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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, 2000
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
------------------- on which registered
Common Stock, par value -------------------
$.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 16 2001 - $467,971,160
Number of Shares of Common Stock
Outstanding on March 16 2001 - 35,934,791
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the
Annual Meeting of Stockholders to be held May 2, 2001 are incorporated by
reference in Part III.
Exhibit Index - See Page 85
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 2
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 2
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 22
Item 4. Submission of Matters to a Vote of Security Holders . . 22
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . 23
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . 25
Item 7a. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . 32
Item 8. Financial Statements and Supplementary Data . . . . . . 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . 75
PART III
Item 10. Directors and Executive Officers of the Registrant. . . 75
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 77
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . 77
Item 13. Certain Relationships and Related Transactions. . . . . 77
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 78
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
1
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2000
PART I
Item 1. Business and Item 2. Properties
- ------- -------- ------- ----------
GENERAL
Through our wholly owned subsidiaries, we contract to drill onshore
oil and natural gas wells for others and explore, develop, acquire and
produce oil and natural gas properties for our self. We were founded in
1963 as a contract drilling company. Today our contract drilling
operations and our exploration and production operations are carried out
primarily in the natural gas producing provinces of the Oklahoma and Texas
areas of the Anadarko and Arkoma Basins and the Texas Gulf Cost. Our
contract drilling operations are also engaged in the East Texas and Rocky
Mountain region.
Our executive offices are located at 1000 Kensington Tower, 7130 South
Lewis, Tulsa, Oklahoma 74136; telephone number (918) 493-7700. We also
have regional offices in Oklahoma City, Oklahoma, Woodward, Oklahoma,
Booker, Texas, Houston, Texas and Casper, Wyoming. When used in this
report, the terms Corporation, Unit, our, we and its refer to Unit
Corporation and, at times, Unit Corporation and/or one or more of its
subsidiaries.
LAND CONTRACT DRILLING OPERATIONS
We drill onshore natural gas and oil wells for a wide range of
customers through our wholly owned subsidiary Unit Drilling Company. 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. We conduct an active maintenance and
replacement program under which components are upgraded 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,
while other components, such as the substructure, mast and drawworks, can
be utilized for extended periods of time with proper maintenance. We also
own additional equipment used in the operation of our rigs, including large
air compressors, trucks and other support equipment.
On September 30, 1999, we completed the acquisition of 13 land
drilling rigs from Parker Drilling Company and Parker Drilling Company
North America, Inc., for $40 million and one million shares of our common
stock.
2
On December 29, 2000, we purchased a 750 horsepower diesel electric rig
with a 13,500 foot depth capacity for $3.2 million and at December 31,
2000, we were completing the construction of two additional rigs.
At December 31, 2000, our drilling rig fleet consisted of 50 rigs with
depth capacities ranging from 9,500 to 40,000 feet of which 34 were located
in the Anadarko and Arkoma Basins of Oklahoma and Texas while nine were
located in the East Texas and Gulf Coast Region and seven in the Rocky
Mountain region.
In January 2001, we purchased a 1,000 horse power diesel electric rig
with a 16,000 foot depth capacity for $3.2 million. This new rig is working
in the Gulf Coast region. In February 2001, we purchased a 1,000 horse
power mechanical rig, also with a 16,000 foot depth capacity, for $2.5
million. This rig will be moved from Alaska to the Rocky Mountain region
in the second quarter of 2001. The addition of these two rigs brings our
fleet to 52 rigs.
At present, we do not have a shortage of drilling rig related
equipment. During 1996 and through 1997, we increased our drill pipe
acquisitions since certain grades of drill pipe were in high demand due to
increased rig utilization. However, at any given time our ability to use
all of our rigs will depend on the availability of qualified labor,
drilling supplies and equipment as well as demand.
3
The following table sets forth, for each of the periods indicated,
certain information concerning our contract drilling operations:
Year Ended December 31,
------------------------------------------------
1996 1997 1998 1999 2000
------ ------ ------ ------ ------
Number of Rigs Owned
At End of Period 24.0 34.0 (1) 34.0 47.0 (2) 50.0 (3)
Average Number of Rigs
Owned During Period 22.7 25.1 34.0 37.3 47.0
Average Number of Rigs
Utilized (4) 14.7 20.0 22.9 23.1 39.8
Utilization Rate (4) 65% 80% 67% 62% 85%
Average Revenue
Per Day (5) $5,351 $6,309 $6,394 $6,582 $7,432
Total Footage Drilled
(Feet in 1000's) 1,468 1,736 2,203 2,211 3,650
Number of Wells
Drilled 130 167 198 197 316
- ----------------------
(1) Includes 10 rigs acquired in the fourth quarter of 1997.
(2) Includes 13 rigs acquired in September 1999.
(3) Includes one rig acquired at the 2000 year-end and two additional rigs
that were completing construction.
(4) Utilization rates are based on a 365-day year and are calculated by
dividing the number of rigs utilized by the total number of rigs owned
during the period, including stacked rigs. A rig is considered utilized
when it is operating or being moved, assembled or dismantled under
contract.
(5) Represents total revenues from contract drilling operations divided by
the total number of days rigs were being utilized for the period.
As of February 7, 2001, 47 of our drilling rigs were operating under
contract.
4
The following table sets forth, as of March 16, 2001, the type and
approximate depth capability of each of our drilling rigs:
Approximate Depth
Rig# Type Capability (feet)
----- --------------------------- -----------------
1 BDW 650 13,000
2 BDW 650 13,000
3 BDW 650 13,500
4 Gardner Denver 500 12,500
5 U-15 Unit Rig 11,000
6 BDW 800 17,000
8 Gardner Denver 800 16,000
9 BDW 800 17,000
10 BDW 450T 9,500
11 Gardner Denver 700 15,000
12 BDW 800 16,000
14 Gardner Denver 700 15,000
15 Mid-Continent 914-C 20,000
16 U-15 Unit Rig 11,000
17 Brewster N-75 15,000
18 BDW 650 12,500
19 Gardner Denver 500 12,000
20 Gardner Denver 700 15,000
21 Gardner Denver 700 15,000
22 BDW 800 16,000
23 Gardner Denver 700 14,000
24 Gardner Denver 700 14,000
25 Gardner Denver 700 15,000
26 National 610 E 13,500
27 BDW 650 13,000
28 Continental Emsco D-3 16,000
29 Brewster N-75A 15,000
30 BDW 1350-M 20,000
31 Shufelt 12,500
32 Brewster N-75 15,000
33 BDW 800 16,000
34 National 110-UE 20,000
35 Continental Emsco C-1 20,000
36 Gardner Denver 1500-E 25,000
37 Mid-Continent 914-EC 20,000
38 Mid-Continent 1220-EB 25,000
39 Mid-Continent U-36-A 12,000
40 BDW 800 16,000
112 Ideco E-3000 25,000
166 OIME E-3000 25,000
180 OIME E-3000 30,000
182 OIME E-3000 30,000
184 OIME E-3000 30,000
201 OIME E-4000 40,000
203 OIME E-2000 25,000
232 Continental Emsco D-3 II 16,000
233 Continental Emsco C-1 III 20,000
234 Continental Emsco D-3 II 16,000
235 Continental Emsco C-1 II 20,000
236 Gardner Denver 800 16,000
237 Continental Emsco C-1 II 20,000
254 OIME E-2000 25,000
5
During most of the past 17 years, our contract drilling operations
encountered significant competition due to depressed levels of activity.
In the last half of 1999 and throughout 2000, as oil and natural gas prices
began to increase, the demand for our contract drilling services increased.
Although we experienced an increase in demand for our drilling services and
our dayrates and utilization have increased, we anticipate that competition
within the industry will, for the foreseeable future, continue to adversely
affect us.
Drilling Contracts. Most of our drilling contracts are obtained
through competitive bidding. Generally, our contracts are for a single
well with the terms and rates varying depending upon the nature and
duration of the work, the equipment and services supplied and other
matters. The contracts obligate us 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. We
generally indemnify our customers against certain types of claims by our
employees and claims arising from surface pollution caused by spills of
fuel, lubricants and other solvents within our control. Customers
generally indemnify us against claims arising from other surface and
subsurface pollution other than claims resulting from our gross negligence.
Our contracts generally compensate us on a daywork, footage or turnkey
basis with additional compensation for special risks and unusual
conditions. Under daywork contracts, we provide the drilling rig with the
required personnel to the operator who supervises the drilling of the
contracted well. Our compensation is based on a negotiated rate for each
day the rig is utilized. Footage contracts usually require us to bear some
of the drilling costs in addition to providing the rig. We are compensated
on a negotiated rate, per foot drilled, upon completion of the well. Under
turnkey contracts, we contract to drill a well for a lump sum amount to a
specified depth and provide most of the equipment and services required.
We bear the risk of drilling the well to the contract depth and are
compensated when the contract provisions have been satisfied.
Turnkey drilling operations, in particular, might result in losses if
we underestimate the costs of drilling a well or if unforeseen events
occur. To date, we have not experienced significant losses in performing
turnkey contracts. For 2000, turnkey revenue represented approximately 9
percent of our contract drilling revenues as compared to 21 percent for
1999 and we did not have any turnkey contracts in progress at December 31,
2000. Because the proportion of turnkey drilling is dictated by market
conditions and the desires of customers using our services, we can't
predict whether the portion of drilling conducted on a turnkey basis will
increase or decrease in the future.
Customers. During 2000, 10 contract drilling customers accounted for
approximately 42 percent of our total contract drilling revenues.
Approximately 4 percent of our total contract drilling revenues were
generated from drilling on oil and natural gas properties of which we were
the operator (including properties owned by limited partnerships for which
we acted as general partner).
6
Further information relating to contract drilling operations is
presented in Notes 1, 2 and 10 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
OIL AND NATURAL GAS OPERATIONS
In 1979, we began to develop our exploration and production operations
to diversify our contract drilling revenues. Our wholly owned subsidiary,
Unit Petroleum Company, conducts our exploration and production activities.
As of December 31, 2000, we had estimated net proved reserves of 4,183
Mbbls and 215,637 MMcf. Our producing oil and natural gas interests,
undeveloped leaseholds and related assets are located primarily in
Oklahoma, Texas, Louisiana and New Mexico and, to a lesser extent, in
Arkansas, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi,
Illinois, Michigan, Nebraska and Canada. As of December 31, 2000, we had
an interest in a total of 2,887 wells in the United States, 667 of which we
served as the operator. We also had an interest in 64 wells located in
Canada. Our technical staff generates the majority of our development and
exploration prospects. When we are the operator of a property, we
generally employ our own drilling rigs and our own engineering staff
supervises the drilling operation.
We intend to continue the growth in our oil and natural gas operations
utilizing funds generated from operations and our bank loan agreement.
7
Well and Leasehold Data. The tables below set forth certain
information regarding our oil and natural gas exploration and development
drilling activities for the periods indicated:
Year Ended December 31,
--------------------------------------------------------
1998 1999 2000
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Wells Drilled:
- --------------
Exploratory:
Oil - - - - - -
Natural gas - - - - 2 1.63
Dry 1 .26 - - - -
-------- -------- -------- -------- -------- --------
Total 1 .26 - - 2 1.63
======== ======== ======== ======== ======== ========
Development:
Oil 6 1.13 1 .48 7 1.45
Natural gas 62 22.71 55 19.23 75 28.51
Dry 27 11.85 10 5.47 17 8.56
-------- -------- -------- -------- -------- --------
Total 95 35.69 66 25.18 99 38.52
======== ======== ======== ======== ======== ========
Oil and Natural
Gas Wells
Producing or
Capable of
Producing:
- ---------------
Oil - USA 841 214.70 783 224.10 799 278.06
Oil - Canada - - - - - -
Gas - USA 1,960 370.70 1,950 403.50 2,088 431.11
Gas - Canada 64 1.60 64 1.60 64 1.60
-------- -------- -------- -------- -------- --------
Total 2,865 587.00 2,797 629.20 2,951 710.77
======== ======== ======== ======== ======== ========
On February 7, 2001, Unit was participating in the drilling of 4
gross (2.36 net) wells in the United States.
8
The following table summarizes our oil and natural gas leasehold
acreage as of the end of each of the years indicated:
Developed Acreage Undeveloped Acreage
--------------------- ---------------------
Gross Net Gross Net
--------- --------- --------- ---------
1998:
- -----
USA 628,241 142,543 52,958 35,371
Canada 39,040 976 22,763 22,763
--------- --------- --------- ---------
667,281 143,519 75,721 58,134
========= ========= ========= =========
1999:
- -----
USA 548,011 142,472 55,989 35,245
Canada 39,040 976 25,293 25,293
--------- --------- --------- ---------
Total 587,051 143,448 81,282 60,538
========= ========= ========= =========
2000:
- -----
USA 564,780 153,507 61,487 39,480
Canada 39,040 976 26,243 13,121
--------- --------- --------- ---------
Total 603,820 154,463 87,730 52,601
========= ========= ========= =========
9
Price and Production Data. The following table sets forth our 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:
Year Ended December 31,
---------------------------------
1998 1999 2000
---------- ---------- ----------
Average Sales Price per Barrel of Oil
Produced:
USA $ 12.77 $ 17.48 $ 26.95
Canada - - -
Average Sales Price per Mcf of Natural
Gas Produced:
USA $ 1.91 $ 2.05 $ 3.91
Canada $ 1.46 $ 1.81 $ 2.39
Oil Production (Mbbls):
USA 486 424 488
Canada - - -
---------- ---------- ----------
Total 486 424 488
========== ========== ==========
Natural Gas Production (MMcf):
USA 17,694 17,402 19,239
Canada 38 35 46
---------- ---------- ----------
Total 17,732 17,437 19,285
========== ========== ==========
Average Production Expense per
Equivalent Mcf:
USA $ .62 $ .59 $ .74
Canada $ .54 $ .56 $ .42
10
Reserves. The following table sets forth our estimated proved
developed and undeveloped oil and natural gas reserves at the end of each
of the years indicated:
Year Ended December 31,
---------------------------------
1998 1999 2000
---------- ---------- ----------
Oil (Mbbls):
USA 3,629 4,527 4,183
Canada - - -
---------- ---------- ----------
Total 3,629 4,527 4,183
========== ========== ==========
Natural gas (MMcf):
USA 175,884 186,770 215,196
Canada 523 569 441
---------- ---------- ----------
Total 176,407 187,339 215,637
========== ========== ==========
Further information relating to oil and natural gas operations is
presented in Notes 1, 10 and 12 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
VOLATILE NATURE OF OUR OIL AND NATURAL GAS MARKETS;
FLUCTUATIONS IN PRICES
Our revenues, operating results, cash flows and future rate of growth
are significantly affected by the prevailing prices for natural gas and
oil. Historically, oil and natural gas prices and markets have been
volatile, and they are likely to continue to be volatile. Oil and natural
gas prices increased substantially in the last half of 1999 and throughout
2000. However, and despite the recent price improvements, it is possible
that such prices could again decline. Price declines had a significant
negative impact on our financial results for 1998 and the first six months
of 1999. We incurred a net loss for the two quarterly periods ending March
31 and June 30, 1999 before incurring net income for the two quarterly
periods ending September 30 and December 31, 1999. Although we had net
income for the twelve months ended December 31, 1999 and significant
increases in net income in 2000, depressed prices in the future would, as
noted, have a negative impact on our future financial results. Because our
oil and natural gas reserves are predominantly natural gas, changes in
natural gas prices would have a disproportionate impact on our financial
results.
11
Prices for oil and natural gas are subject to wide fluctuations in
response to relatively minor changes in the supply of and demand for oil
and natural gas, market uncertainty and a variety of additional factors
that are beyond our control. These factors include:
. political conditions in oil producing regions, including the
Middle East;
. the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
. the price of foreign imports;
. actions of governmental authorities;
. the domestic and foreign supply of oil and natural gas;
. the level of consumer demand;
. weather conditions;
. domestic and foreign government regulations;
. the price, availability and acceptance of alternative fuels; and
. overall economic conditions.
These factors and the volatile nature of the energy markets make it
impossible to predict with any certainty the future prices of oil and
natural gas.
Our oil and condensate production is sold at or near our wells under
purchase contracts at prevailing prices in accordance with arrangements
customary in the oil industry. Our 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 at prices primarily determined on a daily basis. Most of these
contracts contain provisions for readjustment of price, termination and
other terms customary in the industry.
Our contract drilling operations are dependent on the level of demand
in our operating markets. Both short-term and long-term trends in oil and
natural gas prices affect the demand. Because oil and natural gas prices
are volatile, the level of demand for our services can also be volatile.
Decreased oil and natural gas prices during 1998 and early 1999 adversely
affected our contract drilling activity by lowering the demand for our rigs
and reducing the rates we charged for our rigs. With the increase in oil
and natural gas prices in the last half of 1999 and all of 2000 our
dayrates and rig utilization have increased substantially.
12
Although oil and natural gas prices have recently improved, we expect
that in the near term our customers will continue a cautious approach to
exploration and development spending until price gains prove to be
sustainable. Decreases from current oil and natural gas prices would
depress the level of exploration and production activity. This in turn
would likely result in a decline in our contract drilling revenues, cash
flows and profitability. As a result, the future demand for our drilling
services is uncertain.
COMPETITION
All of our lines of business are highly competitive. Competition in
onshore contract drilling traditionally involves such factors as price,
efficiency, condition of equipment, availability of labor and equipment,
reputation and customer relations. Some of our competitors in the onshore
contract drilling business are substantially larger than we are and have
appreciably greater financial and other resources. As a result of the
increase in demand for onshore contract drilling services over the past
year and a half, previous surpluses of certain types of drilling rigs in
the industry have been eliminated and the inventories of certain components
such as specific grades of drill pipe have been depleted from continued
use. The competitive environment within which we operate is uncertain and
extremely price oriented.
Our 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 we are.
OIL AND NATURAL GAS PROGRAMS
Our subsidiary, Unit Petroleum Company, serves as the general partner
of four oil and gas limited partnerships and 12 employee oil and gas
limited partnerships. Each year we form an employee partnership which
acquires an interest, ranging from 2.5% to 15% of our interest, in most oil
and natural gas drilling activities and purchases of producing oil and
natural gas properties that we do that year. The limited partners in the
employee partnerships are either employees or directors of Unit or its
subsidiaries. Our subsidiary, Questa Oil and Gas Co., also formed five
private limited partnerships from 1981 to 1993. We repurchased the limited
partner's interest in three of five of the Questa partnerships in the
fourth quarter of 2000 and the three partnerships were dissolved.
Under the terms of the partnership agreements, the general partner 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
13
when we are the operator of an oil and natural gas well and also provide
contract drilling services. In such cases, these drilling operations are
done pursuant to contracts containing terms and conditions comparable to
those contained in our drilling contracts with non-affiliated operators.
Although we have no formal procedures for resolving such conflicts, we
believe we fulfill our responsibility to each contracting party and comply
fully with the terms of the agreements which regulate such conflicts.
EMPLOYEES
As of February 7, 2000, we had approximately 1,038 employees in our
land contract drilling operations, 54 employees in our oil and natural gas
operations and 52 in our general corporate area. None of our employees are
represented by a union or labor organization nor have our operations ever
been interrupted by a strike or work stoppage. We consider relations with
our employees to be satisfactory.
OPERATING AND OTHER RISKS
Our drilling operations are subject to many hazards inherent in the
drilling industry, including blowouts, cratering, explosions, fires, loss
of well control, loss of hole, damaged or lost drilling equipment and
damage or loss from inclement weather. Our exploration and production
operations are subject to these and similar risks. Any of these events
could result in personal injury or death, damage to or destruction of
equipment and facilities, suspension of operations, environmental damage
and damage to the property of others. Generally, drilling contracts
provide for the division of responsibilities between a drilling company and
its customer, and we seek to obtain indemnification from our drilling
customers by contract for some of these risks. To the extent that we are
unable to transfer these risks to drilling customers by contract or
indemnification agreements, we seek protection through insurance. However,
we cannot assure you that our insurance or our indemnification agreements,
if any, will adequately protect us against liability from all of the
consequences of the hazards described above. The occurrence of an event
not fully insured or indemnified against, or the failure of a customer to
meet its indemnification obligations, could result in substantial losses to
us. In addition, we cannot assure you that insurance will be available to
cover any or all of these risks. Even if available, the insurance might
not be adequate to cover all of our losses, or we might decide against
obtaining that insurance because of high premiums or other costs.
Exploration and development operations involve numerous risks that may
result in dry holes, the failure to produce oil and natural gas in
commercial quantities and the inability to fully produce discovered
reserves. The cost of drilling, completing and operating wells is
substantial and uncertain. Our operations may be curtailed, delayed or
cancelled as a result of many things beyond our control, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
14
. adverse weather conditions;
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs or delivery
crews and the delivery of equipment.
The majority of the wells in which we own an interest are operated by
other parties. As a result, we have little control over the operations of
such wells which can act to increase our risk. Operators of these wells
may act in ways that are not in our best interests.
Our future performance depends upon our ability to find or acquire
additional oil and natural gas reserves that are economically recoverable.
In general, production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. Unless we successfully replace the reserves that we
produce, our reserves will decline, resulting eventually in a decrease in
oil and natural gas production and lower revenues and cash flow from
operations. Historically, we have succeeded in increasing reserves after
taking production into account through exploitation, development and
exploration. We have conducted such activities on our existing oil and
natural gas properties as well as on newly acquired properties. We may not
be able to continue to replace reserves from such activities at acceptable
costs. Low prices of oil and natural gas may further limit the kinds of
reserves that can economically be developed. Lower prices also decrease
our cash flow and may cause us to decrease capital expenditures.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which we conduct
activities impose restrictions on the drilling, production, transportation
and sale of oil and natural gas.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory
Commission (the "FERC") regulates the interstate transportation and the
sale in interstate commerce for resale of natural gas. The FERC's
jurisdiction over interstate natural gas sales was substantially modified
by the Natural Gas Policy Act under which the FERC continued to regulate
the maximum selling prices of certain categories of gas sold in "first
sales" in interstate and intrastate commerce. Effective January 1, 1993,
however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act")
deregulated natural gas prices for all "first sales" of natural gas.
Because "first sales" include typical wellhead sales by producers, all
natural gas produced from our natural gas properties is being sold at
market prices, subject to the terms of any private contracts which may be
in effect. The FERC's jurisdiction over natural gas transportation was not
affected by the Decontrol Act.
15
Our sales of natural gas are affected by intrastate and interstate gas
transportation regulation. Beginning in 1985, the FERC adopted regulatory
changes that have significantly altered the transportation and marketing of
natural gas. These changes were intended by the FERC to foster competition
by, among other things, transforming the role of interstate pipeline
companies from wholesale marketers of natural gas to the primary role of
gas transporters. All natural gas marketing by the pipelines was required
to be divested to a marketing affiliate, which operates separately from the
transporter and in direct competition with all other merchants. As a
result of the various omnibus rulemaking proceedings in the late 1980s and
the individual pipeline restructuring proceedings of the early to mid-
1990s, the interstate pipelines are now required to provide open and
nondiscriminatory transportation and transportation-related services to all
producers, natural gas marketing companies, local distribution companies,
industrial end users and other customers seeking service. Through similar
orders affecting intrastate pipelines that provide similar interstate
services, the FERC expanded the impact of open access regulations to
intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to
affiliated or non-affiliated companies; (2) further development of rules
governing the relationship of the pipelines with their marketing
affiliates; (3) the publication of standards relating to the use of
electronic bulletin boards and electronic data exchange by the pipelines to
make available transportation information on a timely basis and to enable
transactions to occur on a purely electronic basis; (4) further review of
the role of the secondary market for released pipeline capacity and its
relationship to open access service in the primary market; and (5)
development of policy and promulgation of orders pertaining to its
authorization of market-based rates (rather than traditional cost-of-
service based rates) for transportation or transportation-related services
upon the pipeline's demonstration of lack of market control in the relevant
service market. It remains to be seen what effect the FERC's other
activities will have on the access to markets, the fostering of competition
and the cost of doing business.
As a result of these changes, sellers and buyers of natural gas have
gained direct access to the particular pipeline services they need and are
better able to conduct business with a larger number of counter parties.
We believe these changes generally have improved the access to markets for
natural gas while, at the same time, substantially increasing competition
in the natural gas marketplace. We cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt or what effect
subsequent regulations may have on production and marketing of natural gas
from our properties.
In the past, Congress has been very active in the area of natural gas
regulation. However, as discussed above, the more recent trend has been in
favor of deregulation and the promotion of competition in the natural gas
industry. Thus, in addition to "first sales" deregulation, Congress also
repealed incremental pricing requirements and natural gas use restraints
previously applicable. There are other legislative proposals pending in the
16
Federal and State legislatures which, if enacted, would significantly
affect the petroleum industry. At the present time, it is impossible to
predict what proposals, if any, might actually be enacted by Congress or
the various state legislatures and what effect, if any, these proposals
might have on the production and marketing of natural gas by us. Similarly,
and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue or what the
ultimate effect will be on the production and marketing of natural gas by
us cannot be predicted.
Our sales of oil and natural gas liquids are not regulated and are at
market prices. The price received from the sale of these products is
affected by the cost of transporting the products to market. Much of that
transportation is through interstate common carrier pipelines. Effective
as of January 1, 1995, the FERC implemented regulations generally
grandfathering all previously approved interstate transportation rates and
establishing an indexing system for those rates by which adjustments are
made annually based on the rate of inflation, subject to certain conditions
and limitations. These regulations may tend to increase the cost of
transporting oil and natural gas liquids by interstate pipeline, although
the annual adjustments may result in decreased rates in a given year. These
regulations have generally been approved on judicial review. Every five
years, the FERC will examine the relationship between the annual change in
the applicable index and the actual cost changes experienced by the oil
pipeline industry. We are not able to predict with certainty what effect,
if any, these relatively new federal regulations or the periodic review of
the index by the FERC will have on us.
Federal, state, and local agencies have promulgated extensive rules
and regulations applicable to our oil and natural gas exploration,
production and related operations. Oklahoma, Texas and other states
require permits for drilling operations, drilling bonds and the filing of
reports concerning operations and impose other requirements relating to the
exploration of oil and natural gas. Many states also have statutes or
regulations addressing conservation matters including provisions for the
unitization or pooling of oil and natural gas properties, the establishment
of maximum rates of production from oil and natural gas wells and the
regulation of spacing, plugging and abandonment of such wells. The statutes
and regulations of some states limit the rate at which oil and natural gas
can be produced from our properties. The federal and state regulatory
burden on the oil and natural gas industry increases our cost of doing
business and affects its profitability. Because these rules and regulations
are frequently amended or reinterpreted, we are unable to predict the
future cost or impact of complying with those laws.
17
SAFE HARBOR STATEMENT OF FURTHER ACTIVITY
Statements in this document as well as information contained in
written material, press releases and oral statements issued by or on behalf
of us contain, or may contain, certain "forward-looking statements" within
the meaning of federal securities laws. All statements, other than
statements of historical facts, included in this document which address
activities, events or developments which we expect or anticipate will or
may occur in the future are forward-looking statements. The words
"believes," "intends," "expects," "anticipates," "projects," "estimates,"
"predicts" and similar expressions are also intended to identify forward-
looking statements. These forward-looking statements include, among
others, such things as:
. year 2001 plans;
. the amount and nature of future capital expenditures;
. wells to be drilled or reworked;
. oil and natural gas prices and demand;
. exploitation and exploration prospects;
. estimates of proved oil and natural gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and natural gas
industry;
. business strategy;
. production of oil and natural gas reserves;
. expansion and growth of our business and operations; and
. drilling rig utilization, revenues and costs.
These statements are based on certain assumptions and analyses made by
us in light of our experience and our perception of historical trends,
current conditions and expected future developments as well as other
factors we believe are appropriate in the circumstances. However, whether
actual results and developments will conform to our expectations and
predictions is subject to a number of risks and uncertainties which could
cause actual results to differ materially from our expectations, including:
. the risk factors discussed in this document;
. general economic, market or business conditions;
. the nature or lack of business opportunities that may be presented to
and pursued by us;
. demand for land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any forward-looking statements made
by us, the following discussion outlines certain factors that in the future
could cause our consolidated results for 2001 and beyond to differ
materially from those that may be set forth in any such forward-looking
statement made by or on behalf of us.
18
Commodity Prices
The prices we receive for our oil and natural gas production have a
direct impact on our revenues, profitability and cash flow as well as our
ability to meet our projected financial and operational goals. The prices
for natural gas and crude oil are heavily dependent on a number of factors
beyond our control, including 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 natural 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
differences in such prices even on a month-to-month basis. All of these
factors, especially when coupled with the fact that much of our product
prices are determined on a daily basis, can, and at times do, lead to wide
fluctuations in the prices we receive.
Based upon the results of our operations for 2000 we estimate 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
$1,797,000 and $455,000, respectively. During 2000, substantially all of
our natural gas and crude oil volumes were sold at market responsive
prices.
In order to reduce our exposure to short-term fluctuations in the
price of oil and natural gas, we sometimes enter into hedging or swap
arrangements. Our hedging or swap arrangements apply to only a portion of
our production and provide only partial price protection against declines
in oil and natural gas prices. These hedging or swap arrangements may
expose us to risk of financial loss and limit the benefit to us of
increases in prices.
Customer Demand
Demand for our 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 our drilling rigs. These include the
availability of funds to such third parties 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 our 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 our
ability to work our drilling rigs are: the weather which, under adverse
circumstances, can delay or even cause a project to be abandoned by an
19
operator; the competition faced by us in securing the award of a drilling
contract in a given area; our experience and recognition in a new market
area; and the availability of labor to run our drilling rigs.
Uncertainty Of Oil and Natural Gas Reserves and Well Performance
There are numerous uncertainties inherent in estimating quantities of
proved reserves and their values, including many factors beyond our
control. The reserve data included in this document represent only
estimates. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves depend on a number of variable factors, including
historical production from the area compared with production from other
producing areas, and assumptions concerning:
. the effects of regulations by governmental agencies;
. future oil and natural gas prices;
. future operating costs;
. severance and excise taxes;
. development costs; and
. workover and remedial costs.
Some or all of these assumptions may vary considerably from actual
results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, classifications of those reserves based on risk of recovery,
and estimates of the future net cash flows from reserves prepared by
different engineers or by the same engineers but at different times may
vary substantially. Accordingly, reserve estimates may be subject to
downward or upward adjustment. Actual production, revenues and expenditures
with respect to our reserves will likely vary from estimates, and those
variances may be material.
The information regarding discounted future net cash flows included in
this document should not be considered as the current market value of the
estimated oil and natural gas reserves attributable to our properties. As
required by the SEC, the estimated discounted future net cash flows from
proved reserves are based on prices and costs as of the date of the
estimate, while actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by the following
factors:
. the amount and timing of actual production;
. supply and demand for oil and natural gas;
. increases or decreases in consumption; and
. changes in governmental regulations or taxation.
20
In addition, the 10% discount factor, which is required by the SEC to
be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with our
operations or the oil and natural gas industry in general.
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the SEC. Under these
rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved
reserves, discounted at 10%. Application of the ceiling test generally
requires pricing future revenue at the unescalated prices in effect as of
the end of each fiscal quarter and requires a write-down for accounting
purposes if the ceiling is exceeded, even if prices were depressed for only
a short period of time. We may be required to write down the carrying value
of our oil and natural gas properties when oil and natural gas prices are
depressed or unusually volatile. If a write-down is required, it would
result in a charge to earnings but would not impact cash flow from
operating activities. Once incurred, a write-down of oil and natural gas
properties is not reversible at a later date.
We are continually identifying and evaluating opportunities to acquire
oil and natural gas properties, including acquisitions that would be
significantly larger than those consummated to date by us. We cannot
assure you that we will successfully consummate any acquisition, that we
will be able to acquire producing oil and natural gas properties that
contain economically recoverable reserves or that any acquisition will be
profitably integrated into our operations.
Debt and Bank Borrowing
We have experienced and expect to continue to experience substantial
working capital needs due to our growth in drilling operations and our
active exploration, development and exploitation programs. Historically,
we have funded our working capital needs through a combination of
internally generated cash flow, equity financing and borrowings under our
bank loan agreement. As a result of our significant working capital
requirements, we currently have, and will continue to have, a certain
amount of indebtedness. At December 31, 2000, our long-term debt
outstanding was $54.0 million. As of December 31, 2000, we had a total
loan commitment of $100 million, but we elected to limit the amount
available for borrowing under our bank loan agreement to $70 million to
reduce cost. The amount outstanding under our bank loan agreement at
December 31, 2000 was $52.0 million.
Our level of indebtedness, the cash flow needed to satisfy our
indebtedness and the covenants governing our indebtedness could:
. limit funds available for financing capital expenditures, our drilling
program or other activities or cause us to curtail these activities;
. limit our flexibility in planning for or reacting to changes in our
business;
. place us at a competitive disadvantage to some of our competitors that
21
are less leveraged than us;
. make us more vulnerable during periods of low oil and natural gas
prices or in the event of a downturn in our business; and
. prevent us from obtaining additional financing on acceptable terms or
limit amounts available under our existing or any future credit
facilities.
Our ability to meet our debt service obligations will depend on our
future performance. We cannot assure you that we will be able to meet our
debt service requirements. In addition, lower oil and natural gas prices
could result in future reductions in the amount available for borrowing
under our bank loan agreement, reducing our liquidity and even triggering
mandatory loan repayments.
If the requirements of our indebtedness are not satisfied, a default
would be deemed to occur and our lenders would be entitled to accelerate
the payment of the outstanding indebtedness. If this occurs, we cannot
assure you that we would have sufficient funds available or could obtain
the financing required to meet our obligations.
The amount of our existing debt as well as its future debt is, to a
large extent, a function of the costs associated with the projects
undertaken by us at any given time and the cash flow received by us.
Generally, the costs incurred by us in our 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 or
expansion of our drilling rig fleet. To some extent, these costs,
particularly the first two items, are discretionary and we maintain a
degree of control regarding the timing and/or the need to incur the same.
However, in some cases, unforeseen 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 us to incur increased debt above that which we had
expected or forecasted. Likewise, for many of the reasons mentioned above,
our cash flow may not be sufficient to cover our current cash requirements
which would then require us to increase our debt either through bank
borrowings or otherwise.
Item 3. Legal Proceedings
- ------- -----------------
We are a party to various legal proceedings arising in the ordinary
course of our business, none of which, in our opinion, will result in
judgments which would have a material adverse effect on our financial
position, operating results or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
- ------- ---------------------------------------------------
No matters were submitted to our security holders during the fourth
quarter of 2000.
22
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- ------- ------------------------------------------------------------------
Matters
-------
Our common stock is traded on the New York Stock Exchange under the
symbol "UNT." The following table sets forth the high and low sale prices
per share of our common stock as reported in the New York Stock Exchange
composite transactions, for the periods indicated:
1999 2000
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
First $ 7 $ 3 1/2 $ 11 1/2 $ 6 5/8
Second $ 8 1/4 $ 4 7/8 $ 14 9/16 $ 9
Third $ 9 $ 6 3/4 $ 16 1/4 $ 11 13/16
Fourth $ 7 3/4 $ 4 7/8 $ 19 7/16 $ 12 3/8
As of February 7, 2001 our common stock was held by 2,158 holders of
record.
We have not declared nor paid any cash dividends on shares of our
common stock since organization and currently intend to continue our policy
of retaining earnings from our operations. We are 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 our
consolidated net income of the preceding fiscal year, and only if working
capital provided from operations during the prior year is equal to or
greater than 175 percent of current maturities of long-term debt at the end
of the prior year.
23
Item 6. Selected Financial Data
- ------- -----------------------
Year Ended December 31,
----------------------------------------------------------
1996(1) 1997(1) 1998(1) 1999(1) 2000
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 75,751 $ 96,478 $ 97,274 $ 102,352 $ 201,264
========== ========== ========== ========== ==========
Income From
Continuing
Operations $ 9,359 $ 12,330 $ 1,428 $ 3,048 $ 34,344
========== ========== ========== ========== ==========
Net Income $ 9,359 $ 12,330 $ 1,428 $ 3,048 $ 34,344
========== ========== ========== ========== ==========
Earnings Per
Common Share:
Basic $ .38 $ .47 $ .05 $ .10 $ .96
========== ========== ========== ========== ==========
Diluted $ .38 $ .46 $ .05 $ .10 $ .95
========== ========== ========== ========== ==========
Total Assets $ 147,734 $ 213,416 $ 233,096 $ 295,567 $ 346,288
========== ========== ========== ========== ==========
Long-Term Debt $ 42,255 $ 55,480 $ 75,048 $ 67,239 $ 54,000
========== ========== ========== ========== ==========
Other Long-Term
Liabilities $ 2,360 $ 2,363 $ 2,368 $ 2,325 $ 3,597
========== ========== ========== ========== ==========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
========== ========== ========== ========== ==========
--------------------
(1) Restated for the merger with Questa Oil and Gas Co.
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1998, 1999 and 2000 activity.
24
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------- ---------------------------------------------------------------
Results of Operations
---------------------
Financial Condition and Liquidity
- ---------------------------------
On March 20, 2000, we completed the acquisition, by merger, of Questa
Oil and Gas Co.("Questa") under which Questa became a wholly owned
subsidiary of Unit Corporation. In the merger, each of Questa's
outstanding shares of common stock (excluding treasury shares) was
converted into .95 shares of our common stock. We issued approximately 1.8
million shares as a result of this merger. The merger has been accounted
for as a pooling of interests and, accordingly, all amounts within this
document have been restated, unless otherwise noted, as if the companies
had been combined during the periods presented.
Our bank loan agreement provides for a total loan facility of $100
million. Each year on April 1 and October 1 our banks redetermine our
available borrowing value. This value is primarily determined by an amount
equal to a percentage of the discounted future value of our oil and natural
gas reserves, as determined by the banks. An additional amount, limited to
$20 million, is added to the borrowing value for a percentage of the value
of a portion of our drilling rig fleet. Our loan agreement provides for a
revolving credit facility which terminates on May 1, 2002 followed by a
three year term loan. Borrowings under our loan agreement totaled $52
million at December 31, 2000 and $50 million at February 7, 2001. The
latest borrowing value computation determined the full amount of the loan
facility could be available to us, however, in order to reduce cost, we
elected to set the borrowing value at $70 million for the current borrowing
value period. We are charged a facility fee of .375 of 1 percent on any
unused portion of the available borrowing value. The loan agreement also
contains covenants which require us 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,
. a ratio of total liabilities, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.65 to 1, and
. working capital provided by operations, as defined in the loan
agreement, cannot be less than $18 million in any year.
The interest rate on our bank debt was 7.82 percent at December 31,
2000 and 6.72 percent at February 7, 2001. At our election, any portion of
our outstanding bank debt may be fixed at the London Interbank Offered Rate
("Libor Rate"), as adjusted, depending on the level of our debt as a
percentage of the available borrowing value. The Libor Rate may be fixed
for periods of up to 30, 60, 90 or 180 days with the remainder of our bank
25
debt being subject to the Chase Manhattan Bank, N. A. prime rate. During
any Libor Rate funding period, we may not pay any part of the outstanding
principal balance which is subject to the Libor Rate. Borrowings subject
to the Libor Rate were $47.0 million at December 31, 2000 and $50.0 million
at February 7, 2001.
Our shareholders' equity at December 31, 2000 was $214.5 million
giving us a ratio of long-term debt-to-total capitalization of 20 percent.
Our primary source of funds consists of the cash flow from our operations
and borrowings under our bank loan agreement. Net cash provided by our
operations in 2000 was $67.4 million compared to $24.7 million in 1999. We
had working capital of $13.3 million at December 31, 2000. Our total 2000
capital expenditures were $65.3 million, of which $39.9 million was spent
in our oil and natural gas operations. This segment's capital expenditures
consisted primarily of $30.5 million for exploration and development
drilling and $3.8 million for producing property acquisitions. Capital
expenditures for our contract drilling operations totaled $22.0 and
consisted primarily of $3.0 million to rebuild three of our drilling rigs,
$3.2 million to acquire one rig and $1.5 million to start construction on
two additional rigs. We also acquired $3.3 million in new drill pipe with
the remainder of our drilling capital expenditures for major components for
our rig fleet. We anticipate that we will spend approximately $20 million
in 2001 for drilling rig equipment.
As natural gas and oil prices increased during the last six months of
1999 and throughout 2000, we increased the drilling activity in our
exploration and production operation with the result that we drilled 101
wells during 2000 as compared to a total of 51 wells during the 1999. If
oil and natural gas prices remain favorable, we plan to drill an estimated
130 wells and spend approximately $65 million drilling or buying oil and
natural gas properties in 2001.
Most of our capital expenditures are discretionary and directed toward
our future growth. Current operations do not depend on our ability to
obtain funds outside of our loan agreement and our anticipated cash flow.
Future decisions by us to acquire or drill on oil and natural gas
properties will depend on prevailing or anticipated market conditions,
potential return on investment, future drilling potential and the
availability of opportunities to obtain financing under the circumstances
involved, thus providing us with a large degree of flexibility in
determining when and if to incur such costs.
On September 30, 1999, we completed the acquisition of 13 land
drilling rigs from Parker Drilling Company and Parker Drilling Company
North America, Inc., for 1,000,000 shares of our common stock and
$40,000,000 in cash. The cash part of this acquisition was funded through
a public offering of 7,000,000 shares of our common stock which closed on
September 29, 1999. We received proceeds of $50.1 million from the
offering net of commission fees and other costs.
On November 20, 1997, we acquired Hickman Drilling Company pursuant to
an agreement and plan of merger entered into by and between us, Hickman
Drilling Company and all of the holders of the outstanding capital stock of
Hickman Drilling Company. As part of this acquisition, the former
26
shareholders of Hickman held, as of December 31, 2000, promissory notes in
the aggregate outstanding principal amount of $3.0 million. These notes are
payable in equal annual installments on January 2, 2001 through January 2,
2003. The notes bear interest at the Chase Prime Rate which at December 31,
2000 was 9.5 percent and February 7, 2001 was 8.5 percent. At February 7,
2001, the promissory notes outstanding totaled $2.0 million.
Due to a settlement agreement which terminated at December 31, 1997,
we have a liability of $877,000 at December 31, 2000, representing proceeds
received from a natural gas purchaser as prepayment for natural gas. The
$877,000 is payable in equal annual payments on June 1, 2001 and June 1,
2002.
The average price we received for our oil in 2000 increased 54 percent
from the price we received in 1999 and our December 2000 oil price was 10
percent higher than the oil price we received in December 1999. Natural
gas prices remain volatile, but increased substantially during the year.
Our average natural gas price in 2000 was 91 percent higher than our
average 1999 price and our December 2000 natural gas price was 239 percent
higher than our December 1999 price. For the year, the average natural gas
price we received was $3.91 per Mcf and the average oil price we received
was $26.95 per barrel. Natural gas prices are influenced by weather
conditions and supply imbalances, particularly in the domestic market, and
by world wide oil price levels. Domestic oil price levels continue to be
primarily influenced by world market developments. Since natural gas
comprises approximately 90 percent of our total oil and natural gas
reserves, natural gas prices have a significant effect on the value of our
oil and natural gas reserves and large natural gas price declines could
cause us to reduce the carrying value of our oil and natural gas
properties. Any price decreases, if sustained, would also adversely affect
our future cash flow by reducing our oil and natural gas revenues and, if
continued over an extended period, could lessen not only the demand for our
contract drilling rigs but also the rate we would receive. Any declines in
natural gas and oil prices could also adversely affect the semi-annual
determination of the loan value under our bank loan agreement since this
determination is based on the value of our oil and natural gas reserves and
our drilling rigs. Such a reduction would reduce the amount available to
us under our loan agreement which, in turn, may affect our ability to carry
out our capital projects.
Generally, during the past 17 years, our contract drilling operations
have encountered significant competition, as reduced oil and natural gas
prices during most of the period created a reduction in the demand for
domestic land contract drilling rigs. However, in the last half of 1999 and
throughout 2000 as oil and natural gas prices increased we experienced a
substantial increase in demand for our rigs bringing our utilization rates
above 90 percent for the last five months of 2000. Even with the increase
in demand, we anticipate that competition within our industry will, for the
foreseeable future, continue to influence the use of our drilling rigs. In
addition to competition, our ability to use our drilling rigs at any given
time depends on a number of other factors, including the continued
strengthening of the price of both oil and natural gas, the availability of
labor and our ability to supply the type of equipment required.
27
At December 31, 2000, we had tax net operating loss carryforwards
("NOL's") of approximately $39.5 million, the benefit of which has been
recognized in our financial statements as we believe it to be more likely
than not that we will use these NOL's. Should we be unable to generate
sufficient income in future years to allow the use of all the NOL's, a
charge to expense will be required to give recognition to any loss of the
NOL's.
At December 31, 2000, one of our subsidiaries owned 4,949,500 shares
of common stock and 1,800,000 warrants in Shenandoah Resources Ltd., which
is a Canadian oil and natural gas exploration and production company. The
investment of $2,426,000 is part of other assets in our consolidated
balance sheet.
Effects of Inflation
- --------------------
In the previous 17 years the effects of inflation on our operations
have been minimal due to low inflation rates and moderate demand for
contract drilling services. In the last half of 1999 and throughout 2000,
as drilling rig day rates and drilling rig utilization increased, the
impact of inflation has increased as the availability of equipment and
third party services have decreased. Due to industry wide demand for
qualified labor, contract drilling labor cost increased substantially in
the summer of 2000. How inflation will effect us in the future will depend
on additional increases, if any, we realize in our drilling rig rates and
the prices we receive for our oil and natural gas. If industry activity
continues to increase, shortages in support equipment such as drill pipe,
third party services and qualified labor could occur resulting in
additional corresponding increases in our material and labor costs. These
conditions may limit our ability to realize improvements in operating
profits.
New 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). The statement
has subsequently been amended by FASB statements No. 137 and No. 138 and
establishes new accounting and reporting standards for derivative
instruments. We will be required to adopt this statement in the first
quarter of 2001. This statement will require us to recognize all
derivatives as either assets or liabilities on the balance sheet and
measure the effectiveness of the hedges, or the degree that the gain (loss)
for the hedging instrument offsets the loss (gain) on the hedged item, at
fair value for each reporting period. The effective portion of the gain or
loss on the derivative instrument will be recognized in other comprehensive
income as a component of our equity until the hedged item is recognized in
earnings. The ineffective portion of the derivative's change in fair value
is required to be recognized in earnings during the period the change in
value occurs. We have evaluated all of our transactions that could
potentially be classified as derivative instruments under FAS 133. The
adoption of FAS 133 will not have a significant effect on our results of
operations or financial position.
28
Results of Operations
- ---------------------
2000 versus 1999
- ----------------
Net income for 2000 was $34,344,000, compared with $3,048,000 for
1999. This increase resulted primarily from increases in our natural gas
and oil prices and production volumes. Higher oil and natural gas prices
also elevated the demand for our drilling rigs, resulting in increased
utilization of our rigs, dayrates and net income.
Our oil and natural gas revenues increased 99 percent in 2000 due to a
91 percent and 54 percent rise in the average prices we received for
natural gas and oil, respectively. For the year, natural gas production
increased by 11 percent and oil production increased by 15 percent when
compared to 1999. Production grew as we drilled 101 gross wells (40.2 net
wells) in 2000, compared to 51 gross wells (21.4 net wells) in 1999.
Natural gas production for the fourth quarter of 2000 exceeded 1999's
fourth quarter production by 11 percent.
In 2000, revenues from our contract drilling operations increased by
95 percent as the average number of our drilling rigs being used increased
from 23.1 in 1999 to 39.8 in 2000. Revenues per rig per day increased 13
percent between the comparative years. The acquisition of the Parker
drilling rigs added 6.5 rigs to our utilization rate in the fourth quarter
of 1999 and 9.0 rigs to our 2000 utilization at dayrates substantially
higher than those achieved in our other marketing area. Our rigs excluding
those acquired from Parker added 9.3 rigs to utilization and added an
additional 10 percent to their revenue per rig per day. Daywork revenues
represented 75 percent of our total drilling revenues in 2000 and 61
percent in 1999.
Operating margins (revenues less operating costs) for our oil and
natural gas operations were 79 percent in 2000 and 67 percent in 1999.
This increase resulted primarily from the increase in the average oil and
natural gas prices we received. Total operating costs between the
comparative years increased 31 percent due primarily to the 113 percent
increase in production taxes incurred as a result of higher revenues and to
a lesser extent from the addition of new wells through development
drilling.
Our contract drilling operating margins increased from 14 percent in
1999 to 22 percent in 2000. The additional operating margin was generally
due to additional revenue received per day and an increase in the number of
rigs utilized. Our contract drilling operating cost per rig per day
increased $109 in 2000 as total contract drilling operating costs were up
76 percent in 2000 versus 1999 primarily due to increased utilization.
Contract drilling depreciation increased 75 percent due to the impact
of higher depreciation per operating day associated with the newly acquired
29
Parker rigs and an overall increase in our rig utilization. Depreciation,
depletion and amortization ("DD&A") of our oil and natural gas properties
increased 8 percent due to additional production volumes. The average DD&A
rate per Mcfe decreased 4 percent to $0.82 in 2000.
General and administrative expenses increased 14 percent as certain
employee costs, outside contract services and office expenses increased due
to the growth in both of our operating segments. Interest expense
decreased 3 percent as our average outstanding debt decreased 14 percent
during 2000. The average interest rate increased from 7.0 percent in 1999
to 7.9 percent in 2000.
On May 3, 1999, our contract drilling offices in Moore, Oklahoma were
struck by a tornado destroying two buildings and damaging various vehicles
and drilling equipment. In May 1999, we received $500,000 of insurance
proceeds for the destroyed buildings, and, as a result, in the second
quarter of 1999, we recognized a gain of $315,000 recorded as part of other
revenues. During the first quarter of 2000, we received the final
insurance proceeds totaling $987,000 for the contents of the destroyed
buildings, damaged equipment and clean up costs. From these proceeds, we
recognized a gain of $599,000 recorded as part of other revenues in the
first quarter of 2000.
1999 versus 1998
- ----------------
Net income for 1999 was $3,048,000, compared with $1,428,000 in 1998.
Lower natural gas and oil prices in the first half of 1999 reduced both the
demand for our drilling rigs and the rates we received for the drilling
rigs that were operating. As a result of the merger with Questa, the oil
and gas properties of Questa were restated from the successful efforts
method of accounting to the full cost method of accounting used by Unit
Corporation. As part of this restatement, in 1998, the value of Questa's
oil and natural gas properties were impaired due to low prices at the end
of the third quarter of 1998; therefore, the Questa properties were written
down $2.6 million.
Our oil and natural gas revenues increased 7 percent in 1999 due to a
7 percent and 37 percent increase in the average prices we received for
natural gas and oil, respectively. For the year, natural gas production
decreased by 2 percent and oil production decreased by 13 percent when
compared to 1998. Our oil production declined because we in recent years
emphasized the drilling of development wells aimed at replacing and
increasing our natural gas reserves. Our natural gas production decreased
because we curtailed our development drilling program during the first half
of 1999 while oil and natural gas prices were depressed. As prices began
to improve during the last six months of 1999, our natural gas production
increased as we increased our drilling program. Natural gas production for
the fourth quarter of 1999 exceeded 1998's fourth quarter production by 4
percent.
In 1999, revenues from our contract drilling operations increased by 4
percent as the average number of drilling rigs being used increased from
22.9 in 1998 to 23.1 in 1999. Revenues per rig per day increased 3 percent
30
between the comparative years. During the first nine months of 1999 as
compared to the same period of 1998, our average drilling rig utilization
was down 22 percent and our average revenues per rig per day was down 4
percent. The acquisition of the Parker drilling rigs added 6.5 rigs to our
utilization rate in the fourth quarter of 1999 at dayrates substantially
higher than those achieved in our other marketing area. As a result, that
acquisition had a strong impact on our contract drilling fourth quarter and
year-end operating results, adding $5.6 million in revenues. Daywork
revenues represented 61 percent of our total drilling revenues in 1999 and
64 percent in 1998.
Operating margins (revenues less operating costs) for our oil and
natural gas operations were 67 percent in 1999 and 64 percent in 1998.
This increase resulted primarily from the increase in the average oil and
natural gas prices we received and a 2 percent decrease in operating costs
between the comparative years.
Our contract drilling operating margins decreased from 18 percent in
1998 to 14 percent in 1999. This reduction was generally due to decreases
during the first nine months of 1999 in both daily drilling rig revenue
rates and utilization and increases in operating costs. Total contract
drilling operating costs were up 9 percent in 1999 versus 1998 due to
increased labor costs and related benefit costs, including workers'
compensation.
Contract drilling depreciation increased 19 percent due to the impact
of higher depreciation per operating day associated with the newly acquired
Parker rigs. Depreciation, depletion and amortization ("DD&A") of our oil
and natural gas properties decreased 13 percent. Total DD&A was higher in
1998 due to the write down of Questa's oil and natural gas properties in
the third quarter of 1998, as discussed above. Decreases in production as
previously discussed also reduced DD&A in 1999. The average DD&A rate per
Mcfe increased 5 percent to $0.85 in 1999.
General and administrative expenses increased 4 percent as certain
employee benefit costs and outside services increased. Interest expense
increased 6 percent as our average outstanding debt increased 11 percent
during 1999. The average interest rate decreased from 7.1 percent in 1998
to 7.0 percent in 1999.
On May 3, 1999, our contract drilling offices in Moore, Oklahoma were
struck by a tornado destroying two buildings and damaging various vehicles
and drilling equipment. In May 1999, we received $500,000 of insurance
proceeds for the destroyed buildings, and as a result, in the second
quarter of 1999, we recognized a gain of $315,000 recorded as part of other
revenues.
31
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
- -------- ----------------------------------------------------------
Our operations are exposed to market risks primarily as a result of
changes in commodity prices and interest rates.
Commodity Price Risk - Our major market risk exposure is in the
pricing of our oil and natural gas production. The price we receive is
primarily driven by the prevailing worldwide price for crude oil and market
prices applicable to our natural gas production. Historically, prices we
have received for our oil and natural gas production have been volatile and
such volatility is expected to continue.
To reduce the impact of price fluctuations, we periodically use hedging
strategies to hedge the price we will receive for a portion of our future
oil and natural gas production. In the first quarter of 2000, we entered
into swap transactions in an effort to lock in a portion of our production
at the higher oil prices which currently existed. These transactions
applied to approximately 50 percent of our daily oil production covering
the period from April 1, 2000 to July 31, 2000 and 25 percent of our daily
oil production for August and September of 2000, at prices ranging from
$24.42 to $27.01. We have also entered into a collar contract for
approximately 25 percent of our daily production for the period covering
November 1, 2000 to February 28, 2001. The collar has a floor of $26.00
and a ceiling of $33.00 and we are receiving $0.86 per barrel for entering
into the collar transaction. During 2000, the sum of these hedging
transactions yielded a reduction in our oil revenues of $465,000.
Interest Rate Risk - Our interest rate exposure relates to our long-
term debt, all of which bears interest at variable rates based on the prime
rate or the London Interbank Offered Rate ("Libor rate"). At our election,
borrowings under our revolving credit and term loan may be fixed at the
Libor rate for periods up to 180 days. Historically, we have not utilized
any financial instruments, such as interest rate swaps, to attempt to
manage the exposure to increases in interest rates. However, we may
consider the use of such financial instruments in the future based on our
assessment of future interest rates. The impact on annual cash flow before
taxes of a one percent change in the floating rate based on our average
outstanding long-term debt in 2000 would have been approximately $628,000.
32
Item 8. Financial Statements and Supplementary Data
- ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
----------------------
1999 2000
---------- ----------
Restated,
See Note 2)
(In thousands)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 2,647 $ 726
Accounts receivable (less allowance for
doubtful accounts of $583 and $919) 22,070 40,220
Materials and supplies 3,259 3,802
Prepaid expenses and other 2,510 1,269
---------- ----------
Total current assets 30,486 46,017
---------- ----------
Property and Equipment:
Drilling equipment 177,238 196,736
Oil and natural gas properties, on
the full cost method 312,269 349,707
Transportation equipment 3,502 5,803
Other 7,694 8,801
---------- ----------
500,703 561,047
Less accumulated depreciation, depletion,
amortization and impairment 241,649 270,690
---------- ----------
Net property and equipment 259,054 290,357
---------- ----------
Other Assets 6,027 9,914
---------- ----------
Total Assets $ 295,567 $ 346,288
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
33
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
----------------------
1999 2000
---------- ----------
(Restated,
See Note 2)
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
- -----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities $ 2,027 $ 1,627
Accounts payable 14,682 21,012
Accrued liabilities 8,517 9,854
Contract advances 358 179
---------- ----------
Total current liabilities 25,584 32,672
---------- ----------
Long-Term Debt 67,239 54,000
---------- ----------
Other Long-Term Liabilities (Note 4) 2,325 3,597
---------- ----------
Deferred Income Taxes 20,914 41,479
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value,
5,000,000 shares authorized, none issued - -
Common stock, $.20 par value,
40,000,000 and 75,000,000 shares
authorized, 35,641,307 and 35,768,344
shares issued, respectively 7,128 7,154
Capital in excess of par value 139,207 139,872
Retained earnings 33,170 67,514
---------- ----------
Total shareholders' equity 179,505 214,540
---------- ----------
Total Liabilities and Shareholders' Equity $ 295,567 $ 346,288
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
34
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
-------------------------------------
1998 1999 2000
---------- ---------- ----------
(Restated, (Restated,
See Note 2) See Note 2)
(In thousands except per share amounts)
Revenues:
Contract drilling $ 53,528 $ 55,479 $ 108,075
Oil and natural gas 43,346 46,225 92,016
Other 400 648 1,173
---------- ---------- ----------
Total revenues 97,274 102,352 201,264
---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 43,729 47,721 84,051
Depreciation 5,766 6,851 11,999
Oil and natural gas:
Operating costs 15,464 15,084 19,754
Depreciation, depletion,
amortization and
impairment 19,564 17,114 18,492
General and administrative 5,543 5,750 6,560
Interest 4,950 5,268 5,136
---------- ---------- ----------
Total expenses 95,016 97,788 145,992
---------- ---------- ----------
Income Before Income Taxes 2,258 4,564 55,272
---------- ---------- ----------
Income Tax Expense:
Current 214 29 621
Deferred 616 1,487 20,307
---------- ---------- ----------
Total income taxes 830 1,516 20,928
---------- ---------- ----------
Net Income $ 1,428 $ 3,048 $ 34,344
========== ========== ==========
Net Income Per Common Share:
Basic $ .05 $ .10 $ .96
========== ========== ==========
Diluted $ .05 $ .10 $ .95
========== ========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
35
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1998, 1999 and 2000
(1998 and 1999 Restated, See Note 2)
Capital
In
Excess
Common Of Par Retained Treasury
Stock Value Earnings Stock Total
-------- ---------- --------- -------- ----------
(In thousands)
Balances,
January 1, 1998 $ 5,468 $ 81,837 $ 28,694 $ (156) $ 115,843
Net income - - 1,428 - 1,428
Activity in employee
compensation plans
(48,329 shares) 10 144 - 156 310
Retirement of Shares - (58) - - (58)
Purchase of treasury
Stock (25,000
shares) - - - (131) (131)
Questa purchase of
treasury shares - (8) - - (8)
-------- ---------- --------- -------- ----------
Balances,
December 31, 1998 5,478 81,915 30,122 (131) 117,384
Net income - - 3,048 - 3,048
Activity in employee
compensation plans
(252,511 shares) 50 680 - 131 861
Sale of Common Stock
(7,000,000 shares) 1,400 48,682 - - 50,082
Issuance of stock for
acquisition
(1,000,000
shares) 200 7,938 - - 8,138
Questa purchase of
treasury shares - (8) - - (8)
-------- ---------- --------- -------- ----------
Balances,
December 31, 1999 7,128 139,207 33,170 - 179,505
Net income - - 34,344 - 34,344
Activity in employee
compensation plans
(135,419 shares) 26 665 - - 691
-------- ---------- --------- -------- ----------
Balances,
December 31, 2000 $ 7,154 $ 139,872 $ 67,514 $ - $ 214,540
======== ========== ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
36
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------
1998 1999 2000
---------- ---------- ----------
(Restated, (Restated,
See Note 2) See Note 2)
(In thousands)
Cash Flows From Operating
Activities:
Net Income $ 1,428 $ 3,048 $ 34,344
Adjustments to reconcile
net income to net cash
provided (used) by
operating activities:
Depreciation, depletion,
amortization and
impairment 25,681 24,285 30,946
Loss (gain) on disposition
of assets 17 (400) (969)
Employee stock compensation
plans 561 436 443
Bad debt expense - 255 350
Deferred tax expense 616 1,487 20,307
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 6,425 (8,450) (18,500)
Materials and supplies 244 49 (543)
Prepaid expenses and other (441) 140 (96)
Accounts payable 882 2,667 (1,370)
Accrued liabilities 60 1,590 3,067
Contract advances 205 48 (179)
Other liabilities (447) (442) (440)
---------- ---------- ----------
Net cash provided by
operating activities 35,231 24,713 67,360
---------- ---------- ----------
The accompanying notes are an integral part of the
consolidated financial statements
37
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
------------------------------------
1998 1999 2000
---------- ---------- ----------
(Restated, (Restated,
See Note 2) See Note 2)
(In thousands)
Cash Flows From Investing
Activities:
Capital expenditures (including
producing property
acquisitions $ (56,290) $ (69,503) $ (60,447)
Proceeds from disposition of
property and equipment 964 1,438 4,259
(Acquisition) disposition
of other assets (93) 91 (2,656)
---------- ---------- ----------
Net cash used in
investing activities (55,419) (67,974) (58,844)
---------- ---------- ----------
Cash Flows From Financing
Activities:
Borrowings under line of credit 53,475 61,600 31,200
Payments under line of credit (32,900) (68,400) (44,439)
Net payments on notes payable
and other long-term debt (495) (1,090) (556)
Proceeds from sale of
common stock (21) 50,136 250
Book overdrafts (Note 1) - 2,974 3,108
Acquisition of treasury stock (131) - -
---------- ---------- ----------
Net cash provided by
(used in) financing
activities 19,928 45,220 (10,437)
---------- ---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (260) 1,959 (1,921)
Cash and Cash Equivalents,
Beginning of Year 948 688 2,647
---------- ---------- ----------
Cash and Cash Equivalents,
End of Year $ 688 $ 2,647 $ 726
========== ========== ==========
Supplemental Disclosure of Cash
Flow Information:
Cash paid during the year for:
Interest $ 4,199 $ 5,850 $ 5,135
Income taxes $ 617 $ 30 $ 519
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the
consolidated financial statements
38
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
("Unit"). The investment in limited partnerships is accounted for on the
proportionate consolidation method, whereby Unit's share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business
Unit is engaged in the land contract drilling of natural gas and oil
wells and the exploration, development, acquisition and production of oil
and natural gas properties. Unit's current contract drilling operations
are focused primarily in the natural gas producing provinces of the
Oklahoma and Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf
Coast and the Rocky Mountain regions. Unit's primary exploration and
production operations are also conducted in the Anadarko and Arkoma Basins
and in the Texas Gulf Coast area with additional properties in the Permian
Basin. The majority of its contact drilling and exploration and production
activities are oriented toward drilling for and producing natural gas. At
December 31, 2000, Unit had an interest in a total of 2,951 wells and
served as operator of 667 of those wells. Unit provides land contract
drilling services for a wide range of customers using the drilling rigs,
which it owns and operates. In 2000, all of Unit's 47 rigs owned
throughout the year 2000 were in operation. Unit acquired another rig at
the end of the year and two more rigs were under construction, making the
total rig count 50, at December 31, 2000.
Drilling Contracts
Unit recognizes revenues generated from "daywork" drilling contracts
as the services are performed, which is similar to the percentage of
completion method. Under "footage" and "turnkey" contracts, Unit bears the
risk of completion of the well therefore, 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 a 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" contracts, which are still in process at the end of
the period, and are included in other current assets.
39
Cash Equivalents and Book Overdrafts
Unit 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. Book overdrafts
are checks that have been issued prior to the end of the period, but not
presented to Unit's bank for payment prior to the end of the period. At
December 31, 1999 and 2000, book overdrafts of $3.0 million and $6.1
million have been included in accounts payable.
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. Renewals and betterments are capitalized
while repairs and maintenance are expensed. Depreciation of drilling
equipment is recorded using 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. Unit 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 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 Unit to reduce the carrying value of 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.
40
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. If an impairment is determined, the amount of such
impairment is calculated based on the estimated fair market value of the
related assets. Net goodwill reported in other assets at December 31, 1999
and 2000 was $5,575,000 and $5,331,000, respectively with accumulated
amortization at December 31, 1999 and 2000 of $507,000 and $750,000,
respectively.
Oil and Natural Gas Operations
Unit 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. Unit capitalizes internal costs that can be
directly identified with its acquisition, exploration and development
activities. Independent petroleum engineers annually review Unit's
determination of its oil and natural gas reserves. The average composite
rates used for depreciation, depletion and amortization ("DD&A") were
$0.81, $0.85 and $0.82 per Mcfe in 1998, 1999 and 2000, respectively. The
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. Unit's unproved properties
totaling $11.0 million are excluded from the DD&A calculation. 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 Unit's oil and natural gas properties. As discussed in
Note 12, such estimates are imprecise. As part of the merger with Questa,
the oil and gas properties of Questa were restated from the successful
effort method of accounting to the full cost method of accounting used by
Unit Corporation. As part of this restatement, in 1998, the value of
Questa's oil and natural gas properties were impaired due to low prices at
the end of the third quarter of 1998; therefore, the properties were
written down $2.6 million.
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 Unit has an interest or on properties in which a partnership, of
which Unit is a general partner, has an interest. Accordingly, in 1998 and
2000, Unit recorded $437,000 and $179,000 of contract drilling profits,
respectively, as a reduction of the carrying value of its oil and natural
41
gas properties rather than including these profits in current operations.
No contract drilling profits were realized on such interests in 1999.
Limited Partnerships
Unit's wholly owned subsidiary, Unit Petroleum Company, is a general
partner in sixteen oil and natural gas limited partnerships sold privately
and publicly. Some of Unit's officers, directors and employees own the
interests in most of these partnerships. Unit's wholly owned subsidiary,
Questa Oil and Gas Co., is a general partner in two additional oil and
natural gas limited partnerships sold privately. Unit shares partnership
revenues and costs in accordance with formulas prescribed in each limited
partnership agreement. The partnerships also reimburse Unit for certain
administrative costs incurred on behalf of the partnerships.
Income Taxes
Measurement of current and deferred income tax liabilities and assets
is based on provisions of enacted tax law; the effects of future changes in
tax laws or rates are not included in the measurement. Valuation
allowances are established where necessary to reduce deferred tax assets to
the amount expected to be realized. Income tax expense is the tax payable
for the year and the change during that year in deferred tax assets and
liabilities.
Natural Gas Balancing
Unit uses the sales method for recording natural gas sales. This
method allows for recognition of revenue, which may be more or less than
our share of pro-rata production from certain wells. Based upon the 2000
average natural gas price received of $3.91 per Mcf, Unit estimates its
balancing position to be approximately $6.9 million on under-produced
properties and approximately $6.0 million on over-produced properties.
Unit's policy is to expense the pro-rata share of lease operating costs
from all wells as incurred. Such expenses relating to the balancing
position on wells in which Unit has imbalances are not material.
Employee and Director Stock Based Compensation
Unit applies APB Opinion 25 in accounting for its stock option plans
for its employees and directors. 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 Unit's grants in 1998, 1999 and 2000 no
compensation expense has been recognized. As provided by Financial
Accounting Standard No. 123 "Accounting for Stock-Based Compensation," Unit
has disclosed the pro forma effects of recording compensation for such
option grants based on fair value in Note 6 to the financial statements.
42
Self Insurance
Unit 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. Accrued liabilities include $2,974,000 and
$4,462,000 for employer group health insurance and worker's compensation at
December 31, 1999 and 2000, respectively.
Financial Instruments and Concentrations of Credit Risk
Financial instruments, which potentially subject Unit to
concentrations of credit risk, consist primarily of trade receivables with
a variety of national and international oil and natural gas companies. Unit
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 Unit's customer base. During 2000, one purchaser of
Unit's oil and natural gas production accounted for approximately 12
percent of consolidated revenues. At December 31, 2000 accounts receivable
from one oil and natural gas purchaser was approximately $12.5 million. In
addition, at December 31, 1999 and 2000, Unit had a concentration of cash
of $0.4 million and $1.7 million, respectively, with one bank.
Hedging Activities
To reduce the impact of fluctuations in the market prices of oil and
natural gas, Unit periodically utilizes hedging strategies such as futures
transactions or swaps to hedge the price of a portion of its future oil and
natural gas production. Results of these hedging transactions are reflected
in oil and natural gas sales in the month of the hedged production. At
December 31, 1998 and 1999, Unit had no such hedging or derivative
transactions. In the first quarter of 2000, we entered into swap
transactions in an effort to lock in a portion of our daily production at
the higher oil prices which currently existed. These transactions applied
to approximately 50 percent of our daily oil production covering the period
from April 1, 2000 to July 31, 2000 and 25 percent of our oil production
for August and September of 2000, at prices ranging from $24.42 to $27.01.
We have also entered into a collar contract for approximately 25 percent of
our daily production for the period covering November 1, 2000 to February
28, 2001. The collar has a floor of $26.00 and a ceiling of $33.00 and we
are receiving $0.86 per barrel for entering into the collar transaction.
During 2000, the sum of these hedging transactions yielded a reduction in
our oil revenues of $465,000.
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.
43
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"). The statement
has subsequently been amended by FASB statements No. 137 and No. 138 and
establishes new accounting and reporting standards for derivative
instruments. Unit will be required to adopt this statement in the first
quarter of 2001. FASB 133 requires the recognition of all derivatives as
either assets or liabilities on the balance sheet and measure the
effectiveness of the hedges, or the degree that the gain (loss) for the
hedging instrument offsets the loss (gain) on the hedged item, at fair
value for each reporting period. The effective portion of the gain or loss
on the derivative instrument will be recognized in other comprehensive
income as a component of Unit's equity until the hedged item is recognized
in earnings. The ineffective portion of the derivative's change in fair
value is required to be recognized in earnings during the period the change
in value occurs. Unit has evaluated all of the transactions that could
potentially be classified as derivative instruments under FAS 133. The
adoption of FAS 133 will not have a significant effect on the results of
operations or financial position.
44
NOTE 2 - ACQUISITIONS AND MERGER
- --------------------------------
On March 20, 2000, Unit completed the acquisition, by merger, of
Questa Oil and Gas Co.("Questa") under which Questa became a wholly owned
subsidiary of Unit Corporation. In the merger each of Questa's outstanding
shares of common stock (excluding treasury shares) was converted into .95
shares of our common stock. Unit issued approximately 1.8 million shares
as a result of this merger. The merger has been accounted for as a pooling
of interests and, accordingly, all amounts in the financial statements have
been restated as if the companies had been combined throughout the periods
presented.
The results of operations for each company and the combined amounts
presented in Unit Corporation's consolidated financial statements are as
follows:
Three Months
Year Ended Year Ended Ended
December 31, December 31, March 31,
1998 1999 2000
-------------- -------------- --------------
(In thousands)
Revenues:
Unit Corporation $ 93,337 $ 97,453 $ 35,807
Questa 3,937 4,899 1,420
-------------- -------------- --------------
Combined $ 97,274 $ 102,352 $ 37,227
============== ============== ==============
Net Income:
Unit Corporation $ 2,246 $ 1,486 $ 3,095
Questa (818) 1,562 483
-------------- -------------- --------------
Combined $ 1,428 $ 3,048 $ 3,578
============== ============== ==============
Questa's net income has been reduced by $1,219,000 in 1998, increased
by $527,000 in 1999 and increased by $12,000 in the first quarter of 2000
to restate Questa's financial statements to the full cost method of
accounting used by Unit.
On September 30, 1999, Unit acquired 13 land drilling rigs from Parker
Drilling Company and Parker Drilling Company North America, Inc. Under the
terms of the acquisition, the sellers received 1,000,000 shares of Unit's
common stock valued at $8,138,000 and $40,000,000 in cash. The cash portion
of the consideration was funded through an offering of 7,000,000 shares of
Unit's common stock, which closed on September 29, 1999. The proceeds
received by Unit from the offering were $50,082,000 net of commission fees
and other costs. The acquisition has been accounted for as a purchase and
the results of operations of the acquired rigs have been included in the
consolidated financial statements since the date of acquisition.
45
NOTE 3 - EARNINGS PER SHARE
- ---------------------------
The following data shows the amounts used in computing earnings per
share.
WEIGHTED
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
For the Year Ended
December 31, 1998:
Basic earnings per
common share $ 1,428,000 27,370,000 $ 0.05
==========
Effect of dilutive
stock options - 340,000
------------- -------------
Diluted earnings per
common share $ 1,428,000 27,710,000 $ 0.05
============= ============= ==========
For the Year Ended
December 31, 1999:
Basic earnings per
common share $ 3,048,000 29,639,000 $ 0.10
==========
Effect of dilutive
stock options - 274,000
------------- -------------
Diluted earnings per
common share $ 3,048,000 29,913,000 $ 0.10
============= ============= ==========
For the Year Ended
December 31, 2000:
Basic earnings per
common share $ 34,344,000 35,723,000 $ 0.96
==========
Effect of dilutive
stock options 409,000
------------- -------------
Diluted earnings per
common share $ 34,344,000 36,132,000 $ 0.95
============= ============= ==========
46
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 of common
shares for the years ended December 31,:
1998 1999 2000
---------- ---------- ----------
Options 191,000 196,500 144,000
========== ========== ==========
Average exercise price $ 8.60 $ 8.49 $ 16.59
========== ========== ==========
NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
- -------------------------------------------------------
Long-term debt consisted of the following as of December 31, 1999 and
2000:
1999 2000
---------- ----------
(In thousands)
Revolving credit and term loan,
with interest at December 31,
1999 and 2000 of 7.5 percent
and 7.8 percent, respectively $ 62,400 $ 52,000
Notes payable for Hickman
Drilling Company acquisition
with interest at December 31,
1999 and 2000 of 8.5 percent
and 9.5 percent, respectively 4,000 3,000
Notes payable to banks by Questa
with interest at December 31,
1999 of 8.5 percent 2,147 -
---------- ----------
68,547 55,000
Less current portion 1,308 1,000
---------- ----------
Total long-term debt $ 67,239 $ 54,000
========== ==========
At December 31, 2000, Unit's bank 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. At
December 31, 2000, the latest borrowing value computation had determined
the full amount of the loan facility could be available to Unit, but the
company elected to set the borrowing value at $70 million in order to
reduce cost. The loan value under the revolving credit facility is subject
to a semi-annual re-determination calculated as the sum of a percentage of
47
the discounted future value of Unit's oil and natural gas reserves, as
determined by the banks. An additional amount, limited to $20 million, is
added to the borrowing value from a percentage of the value of a portion of
our drilling rig fleet. 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 1.00 to 1.50 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 or the Libor rate plus 1.25 to 1.75 percent
depending on the level of debt as a percentage of the total loan value.
At Unit'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 outstanding principal balance of the note to which such
Libor Rate option applies may not be paid. Borrowings under the Prime Rate
option may be paid anytime in part or in whole without premium or penalty.
Unit 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. Some of Unit's drilling rigs are
collateral for such indebtedness and the balance of Unit'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 Unit 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 Unit 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 Unit or any of its
subsidiaries, except in favor of its banks. The loan agreement also
requires that Unit 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, Unit completed the acquisition of Hickman Drilling
Company. In association with this acquisition, we 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.
48
At December 31, 1999, Questa had $2.1 million of notes payable to a
local bank, collateralized by certain of Questa's oil and natural gas
interests, bearing interest at the prime rate of 8.5 percent and payable in
quarterly installments of $75,000 with all remaining principal and accrued
interest due at maturity on June 30, 2001. Other 60 month notes payable of
$22,000, collateralized by automotive equipment, were owed by Questa at
December 31, 1999, at interest rates of 7.5 to 7.75 percent. All of
Questa's long-term debt was paid before Questa merged with Unit.
Other long-term liabilities consisted of the following as of December
31, 1999 and 2000:
1999 2000
---------- ----------
(In thousands)
Natural gas purchaser prepayment $ 1,317 $ 877
Separation benefit plan 1,419 1,811
Deferred compensation plan - 1,536
Rig acquisition 248 -
Questa severance tax settlement payable 60 -
---------- ----------
3,044 4,224
Less current portion 719 627
---------- ----------
Total other long-term liabilities $ 2,325 $ 3,597
========== ==========
At December 31, 2000, Unit has a prepayment balance of $877,000
representing proceeds received from a purchaser for prepayment of natural
gas under a natural gas settlement agreement, which terminated on December
31, 1997. This amount is net of natural gas recouped and net of certain
amounts disbursed to other owners for their proportionate share of the
prepayments. At termination, the December 31, 1997 prepayment balance of
$2.2 million became payable in equal annual payments over a five year
period. A payment of $441,000 is due on June 1, 2001 and the final payment
of $436,000 is due on June 1, 2002.
Unit has other long-term liabilities of $3,347,000, consisting of
$1,811,000 accrued in connection with its separation benefit plans and
$1,536,000 accrued in connection with its Deferred Compensation Plan.
Estimated annual principal payments under the terms of long-term debt
and other long-term liabilities from 2001 through 2005 are $1,627,000,
$11,549,000, $18,333,000, $17,333,000 and $7,222,000. Based on the
borrowing rates currently available to Unit for debt with similar terms and
maturities, long-term debt at December 31, 2000 approximates its fair
value.
49
NOTE 5 - INCOME TAXES
- ---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income to Unit's effective income tax
expense is as follows:
1998 1999 2000
---------- ---------- ----------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 768 $ 1,552 $ 19,345
State income tax, net of
federal benefit 77 139 1,575
Goodwill and other (15) (175) 8
---------- ---------- ----------
Income tax expense $ 830 $ 1,516 $ 20,928
========== ========== ==========
Deferred tax assets and liabilities are comprised of the following at
December 31, 1999 and 2000:
1999 2000
----------- -----------
(In thousands)
Deferred tax assets:
Allowance for losses
and nondeductible accruals $ 2,370 $ 3,308
Net operating loss carryforward 23,475 15,027
Statutory depletion carryforward 2,260 2,260
Investment tax credit carryforward 339 -
Alternative minimum tax credit
carryforward 895 1,123
----------- -----------
Gross deferred tax assets 29,339 21,718
Valuation allowance (335) -
Deferred tax liability-
Depreciation, depletion and
amortization (49,918) (63,197)
----------- -----------
Net deferred tax liability $ (20,914) $ (41,479)
=========== ===========
50
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 2000.
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, 2000, Unit has net operating loss carryforwards for
regular tax purposes of approximately $39,546,000 and net operating loss
carryforwards for alternative minimum tax purposes of approximately
$10,824,000, which expire in various amounts from 2001 to 2019. 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 6 - 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, Unit'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. On January
4, 1999, 87,376 shares of common stock were issued for payment of Unit's
1998 year-end bonuses. No shares were issued under the Plan in 1998 and
2000.
Unit also has a Stock Option Plan (the "Option Plan"), which provides
for the granting of options for up to 2,700,000 shares of common stock to
officers and employees. The Option 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 under this plan is the fair market value on the date of the grant.
51
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 1998 574,160 $ 4.28
Granted 227,000 3.96
Exercised (21,300) 2.71
Cancelled (10,500) 7.05
----------- ----------
Outstanding at December 31, 1998 769,360 4.19
Exercised (109,760) 2.76
Cancelled (2,000) 10.00
----------- ----------
Outstanding at December 31, 1999 657,600 $ 4.41
Granted 146,000 16.59
Exercised (79,700) 4.19
Cancelled (4,200) 4.94
----------- ----------
Outstanding at December 31, 2000 719,700 $ 6.87
=========== ==========
OUTSTANDING OPTIONS
------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 2.37 - $ 4.00 439,100 4.8 years $ 3.14
$ 7.25 - $16.69 280,600 8.1 years $ 12.75
52
EXERCISABLE OPTIONS
------------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
------------------------------------ ----------- -----------
$ 2.37 - $ 4.00 313,400 $ 2.90
$ 7.25 - $10.00 94,500 $ 8.69
Options for 427,000, 414,200 and 407,900 shares were exercisable with
weighted average exercise prices of $3.42, $3.96 and $4.24 at December 31,
1998, 1999 and 2000, respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Old Plan") and in February and May 2000, the Board of
Directors and shareholders, respectively, approved the Unit Corporation
2000 Non-Employee Director's Stock Option Plan (the "Directors' Plan").
Under the Directors' Plan, which replaced the Old Plan, an aggregate of
300,000 shares of Unit's common stock may be issued upon exercise of the
stock options. Under the Old Plan, on the first business day following
each annual meeting of stockholders of Unit, each person who was then a
member of the Board of Directors of Unit and who was not then an employee
of Unit or any of its subsidiaries was granted an option to purchase 2,500
shares of common stock. Under the Directors' Plan, commencing with the
year 2000 annual meeting, the amount granted has been increased to 3,500
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.
53
Activity pertaining to the Directors' Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 1998 60,000 $ 5.06
Granted 12,500 9.00
----------- ----------
Outstanding at December 31, 1998 72,500 5.74
Granted 12,500 6.90
Exercised (5,000) 5.13
Cancelled (2,500) 8.94
----------- ----------
Outstanding at December 31, 1999 77,500 5.86
Granted 17,500 12.19
----------- ----------
Outstanding at December 31, 2000 95,000 $ 7.03
=========== ==========
OUTSTANDING AND
EXERCISABLE OPTIONS
------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 1.75 - $ 3.75 32,500 2.8 years $ 3.00
$ 6.87 - $12.19 62,500 7.6 years $ 9.12
54
Unit applies APB Opinion 25 in accounting for Unit's Stock Option Plan
and Non-Employee Director's Stock Option Plan. Accordingly, based on the
nature of Unit's grants of options, no compensation cost has been
recognized in 1998, 1999 and 2000. 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 1999 2000
--------- --------- ---------
Net Income (In thousands):
As reported $ 1,428 $ 3,048 $ 33,344
========= ========= =========
Pro forma $ 1,115 $ 2,652 $ 33,986
========= ========= =========
Basic Earnings per Share:
As reported $ .05 $ .10 $ .96
========= ========= =========
Pro forma $ .04 $ .09 $ .95
========= ========= =========
Diluted Earnings per Share:
As reported $ .05 $ .10 $ .95
========= ========= =========
Pro forma $ .04 $ .09 $ .94
========= ========= =========
The fair value of each option granted is estimated using the Black-
Scholes model. Unit's estimate of stock volatility was 0.53, 0.55 and 0.55
in 1998, 1999 and 2000, respectively, based on previous stock performance.
Dividend yield was estimated to remain at zero with a risk free interest
rate of 4.95, 6.70 and 5.26 percent in 1998, 1999 and 2000, 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 and 2000 under the
Stock Option Plan were $527,000 and $1,470,000, respectively. No options
were issued under the Stock Option Plan in 1999. Under the Non-Employee
Director's Stock Option Plan the aggregate fair value of options granted
during 1998, 1999 and 2000 were $71,000, $58,000 and $99,000, respectively.
Under Unit'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. Unit may match each
employee's contribution, up to a specified maximum, in full or on a partial
basis. The Company made discretionary contributions under the plan of
46,892, 105,819 and 58,353 shares of common stock and recognized expense of
$536,000, $464,000 and $595,000 in 1998, 1999 and 2000, respectively.
Unit 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
55
employment, death or certain defined unforeseeable emergency hardships.
Funds set aside in a trust to satisfy Unit's obligation under the Deferral
Plan at December 31, 1999 and 2000 totaled $1,165,000 and $1,536,000,
respectively. Unit recognizes payroll expense and records a liability at
the time of deferral.
Effective January 1, 1997, Unit adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees whose
employment with Unit 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 weeks salary
for every whole year of service completed with Unit up to a maximum of 104
weeks. To receive payments the recipient must waive any claims against
Unit in exchange for receiving the separation benefits. On October 28,
1997, Unit adopted a Separation Benefit Plan for Senior Management ("Senior
Plan"). The Senior Plan provides certain officers and key executives of
Unit 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. Unit recognized
expense of $577,000, $502,000 and $558,000 in 1998, 1999 and 2000,
respectively, for benefits associated with anticipated payments from both
separation plans.
NOTE 7 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
Unit formed private limited partnerships (the "Partnerships") with
certain qualified employees, officers and directors from 1984 through 2000,
with a subsidiary of Unit serving as General Partner. Questa Oil and Gas
Co. formed five private limited partnerships for 1981 to 1993. 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 Unit in any additional limited partnerships formed during that
year. The Partnerships participated on a proportionate basis with Unit and
Questa, respectively, in most drilling operations and most producing
property acquisitions commenced by Unit or Questa for its own account
during the period from the formation of the Partnership through December 31
of each year. Unit repurchased the limited partner's interest in three of
five Questa partnerships in the fourth quarter of 2000 and the three
partnerships were dissolved.
56
Amounts received in the years ended December 31 from both public and
private Partnerships for which Unit and Questa are a general partner are as
follows:
1998 1999 2000
--------- --------- ---------
(In thousands)
Contract drilling $ 180 $ 94 $ 296
Well supervision and other fees $ 415 $ 425 $ 478
General and administrative
expense reimbursement $ 176 $ 175 $ 192
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 Unit paid the Partnerships, for which Unit or a
subsidiary is the general partner, $21,000, $9,000 and $6,000 during the
years ended December 31, 1998, 1999 and 2000, respectively, for purchases
of natural gas production.
NOTE 8 - SHAREHOLDER RIGHTS PLAN
- --------------------------------
Unit 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 Unit 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 Unit one one-hundredth
of a newly issued share of Series A Participating Cumulative Preferred
Stock at a price subject to adjustment by Unit 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 Unit learns that an
acquiring person (as defined in the Plan) has acquired 15 percent or more
of the outstanding common stock of Unit 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. Unit can redeem the rights for $0.01 per
right at any date prior to the earlier of (i) the close of business on the
57
tenth day following the time Unit 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 Unit.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
Unit leases office space under the terms of operating leases expiring
through January 31, 2005. Future minimum rental payments under the terms
of the leases are approximately $478,000, $393,000, $386,000, $386,000 and
$32,000 in 2001, 2002, 2003, 2004 and 2005, respectively. Total rent
expense incurred by the Company was $412,000, $422,000 and $535,000 in
1998, 1999 and 2000, respectively.
Unit 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 $1,436,000 at December 31, 2000).
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
Unit 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. Unit made repurchases of $15,000,
$10,000 and $14,000 in 1998, 1999 and 2000, respectively, for such limited
partners' interests. Subsequent to the merger, Unit also paid $17,000 for
additional interest in two of the Questa limited partnerships and
$1,980,000 for all the remaining interest in three other Questa
partnerships.
Unit is a party to various legal proceedings arising in the ordinary
course of its business none of which, in management's opinion, will result
in judgments which would have a material adverse effect on Unit's financial
position, operating results or cash flows.
58
NOTE 10 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
In 1998, Unit adopted Statement of Financial Accounting Standard No.
131, "Disclosures about Segments of an Enterprise and Related Information."
Unit 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).
Management evaluates the performance of Unit's operating segments based on
operating income, which is defined as operating revenues less operating
expenses and depreciation, depletion and amortization. Unit has natural
gas production in Canada, which is not significant.
59
1998 1999 2000
---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 53,528 $ 55,479 $ 108,075
Oil and natural gas 43,346 46,225 92,016
Other 400 648 1,173
---------- ---------- ----------
Total revenues $ 97,274 $ 102,352 $ 201,264
========== ========== ==========
Operating Income (1):
Contract drilling $ 4,033 $ 907 $ 12,025
Oil and natural gas 8,318 14,027 53,770
---------- ---------- ----------
Total operating income 12,351 14,934 65,795
General and administrative
expense (5,543) (5,750) (6,560)
Interest expense (4,950) (5,268) (5,136)
Other income (expense)- net 400 648 1,173
---------- ---------- ----------
Income before income taxes $ 2,258 $ 4,564 $ 55,272
========== ========== ==========
Identifiable Assets (2):
Contract drilling $ 69,147 $ 125,853 $ 141,324
Oil and natural gas 160,424 164,252 198,251
---------- ---------- ----------
Total identifiable assets 229,571 290,105 339,575
Corporate assets 3,525 5,462 6,713 (3)
---------- ---------- ----------
Total assets $ 233,096 $ 295,567 $ 346,288
========== ========== ==========
60
1998 1999 2000
---------- ---------- ----------
(In thousands)
Capital Expenditures:
Contract drilling $ 11,485 $ 55,656 $ 22,045
Oil and natural gas 41,046 21,532 39,884
Other 216 744 3,324
---------- ---------- ----------
Total capital expenditures $ 52,747 $ 77,932 $ 65,253
========== ========== ==========
Depreciation, Depletion,
Amortization and Impairment:
Contract drilling $ 5,766 $ 6,851 $ 11,999
Oil and natural gas 19,564 17,114 18,492
Other 351 320 455
---------- ---------- ----------
Total depreciation,
depletion, amortization
and impairment $ 25,681 $ 24,285 $ 30,946
========== ========== ==========
- ----------------------
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not
include non-operating revenues, general corporate expenses, interest
expense or income taxes.
(2) Identifiable assets are those used in Unit's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements,
furniture and equipment.
(3) Includes an investment in a Canadian oil and natural gas exploration
and production company of $2,426,000.
61
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1999 and 2000 is as
follows:
Three Months Ended
---------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ----------- ------------ -----------
Year ended (In thousands except per share amounts)
December 31, 1999:
Revenues $ 20,626 $ 20,495 $ 23,920 $ 37,311
=========== =========== =========== ===========
Gross profit(1) $ 851 $ 1,272 $ 4,551 $ 8,260
=========== =========== =========== ===========
Income (loss)
before income
taxes $ (1,760) $ (1,047) $ 1,870 $ 5,501
=========== =========== =========== ===========
Net income
(loss) $ (1,119) $ (656) $ 1,094 $ 3,729
=========== =========== =========== ===========
Earnings (loss)
per common
share:
Basic (2) $ (0.04) $ (0.02) $ 0.04 $ 0.10
=========== =========== =========== ===========
Diluted (3) $ (0.04) $ (0.02) $ 0.04 $ 0.10
=========== =========== =========== ===========
December 31, 2000:
Revenues $ 37,227 $ 43,587 $ 54,788 $ 65,662
=========== =========== =========== ===========
Gross profit(1) $ 7,719 $ 11,810 $ 18,154 $ 28,112
=========== =========== =========== ===========
Income before
Income taxes $ 5,648 $ 9,076 $ 15,622 $ 24,926
=========== =========== =========== ===========
Net income $ 3,578 $ 5,627 $ 9,685 $ 15,454
=========== =========== =========== ===========
Earnings per
Common share:
Basic $ 0.10 $ 0.16 $ 0.27 $ 0.43
=========== =========== =========== ===========
Diluted (4) $ 0.10 $ 0.16 $ 0.27 $ 0.43
=========== =========== =========== ===========
- ------------------
(1) Gross Profit excludes other revenues, general and administrative
expense and interest expense.
62
(2) As a result of shares issued during the year, earnings per share for
the year's four quarters, which is based on average shares outstanding
during each quarter, does not equal the annual earnings per share, which is
based on the average shares outstanding during the year.
(3) Due to the effect of additional shares sold in the equity offering and
issued for the Parker rig acquisition and the effect of price changes
of Unit'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.
(4) Due to the effect of price changes of Unit'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.
63
NOTE 12 - OIL AND NATURAL GAS INFORMATION
- -----------------------------------------
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 $ 279,988 $ 480 $ 280,468
Unproved properties 10,602 281 10,883
----------- --------- -----------
290,590 761 291,351
Accumulated depreciation,
depletion, amortization
and impairment (141,287) (412) (141,699)
----------- --------- -----------
Net capitalized costs $ 149,303 $ 349 $ 149,652
=========== ========= ===========
Cost incurred:
Unproved properties $ 4,856 $ 203 $ 5,059
Producing properties 9,223 - 9,223
Exploration 2,380 - 2,380
Development 24,384 - 24,384
----------- --------- -----------
Total costs incurred $ 40,843 $ 203 $ 41,046
=========== ========= ===========
1999:
Capitalized costs:
Proved properties $ 301,725 $ 508 $ 302,233
Unproved properties 9,654 382 10,036
----------- --------- -----------
311,379 890 312,269
Accumulated depreciation,
depletion, amortization
and impairment (158,147) (420) (158,567)
----------- --------- -----------
Net capitalized costs $ 153,232 $ 470 153,702
=========== ========= ===========
Cost incurred:
Unproved properties $ 1,724 $ 101 $ 1,825
Producing properties 3,733 28 3,761
Exploration 2,037 - 2,037
Development 13,909 - 13,909
----------- --------- -----------
Total costs incurred $ 21,403 $ 129 $ 21,532
=========== ========= ===========
64
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Capitalized costs:
Proved properties $ 338,159 $ 553 $ 338,712
Unproved properties 10,795 200 10,995
----------- --------- -----------
348,954 753 349,707
Accumulated depreciation,
depletion, amortization
and impairment (176,515) (435) (176,950)
----------- --------- -----------
Net capitalized costs $ 172,439 $ 318 $ 172,757
=========== ========= ===========
Cost incurred:
Unproved properties $ 5,522 $ 16 $ 5,538
Producing properties 3,752 45 3,797
Exploration 2,409 - 2,409
Development 28,140 - 28,140
----------- --------- -----------
Total costs incurred $ 39,823 $ 61 $ 39,884
=========== ========= ===========
65
The results of operations for producing activities are provided below.
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
1998:
Revenues $ 40,133 $ 55 $ 40,188
Production costs (12,684) (20) (12,704)
Depreciation, depletion
amortization and impairment (19,384) (8) (19,392)
----------- --------- -----------
8,065 27 8,092
Income tax expense (3,094) (9) (3,103)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 4,971 $ 18 $ 4,989
=========== ========= ===========
1999:
Revenues $ 42,999 $ 63 $ 43,062
Production costs (11,739) (20) (11,759)
Depreciation, depletion
and amortization (16,848) (8) (16,856)
----------- --------- -----------
14,412 35 14,447
Income tax expense (4,387) (14) (4,401)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 10,025 $ 21 $ 10,046
=========== ========= ===========
2000:
Revenues $ 88,461 $ 110 $ 88,571
Production costs (16,457) (19) (16,476)
Depreciation, depletion
and amortization (18,258) (15) (18,273)
----------- --------- -----------
53,746 76 53,822
Income tax expense (20,350) (30) (20,380)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 33,396 $ 46 $ 33,442
=========== ========= ===========
66
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 (unaudited):
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 4,596 159,012 - 723 4,596 159,735
Revision of previous
estimates (1,205) (5,484) - (162) (1,205) (5,646)
Extensions,
discoveries
and other additions 466 33,413 - - 466 33,413
Purchases of minerals
in place 261 7,169 - - 261 7,169
Sales of minerals in - -
place (3) (532) - - (3) (532)
Production (486) (17,694) - (38) (486) (17,732)
------- -------- ------- -------- ------- --------
End of Year 3,629 175,884 - 523 3,629 176,407
======= ======== ======= ======== ======= ========
Proved developed
reserves:
Beginning of year 3,871 129,422 - 295 3,871 129,717
End of year 2,749 134,504 - 421 2,749 134,925
1999:
Proved developed and
undeveloped reserves:
Beginning of year 3,629 175,884 - 523 3,629 176,407
Revision of previous
estimates 1,046 1,308 - 81 1,046 1,389
Extensions, discoveries
and other additions 157 19,398 - - 157 19,398
Purchases of minerals
in place 139 7,922 - - 139 7,922
Sales of minerals in - -
place (20) (340) (20) (340)
Production (424) (17,402) - (35) (424) (17,437)
------- -------- ------- -------- ------- --------
End of Year 4,527 186,770 - 569 4,527 187,339
======= ======== ======= ======== ======= ========
Proved developed
reserves:
Beginning of year 2,749 134,504 - 421 2,749 134,925
End of year 3,583 144,992 - 467 3,583 145,459
67
USA CANADA TOTAL
---------------- ---------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- -------- ------- --------
(In thousands)
2000:
Proved developed and
undeveloped reserves:
Beginning of year 4,527 186,770 - 569 4,527 187,339
Revision of previous
estimates (45) 6,385 - (82) (45) 6,303
Extensions, discoveries
and other additions 286 37,896 - - 286 37,896
Purchases of minerals
in place 229 4,893 - - 229 4,893
Sales of minerals in (326) (1,509) - - (326) (1,509)
place
Production (488) (19,239) - (46) (488) (19,285)
------- -------- ------- -------- ------- --------
End of Year 4,183 215,196 - 441 4,183 215,637
======= ======== ======= ======== ======= ========
Proved developed
reserves:
Beginning of year 3,583 144,992 - 467 3,583 145,459
End of year 3,222 162,718 - 389 3,222 163,107
68
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. Unit utilizes Ryder Scott
Company, independent petroleum consultants, to review our reserves as
prepared by our reservoir engineers.
Proved reserves are those quantities which, upon analysis of
geological and engineering data, appear with reasonable certainty to be
recoverable in the future from known oil and natural gas reservoirs under
existing 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
expenditure 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
escalations or de-escalations have been considered, the results are not
necessarily indicative of the estimated fair market value of estimated
proved reserves nor of estimated future cash flows.
69
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
(unaudited):
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
1998:
Future cash flows $ 418,744 $ 1,089 $ 419,833
Future production and
development costs (167,114) (271) (167,385)
Future income tax expenses (51,702) (160) (51,862)
----------- --------- -----------
Future net cash flows 199,928 658 200,586
10% annual discount for
estimated timing of cash flows (68,705) (259) (68,964)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 131,223 $ 399 $ 131,622
=========== ========= ===========
1999:
Future cash flows $ 557,915 $ 1,281 $ 559,196
Future production and
development costs (213,929) (344) (214,273)
Future income tax expenses (81,039) (175) (81,214)
----------- --------- -----------
Future net cash flows 262,947 762 263,709
10% annual discount for
estimated timing of cash flows (95,722) (285) (96,007)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 167,225 $ 477 $ 167,702
=========== ========= ===========
2000:
Future cash flows $2,260,796 $ 4,155 $2,264,951
Future production and
development costs (484,900) (433) (485,333)
Future income tax expenses (574,099) (1,099) (575,198)
----------- --------- -----------
Future net cash flows 1,201,797 2,623 1,204,420
10% annual discount for
estimated timing of cash flows (527,210) (1,184) (528,394)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 674,587 $ 1,439 $ 676,026
=========== ========= ===========
70
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows (unaudited):
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
1998:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (27,449) $ (35) $ (27,484)
Net changes in prices and
production costs (46,042) (186) (46,228)
Revisions in quantity
estimates and changes in
production timing (18,105) (335) (18,440)
Extensions, discoveries and
improved recovery, less
related costs 28,096 - 28,096
Purchases of minerals in place 6,711 - 6,711
Sales of minerals in place (603) - (603)
Accretion of discount 19,741 91 19,832
Net change in income taxes 18,352 486 18,838
Other - net 1,087 (13) 1,074
----------- --------- -----------
Net change (18,212) 8 (18,204)
Beginning of year 149,435 391 149,826
----------- --------- -----------
End of year $ 131,223 $ 399 $ 131,622
=========== ========= ===========
1999:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (31,260) $ (44) $ (31,304)
Net changes in prices and
production costs 42,319 23 42,342
Revisions in quantity
estimates and changes in
production timing 987 44 1,031
Extensions, discoveries and
improved recovery, less
related costs 24,035 - 24,035
Purchases of minerals in place 8,612 - 8,612
Sales of minerals in place (320) - (320)
Accretion of discount 8,096 44 8,140
Net change in income taxes (18,355) 7 (18,348)
Other - net 1,888 4 1,892
----------- --------- -----------
Net change 36,002 78 36,080
Beginning of year 131,223 399 131,622
----------- --------- -----------
End of year $ 167,225 $ 477 $ 167,702
=========== ========= ===========
71
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (72,005) $ (91) $ (72,096)
Net changes in prices and
production costs 647,313 1,854 649,167
Revisions in quantity
estimates and changes in
production timing 44,991 (324) 44,667
Extensions, discoveries and
improved recovery, less
related costs 184,624 - 184,624
Purchases of minerals in place 23,144 - 23,144
Sales of minerals in place (3,469) - (3,469)
Accretion of discount 19,881 51 19,932
Net change in income taxes (293,357) (581) (293,938)
Other - net (43,760) 53 (43,707)
----------- --------- -----------
Net change 507,362 962 508,324
Beginning of year 167,225 477 167,702
----------- --------- -----------
End of year $ 674,587 $ 1,439 $ 676,026
=========== ========= ===========
Unit's SMOG and changes therein were determined in accordance with
Statement of Financial Accounting Standards No. 69. Certain information
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 spot prices of oil
($25.55) and natural gas ($9.41) 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. This year-end spot natural gas price was significantly higher than
the average natural gas price of $6.89 received by Unit in December 2000
and the natural gas price that Unit expects to receive in the future.
72
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.
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 Unit's
properties. The future income tax expenses also give effect to permanent
differences and tax credits and allowances relating to Unit'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.
73
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, changes in shareholders'
equity and cash flows present fairly in all material respects, the
financial position of Unit Corporation and its subsidiaries at December 31,
1999 and 2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United
States of America. 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
auditing standards generally accepted in the United States of America 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 our opinion.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 7, 2001
74
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
information concerning each executive officer of Unit. 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 73 Chairman of the Board, Chief
Executive Officer and Director
John G. Nikkel 66 President, Chief Operating Officer
and Director
Earle Lamborn 66 Senior Vice President, Drilling and Director
Philip M. Keeley 59 Senior Vice President, Exploration
and Production
Larry D. Pinkston 46 Vice President, Treasurer and Chief Financial
Officer
Mark E. Schell 43 General Counsel and Secretary
________
Mr. Kirchner, a co-founder of Unit, has been the Chairman of the Board
and a director since 1963 and was President until November 1983. Mr.
Kirchner is a Registered Professional Engineer within the State of
Oklahoma, having received degrees in Mechanical Engineering from Oklahoma
State University and in Petroleum Engineering, with honors, from the
University of Oklahoma. Following graduation, he was employed by, Lufkin
Manufacturing as a development engineer for hydraulic pumping units. Prior
to co-founding Unit, he served in the US Army during the Korean War and
after that as vice-president - engineering and operations for Woolaroc Oil
Company.
75
Mr. Nikkel joined Unit in 1983 as its President and a director. From
1976 until January 1982 when he co-founded Nike Exploration Company, Mr.
Nikkel was an officer and director of Cotton Petroleum Corporation, serving
as the President of that Company from 1979 until his departure. Prior to
joining Cotton, Mr. Nikkel was employed by Amoco Production Company for 18
years, last serving as Division Geologist for Amoco's Denver Division. Mr.
Nikkel presently serves as President and a director of Nike Exploration
Company. Mr. Nikkel received a Bachelor of Science degree in Geology and
Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 49
years, joining Unit'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 Unit 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 Unit 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 Unit in January of 1987, as its Secretary and
General Counsel. From 1979 until joining Unit, Mr. Schell was Counsel,
Vice President and a member of the Board of Directors of C & S Exploration,
Inc. He received a Bachelor of Science degree in Political Science from
Arizona State University and his Juris Doctorate degree from the University
of Tulsa Law School. 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
incorporated by reference from Unit's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 2001
annual meeting of stockholders.
76
Item 11. Executive Compensation
- -------- ----------------------
Information required by this item is incorporated by reference from
Unit's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with Unit's 2001 annual meeting of stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- -------- --------------------------------------------------------------
Information required by this item is incorporated by reference from
Unit's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with Unit's 2001 annual meeting of stockholders.
Item 13. Certain Relationships and Related Transactions
- -------- ----------------------------------------------
Information required by this item is incorporated by reference from
Unit's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with Unit's 2001 annual meeting of stockholders.
77
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, 1999 and 2000
Consolidated Statements of Operations for the years ended
December 31, 1998, 1999 and 2000
Consolidated Statements of Changes in Shareholders' Equity for
the years ended December 31, 1998, 1999 and 2000
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1999 and 2000
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, 1999 and 2000:
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:
--------
2.1 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 Unit's
Form 8-K dated November 21, 1997, which is incorporated
herein by reference).
78
2.2 Asset Purchase Agreement dated August 12, 1999, by and among Unit
Corporation, Parker Drilling Company and Parker Drilling Company
North America, Inc. (filed as Exhibit 99.1 to Unit's Form 8-K
dated September 23, 1999, which is incorporated herein by
reference).
2.3 Agreement and Plan of Merger, dated as of December 8, 1999, among
Unit Corporation, Questa Oil & Gas Co. and Unit Acquisition
Company (filed as Appendix A to the Proxy Statement/Prospectus
which forms a part of Unit's Registration Statement on Form S-4 as
S.E.C. File No. 333-94325, which is incorporated herein by
reference).
2.4 Form of Stockholder Agreement, between Unit Corporation and the
directors and executive officers of Questa Oil & Gas Co. (filed as
Exhibit 2.2 of Unit's Registration Statement on Form S-4 as S.E.C.
File No. 333-94325, which is incorporated herein by reference).
3.1.4 Amended and Restated Certificate of Incorporation of Unit
Corporation dated May 11, 2000 (filed as Exhibit 3.1 to
Unit's Form 8-K dated June 29, 2000, which is incorporated
herein by reference).
3.2.2 By-Laws of Unit Corporation (filed as an Exhibit to Unit's
Registration Statement on Form S-3 as S.E.C. file No. 333-
83551, 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
Unit's Form 8-K dated November 21, 1997, which is
incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.1 on
Form S-3 as S.E.C. File No. 333-83551, which is incorporated
herein by reference).
4.2.6 Rights Agreement between Unit Corporation and Chemical Bank,
as Rights Agent (filed as Exhibit 1 to Unit's Form 8-A filed
with the S.E.C. on May 23, 1995, File No. 1-92601 and
incorporated herein by reference).
10.1.23 Loan Agreement dated April 30, 1998 (filed as an Exhibit to
Unit's Quarterly Report under cover of Form 10-Q for the
quarter ended June 30, 1998, which is incorporated herein by
reference).
79
10.1.24 First Amendment to the Loan Agreement effective as of May 1,
1999 between and among Unit Corporation, Bank of Oklahoma,
N.A., BankBoston, N.A., Bank of America, N.A. and Local
Oklahoma Bank, N.A. (filed as an Exhibit to Unit's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1999, 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).
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to Unit'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 Unit'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 Unit'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 Unit'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 Unit'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).
80
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to Unit'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 Unit'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
Unit'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 Unit'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 Unit's Annual
Report under cover of Form 10-K for the year ended December
31, 1995, which is incorporated herein by reference).
10.2.30* Separation Benefit Plan of Unit Corporation and Participating
Subsidiaries (filed as an Exhibit to Unit's Annual Report
under the cover of Form 10-K for the year ended December 31,
1996, which is incorporated herein by reference).
10.2.31 Unit 1997 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to Unit'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 Unit'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 Unit'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 as an Exhibit to Unit's Annual
Report under the cover of Form 10-K for the year ended
December 31, 1998).
10.2.35 Unit 2000 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to Unit's Annual
Report under the cover of Form 10-K for the year ended
December 31, 1999).
81
10.2.36* Unit Corporation 2000 Non-Employee Directors' Stock Option
Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 333-
38166, which is incorporated herein by reference).
10.2.37* Unit Corporation's Amended and Restated Stock Option Plan
(filed as an Exhibit to Unit's Registration Statement on Form
S-8 as S.E.C. File No. 333-39584 which is incorporated herein
by reference).
10.2.38 Unit 2001 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed herewith).
10.2.39* Form of Unit Corporation Key Employee Change of Control
Contract (filed herewith).
21 Subsidiaries of the Registrant (filed herewith).
23 Consent of Independent Accountants (filed herewith).
* Indicates a management contract or compensatory plan identified pursuant
to the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended
December 31, 2000.
82
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 $ 514 $ - $ 80 $ 434
========== ========== ========== ==========
Year ended
December 31, 1999 $ 434 $ 305 $ 15 $ 583
========== ========== ========== ==========
Year ended
December 31, 2000 $ 583 $ 350 $ 14 $ 919
========== ========== ========== ==========
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, 1999 $ 530 $ - $ 195 $ 335
========== ========== ========== ==========
Year ended
December 31, 2000 $ 335 $ - $ 335 $ -
========== ========== ========== ==========
83
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 20, 2001 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 20h day of March, 2001.
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
84
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
- ------- ----------------------------------------------- -----
10.2.38 Unit 2001 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
10.2.39 Form of Unit Corporation Key Employee Change
of Control Contract.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
85