling $ 180 $ 135 $ 37
Well supervision and other fees $ 415 $ 384 $ 349
General and administrative
expense reimbursement $ 133 $ 119 $ 105
50
Related party transactions for contract drilling and well supervision
fees are the related party's share of such costs. These costs are billed
to related parties on the same basis as billings to unrelated parties for
such services. General and administrative reimbursements are both direct
general and administrative expense incurred on the related party's behalf
and indirect expenses allocated to the related parties. Such allocations
are based on the related party's level of activity and are considered by
management to be reasonable.
A subsidiary of the Company paid the Partnerships, for which the
Company or a subsidiary is the general partner, $21,000, $32,000 and
$31,000 during the years ended December 31, 1998, 1997 and 1996,
respectively, for purchases of natural gas production.
During 1997 and 1996 a bank owned by one of the Company's former
Directors was a participant in the Company's Loan Agreement. The bank's
pro rata share of the Company's line of credit was limited to an amount not
to exceed $1.5 million.
NOTE 10 - SHAREHOLDER RIGHTS PLAN
- --------------------------------
The Company maintains a Shareholder Rights Plan (the "Plan") designed
to deter coercive or unfair takeover tactics, to prevent a person or group
from gaining control of the Company without offering fair value to all
shareholders and to deter other abusive takeover tactics which are not in
the best interest of shareholders.
Under the terms of the Plan, each share of common stock is accompanied
by one right, which given certain acquisition and business combination
criteria, entitles the shareholder to purchase from the Company one one-
hundredth of a newly issued share of Series A Participating Cumulative
Preferred Stock at a price subject to adjustment by the Company or to
purchase from an acquiring Company certain shares of its common stock or
the surviving company's common stock at 50 percent of its value.
The rights become exercisable 10 days after the Company learns that an
acquiring person (as defined in the Plan) has acquired 15 percent or more
of the outstanding common stock of the Company or 10 business days after
the commencement of a tender offer which would result in a person owning 15
percent or more of such shares. The Company can redeem the rights for
$0.01 per right at any date prior to the earlier of (i) the close of
business on the tenth day following the time the Company learns that a
person has become an acquiring person or (ii) May 19, 2005 (the "Expiration
Date"). The rights will expire on the Expiration Date, unless redeemed
earlier by the Company.
51
NOTE 11 - COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
The Company leases office space under the terms of operating leases
expiring through January 31, 2002. Future minimum rental payments under
the terms of the leases are approximately $372,000, $104,000, $73,000 and
$7,000 in 1999, 2000, 2001 and 2002, respectively. No minimum rental
payments are due in 2003. Total rent expense incurred by the Company was
$412,000, $373,000 and $323,000 in 1998, 1997 and 1996, respectively.
The Company had letters of credit supported by its Loan Agreement
totaling $210,000 at December 31, 1998.
The Company as a 40 percent owner in a corporation which provides gas
gathering services, guarantees certain indebtedness of that corporation up
to a maximum of $2 million (approximately $950,000 at December 31, 1998).
The guarantee extends for a period ending on June 21, 2001.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership agreements along with the employee oil and gas
limited partnerships require, upon the election of a limited partner, that
the Company repurchase the limited partner's interest at amounts to be
determined by appraisal in the future. Such repurchases in any one year
are limited to 20 percent of the units outstanding. The Company made
repurchases of $15,000 and $30,000 in 1998 and 1996, respectively, for such
limited partners' interests and did not make any such repurchases in 1997.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
will result in judgements which would have a material adverse effect on the
Company.
52
NOTE 12 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
In 1998, the Company adopted Statement of Financial Accounting
Standard No. 131 "Disclosures about Segments of an Enterprise and Related
Information." The Company has two business segments: Contract Drilling
and Oil and Natural Gas, representing its two strategic business units
offering different products and services. The Contract Drilling segment
provides land contract drilling of oil and natural gas wells and the Oil
and Natural Gas segment is engaged in the development, acquisition and
production of oil and natural gas properties.
The accounting policies of the segments are the same as those
described in the Summary of Significant Accounting Policies (Note 1). The
Company evaluates the performance of its operating segments based on
operating income, which is defined as operating revenues less operating
expenses and depreciation, depletion and amortization. The Company has
natural gas production in Canada which is not significant.
1998 1997 1996
--------- --------- ---------
(In thousands)
Revenues:
Contract drilling $ 53,528 $ 46,199 $ 28,819
Oil and natural gas 39,703 45,581 43,013
Other 106 84 238
--------- --------- ---------
Total revenues $ 93,337 $ 91,864 $ 72,070
========= ========= =========
Operating Income (1):
Contract drilling $ 4,033 $ 5,564 $ 1,616
Oil and natural gas 9,306 19,755 18,797
--------- --------- ---------
Total operating income 13,339 25,319 20,413
General and administrative (4,891) (4,621) (4,122)
Expense
Interest expense (4,815) (2,921) (3,162)
Other income (expense)- net 106 84 238
--------- --------- ---------
Income before income taxes $ 3,739 $ 17,861 $ 13,367
========= ========= =========
53
1998 1997 1996
--------- --------- ---------
(In thousands)
Identifiable Assets (2):
Contract drilling $ 69,147 $ 66,188 $ 24,500
Oil and natural gas 150,718 132,332 110,207
--------- --------- ---------
Total identifiable assets 219,865 198,520 134,707
Corporate assets 3,199 3,977 3,286
--------- --------- ---------
Total assets $223,064 $202,497 $137,993
========= ========= =========
Capital Expenditures:
Contract drilling $ 11,485 $ 35,193 $ 9,910
Oil and natural gas 38,409 33,525 25,644
Other 216 1,464 989
--------- --------- ---------
Total capital expenditures $ 50,110 $ 70,182 $ 36,543
========= ========= =========
Depreciation, Depletion and
Amortization:
Contract drilling $ 5,766 $ 4,216 $ 2,944
Oil and natural gas 16,069 12,625 10,807
Other 351 358 328
--------- --------- ---------
Total depreciation,
depletion and amortization $ 22,186 $ 17,199 $ 14,079
========= ========= =========
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion and amortization and does not include non-operating
revenues, general corporate expenses, interest expense or income taxes.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements,
furniture and equipment.
54
NOTE 13 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1998 and 1997 is as
follows:
Three Months Ended
------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- --------- --------- ------------
(In thousands except per share amounts)
Year ended December 31, 1998:
Revenues $ 24,249 $ 26,054 $ 23,627 $ 19,407
========= ========= ========= =========
Gross profit(1) $ 3,471 $ 4,450 $ 3,537 $ 1,881
========= ========= ========= =========
Income before
income taxes $ 1,163 $ 2,053 $ 1,136 $ (613)
========= ========= ========= =========
Net Income $ 725 $ 1,235 $ 654 $ (368)
========= ========= ========= =========
Earnings per common share:
Basic (2) $ .03 $ .05 $ .03 $ (.01)
========= ========= ========= =========
Diluted (2) $ .03 $ .05 $ .03 $ (.01)
========= ========= ========= =========
Year ended December 31, 1997:
Revenues $ 24,322 $ 19,806 $ 21,585 $ 26,151
========= ========= ========= =========
Gross profit(1) $ 7,970 $ 4,161 $ 5,227 $ 7,961
========= ========= ========= =========
Income before
income taxes $ 6,219 $ 2,299 $ 3,409 $ 5,934
========= ========= ========= =========
Net Income $ 3,874 $ 1,432 $ 2,121 $ 3,697
========= ========= ========= =========
Earnings per common share:
Basic $ .16 $ .06 $ .09 $ .15
========= ========= ========= =========
Diluted (2) $ .16 $ .06 $ .09 $ .15
========= ========= ========= =========
(1) Gross profit excludes other revenues, general and administrative
expense and interest expense.
55
(2) Due to the effect of price changes of the Company's stock, diluted
earnings per share for the year's four quarters, which includes the
effect of potential dilutive common shares calculated during each
quarter, does not equal the annual diluted earnings per share, which
includes the effect of such potential dilutive common shares calculated
for the entire year.
NOTE 14 - OIL AND NATURAL GAS INFORMATION (UNAUDITED)
- -----------------------------------------------------
The capitalized costs at year end and costs incurred during the year
were as follows:
USA CANADA TOTAL
---------- -------- ----------
(In thousands)
1998:
Capitalized costs:
Proved properties $ 261,299 $ 480 $ 261,779
Unproved properties 9,900 281 10,181
---------- -------- ----------
271,199 761 271,960
Less accumulated depreciation,
depletion, amortization
and impairment (130,894) (412) (131,306)
---------- -------- ----------
Net capitalized costs $ 140,305 $ 349 $ 140,654
========== ======== ==========
Cost incurred:
Unproved properties $ 4,297 $ 203 $ 4,500
Producing properties 9,026 - 9,026
Exploration 2,270 - 2,270
Development 22,613 - 22,613
---------- -------- ----------
Total costs incurred $ 38,206 $ 203 $ 38,409
========== ======== ==========
1997:
Capitalized costs:
Proved properties $ 225,166 $ 480 $ 225,646
Unproved properties 7,935 78 8,013
---------- -------- ----------
233,101 558 233,659
Accumulated depreciation,
depletion, amortization
and impairment (115,000) (405) (115,405)
---------- -------- ----------
Net capitalized costs $ 118,101 $ 153 $ 118,254
========== ======== ==========
Cost incurred:
Unproved properties $ 3,540 $ 78 $ 3,618
Producing properties 1,518 - 1,518
Exploration 1,785 - 1,785
Development 26,604 - 26,604
---------- -------- ----------
Total costs incurred $ 33,447 $ 78 $ 33,525
========== ======== ==========
56
USA CANADA TOTAL
---------- --------- ----------
(In thousands)
1996:
Capitalized costs:
Proved properties $ 195,528 $ 480 $ 196,008
Unproved properties 4,602 - 4,602
---------- --------- ----------
200,130 480 200,610
Less accumulated depreciation,
depletion, amortization
and impairment (102,463) (389) (102,852)
---------- --------- ----------
Net capitalized costs $ 97,667 $ 91 $ 97,758
========== ========= ==========
Cost incurred:
Unproved properties $ 1,640 $ - $ 1,640
Producing properties 2,338 - 2,338
Exploration 1,501 - 1,501
Development 20,150 15 20,165
---------- --------- ----------
Total costs incurred $ 25,629 $ 15 $ 25,644
========== ========= ==========
57
The results of operations for producing activities are provided below.
USA CANADA TOTAL
--------- -------- ---------
(In thousands)
1998:
Revenues $ 36,861 $ 55 $ 36,916
Production costs (11,572) (20) (11,592)
Depreciation, depletion
and amortization (15,893) (8) (15,901)
--------- -------- ---------
9,396 27 9,423
Income tax expense (3,752) (9) (3,761)
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 5,644 $ 18 $ 5,662
========= ======== =========
1997:
Revenues $ 42,830 $ 69 $ 42,899
Production costs (10,678) (24) (10,702)
Depreciation, depletion
and amortization (12,537) (16) (12,553)
--------- -------- ---------
19,615 29 19,644
Income tax expense (7,394) (17) (7,411)
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 12,221 $ 12 $ 12,233
========= ======== =========
1996:
Revenues $ 40,432 $ 60 $ 40,492
Production costs (11,195) (14) (11,209)
Depreciation, depletion
and amortization (10,723) (11) (10,734)
--------- -------- ---------
18,514 35 18,549
Income tax expense (6,986) (15) (7,001)
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 11,528 $ 20 $ 11,548
========= ======== =========
58
Estimated quantities of proved developed oil and natural gas reserves
and changes in net quantities of proved developed and undeveloped oil and
natural gas reserves were as follows:
USA CANADA TOTAL
---------------- --------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- ------- ------- --------
(In thousands)
1998:
Proved developed and
undeveloped reserves:
Beginning of year 4,131 144,661 - 723 4,131 145,384
Revision of previous
estimates (1,142) (5,207) - (162) (1,142) (5,369)
Extensions, discoveries
and other additions 445 31,460 - - 445 31,460
Purchases of minerals
in place 257 6,840 - - 257 6,840
Sales of minerals in
place (3) (532) - - (3) (532)
Production (443) (16,427) - (38) (443) (16,465)
------- -------- ----- ----- ------- --------
End of Year 3,245 160,795 - 523 3,245 161,318
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 3,406 115,071 - 295 3,406 115,366
End of year 2,365 119,415 - 421 2,365 119,836
1997:
Proved developed and
undeveloped reserves:
Beginning of year 5,204 128,408 - 753 5,204 129,161
Revision of previous
estimates (927) (12,780) - 44 (927) (12,736)
Extensions, discoveries
and other additions 399 41,108 - - 399 41,108
Purchases of minerals
in place 6 2,618 - - 6 2,618
Sales of minerals in
place (58) (951) - - (58) (951)
Production (493) (13,742) - (74) (493) (13,816)
------- -------- ----- ----- ------- --------
End of Year 4,131 144,661 - 723 4,131 145,384
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 4,509 107,536 - 326 4,509 107,862
End of year 3,406 115,071 - 295 3,406 115,366
59
USA CANADA TOTAL
---------------- --------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- ------- ------- --------
(In thousands)
1996:
Proved developed and
undeveloped reserves:
Beginning of year 5,428 107,950 - 778 5,428 108,728
Revision of previous
estimates (387) (3,822) - 26 (387) (3,796)
Extensions, discoveries
and other additions 718 34,625 - - 718 34,625
Purchases of minerals
in place 67 3,036 - - 67 3,036
Sales of minerals
in place (43) (407) - - (43) (407)
Production (579) (12,974) - (51) (579) (13,025)
------- -------- ----- ----- ------- --------
End of Year 5,204 128,408 - 753 5,204 129,161
======= ======== ===== ===== ======= ========
Proved developed reserves:
Beginning of year 4,697 94,975 - 350 4,697 95,325
End of year 4,509 107,536 - 326 4,509 107,862
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made
in connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's
reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog-
ical and engineering data, appear with reasonable certainty to be recov-
erable in the future from known oil and natural gas reservoirs under exist-
ing economic and operating conditions. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods. Proved undeveloped reserves are
those reserves which are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expendi-
ture is required.
Estimates of oil and natural gas reserves require extensive judgments
of reservoir engineering data as previously explained. Assigning monetary
values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. Indeed the uncertainties inherent in the
disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves. The information set forth herein is therefore
subjective and, since judgments are involved, may not be comparable to
estimates submitted by other oil and natural gas producers. In addition,
since prices and costs do not remain static and no price or cost escala-
60
tions or de-escalations have been considered, the results are not neces-
sarily indicative of the estimated fair market value of estimated proved
reserves nor of estimated future cash flows.
The standardized measure of discounted future net cash flows ("SMOG")
was calculated using year-end prices and costs, and year-end statutory tax
rates, adjusted for permanent differences, that relate to existing proved
oil and natural gas reserves. SMOG as of December 31 is as follows:
USA CANADA TOTAL
---------- -------- ----------
(In thousands)
1998:
Future cash flows $ 388,887 $ 1,089 $ 389,976
Future production and
development costs (154,843) (271) (155,114)
Future income tax expenses (47,305) (160) (47,465)
---------- -------- ----------
Future net cash flows 186,739 658 187,397
10% annual discount for
estimated timing of cash flows (62,770) (259) (63,029)
---------- -------- ----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 123,969 $ 399 $ 124,368
========== ======== ==========
1997:
Future cash flows $ 427,292 $ 1,684 $ 428,976
Future production and
development costs (153,220) (312) (153,532)
Future income tax expenses (63,868) (794) (64,662)
---------- -------- ----------
Future net cash flows 210,204 578 210,782
10% annual discount for
estimated timing of cash flows (71,768) (187) (71,955)
---------- -------- ----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 138,436 $ 391 $ 138,827
========== ======== ==========
61
USA CANADA TOTAL
---------- -------- ----------
(In thousands)
1996:
Future cash flows $ 626,945 $ 2,735 $ 629,680
Future production and
development costs (171,749) (339) (172,088)
Future income tax expenses (125,540) (1,422) (126,962)
---------- -------- ----------
Future net cash flows 329,656 974 330,630
10% annual discount for
estimated timing of cash flows (129,610) (368) (129,978)
---------- -------- ----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 200,046 $ 606 $ 200,652
========== ======== ==========
62
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
---------- -------- ----------
(In thousands)
1998:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (25,289) $ (35) $ (25,324)
Net changes in prices and
production costs (35,654) (186) (35,840)
Revisions in quantity estimates
and changes in production timing (17,020) (335) (17,355)
Extensions, discoveries and improved
recovery, less related costs 24,256 - 24,256
Purchases of minerals in place 6,062 - 6,062
Sales of minerals in place (603) - (603)
Accretion of discount 16,719 91 16,810
Net change in income taxes 16,083 486 16,569
Other - net 979 (13) 966
---------- -------- ----------
Net change (14,467) 8 (14,459)
Beginning of year 138,436 391 138,827
---------- -------- ----------
End of year $ 123,969 $ 399 $ 124,368
========== ======== ==========
1997:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (32,152) $ (45) $ (32,197)
Net changes in prices and
production costs (111,745) (651) (112,396)
Revisions in quantity estimates
and changes in production timing (19,377) 47 (19,330)
Extensions, discoveries and improved
recovery, less related costs 46,787 - 46,787
Purchases of minerals in place 2,235 - 2,235
Sales of minerals in place (2,282) - (2,282)
Accretion of discount 26,227 147 26,374
Net change in income taxes 33,473 345 33,818
Other - net (4,776) (58) (4,834)
---------- -------- ----------
Net change (61,610) (215) (61,825)
Beginning of year 200,046 606 200,652
---------- -------- ----------
End of year $ 138,436 $ 391 $ 138,827
========== ======== ==========
63
USA CANADA TOTAL
---------- -------- ----------
(In thousands)
1996:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (29,237) $ (46) $ (29,283)
Net changes in prices and
production costs 92,541 738 93,279
Revisions in quantity estimates
and changes in production timing (13,390) 58 (13,332)
Extensions, discoveries and improved
recovery, less related costs 69,942 - 69,942
Purchases of minerals in place 5,821 - 5,821
Sales of minerals in place (514) - (514)
Accretion of discount 12,101 71 12,172
Net change in income taxes (44,039) (470) (44,509)
Other - net 3,998 (60) 3,938
---------- -------- ----------
Net change 97,223 291 97,514
Beginning of year 102,823 315 103,138
---------- -------- ----------
End of year $ 200,046 $ 606 $ 200,652
========== ======== ==========
The Company's SMOG and changes therein were determined in accordance
with Statement of Financial Accounting Standards No. 69. Certain infor-
mation concerning the assumptions used in computing SMOG and their inherent
limitations are discussed below. Management believes such information is
essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those
reserves nor their present worth. Assigning monetary values to the reserve
quantity estimation process does not reduce the subjective and ever-
changing nature of such reserve estimates. Additional subjectivity occurs
when determining present values because the rate of producing the reserves
must be estimated. In addition to errors inherent in predicting the
future, variations from the expected production rate could result from
factors outside of management's control, such as unintentional delays in
development, environmental concerns or changes in prices or regulatory
controls. Also, the reserve valuation assumes that all reserves will be
disposed of by production. However, other factors such as the sale of
reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided
by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of
existing economic conditions.
64
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates to the future pretax net cash flows relating
to proved oil and natural gas reserves less the tax basis of the Company's
properties. The future income tax expenses also give effect to permanent
differences and tax credits and allowances relating to the Company's proved
oil and natural gas reserves.
Care should be exercised in the use and interpretation of the above
data. As production occurs over the next several years, the results shown
may be significantly different as changes in production performance,
petroleum prices and costs are likely to occur.
In early 1999, the oil and natural gas industry has experienced a
downturn in natural gas prices. The Company's reserves were determined at
December 31, 1998 using an oil and natural gas price of $11.10 per barrel
and $2.08 per Mcf. During February 1999, the oil and natural gas prices
received by the Company were approximately $11.62 and $1.74, respectively.
The decreases in natural gas prices would have a significant effect on the
SMOG value of the Company's reserves at December 31, 1998 and would result
in a provision to reduce the carrying value of oil and natural gas
properties of approximately $22 million before taxes.
65
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
In our opinion, the accompanying consolidated balance sheet and the
related consolidated statements of operations, stockholders' equity and
cash flows present fairly in all material respects, the financial position
of Unit Corporation and its subsidiaries at December 31, 1998 and 1997, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles. In addition, in our opinion, the
accompanying financial statement schedule presents fairly, in all material
respects, the information set forth therein when read in conjunction with
the related consolidated financial statements. These financial statements
and financial statement schedule are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits. We
conducted our audits of these financial statements in accordance with
generally accepted auditing standards which require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 23, 1999
66
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure.
- ---------------------
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
- -------------------------------------------------------------
The table below and accompanying footnotes set forth certain infor-
mation concerning each executive officer of the Company. Unless otherwise
indicated, each has served in the positions set forth for more than five
years. Executive officers are elected for a term of one year. There are
no family relationships between any of the persons named.
NAME AGE POSITION
- ---------------- --- ----------------------------------------
King P. Kirchner 71 Chairman of the Board, Chief Executive
Officer and Director
John G. Nikkel 64 President, Chief Operating Officer and
Director
Earle Lamborn 64 Senior Vice President, Drilling and
Director
Philip M. Keeley 57 Senior Vice President, Exploration and
Production
Larry D. Pinkston 44 Vice President, Treasurer and Chief
Financial Officer
Mark E. Schell 41 General Counsel and Secretary
________
Mr. Kirchner, a co-founder of the Company, has been the Chairman of
the Board and a director since 1963 and was President until November 1983.
Mr. Kirchner is a Registered Professional Engineer within the State of
Oklahoma, having received degrees in Mechanical Engineering from Oklahoma
State University and in Petroleum Engineering from the University of
Oklahoma.
Mr. Nikkel joined the Company in 1983 as its President and a director.
From 1976 until January 1982 when he co-founded Nike Exploration Company,
Mr. Nikkel was an officer and director of Cotton Petroleum Corporation,
serving as the President of that Company from 1979 until his departure.
Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production
Company for 18 years, last serving as Division Geologist for Amoco's Denver
Division. Mr. Nikkel presently serves as President and a director of Nike
Exploration Company. Mr. Nikkel received a Bachelor of Science degree in
Geology and Mathematics from Texas Christian University.
67
Mr. Lamborn has been actively involved in the oil field for over 45
years, joining the Company's predecessor in 1952 prior to it becoming a
publicly-held corporation. He was elected Vice President, Drilling in 1973
and to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice
President, Exploration and Production. Prior to that time, Mr. Keeley co-
founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and
serves as Executive Vice President and a director of that company. From
1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation,
serving first as Manager of Land and from 1979 as Vice President and a
director. Before joining Cotton, Mr. Keeley was employed for four years by
Apexco, Inc. as Manager of Land and prior thereto he was employed by
Texaco, Inc. for nine years. He received a Bachelor of Arts degree in
Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as
Corporate Budget Director and Assistant Controller prior to being appointed
as Controller in February 1985. He has been Treasurer since December 1986
and was elected to the position of Vice President and Chief Financial
Officer in May 1989. He holds a Bachelor of Science Degree in Accounting
from East Central University of Oklahoma and is a Certified Public
Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and
General Counsel. From 1979 until joining the Company, Mr. Schell was
Counsel, Vice President and a member of the Board of Directors of C & S
Exploration, Inc. He received a Bachelor of Science degree in Political
Science from Arizona State University and his Juris Doctorate degree from
the University of Tulsa Law School. He is a member of the Oklahoma and
American Bar Association as well as being a member of the American
Corporate Counsel Association and the American Society of Corporate
Secretaries.
The balance of the information required in this Item 10 is incorpo-
rated by reference from the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1999
annual meeting of stockholders.
Item 11. Executive Compensation
- ---------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1999 annual meeting of
stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1999 annual meeting of
stockholders.
68
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1999 annual meeting of
stockholders.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements:
- ------------------------
Included in Part II of this report:
Consolidated Balance Sheets as of December 31, 1998 and 1997
Consolidated Statements of Operations for the years ended December
31, 1998, 1997 and 1996
Consolidated Statements of Changes in Shareholders' Equity for the
years ended December 31, 1998, 1997 and 1996
Consolidated Statements of Cash Flows for the years ended December
31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements
Report of Independent Accountants
2. Financial Statement Schedules:
- ---------------------------------
Included in Part IV of this report for the years ended December 31, 1998,
1997 and 1996:
Schedule II - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under
which they are required or because the required information is included
in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers
assigned such exhibits in the Exhibit Table of Item 601 of Regulation
S-K.
3. Exhibits:
---------
2 Certificate of Ownership and Merger of the Company and Unit
Drilling Co., dated February 22, 1979 (filed as an Exhibit to
the Company's Registration Statement No. 2-63702, which is
incorporated herein by reference).
2.1 Agreement and Plan of Merger dated November 21, 1997, by and
among the Registrant, Unit Drilling Company, the Shareholders
and Hickman Drilling Company (filed as an Exhibit to the
Company's Form 8-K dated November 21, 1997, which is
incorporated herein by reference).
69
3.1.1 Certificate of Incorporation (filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated
July 21, 1988 (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December
31, 1989, which is incorporated herein by reference).
3.1.3 Restated Certificate of Incorporation of Unit Corporation dated
February 2, 1994 (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
3.2.1 By-Laws (filed as Exhibit 3.5 to the Company's Registration
Statement of Form S-4 as S.E.C. File No. 33-7848, which is
incorporated herein by reference).
3.2.2 Amended and Restated By-Laws, dated June 29, 1988 (filed as an
Exhibit to the Company's Annual Report under cover of Form 10-
K for the year ended December 31, 1989, which is incorporated
herein by reference).
4.1 Form of Promissory Note to be issued to the Shareholders of
Hickman Drilling Company pursuant to the Agreement and Plan of
Merger dated November 21, 1997 (filed as an Exhibit to the
Company's Form 8-K dated November 21, 1997, which is
incorporated herein by reference).
4.2.1 Form of Warrant Agreement between the Company and the Warrant
Agent (filed as Exhibit 4.1 to the Company's Registration
statement on Form S-2 as S.E.C. File No. 33-16116, which is
incorporated herein by reference).
4.2.2 Form of Warrant (filed as Exhibit 4.3 to the Company's
Registration Statement of Form S-2 as S.E.C. File No. 33-
16116, which is incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.2 on Form
S-2 as S.E.C. File No. 33-16116, which is incorporated herein
by reference).
4.2.4 First Amendment to Warrant Agreement (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1992, which is incorporated herein
by reference).
4.2.5 Second Amendment to Warrant Agreement (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1994, which is incorporated herein
by reference).
4.2.6 Rights Agreement dated as of May 19, 1995 between the Company
and Chemical Bank, as Rights Agent (filed as Exhibit 1 to the
Company's Form 8-A filed May 23, 1995, File No. 1-92601 and
incorporated herein by reference).
70
10.1.14 Amended and Restated Credit Agreement dated as of January 17,
1992 by and between Unit Corporation and Bank of Oklahoma
N.A., F&M Bank and Trust Company, Fourth National Bank of
Tulsa and Western National Bank of Tulsa (filed as an Exhibit
to the Company's Annual Report under cover of Form 10-K for
the year ended December 31, 1991, which is incorporated herein
by reference).
10.1.16 First Amendment to Amended and Restated Credit Agreement dated
as of May 1, 1992, by and between Unit Corporation and Bank of
Oklahoma, N.A., F&M Bank and Trust Company, Fourth National
Bank of Tulsa, and Western National Bank of Tulsa (filed as an
Exhibit to the Company's Quarterly Report under cover of Form
10-Q for the quarter ended June 30, 1992, which is
incorporated herein by reference).
10.1.17 Second Amendment to Amended and Restated Credit Agreement, dated
March 3, 1993 and effective as of March 1, 1993, by and
between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank
and Trust Company, Fourth National Bank of Tulsa, and Western
National Bank of Tulsa (filed as an Exhibit to the Company's
Quarterly Report under cover of Form 10-Q for the quarter
ended March 31, 1993, which is incorporated herein by
reference).
10.1.18 Third Amendment to Amended and Restated Credit Agreement
effective as of March 31, 1994, by and between Unit
Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust
Company, Bank IV, Oklahoma, N.A. and American National Bank
and Trust Company of Shawnee (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the
quarter ended March 31, 1994, which is incorporated herein by
reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement dated
as of December 12, 1994, by and between Unit Corporation
and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank
IV, Oklahoma, N.A. and American National Bank and Trust
Company of Shawnee (filed as an Exhibit in Form 8-K dated
December 15, 1994, which is incorporated herein by reference).
10.1.20 Loan Agreement dated August 3, 1995 (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended June 30, 1995, which is incorporated herein
by reference).
10.1.21 First Amendment to the Loan Agreement effective as of
September 4, 1996, by and between Unit Corporation and Bank of
Oklahoma, N.A., The First National Bank of Boston, Bank IV
Oklahoma, N.A. and American National Bank and Trust Company of
Shawnee (filed as an Exhibit to the Company's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1996, which is incorporated herein by reference).
71
10.1.22 Second Amendment to the Loan Agreement effective as of December
16, 1996 by and between Unit Corporation and Bank of Oklahoma,
N.A., The First National Bank of Boston, Boatman's
National Bank of Oklahoma and American National Bank and Trust
Company of Shawnee (filed herewith).
10.1.23 Loan Agreement dated April 30, 1998 (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended June 30, 1998, which is incorporated herein
by reference).
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership
(filed as Exhibit I to Unit Drilling and Exploration Company's
Registration Statement on Form S-1 as S.E.C. File No. 2-66347,
which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership
(filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's
Registration Statement Form S-1 as S.E.C. File No. 2-92582,
which is incorporated herein by reference).
10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited
Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil
and Gas Program's Registration Statement of Form S-1 as S.E.C.
File No. 2-89678, which is incorporated herein by reference).
10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit 3.1 to Unit 1985
Employee Oil and Gas Limited Partnership's Registration
Statement on Form S-1 as S.E.C. File No. 2-95068, which is
incorporated herein by reference).
10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit 10.11 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1990, which is incorporated herein by reference).
72
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1991, which is incorporated herein by reference).
10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as
Exhibit 10.16 to the Company's Registration Statement on Form
S-4 as S.E.C. File No. 33-7848, which is incorporated herein
by reference).
10.2.22* The Company's Amended and Restated Stock Option Plan (filed as
an Exhibit to the Company's Registration Statement on Form S-8
as S.E.C. File No's. 33-19652, 33-44103 and 33-64323 which is
incorporated herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan (filed
as an Exhibit to Form S-8 as S.E.C. File No. 33-49724,
which is incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed as an Exhibit to
Form S-8 as S.E.C. File No. 33-53542, which is incorporated
herein by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1993,
which is incorporated herein by reference).
10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to
the Company's Annual Report under cover of Form 10-K for the
year ended December 31, 1993, which is incorporated herein by
reference).
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report, under cover of Form 10-K for the year ended
December 31, 1994, which is incorporated herein by reference).
10.2.29 Unit 1996 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the
Company's Annual Report under cover of Form 10-K for the year
ended December 31, 1995, which is incorporated herein by
reference).
73
10.2.30* Separation Benefit Plan of Unit Corporation and Participating
Subsidiaries (filed as an Exhibit to the Company's Annual
Report under the cover of Form 10-K for the year ended
December 31, 1996).
10.2.31 Unit 1997 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under the cover of Form 10-K for the year ended
December 31, 1996).
10.2.32 Unit Corporation Separation Benefit Plan for Senior
Management(filed as an Exhibit to the Company's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1997, which is incorporated herein by
reference).
10.2.33 Unit 1998 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to the Company's
Annual Report under the cover of Form 10-K for the year ended
December 31, 1997).
10.2.34 Unit 1999 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed herewith).
10.5 Acquisition and Development Agreement, dated September 26, 1991,
between Registrant and Municipal Energy Agency of
Nebraska (filed as an Exhibit to Form 8-K dated September 30,
1991, which is incorporated herein by reference).
10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco
Exploration, Inc. and Aleco Production Company (as "Seller")
and Unit Petroleum Company (a "Buyer") and Helmerich & Payne,
Inc. (a "Buyer") (filed as an Exhibit to Form 8-K dated May
21, 1992, which is incorporated herein by reference).
10.7 Asset Purchase Agreement, dated as of November 28, 1994, between
the Registrant and Patrick Petroleum Corp of Michigan
and American National Petroleum Company (filed as an Exhibit
to Form 8-K dated December 15, 1994, which is incorporated
herein by reference).
21 Subsidiaries of the Registrant (filed herewith).
23 Consent of Independent Accountants (filed herewith).
27 Financial Data Schedules (filed herewith).
* Indicates a management contract or compensatory plan identified
pursuant to the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
No reports under Form 8-K were filed during the quarter ended
December 31, 1998.
74
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance
Balance at charged to Deductions at
beginning costs & & net end of
Description of period expenses write-offs period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1998 $ 354 $ - $ 80 $ 274
======== ======== ======== ========
Year ended
December 31, 1997 $ 104 $ 250 $ - $ 354
======== ======== ======== ========
Year ended
December 31, 1996 $ 116 $ - $ 12 $ 104
======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance
Balance at at
beginning end of
Description of period Additions Deductions period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1998 $ 1,552 $ - $ 1,022 $ 530
======== ======== ======== ========
Year ended
December 31, 1997 $ 3,530 $ - $ 1,978 $ 1,552
======== ======== ======== ========
Year ended
December 31, 1996 $ 3,530 $ - $ - $ 3,530
======== ======== ======== ========
75
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 17, 1999 By: /s/ John G. Nikkel
-------------- ---------------------------
JOHN G. NIKKEL
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities indicated on the 17th day of March, 1997.
Name Title
/s/ King P. Kirchner
- ------------------------------- Chairman of the Board and Chief
KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel
- ------------------------------- President and Chief Operating
JOHN G. NIKKEL Officer, Director
/s/ Earle Lamborn
- ------------------------------- Senior Vice President, Drilling,
EARLE LAMBORN Director
/s/ Larry D. Pinkston
- ------------------------------- Vice President, Chief Financial
LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz
- ------------------------------- Controller
STANLEY W. BELITZ
/s/ J. Michael Adcock
- ------------------------------- Director
J. MICHAEL ADCOCK
/s/ Don Cook
- ------------------------------- Director
DON COOK
/s/ William B. Morgan
- ------------------------------- Director
WILLIAM B. MORGAN
/s/ John S. Zink
- ------------------------------- Director
JOHN S. ZINK
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
76
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
------ ----------------------------------------------- -----
10.2.34 Unit 1999 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
27 Financial Data Schedules.
77