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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, 2001
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 7, 2002 - $390,907,479
Number of Shares of Common Stock
Outstanding on March 7, 2002 - 36,074,419
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the
Annual Meeting of Stockholders to be held May 1, 2002 are incorporated by
reference in Part III.
Exhibit Index - See Page 94
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 . . . . . . . . . . . . . . . . . . . . . 38
Item 8. Financial Statements and Supplementary Data . . . . . . 40
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . 84
PART III
Item 10. Directors and Executive Officers of the Registrant. . . 84
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 86
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . 86
Item 13. Certain Relationships and Related Transactions. . . . . 86
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 88
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
1
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2001
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. 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.
While natural gas prices were high in early 2001, we continued to add
to our rig fleet. In January 2001, we purchased a 750 horse power diesel
electric rig with a 13,000 foot depth capacity for $3.2 million. In
February 2001, we purchased a 1,000 horse power, winterized mechanical rig,
with a 16,000 foot depth capacity, for $2.5 million. In May we acquired two
diesel electric rigs with depth capacities of 16,000 and 20,000 feet, for
$7.8 million. We also acquired a 16,000 foot depth capacity diesel electric
rig. This rig will, depending on industry conditions and additional capital
2
requirements, be placed in service when conditions warrant. The addition of
these five rigs brings our fleet to 55 at December 31, 2001, 54 of which
are currently capable of operating. Our rigs have depth capacities ranging
from 9,500 to 40,000 feet. As of March 1, 2002 twenty-nine of our rigs
were located in the Anadarko Basin of Oklahoma and Texas, 6 in the Arkoma
Basins of Oklahoma while 12 were located in the East Texas and Gulf Coast
Region and 8 in the Rocky Mountain region. As of February 20, 2002, 34 of
our drilling rigs were operating under contract.
At present, we do not have a shortage of drilling rig related
equipment. However, at any given time our ability to use all of our rigs
is dependent on a number of conditions, including 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,
-----------------------------------------------------------
1997 1998 1999 2000 2001
------ ------ ------ ------ ------
Number of Rigs
Owned at End
of Period 34.0 (1) 34.0 47.0 (2) 50.0 (3) 55.0 (4)
Average Number
of Rigs Owned
During Period 25.1 34.0 37.3 47.0 51.8
Average Number
of Rigs
Utilized (5) 20.0 22.9 23.1 39.8 46.3
Utilization
Rate (5) 80% 67% 62% 85% 90%
Average Revenue
Per Day (6) $6,309 $6,394 $6,582 $7,432 $9,879
Total Footage
Drilled
(Feet in
1000's) 1,736 2,203 2,211 3,650 4,008
Number of Wells
Drilled 167 198 197 316 361
- ---------------
(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) Includes 5 rigs acquired during the first 7 months of 2001.
(5) 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.
(6) Represents total revenues from contract drilling operations divided by
the total number of days rigs were being utilized for the period.
4
The following table sets forth, as of February 20, 2002, the type and
approximate depth capability of each of our drilling rigs:
Approximate
Depth
Capability
Rig# Type (feet)
----- --------------------------- -----------
1 BDW 650 13,000
2 BDW 650 13,000
3 BDW 650 13,500
4 Gardner Denver 500 11,000
5 U-15 Unit Rig 11,000
6 BDW 800 16,000
8 Gardner Denver 800 16,000
9 BDW 800 16,000
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 600 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
100 National 80-UE 16,000 (1)
101 Continental Emsco D-3 16,000
102 Continental Emsco A-1500 20,000
112 Ideco E-3000 25,000
166 OIME E-3000 25,000
180 OIME E-3000 25,000
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
(1) Rig 100 was acquired in 2001 and will not be refurbished and marketed
by us until industry conditions improve.
During most of the past 18 years, our contract drilling operations
encountered significant competition due to depressed levels of activity.
In the last half of 1999 through the first half of 2001, as oil and natural
gas prices increased, the demand for our contract drilling services
increased rapidly. However starting in October 2001 we began to experience
rapidly declining demand for our rigs as the prices of natural gas began to
fall from the high prices reached in January, 2001. We anticipate that
competition within the industry will, for the foreseeable future, continue
to adversely affect us.
Drilling Contracts. Our drilling contracts are predominantly obtained
through competitive bidding. Normally, 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. These contracts also
specify certain provisions regarding indemnification against certain types
of claims involving injury to persons, property and for acts of pollution.
The specific provisions regarding the responsibility for, the extent of and
the type of claims covered is subject to negotiation on a contract by
contract basis.
Our compensation under a contract is based on the type of contract
used. The contracts we use are generally one of three types: a daywork; a
footage; or a turnkey contract. Additional compensation may also be
involved 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.
Drilling operations under a turnkey contract, in particular, may
result in us incurring losses if we underestimate the costs to drill the
well or if unforeseen events occur. To date, we have not experienced
significant losses in performing turnkey contracts. In 2001, we drilled one
turnkey well and turnkey revenue represented less than one percent of our
contract drilling revenues as compared to 9 percent for 2000. We had one
turnkey contract in progress at December 31, 2001. Because market
conditions as well as the desires of our customers determine the use of
turnkey contracts, we can't predict whether the portion of drilling
conducted on a turnkey basis will increase or decrease in the future.
6
Customers. During 2001, 10 contract drilling customers accounted for
approximately 49 percent of our total contract drilling revenues.
Approximately 4 percent of our total contract drilling revenues were
generated from drilling operations performed 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).
Further information relating to contract drilling operations is
presented in Notes 1 and 10 of Notes to Consolidated Financial Statements
set forth in Item 8 hereof.
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, 2001, we had estimated net proved reserves of 4,343
Mbbls and 228,254 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, 2001, we had
an interest in a total of 2,974 wells in the United States, 688 of which we
are also the operator of. 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.
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,
--------------------------------------------------------
1999 2000 2001
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Wells Drilled:
- --------------
Exploratory:
Oil - - - - 1 .01
Natural gas - - 2 1.63 8 3.60
Dry - - - - 5 4.46
-------- -------- -------- -------- -------- --------
Total - - 2 1.63 14 8.07
======== ======== ======== ======== ======== ========
Development:
Oil 1 .48 7 1.45 6 1.06
Natural gas 55 19.23 75 28.51 87 33.51
Dry 10 5.47 17 8.56 18 10.80
-------- -------- -------- -------- -------- --------
Total 66 25.18 99 38.52 111 45.37
======== ======== ======== ======== ======== ========
Oil and Natural
Gas Wells
Producing or
Capable of
Producing:
- ---------------
Oil - USA 783 224.10 799 278.06 786 279.06
Oil -
Canada - - - - - -
Gas - USA 1,950 403.50 2,088 431.11 2,188 457.38
Gas -
Canada 64 1.60 64 1.60 64 1.60
-------- -------- -------- -------- -------- --------
Total 2,797 629.20 2,951 710.77 3,038 738.04
======== ======== ======== ======== ======== ========
On February 20, 2002, Unit was participating in the drilling of 3
gross (1.99 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
--------- --------- --------- ---------
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 603,820 154,483 87,730 52,601
========= ========= ========= =========
2001:
- -----
USA 567,731 155,890 110,489 69,229
Canada 39,040 976 7,273 3,636
--------- --------- --------- ---------
Total 606,771 156,866 117,762 72,865
========= ========= ========= =========
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,
---------------------------------
1999 2000 2001
---------- ---------- ----------
Average Sales Price per Barrel of Oil
Produced:
USA $ 17.48 $ 26.95 $ 23.62
Canada - - -
Average Sales Price per Mcf of Natural
Gas Produced:
USA $ 2.05 $ 3.91 $ 4.00
Canada $ 1.81 $ 2.39 $ 4.21
Oil Production (Mbbls):
USA 424 488 492
Canada - - -
---------- ---------- ----------
Total 424 488 492
========== ========== ==========
Natural Gas Production (MMcf):
USA 17,402 19,239 18,819
Canada 35 46 45
---------- ---------- ----------
Total 17,437 19,285 18,864
========== ========== ==========
Average Production Expense per
Equivalent Mcf:
USA $ .59 $ .74 $ .86
Canada $ .56 $ .42 $ .51
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,
---------------------------------
1999 2000 2001
---------- ---------- ----------
Oil (Mbbls):
USA 4,527 4,183 4,343
Canada - - -
---------- ---------- ----------
Total 4,527 4,183 4,343
========== ========== ==========
Natural gas (MMcf):
USA 186,770 215,196 227,865
Canada 569 441 389
---------- ---------- ----------
Total 187,339 215,637 228,254
========== ========== ==========
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 have been volatile, and we
expect that they will continue to be volatile. Oil and natural gas prices
increased substantially in the last half of 1999 and throughout 2000 and by
January 2001, the average price we received for natural gas reached $9.35
per Mcf. Prices however, started to decline sharply thereafter and by
September 2001, the average price we received for natural gas was $2.05 per
Mcf. The average price we received for oil reached a high of $28.13 per
barrel in February 2001. Oil prices then started to decline and we
received the lowest average price of the year for oil of $16.28 per barrel
in December 2001.1
Because natural gas makes up the biggest part of our oil and natural
gas reserves, changes in natural gas prices have a disproportionate impact
on our financial results than do oil price changes.
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;
. United States storage levels of natural gas;
. 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 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 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 were able to charge for our drilling services.
With the increase in oil and natural gas prices starting in the last half
of 1999 and continuing through January 2001 our dayrates and rig
utilization increased substantially.
12
Natural gas prices began to fall in February, 2001, and as a result, we
began to experience less demand for our drilling rigs starting in October,
2001 and the rates received for our rigs also began to fall. We expect
that in the near term our customers will continue a cautious approach to
exploration and development spending until prices again begin to rise. As
a result, the future extent of the 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. 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 AND CONFLICTS OF INTEREST
Our subsidiary, Unit Petroleum Company, serves as the general partner
of five oil and gas limited partnerships and 13 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 of
the oil and natural gas wells we drill or acquire for our own account
during that particular year. The limited partners in the employee
partnerships are either employees or directors of Unit or its subsidiaries.
One of the companies we acquired, Questa Oil and Gas Co., also served as
the general partner of five private limited partnerships. We repurchased
the limited partners' interest in three of the five Questa partnerships in
the fourth quarter of 2000 and three of the partnerships were dissolved. In
the first quarter of 2001, we purchased additional interests in the
remaining two Questa partnerships and subsequently dissolved one of those
partnerships.
Under the terms of our 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 entirely
eliminate such conflicts. Additionally, conflicts of interest may arise
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
13
done under contracts containing terms and conditions comparable to those
contained in our drilling contracts with non-affiliated operators. 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 20, 2002, we had approximately 949 employees in our
land contract drilling operations, 58 employees in our oil and natural gas
operations and 51 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 the many hazards inherent in
the drilling industry, including injury or death to personnel, 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 our
drilling customers, we seek protection through insurance. However, our
insurance or our indemnification agreements, if any, may not adequately
protect us against liability from all of the consequences of the hazards
described above. In addition, even if we have insurance coverage we may
still have a degree of exposure based on the amount of our deductible. 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 may not be able to obtain
insurance 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;
. adverse weather conditions;
14
. 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 our oil and natural gas operations.
However, it is possible that we may not be able to continue to replace
reserves from such activities. Low prices of oil and natural gas may
further limit the kinds of reserves that we can economically develop.
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.
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
15
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
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,
16
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.
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:
17
. our year 2002 plans;
. the amount and nature of our future capital expenditures;
. the number of wells we intend to drill or rework;
. demand for our oil and natural gas and the price we will be paid for
such production;
. our oil and natural gas prospects;
. estimates of our proved oil and natural gas reserves;
. reserve potential;
. development and infill drilling potential;
. expansion and other development trends of the oil and natural gas
industry;
. our business strategy;
. production of our oil and natural gas reserves;
. expansion and growth of our business and operations; and
. the use of our drilling rig services and what we will be paid for such
services.
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.2 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 our 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 2002 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.
Commodity Prices
The prices we receive for our oil and natural gas production have a
direct impact on the amount of our revenues, our profitability and the
amount of our 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
18
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 on our 2001 production, a $.10 per Mcf change in what we are
paid for our natural production would result in a corresponding $146,000
per month ($1,752,000 annualized) change in our pre-tax cash flow. A $1.00
per barrel change in our oil price would have a $33,000 per month ($396,000
annualized) change in our pre-tax cash flow. During 2001, 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.
Drilling 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
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
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
19
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.
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
20
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 and development 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 working capital requirements, we currently have, and
will continue to have, a certain amount of indebtedness. At December 31,
2001, our long-term debt outstanding was $31.0 million. As of December 31,
2001, 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
$60 million to reduce cost. The amount outstanding under our bank loan
agreement at December 31, 2001 was $30.0 million.
Our level of debt, the cash flow needed to satisfy our indebtedness
and the covenants governing our indebtedness could:
. limit funds otherwise available for financing our 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
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. 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 would not have sufficient funds available nor would we be
able to obtain the financing required to meet our obligations.
21
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 2001.
22
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- ------- ------------------------------------------------------------------
Matters
-------
Our common stock trades on the New York Stock Exchange under the
symbol "UNT." The following table identifies the high and low sales prices
per share of our common stock for the periods indicated:
2000 2001
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
First $ 11.5000 $ 6.6250 $ 21.3750 $ 16.3000
Second $ 14.5625 $ 9.0000 $ 23.0000 $ 14.5000
Third $ 16.2500 $ 11.8125 $ 15.8000 $ 7.4100
Fourth $ 19.4375 $ 12.3750 $ 14.2400 $ 8.2900
On February 20, 2002, there were 1,985 record holders of our common
stock.
We have never paid cash dividends on our common stock and currently
intend to continue our policy of retaining earnings from our operations.
Our loan agreement prohibits us from declaring and paying dividends (other
than stock dividends) in any fiscal year in an amount greater than 25
percent of our preceding year's consolidated net income and then only if
our working capital provided from operations for the previous year was
equal to or greater than 175 percent of the current maturities of our long-
term debt at the end of the previous year.
23
Item 6. Selected Financial Data
- ------- -----------------------
Year Ended December 31,
----------------------------------------------------------
1997 (1) 1998 (1) 1999 (1) 2000 2001
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 96,478 $ 97,274 $ 102,352 $ 201,264 $ 259,179
========== ========== ========== ========== ==========
Net Income $ 12,330 $ 1,428 $ 3,048 $ 34,344 $ 62,766
========== ========== ========== ========== ==========
Earnings Per
Common Share:
Basic $ .47 $ .05 $ .10 $ .96 $ 1.75
========== ========== ========== ========== ==========
Diluted $ .46 $ .05 $ .10 $ .95 $ 1.73
========== ========== ========== ========== ==========
Total Assets $ 213,416 $ 233,096 $ 295,567 $ 346,288 $ 417,253
========== ========== ========== ========== ==========
Long-Term Debt $ 55,480 $ 75,048 $ 67,239 $ 54,000 $ 31,000
========== ========== ========== ========== ==========
Other Long-Term
Liabilities $ 2,363 $ 2,368 $ 2,325 $ 3,597 $ 4,110
========== ========== ========== ========== ==========
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 1999, 2000 and 2001 activity.
24
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------- ---------------------------------------------------------------
Results of Operations
---------------------
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Our financial condition and liquidity, for current operations, depends
on our cash flow from operating activities and borrowings under our bank
loan agreement. Our cash flow is influenced mainly by the prices we receive
for our natural gas production, the demand for and the dayrates we receive
for our drilling rigs and, to a lesser extent, the prices we receive for
our oil production. Our loan agreement provides for a revolving credit
facility, which terminates on May 1, 2005 followed by a three-year term
loan. At December 31, 2001, we had borrowed $30.0 million, which was 50
percent of the amount available, as elected by us on October 1, 2001, and
represented 30 percent of the loan value of our assets as determined by our
banks on October 1, 2001. Most of our capital expenditures are
discretionary and directed toward future growth.
Our Oil and Natural Gas Operations. Natural gas comprises
approximately 90 percent of our total oil and natural gas reserves. Any
appreciable change in natural gas prices has a significant affect on our
revenues, cash flow and the value of our oil and natural gas reserves. Such
price changes also influence the demand for our natural gas production, our
drilling rigs (since they are used mainly to drill natural gas wells) and
the amount we can charge for our contract drilling services.
Based on our 2001 production, a $.10 per Mcf change in what we are
paid for our natural production would result in a corresponding $146,000
per month ($1,752,000 annualized) change in our pre-tax cash flow. Our 2001
average natural gas price declined from a high of $9.35 per Mcf in January
to $2.05 per Mcf in September (an 78 percent decrease) before recovering to
$2.16 per Mcf in December. For the year, our average natural gas price was
$4.00 per Mcf. A $1.00 per barrel change in our oil price would have a
$33,000 per month ($396,000 annualized) change in our pre-tax cash flow. We
received the highest average oil price for the year during February at
$28.13 per barrel. For the balance of the year oil prices declined
resulting in our lowest average oil price of $16.28 per barrel in December.
Our average oil price for the year was $23.62 per barrel.
Generally, prices and demand for domestic natural gas are influenced
by weather conditions, supply imbalances and by world wide oil price
levels. Domestic oil prices are primarily influenced by world oil market
developments. All of these factors are beyond our control and we can not
predict nor measure their future influence on the prices we will receive.
Because natural gas prices have such a significant affect on the value
of our oil and natural gas reserves declines in these prices can result in
a reduction of the carrying value of our oil and natural gas properties.
Likewise, price declines can also adversely affect the semi-annual
25
determination of the amount available for us to borrow under our bank loan
agreement since that determination is based mainly on the value of our oil
and natural gas reserves. Such a reduction could limit our ability to
carry out our planned capital projects.
Hedging Activities. Periodically we hedge the prices we will receive
for a portion of our future natural gas and oil production. We do so in an
attempt to reduce the impact and uncertainty that price fluctuations have
on our cash flow. In the first quarter of 2000, we entered into swap
transactions to lock in a portion of our oil production at higher oil
prices. 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 entered into a collar contract
covering approximately 25 percent of our daily oil production from November
1, 2000 through February 28, 2001. The collar had a floor of $26.00 per
barrel and a ceiling of $33.00 per barrel and we received $0.86 per barrel
for entering into the transaction. During 2000, the net effect of our oil
hedging transactions for oil reduced our oil revenues by $465,000. We did
not have any hedging transactions for natural gas in 2000. During the first
quarter of 2001, our oil hedging transaction yielded an increase in our oil
revenues of $17,200.
We entered into a natural gas collar contract for approximately 36
percent of our June and July 2001 natural gas production at a floor price
of $4.50 and a ceiling price of $5.95. We also entered into two natural
gas collar contracts for approximately 38 percent of our September through
November 2001 natural gas production. Both contracts had a floor price of
$2.50. One contract had a ceiling price of $3.68 and the other contract had
a ceiling price of $4.25. For the year our natural gas collar contracts
added $2,030,000 to our natural gas revenues. We did not have any hedging
transactions outstanding at December 31, 2001 nor on February 20, 2002.
Contract Drilling Operations. Our drilling operations are subject to
many factors that influence the number of rigs we have working at any one
time as well as the costs and revenues associated with such work. These
factors include competition from other drilling contractors, the prevailing
prices for natural gas and oil, the availability of labor to operate our
rigs and our ability to supply the type of equipment required. We have not
encountered major difficulty in hiring and retaining rig crews, but such
shortages have occurred periodically in the past. If demand for drilling
rigs was to increase rapidly in the future, shortages of experienced
personnel would limit our ability to increase the number of rigs we could
operate.
Low oil and natural gas prices during most of the 1980's and 1990's
reduced 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.
Our average utilization of 44.6 rigs (95 percent) in January 2001 increased
to 51.9 rigs (96 percent) in July before dropping to 33.5 rigs (62 percent)
in December 2001. Our average utilization for the year was 46.3 rigs (90
percent).
26
As demand for our rigs increased during the year so did the dayrates
we received. Our average dayrate in January was $8,176 and by September it
had increased to $11,142. However, as demand began to decrease so did our
rates and by December our average dayrate was $9,594. That rate has
continued to fall into the first quarter of 2002. Based on the average
utilization rate we achieved in 2001, a $100 per day change in dayrates has
a $4,630 per day ($1,690,000 annualized) change in our pre-tax operating
cash flow.
We anticipate that for the first half of 2002 the number of our rigs
operating will range in the mid to high thirties and dayrates will continue
to decline early in the first quarter before stabilizing. Utilization and
dayrates for the last half of 2002 and beyond will depend mainly on the
price of natural gas during the first half of 2002 and beyond. Even if
demand increases in 2002, we anticipate that competition will continue to
influence our operations.
Bank Loan Agreement. On July 24, 2001, we signed a $100 million bank
loan agreement. At our election the amount currently available for us to
borrow is set at $60 million. Although the current value of our assets
would have allowed us to have access to the full $100 million, we elected
to set the loan commitment at $60 million in order to reduce financing
costs since we are charged a facility fee of .375 of 1 percent on the
amount available but not borrowed.
Each year on April 1 and October 1 our banks redetermine the loan
value of our assets. This value is primarily determined to be an amount
equal to a percentage of the discounted future value of our oil and natural
gas reserves, as determined by the banks. In addition, an amount
representing a part of the value of our drilling rig fleet, limited to $20
million, is added to the loan value. Our loan agreement provides for a
revolving credit facility which terminates on May 1, 2005 followed by a
three-year term loan. Borrowing under our loan agreement totaled $30.0
million at December 31, 2001 and $28.0 million on February 20, 2002.
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 loan value. Subsequent
to May 1, 2005, 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. In addition, the
loan agreement allows us to select, at any time between the date of the
agreement and 3 days prior to the start of the term loan, a fixed rate for
the amount outstanding under the credit facility. Our ability to select the
fixed rate option is subject to a number of conditions, all of which are
more fully set out in the loan agreement.
The interest rate on our bank debt was 3.3 percent at December 31,
2001 and 3.0 percent on February 20, 2002. At our election, any portion of
our outstanding bank debt may be fixed at the Libor Rate, as adjusted
depending on the level of our debt as a percentage of the amount available
for us to borrow. The Libor Rate may be fixed for periods of up to 30, 60,
90 or 180 days with the remainder of our bank debt being subject to the
27
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 $28.0 million at December 31,
2001 and February 20, 2002.
The loan agreement requires us to maintain consolidated net worth of
at least $125 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 our
operations, as defined in the loan agreement, cannot be less than $40
million in any year. We are prohibited from paying dividends (other than
stock dividends) during any fiscal year in excess of 25 percent of our
consolidated net income from the preceding fiscal year and we can pay
dividends only if working capital provided from our operations during the
preceding year is equal to or greater than 175 percent of current
maturities of long-term debt at the end of the preceding year. We also
cannot incur additional debt except in certain very limited exceptions and
the creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any of our property is prohibited unless it
is in favor of our banks.
Shareholders' Equity, Working Capital and Capital Expenditures. Our
shareholders' equity at December 31, 2001 was $279.2 million giving us a
ratio of long-term debt-to-total capitalization of 10 percent. Net cash
provided by operations in 2001 was $133.0 million compared to $67.4 million
in 2000. We had working capital of $17.6 million at December 31, 2001. Our
total 2001 capital expenditures were $108.8 million ($400,000 net in
accounts payable), of which $56.9 million was spent on our oil and natural
gas operations, $51.3 million was spent on our drilling segment and
$539,000 was spent primarily on furniture and fixtures and leasehold
improvements.
Additional Oil and Gas Information. Our decisions on whether we try
to increase our oil and natural gas reserves through acquisitions or
through drilling depends on the prevailing or anticipated market
conditions, potential return on investment, future drilling potential and
the availability of opportunities to obtain financing under the
circumstances involved, all of which tend to provide us with a large degree
of flexibility in determining when and if to incur such costs. As a result
of the high natural gas prices during the last half of 2000 and into the
first half of 2001, there were not many opportunities during 2001 to
acquire producing properties at prices we consider attractive. As a result
we spent $48.0 million on exploration and development drilling, $7.5
million for undeveloped leasehold and only $1.4 million for producing
property acquisitions. We drilled 125 wells in 2001 as compared with 101
wells in 2000. Based on current prices, for 2002, we plan to drill an
estimated 140 wells and have total capital expenditures of approximately
$65 million for exploration, development drilling and acquisition of oil
and natural gas properties.
28
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 was accounted for as
a pooling of interests and, accordingly, all amounts prior to the merger
were restated, unless otherwise noted, as if the companies had been
combined during the periods presented.
Additional Drilling Information. While natural gas prices were high
in early 2001, we continued to add to our rig fleet. In January 2001, we
purchased a 750 horse power diesel electric rig with a 13,000 foot depth
capacity for $3.2 million. This rig was working in our Gulf Coast region at
December 31, 2001. In February 2001, we purchased a 1,000 horse power,
winterized mechanical rig, with a 16,000 foot depth capacity, for $2.5
million. This rig was under contract in our Rocky Mountain region on
December 31, 2001. In May we acquired two diesel electric rigs with depth
capacities of 16,000 and 20,000 feet, for $7.8 million. These two rigs are
both working in our Gulf Coast region. We also acquired a 16,000 foot depth
capacity diesel electric rig. This rig will, depending on industry
conditions and additional capital requirements, be placed in service when
conditions warrant. The addition of these five rigs brings our fleet to
55, 54 of which are currently capable of operating. During 2001, we spent
$38.7 million for new drilling rigs, drilling rig components and
refurbishments of existing rigs, $11.6 million for new drill pipe and
collars and $1.0 million for transportation equipment. For 2002 we
anticipate that we will spend approximately $20 million on our drilling
operations.
Our contract drilling segment provides drilling services for our
exploration and production segment. The contracts for these services are
issued under the same conditions and rates as the contracts that we are in
with unrelated parties. The profit received by our contract drilling
segment of $179,000 and $2,259,000 in 2000 and 2001, respectively, for this
work was used to reduce the carrying value of our oil and natural gas
properties rather than being included in our profits in current operations.
29
Contractual Commitments. We have various contractual obligations at
December 31, 2001, which are as follows:
Payments Due by Period
-----------------------------------------------
Less
Contractual Than 1 2-3 4-5 After 5
Obligations Total Year Years Years Years
------------- --------- ------- -------- --------- --------
(In thousands)
Bank Debt(1) $ 30,000 $ - $ - $ 15,833 $14,167
Hickman
Note(2) 2,000 1,000 1,000 - -
Retirement
Agreement(3) 1,330 20 470 600 240
Gas Purchaser
Prepay-
ment(4) 437 437 - - -
Operating
Leases(5) 2,306 654 1,296 344 12
--------- ------- -------- --------- --------
Total
Contractual
Obligations $ 36,073 $2,111 $ 2,766 $ 16,777 $14,419
========= ======= ======== ========= ========
-------------------
(1) See Previous Discussion in Management Discussion and Analysis
regarding bank debt.
(2) 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 shareholders of Hickman
held, as of December 31, 2001, promissory notes in the aggregate
outstanding principal amount of $2.0 million (See Note 4 of our
Consolidated Financial Statements). These notes are payable in
equal annual installments on January 2, 2002 and January 2, 2003.
The notes bear interest at the Chase Prime Rate, which at
December 31, 2001 and February 20, 2002 was 4.75 percent. At
February 20, 2002 the promissory notes outstanding totaled $1.0
million.
(3) In the second quarter of 2001, we recorded $1.3 million in
additional employee benefit expenses for the present value of a
separation agreement made in connection with the retirement of
King Kirchner from his position as Chief Executive Officer. The
liability associated with this expense, including accrued
interest, will be paid in $25,000 monthly payments starting in
July 2003 and continuing through June 2009 (See Note 4 of our
Consolidated Financial Statements).
(4) Due to a settlement agreement, which terminated at December 31,
1997, we have a liability of $437,000 at December 31, 2001,
included in current portion of long-term debt on our Consolidated
30
Balance Sheet, representing proceeds received from a natural gas
purchaser as prepayment for natural gas. The $437,000 is payable on
June 1, 2002.
(5) We lease office space in Tulsa, Houston and Woodward under the
terms of operating leases expiring through January 31, 2007 (See
Note 9 of our Consolidated Financial Statements).
At December 31, 2001, we also have the following commitments and
contingencies that could create, increase or accelerate our liabilities:
Amount of Commitment Expiration
Per Period
-------------------------------------
Total
Amount
Committed Less
Other Or Than 1 2-3 4-5 After 5
Commitments Accrued Year Years Years Years
--------------- --------- -------- -------- -------- --------
(In thousands)
Deferred
Compensation
Agreement(1) $ 1,277 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 1,959 $ 436 Unknown Unknown Unknown
Repurchase
Obliga-
tions(3) Unknown Unknown Unknown Unknown Unknown
(1) We provide a salary deferral plan which allows participants to
defer the recognition of salary for income tax purposes until
actual distribution of benefits, which occurs at either
termination of employment, death or certain defined unforeseeable
emergency hardships. We recognize payroll expense and record a
liability, included in other long-term liabilities in our
Consolidated Balance Sheet, at the time of deferral (See Note 6
of our Consolidated Financial Statements).
(2) Effective January 1, 1997, We adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible
employees whose employment with us 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 us
in exchange for receiving the separation benefits. On October
28, 1997, we 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 (See Note 6 of our
31
Consolidated Financial Statements).
(3) We formed The Unit 1984 Oil and Gas Limited Partnership and the
1986 Energy Income Limited Partnership along with private limited
partnerships (the "Partnerships") with certain qualified
employees, officers and directors from 1984 through 2002, with a
subsidiary of ours serving as General Partner. The Partnerships
were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as
co-general partner with us in any additional limited partnerships
formed during that year. The Partnerships participated on a
proportionate basis with us in most drilling operations and most
producing property acquisitions commenced by us for our own
account during the period from the formation of the Partnership
through December 31 of each year. These partnership agreements
require, upon the election of a limited partner, that we
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. We
made repurchases of $10,000 and $14,000 in 1999 and 2000,
respectively, for such limited partners' interests. No
repurchases were made in 2001 (See Note 9 of our Consolidated
Financial Statements).
Oil and Natural Gas Limited Partnerships. We are the general partner
for eighteen oil and natural gas partnerships which were formed privately
and publicly. The partnership's revenues and costs are shared in accordance
with formulas prescribed in each limited partnership agreement. The
partnerships reimburse us for contract drilling, well supervision and
general and administrative expense reimbursements. Related party
transactions for contract drilling and well supervision fees are the
related party's share of such costs. These costs are billed on the same
basis as billings to unrelated parties for similar services. General and
administrative reimbursements consist of direct general and administrative
expense incurred on the related party's behalf as well as 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. During the 1999, 2000 and 2001, the total paid to us for all
of these fees was $694,000, $966,000 and $1,107,000, respectively. Our
proportionate share of assets, liabilities and net income relating to the
oil and natural gas partnerships is included in our consolidated financial
statements.
At December 31, 2001, we owned a 40 percent equity interest in a
natural gas gathering and processing company. Our balance sheet investment
and equity in the company totaled $1.6 million at December 31, 2001. At
December 31, 2001 and February 20, 2002, we were not guaranteeing any
indebtedness of the gas gathering and processing company.
At December 31, 2001, one of our subsidiaries owned 4,949,500 shares
of common stock and 1,800,000 warrants of Shenandoah Resources Ltd., a
Canadian oil and natural gas exploration and production company. The
investment of $346,000 is part of other assets in our consolidated balance
sheet and was written down by $2.1 million during 2001.
32
Critical Accounting Policies. We account for our oil and natural gas
exploration and development activities using the full cost method of
accounting. Under this method, all costs incurred in the acquisition,
exploration and development of oil and natural gas properties are
capitalized. At the end of each quarter, the net capitalized costs of our
oil and natural gas properties is limited to the lower of unamortized cost
or a ceiling. The ceiling is defined as the sum of the present value (10
percent discount rate) of estimated future net revenues from proved
reserves, based on period-ending oil and natural gas prices, plus the lower
of cost or estimated fair value of unproved properties included in the
costs being amortized less related income tax. If the net capitalized costs
of our oil and natural gas properties exceed the ceiling, we are subject to
a ceiling test write-down to the extent of such excess. A ceiling test
write-down is a non-cash charge to earnings. If required, it reduces
earnings and impacts stockholders' equity in the period of occurrence and
results in lower depreciation, depletion and amortization expense in future
periods.
The risk that we will be required to write-down the carrying value of
our oil and natural gas properties increases when oil and natural gas
prices are depressed or if we have substantial downward revisions in our
estimated proved reserves. Application of these rules during periods of
relatively low oil or natural gas prices, even if temporary, increases the
probability of a ceiling test write-down. Based on oil and natural gas
prices in effect on December 31, 2001 ($2.51 per Mcf for natural gas and
$17.71 per barrel for oil), the unamortized cost of our domestic oil and
natural gas properties did not exceed the ceiling of our proved oil and
natural gas reserves. Natural gas pricing has been erratic since year-end
and any significant declines below year-end prices used in the reserve
evaluation would likely result in a ceiling test write-down in subsequent
quarterly reporting periods.
The value of our oil and natural gas reserves is used to determine the
loan value under our loan agreement. This value is affected by both price
changes and the measurement of reserve volumes. Oil and natural gas
reserves cannot be measured exactly. Our estimate of oil and natural gas
reserves require extensive judgments of our reservoir engineering data and
are generally less precise than other estimates made in connection with
financial disclosures. 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. We
utilizes Ryder Scott Company, independent petroleum consultants, to review
our reserves as prepared by our reservoir engineers.
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. Renewals and betterments are capitalized
while repairs and maintenance are expensed. 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
33
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.
Under "footage" and "turnkey" contracts, we bear the risk of
completion of the well, so revenues and expenses are recognized using the
completed contract method. The entire amount of a loss, if any, is recorded
when the loss can be determined. 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.
EFFECTS OF INFLATION
- --------------------
In the 18 years prior to the last half of 1999, the effects of
inflation on our operations was minimal due to low inflation rates and
moderate demand for contract drilling services. However, starting in the
last half of 1999 and throughout 2000 and the first three quarters of 2001,
as drilling rig dayrates and utilization increased, the impact of inflation
increased as the availability of used equipment and third party services
decreased. Due to industry-wide demand for qualified labor, contract
drilling labor costs increased substantially in the summer of 2000 and once
again in the summer of 2001. How inflation will affect us in the future
will depend on additional increases, if any, realized in our drilling rig
rates and the prices we receive for our oil and natural gas. If industry
activity recovers and returns to levels achieved in early 2001, 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 January 1, 2001, we adopted Statement of Financial Accounting
Standard No. 133 (subsequently amended by Financial Accounting Standard
No.'s 137 and 138), "Accounting for Derivative Instruments and Hedging
Activities" (FAS 133). This statement requires all derivatives to be
recognized on the balance sheet and measured at fair value. If a
derivative is designated as a cash flow hedge, we are required to measure
the effectiveness of the hedge, or the degree that the gain (loss) for the
hedging instrument offsets the loss (gain) on the hedged item, at each
reporting period. The effective portion of the gain (loss) on the
derivative instrument is recognized in other comprehensive income as a
component of equity and subsequently reclassified into earnings when the
forecasted transaction affects earnings. The ineffective portion of a
derivative's change in fair value is required to be recognized in earnings
immediately. Derivatives that do not qualify for hedge treatment under FAS
133 must be recorded at fair value with gains (losses) recognized in
34
earnings in the period of change. We periodically enter into derivative
commodity instruments to hedge our exposure to price fluctuations on oil
and natural gas production. Such instruments include regulated natural gas
and crude oil futures contracts traded on the New York Mercantile Exchange
(NYMEX) and over-the-counter swaps and basic hedges with major energy
derivative product specialists. At December 31, 2001, we were not holding
any natural gas or oil derivative contracts.
On July 20, 2001, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 142, "Goodwill and
Other Intangible Assets" (FAS 142). For goodwill and intangible assets
already recorded in the financial statements, FAS 142 ends the amortization
of goodwill and certain intangible assets and subsequently requires, at
least annually, that an impairment test be performed on such assets to
determine whether the fair value has changed. We expensed $243,000
annually for the amortization of goodwill, and the unamortized balance of
goodwill is $5,088,000 at December 31, 2001. FAS 142 is effective for the
fiscal years starting after December 15, 2001 (January 1, 2002 for us). We
do not believe the future impact from the adoption of FAS 142 on our
financial position or results of operation will be material.
In July 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS
143). FAS 143 is effective for fiscal years beginning after June 15, 2002
(January 1, 2003 for us) and establishes an accounting standard requiring
the recording of the fair value of liabilities associated with the
retirement of long-lived assets (mainly plugging and abandonment costs for
our depleted wells) in the period in which the liability is incurred (at
the time the wells are drilled). We have not yet determined the effect of
the adoption of FAS 143 on our financial position or results of operations.
In August 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" (FAS 144). FAS 144 is effective for fiscal years beginning after
December 15, 2001 (January 1, 2002 for us). This statement supersedes
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of" and amends Accounting Principles Board Opinion No. 30 for the
accounting and reporting of discontinued operations, as it relates to long-
lived assets. We do not believe the future impact from the adoption of FAS
144 on our financial position or results of operations will be material.
35
RESULTS OF OPERATIONS
- ---------------------
2001 versus 2000
- ----------------
Net income for 2001 was $62,766,000, compared with $34,344,000 for
2000. This increase was due to increases in the use of our drilling rigs,
as well as, the dayrates we received for the use of the drilling rigs.
High natural gas prices in the last quarter of 2000 and the first quarter
of 2001 increased the demand for our drilling rigs which in turn pushed
contract drilling dayrates higher.
Our oil and natural gas revenues decreased 2 percent in 2001 when
compared with 2000. The average natural gas prices we received in 2001
increased 2 percent, but this increase was offset by a 2 percent reduction
in our natural gas production. The average oil price we received dropped
12 percent while oil production increased one percent between the
comparative years. We drilled 125 gross wells (53.4 net wells) in 2001,
compared to 101 gross wells (40.2 net wells) in 2000.
In 2001, revenues from our contract drilling operations increased by
55 percent as the average number of our drilling rigs being used increased
from 39.8 in 2000 to 46.3 in 2001. Revenues per rig per day increased 33
percent between the comparative years. Daywork revenues represented 88
percent of our total drilling revenues in 2001 and 75 percent in 2000.
Operating margins (revenues less operating costs) for our oil and
natural gas operations were 75 percent in 2001 and 79 percent in 2000.
This decrease resulted mainly from declines in production on older wells
without corresponding declines in operating expenses. Total operating cost
increased 12 percent and was due mainly to the addition of new wells
through development drilling and increases in ad valorem taxes, workover
expenses and compression fees.
Our contract drilling operating margins increased from 22 percent in
2000 to 46 percent in 2001. The additional operating margin was generally
due to additional revenue received per day and an increase in the number of
rigs being used. Our contract drilling operating cost per rig per day
decreased $400 in 2001 when compared with 2000 as increased usage reduced
the impact of our fixed indirect drilling expenses. Total contract drilling
operating costs were up 8 percent in 2001 versus 2000 primarily due to
increased utilization and increases in field labor cost.
Contract drilling depreciation increased 16 percent due to higher rig
utilization. Depreciation, depletion and amortization ("DD&A") of our oil
and natural gas properties increased 20 percent due primarily to a $2.1
million impairment of our investment in a company which has oil and natural
gas properties located in Canada and from a 11 percent increase in the
average DD&A rate per Mcfe to $0.91 in 2001 from $0.82 Mcfe in 2000.
General and administrative expenses increased 29 percent. In the
second quarter of 2001, we recorded $1.3 million in additional employee
benefit expenses for the present value of a separation agreement made in
36
connection with the retirement of King Kirchner from his position as Chief
Executive Officer. The liability associated with this expense plus accrued
interest will be paid in $25,000 monthly payments starting in July 2003 and
continuing through June 2009. Interest expense decreased 45 percent as our
average outstanding debt decreased 28 percent during 2001. The average
interest rate decreased from 7.9 percent in 2000 to 5.7 percent in 2001.
2000 versus 1999
- ----------------
Net income for 2000 was $34,344,000, compared with $3,048,000 for
1999. This improvement was mainly due to 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 day increased
$109 in 2000 as total contract drilling operating costs were up 76 percent
in 2000 versus 1999 primarily due to increased utilization.
37
Contract drilling depreciation increased 75 percent due to the impact
of higher depreciation per operating day associated with the newly acquired
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 office in Moore, Oklahoma was
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.
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 price
we receive for 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. The price of natural gas also
effects the demand for our rigs and the amount we can charge for the use of
the rigs. Based on our 2001 production, a $.10 per Mcf change in what we
are paid for our natural gas production would result in a corresponding
$146,000 per month ($1,752,000 annualized) change in our pre-tax cash flow.
A $1.00 per barrel change in our oil price would have a $33,000 per month
($396,000 annualized) change in our pre-tax cash flow.
Periodically we hedge the prices we will receive for a portion of our
future natural gas and oil production. We do so in an attempt to reduce
the impact and uncertainty that price fluctuations have on our cash flow.
In the first quarter of 2000, we entered into swap transactions to lock in
a portion of our oil production at higher oil prices. 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 entered into a collar contract covering approximately
25 percent of our daily oil production from November 1, 2000 through
38
February 28, 2001. The collar had a floor of $26.00 per barrel and a
ceiling of $33.00 per barrel and we received $0.86 per barrel for entering
into the transaction. During 2000, the net effect of our oil hedging
transactions for oil reduced our oil revenues by $465,000. We did not have
any hedging transactions for natural gas in 2000. During the first quarter
of 2001, our oil hedging transaction yielded an increase in our oil
revenues of $17,200.
We entered into a natural gas collar contract for approximately 36
percent of our June and July 2001 natural gas production at a floor price
of $4.50 and a ceiling price of $5.95. We also entered into two natural
gas collar contracts for approximately 38 percent of our September through
November 2001 natural gas production. Both contracts had a floor price of
$2.50. One contract had a ceiling price of $3.68 and the other contract had
a ceiling price of $4.25. For the year our natural gas collar contracts
added $2,030,000 to our natural gas revenues. We did not have any hedging
transactions outstanding at December 31, 2001 nor on February 20, 2002.
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 manage our
exposure to increases in interest rates. However, we may use such
financial instruments in the future should our assessment of future
interest rates warrant such use. Based on our average outstanding long-term
debt in 2001, a one percent change in the floating rate would change our
annual cash flow before income taxes by approximately $450,000.
39
Item 8. Financial Statements and Supplementary Data
- ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
----------------------
2000 2001
---------- ----------
(In thousands)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 726 $ 391
Accounts receivable (less allowance for
doubtful accounts of $919 and $604) 40,220 33,886
Materials and supplies 3,802 5,358
Income tax receivable - 3,198
Prepaid expenses and other 1,269 3,761
---------- ----------
Total current assets 46,017 46,594
---------- ----------
Property and Equipment:
Drilling equipment 196,736 244,698
Oil and natural gas properties, on
the full cost method 349,707 406,491
Transportation equipment 5,803 6,441
Other 8,801 9,231
---------- ----------
561,047 666,861
Less accumulated depreciation, depletion,
amortization and impairment 270,690 304,643
---------- ----------
Net property and equipment 290,357 362,218
---------- ----------
Other Assets 9,914 8,441
---------- ----------
Total Assets $ 346,288 $ 417,253
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
40
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
----------------------
2000 2001
---------- ----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
- -----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities $ 1,627 $ 1,893
Accounts payable 21,012 16,292
Accrued liabilities 9,854 10,616
Contract advances 179 240
---------- ----------
Total current liabilities 32,672 29,041
---------- ----------
Long-Term Debt 54,000 31,000
---------- ----------
Other Long-Term Liabilities (Note 4) 3,597 4,110
---------- ----------
Deferred Income Taxes 41,479 73,940
---------- ----------
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,
75,000,000 shares authorized,
35,768,344 and 36,006,267
shares issued, respectively 7,154 7,201
Capital in excess of par value 139,872 141,977
Retained earnings 67,514 130,280
Treasury stock at cost (30,000 shares) - (296)
---------- ----------
Total shareholders' equity 214,540 279,162
---------- ----------
Total Liabilities and Shareholders' Equity $ 346,288 $ 417,253
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
41
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
-------------------------------------
1999 2000 2001
---------- ---------- ----------
(Restated,
See Note 2)
(In thousands except per share amounts)
Revenues:
Contract drilling $ 55,479 $ 108,075 $ 167,042
Oil and natural gas 46,225 92,016 90,237
Other 648 1,173 1,900
---------- ---------- ----------
Total revenues 102,352 201,264 259,179
---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 47,721 84,051 91,006
Depreciation 6,851 11,999 13,888
Oil and natural gas:
Operating costs 15,084 19,754 22,196
Depreciation, depletion,
amortization and
impairment 17,114 18,492 22,116
General and administrative 5,750 6,560 8,476
Interest 5,268 5,136 2,818
---------- ---------- ----------
Total expenses 97,788 145,992 160,500
---------- ---------- ----------
Income Before Income Taxes 4,564 55,272 98,679
---------- ---------- ----------
Income Tax Expense:
Current 29 621 5,609
Deferred 1,487 20,307 30,304
---------- ---------- ----------
Total income taxes 1,516 20,928 35,913
---------- ---------- ----------
Net Income $ 3,048 $ 34,344 $ 62,766
========== ========== ==========
Net Income Per Common Share:
Basic $ .10 $ .96 $ 1.75
========== ========== ==========
Diluted $ .10 $ .95 $ 1.73
========== ========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
42
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1999, 2000 and 2001
(1999 Restated, See Note 2)
Accumulated
Capital Other
In Excess Comprehen-
Common Of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- --------- ----------
(In thousands)
Balances,
January 1, 1999 $ 5,478 $ 81,915 $ 30,122 $ - $ (131) $ 117,384
Net income - - 3,048 - - 3,048
Activity in
employee
compensation
plans
(252,511 50 680 - - 131 861
shares)
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
43
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED
Year Ended December 31, 1999, 2000 and 2001
(1999 Restated, See Note 2)
Accumulated
Capital Other
In Excess Comprehen-
Common Of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- --------- ----------
(In thousands)
Balances,
December 31, 2000 $ 7,154 $ 139,872 $ 67,514 $ - $ - $ 214,540
Net Income - - 62,766 - - 62,766
Activity in
employee
compensation
plans
(237,923
shares) 47 2,105 - - - 2,152
Purchase of
treasury
shares
(30,000
shares) - - - - (296) (296)
Other
comprehensive
income (net
of tax):
Change in
value of
cash
flow
deriva-
tive
instru-
ments
used
as cash
flow
hedges - - - 1,258 - 1,258
Adjustments
reclasif-
ication -
derivative
settlments - - - (1,258) - (1,258)
-------- ---------- --------- --------- --------- ----------
Balances,
December 31, 2001 $ 7,201 $ 141,977 $130,280 $ - $ (296) $ 279,162
======== ========== ========= ========= ========= ==========
The accompanying notes are an integral part of the
consolidated financial statements
44
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------
1999 2000 2001
---------- ---------- ----------
(Restated,
See Note 2)
(In thousands)
Cash Flows From Operating
Activities:
Net Income $ 3,048 $ 34,344 $ 62,766
Adjustments to reconcile
net income to net cash
provided (used) by
operating activities:
Depreciation, depletion,
amortization and
impairment 24,285 30,946 36,642
Equity in net earnings of
unconsolidated subsidiary - - (1,148)
Loss (gain) on disposition
of assets (400) (969) (56)
Employee stock compensation
plans 436 443 2,873
Bad debt expense 255 350 -
Deferred tax expense 1,487 20,307 30,304
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (8,450) (18,500) 6,334
Materials and supplies 49 (543) (1,556)
Prepaid expenses and other 140 (96) (3,533)
Accounts payable 2,667 (1,370) (155)
Accrued liabilities 1,590 3,067 929
Contract advances 48 (179) 61
Other liabilities (442) (440) (440)
---------- ---------- ----------
Net cash provided by
operating activities 24,713 67,360 133,021
---------- ---------- ----------
The accompanying notes are an integral part of the
consolidated financial statements
45
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
------------------------------------
1999 2000 2001
---------- ---------- ----------
(Restated,
See Note 2)
(In thousands)
Cash Flows From Investing
Activities:
Capital expenditures (including
producing property
acquisitions) $ (69,503) $ (60,447) $(108,339)
Proceeds from disposition of
property and equipment 1,438 4,259 2,631
(Acquisition) disposition
of other assets 91 (2,656) 17
---------- ---------- ----------
Net cash used in
investing activities (67,974) (58,844) (105,691)
---------- ---------- ----------
Cash Flows From Financing
Activities:
Borrowings under line of credit 61,600 31,200 57,200
Payments under line of credit (68,400) (44,439) (79,200)
Net payments on notes payable
and other long-term debt (1,090) (556) (1,000)
Proceeds from sale of
common stock 50,136 250 609
Book overdrafts (Note 1) 2,974 3,108 (4,978)
Acquisition of treasury stock - - (296)
---------- ---------- ----------
Net cash provided by
(used in) financing
activities 45,220 (10,437) (27,665)
---------- ---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents 1,959 (1,921) (335)
Cash and Cash Equivalents,
Beginning of Year 688 2,647 726
---------- ---------- ----------
Cash and Cash Equivalents,
End of Year $ 2,647 $ 726 $ 391
========== ========== ==========
Supplemental Disclosure of Cash
Flow Information:
Cash paid during the year for:
Interest $ 5,850 $ 5,135 $ 2,807
Income taxes $ 30 $ 519 $ 7,779
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the
consolidated financial statements
46
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 contract drilling and
exploration and production activities are oriented toward drilling for and
producing natural gas. At December 31, 2001, Unit had an interest in a
total of 3,038 wells and served as operator of 688 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 2001, 54 of Unit's
55 rigs performed contract drilling services.
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, but
some of our daywork contracts in the Rocky Mountains can range up to one
year. 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.
47
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, 2000 and 2001, book
overdrafts of $6.1 million and $1.1 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.
48
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 has been amortized on the straight-line method using a
25 year life through December 31, 2001. On July 20, 2001, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets" (FAS 142). For
goodwill and intangible assets recorded in the financial statements, FAS
142 ends the amortization of goodwill and certain intangible assets and
subsequently requires, at least annually, that an impairment test be
performed on such assets to determine whether the fair value has changed.
FAS 142 is effective for the fiscal years starting after December 15, 2001
(January 1, 2002 for Unit). We do not believe the future impact from the
adoption of FAS 142 on our financial position or results of operation will
be material. Net goodwill reported in other assets at December 31, 2000
and 2001 was $5,331,000 and $5,088,000, respectively with accumulated
amortization at December 31, 2000 and 2001 of $750,000 and $993,000,
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 $0.85, $0.82 and $0.91 per Mcfe in 1999, 2000
and 2001, 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 $14.4 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.
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 2000 and
2001, Unit recorded $179,000 and $2,259,000 of contract drilling profits,
49
respectively, as a reduction of the carrying value of its oil and natural
gas properties rather than including these profits in current operations.
No contract drilling profits were realized on such interests in 1999.
Limited Partnerships. Unit's wholly owned subsidiary, Unit Petroleum
Company, is a general partner in eighteen 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 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 2001 average natural gas price received of $3.89 per
Mcf which excludes the effects of hedging, Unit estimates its balancing
position to be approximately $6.4 million on under-produced properties and
approximately $6.1 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 1999, 2000 and 2001 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.
50
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
$4,462,000 and $4,583,000 for employer group health insurance and worker's
compensation at December 31, 2000 and 2001, respectively. Due to high
premium cost, Unit has decided to increase its deductible for general
liability claims from $25,000 to $200,000.
Treasury Stock. On August 30, 2001, Unit's Board of Directors
authorized the purchase of up to one million shares of Unit's common stock.
The timing of stock purchases are made at the discretion of management. At
December 31, 2001, 30,000 shares had been repurchased for $296,000.
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 2001, one purchaser of Unit's oil and natural
gas production accounted for approximately 15 percent of consolidated
revenues. At December 31, 2001, accounts receivable from one oil and
natural gas purchaser was approximately $2.1 million. In addition, at
December 31, 2000 and 2001, Unit had a concentration of cash of $1.7
million and $2.0 million, respectively, with one bank.
Hedging Activities. On January 1, 2001, Unit adopted Statement of
Financial Accounting Standard No. 133 (subsequently amended by Financial
Accounting Standard No.'s 137 and 138), "Accounting for Derivative
Instruments and Hedging Activities" (FAS 133). This statement requires all
derivatives to be recognized on the balance sheet and measured at fair
value. If a derivative is designated as a cash flow hedge, Unit is
required to measure the effectiveness of the hedge, or the degree that the
gain (loss) for the hedging instrument offsets the loss (gain) on the
hedged item, at each reporting period. The effective portion of the gain
(loss) on the derivative instrument is recognized in other comprehensive
income as a component of equity and subsequently reclassified into earnings
when the forecasted transaction affects earnings. The ineffective portion
of a derivative's change in fair value is required to be recognized in
earnings immediately. Derivatives that do not qualify for hedge treatment
under FAS 133 must be recorded at fair value with gains (losses) recognized
in earnings in the period of change. Unit periodically enters into
derivative commodity instruments to hedge its exposure to price
fluctuations on oil and natural gas production. Such instruments include
regulated natural gas and crude oil futures contracts traded on the New
York Mercantile Exchange (NYMEX) and over-the-counter swaps and basic
hedges with major energy derivative product specialists. Initial adoption
of this standard was not material. In the first quarter of 2000, Unit
entered into swap transactions in an effort to lock in a portion of its
daily production at the higher oil prices which currently existed. These
transactions applied to approximately 50 percent of Unit's daily oil
production covering the period from April 1, 2000 to July 31, 2000 and 25
51
percent of our oil production for August and September of 2000, at prices
ranging from $24.42 to $27.01. Unit entered into a collar contract for
approximately 25 percent of its daily production for the period covering
November 1, 2000 to February 28, 2001. The collar had a floor of $26.00
and a ceiling of $33.00 and Unit received $0.86 per barrel for entering
into the collar transaction. During 2000, the net effect of these hedging
transactions yielded a reduction in Unit's oil revenues of $465,000. During
the first quarter of 2001, the net effect of this hedging transaction
yielded an increase in oil revenues of $17,200. During the second quarter
of 2001, Unit entered into a natural gas collar contract for approximately
36 percent of its June and July 2001 natural gas production, at a floor
price of $4.50 and a ceiling price of $5.95. During the third quarter of
2001, Unit entered into two natural gas collar contracts for approximately
38 percent of its September thru November 2001 natural gas production. Both
contracts had a floor price of $2.50. One contract had a ceiling price of
$3.68 and the other contract had a ceiling price of $4.25. During 2001
natural gas collar contracts added $2,030,000 to Unit's natural gas
revenues. At December 31, 2001, Unit was not holding any natural gas or oil
derivative contracts.
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.
Impact of Financial Accounting Pronouncements. On July 20, 2001, the
Financial Accounting Standards Board (FASB) issued Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (FAS
142). For goodwill and intangible assets already in the financial
statements, FAS 142 ends the amortization of goodwill and certain
intangible assets and subsequently requires, at least annually, that an
impairment test be performed on such assets to determine whether the fair
value has changed. Unit expensed $243,000 annually for the amortization of
goodwill, and the unamortized balance of goodwill is $5,088,000 at December
31, 2001. FAS 142 is effective for the fiscal years starting after December
15, 2001 (January 1, 2002 for Unit). Unit does not believe the future
impact from the adoption of FAS 142 on our financial position or results of
operations will be material.
In July 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS
143). FAS 143, is effective for fiscal years beginning after June 15, 2002
(January 1, 2003 for Unit), and establishes an accounting standard
requiring the recording of the fair value of liabilities associated with
the retirement of long-lived assets (mainly plugging and abandonment costs
for Unit's depleted wells), in the period in which the liabilities are
incurred (at the time the wells are drilled). Unit has not yet determined
the effect of the adoption of FAS 143 on its financial position or results
of operations.
52
In August 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, "Accounting for Impairment or Disposal of Long-Lived
Assets" (FAS 144). FAS 144 is effective for fiscal years beginning after
December 15, 2001 (January 1, 2002 for Unit). This statement supersedes
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of" and amends Accounting Principles Board Opinion No. 30 for the
accounting and reporting of discontinued operations, as it relates to long-
lived assets. Unit does do not believe the future impact from the adoption
of FAS 144 on our financial position and results of operation will be
material.
53
NOTE 2 - ACQUISITIONS
- ---------------------
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 Ended
December 31, March 31,
1999 2000
-------------- --------------
(In thousands)
Revenues:
Unit Corporation $ 97,453 $ 35,807
Questa 4,899 1,420
-------------- --------------
Combined $ 102,352 $ 37,227
============== ==============
Net Income:
Unit Corporation $ 1,486 $ 3,095
Questa 1,562 483
-------------- --------------
Combined $ 3,048 $ 3,578
============== ==============
Questa's net income has been 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.
54
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, 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
============= ============= ==========
For the Year Ended
December 31, 2001:
Basic earnings per
common share $ 62,766,000 35,967,000 $ 1.75
==========
Effect of dilutive
stock options 291,000
------------- -------------
Diluted earnings per
common share $ 62,766,000 36,258,000 $ 1.73
============= ============= ==========
55
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,:
1999 2000 2001
---------- ---------- ----------
Options 196,500 144,000 153,000
========== ========== ==========
Average exercise price $ 8.49 $ 16.59 $ 16.79
========== ========== ==========
NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
- -------------------------------------------------------
Long-term debt consisted of the following as of December 31, 2000 and
2001:
2000 2001
---------- ----------
(In thousands)
Revolving credit and term loan,
with interest at December 31,
2000 and 2001 of 7.8 percent
and 3.3 percent, respectively $ 52,000 $ 30,000
Notes payable for Hickman
Drilling Company acquisition
with interest at December 31,
2000 and 2001 of 9.5 percent
and 4.75 percent, respectively 3,000 2,000
---------- ----------
55,000 32,000
Less current portion 1,000 1,000
---------- ----------
Total long-term debt $ 54,000 $ 31,000
========== ==========
At December 31, 2001, Unit has a $100 million bank loan agreement
consisting of a revolving credit facility through May 1, 2005 and a term
loan thereafter, maturing on May 1, 2008. Borrowings under the loan
agreement are limited to a commitment amount. Although, the current value
of Unit's assets under the latest loan value computation supported a full
$100 million, Unit elected to set the loan commitment at $60 million in
order to reduce costs. The loan value under the revolving credit facility
is subject to a semi-annual re-determination calculated primarily as the
sum of a percentage of the discounted future value of Unit's oil and
natural gas reserves, as determined by the banks. In addition, an amount
representing a part of the value of Unit's drilling rig fleet, limited to
56
$20 million, is added to the loan value. Any declines in commodity prices
would adversely impact the determination of the loan 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 loan value. Subsequent
to May 1, 2005, 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 $60,000 at inception of the loan
agreement and a facility fee of 3/8 of one percent is charged for any
unused portion of the commitment amount. 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 $125
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 $40 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.
57
Other long-term liabilities consisted of the following as of December
31, 2000 and 2001:
2000 2001
---------- ----------
(In thousands)
Natural gas purchaser prepayment $ 877 $ 437
Separation benefit plan 1,811 1,959
Deferred compensation plan 1,536 1,277
Retirement agreement - 1,330
---------- ----------
4,224 5,003
Less current portion 627 893
---------- ----------
Total other long-term liabilities $ 3,597 $ 4,110
========== ==========
At December 31, 2001, Unit has a prepayment balance of $437,000
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. The final payment of $437,000 is due on June 1, 2002.
Unit has other long-term liabilities of $4,110,000, consisting of
$1,523,000 accrued in connection with its separation benefit plans,
$1,277,000 accrued in connection with its Deferred Compensation Plan and
$1,310,000 for the present value of a separation agreement, made in the
second quarter of 2001, in connection with the retirement of King Kirchner
from his position as Chief Executive Officer.
Estimated annual principal payments under the terms of long-term debt
and other long-term liabilities from 2002 through 2006 are $1,893,000,
$1,170,000, $300,000, $6,133,000 and $10,300,000. Based on the borrowing
rates currently available to Unit for debt with similar terms and
maturities, long-term debt at December 31, 2001 approximates its fair
value.
58
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:
1999 2000 2001
---------- ---------- ----------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 1,552 $ 19,345 $ 34,538
State income tax, net of
federal benefit 139 1,575 2,859
Goodwill and other (175) 8 (1,484)
---------- ---------- ----------
Income tax expense $ 1,516 $ 20,928 $ 35,913
========== ========== ==========
Deferred tax assets and liabilities are comprised of the following at
December 31, 2000 and 2001:
2000 2001
----------- -----------
(In thousands)
Deferred tax assets:
Allowance for losses
and nondeductible accruals $ 3,308 $ 3,867
Net operating loss carryforward 15,027 -
Statutory depletion carryforward 2,260 2,874
Alternative minimum tax credit
carryforward 1,123 5,196
----------- -----------
Gross deferred tax assets 21,718 11,937
Deferred tax liability:
Depreciation, depletion and
amortization (63,197) (83,720)
----------- -----------
Net deferred tax liability (41,479) (71,783)
Current deferred tax asset - 2,157
----------- -----------
Non-current - deferred tax
liability $ (41,479) $ (73,940)
=========== ===========
59
Realization of the deferred tax asset is dependent on generating
sufficient future taxable income. 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 are reduced.
At December 31, 2001, Unit has an excess statutory depletion
carryforward of approximately $7,562,000, which may be carried forward
indefinitely and 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 2000 and
2001.
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 of the common stock on the
date of the grant.
60
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 1999 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
Exercised (177,200) 3.13
Cancelled (10,400) 10.26
----------- ----------
Outstanding at December 31, 2001 532,100 $ 8.09
=========== ==========
OUTSTANDING OPTIONS
AT DECEMBER 31, 2001
------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 2.75 - $ 3.75 270,500 5.3 years $ 3.42
$ 7.25 - $16.69 261,600 7.2 years $ 12.92
61
EXERCISABLE OPTIONS
AT DECEMBER 31, 2001
------------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
------------------------------------ ----------- -----------
$ 2.75 - $ 3.75 189,500 $ 3.27
$ 7.25 - $16.69 139,800 $ 10.28
Options for 414,200, 407,900 and 329,300 shares were exercisable with
weighted average exercise prices of $3.96, $4.24 and $6.25 at December 31,
1999, 2000 and 2001, 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 Directors' 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.
62
Activity pertaining to the Directors' Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 1999 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
Granted 17,500 17.54
Exercised (37,000) 6.80
----------- ----------
Outstanding at December 31, 2001 75,500 $ 9.58
=========== ==========
OUTSTANDING AND
EXERCISABLE OPTIONS
AT DECEMBER 31, 2001
------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 1.75 - $ 3.75 17,500 1.8 years $ 3.16
$ 6.87 - $17.54 58,000 7.4 years $ 11.51
63
Unit applies APB Opinion 25 in accounting for Unit's Stock Option Plan
and Non-Employee Directors' Stock Option Plan. Accordingly, based on the
nature of Unit's grants of options, no compensation cost has been
recognized in 1999, 2000 and 2001. 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:
1999 2000 2001
--------- --------- ---------
Net Income (In thousands):
As reported $ 3,048 $ 34,344 $ 62,766
========= ========= =========
Pro forma $ 2,652 $ 33,986 $ 61,822
========= ========= =========
Basic Earnings per Share:
As reported $ .10 $ .96 $ 1.75
========= ========= =========
Pro forma $ .09 $ .95 $ 1.72
========= ========= =========
Diluted Earnings per Share:
As reported $ .10 $ .95 $ 1.73
========= ========= =========
Pro forma $ .09 $ .94 $ 1.71
========= ========= =========
The fair value of each option granted is estimated using the Black-
Scholes model. Unit's estimate of stock volatility in 1999, 2000 and 2001
was 0.55, based on previous stock performance. Dividend yield was estimated
to remain at zero with a risk free interest rate of 6.70, 5.26 and 5.41
percent in 1999, 2000 and 2001, 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 2000 under the Stock Option Plan were
$1,470,000. No options were issued under the Stock Option Plan in 1999 and
2001. Under the Non-Employee Directors' Stock Option Plan the aggregate
fair value of options granted during 1999, 2000 and 2001 were $58,000,
$99,000 and $201,000, 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
105,819, 58,353 and 35,016 shares of common stock and recognized expense of
$464,000, $595,000 and $1,082,000 in 1999, 2000 and 2001, 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
64
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, 2000 and 2001 totaled $1,165,000, $1,536,000 and
$1,277,000, 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 $502,000, $558,000 and $589,000 in 1999, 2000 and 2001,
respectively, for benefits associated with anticipated payments from both
separation plans.
We have entered into key employee change of control contracts with
five of our executive officers. These severance contracts have an initial
three-year term that is automatically extended for one year upon each
anniversary, unless a notice not to extend is given by us. If a change of
control of the company, as defined in the contracts, occurs during the term
of the severance contract, then the contract becomes operative for a fixed
three-year period. The severance contracts generally provide that the
executive's terms and conditions for employment (including position, work
location, compensation and benefits) will not be adversely changed during
the three-year period after a change of control. If the executive's
employment is terminated by the company (other than for cause, death or
disability), the executive terminates for good reason during such three-
year period, or the executive terminates employment for any reason during
the 30-day period following the first anniversary of the change of control,
and upon certain terminations prior to a change of control or in connection
with or in anticipation of a change of control, the executive is generally
entitled to receive, in addition to certain other benefits, any earned but
unpaid compensation; up to 2.9 times the executive's base salary plus
annual bonus (based on historic annual bonus); and the company matching
contributions that would have been made had the executive continued to
participate in the company's 401(k) plan for up to an additional three
years.
The severance contract provides that the executive is entitled to
receive a payment in an amount sufficient to make the executive whole for
any excise tax on excess parachute payments imposed under Section 4999 of
the Code. As a condition to receipt of these severance benefits, the
executive must remain in the employ of the company prior to change of
control and render services commensurate with his position.
65
NOTE 7 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
Unit formed private limited partnerships (the "Partnerships") with
certain qualified employees, officers and directors from 1984 through 2001,
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 their own account
during the period from the formation of the Partnerships 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 one of the
Questa partnerships in the first quarter of 2001 and the four partnerships
were dissolved.
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:
1999 2000 2001
--------- --------- ---------
(In thousands)
Contract drilling $ 94 $ 296 $ 416
Well supervision and other fees $ 425 $ 478 $ 498
General and administrative
expense reimbursement $ 175 $ 192 $ 193
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, $9,000, $6,000 and $3,000 during the
years ended December 31, 1999, 2000 and 2001, respectively, for purchases
of natural gas production.
66
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
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, 2007. Future minimum rental payments under the terms
of the leases are approximately $654,000, $648,000, $648,000, $193,000 and
$151,000 in 2002, 2003, 2004, 2005 and 2006, respectively. Total rent
expense incurred by the Company was $422,000, $535,000 and $582,000 in
1999, 2000 and 2001, respectively.
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 $10,000
and $14,000 in 1999 and 2000, respectively, for such limited partners'
interests. No repurchases were made in 2001. Subsequent to the merger, in
2000, 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. In 2001, Unit paid $15,000 for interests in two
of the Questa limited partnerships and subsequently dissolved one of the
Questa partnerships.
67
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.
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.
68
1999 2000 2001
---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 55,479 $ 108,075 $ 167,042
Oil and natural gas 46,225 92,016 90,237
Other 648 1,173 1,900
---------- ---------- ----------
Total revenues $ 102,352 $ 201,264 $ 259,179
========== ========== ==========
Operating Income (1):
Contract drilling $ 907 $ 12,025 $ 62,148
Oil and natural gas 14,027 53,770 45,925
---------- ---------- ----------
Total operating income 14,934 65,795 108,073
General and administrative
expense (5,750) (6,560) (8,476)
Interest expense (5,268) (5,136) (2,818)
Other income (expense)- net 648 1,173 1,900
---------- ---------- ----------
Income before income taxes $ 4,564 $ 55,272 $ 98,679
========== ========== ==========
Identifiable Assets (2):
Contract drilling $ 125,853 $ 141,324 $ 183,471
Oil and natural gas 164,252 198,251 220,476
---------- ---------- ----------
Total identifiable assets 290,105 339,575 403,947
Corporate assets 5,462 6,713 13,306
---------- ---------- ----------
Total assets $ 295,567 $ 346,288 $ 417,253
========== ========== ==========
69
1999 2000 2001
---------- ---------- ----------
(In thousands)
Capital Expenditures:
Contract drilling $ 55,656 $ 22,045 $ 51,280
Oil and natural gas 21,532 39,884 56,933
Other 744 3,324 539
---------- ---------- ----------
Total capital expenditures $ 77,932 $ 65,253 $ 108,752
========== ========== ==========
Depreciation, Depletion, Amortization
and Impairment:
Contract drilling $ 6,851 $ 11,999 $ 13,888
Oil and natural gas 17,114 18,492 22,116
Other 320 455 638
---------- ---------- ----------
Total depreciation, depletion,
amortization and impairment $ 24,285 $ 30,946 $ 36,642
========== ========== ==========
- ----------------------
(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.
70
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 2000 and 2001 is as
follows:
THREE MONTHS ENDED
---------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ----------- ------------ -----------
(In thousands except per share amounts)
Year Ended
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 (2) $ 0.10 $ 0.16 $ 0.27 $ 0.43
=========== =========== =========== ===========
Year Ended
December 31, 2001:
Revenues $ 70,443 $ 71,087 $ 68,399 $ 49,250
=========== =========== =========== ===========
Gross profit(1) $ 33,414 $ 32,091 $ 27,277 $ 15,291
=========== =========== =========== ===========
Income before
income taxes $ 30,862 $ 29,070 $ 25,170 $ 13,577
=========== =========== =========== ===========
Net income(3) $ 19,172 $ 18,048 $ 15,631 $ 9,915
=========== =========== =========== ===========
Earnings per
common share:
Basic (4) $ 0.53 $ 0.50 $ 0.43 $ 0.28
=========== =========== =========== ===========
Diluted $ 0.53 $ 0.50 $ 0.43 $ 0.27
=========== =========== =========== ===========
- ------------------
(1) Gross Profit excludes other revenues, general and administrative
expense and interest expense.
71
(2) 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.
(3) The net income for the three months ended December 31, 2001 includes a
tax benefit of $2.1 million relating to an increase in the estimated
amount of statutory depletion carryforward.
(4) Due to the effect of rounding basic earnings per share for the year's
four quarters does not equal the annual earnings per share.
72
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)
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
=========== ========= ===========
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
=========== ========= ===========
73
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2001:
Capitalized costs:
Proved properties $ 391,216 $ 888 $ 392,104
Unproved properties 14,207 180 14,387
----------- --------- -----------
405,423 1,068 406,491
Accumulated depreciation,
depletion, amortization
and impairment (196,270) (475) (196,745)
----------- --------- -----------
Net capitalized costs $ 209,153 $ 593 $ 209,746
=========== ========= ===========
Cost incurred:
Unproved properties $ 7,503 $ 21 $ 7,524
Producing properties 1,419 - 1,419
Exploration 9,336 - 9,336
Development 38,359 295 38,654
----------- --------- -----------
Total costs incurred $ 56,617 $ 316 $ 56,933
=========== ========= ===========
74
The results of operations for producing activities are provided below.
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
1999:
Revenues $ 42,999 $ 63 $ 43,062
Production costs (11,739) (20) (11,759)
Depreciation, depletion,
amortization and impairment (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
=========== ========= ===========
2001:
Revenues $ 86,810 $ 190 $ 87,000
Production costs (18,636) (23) (18,659)
Depreciation, depletion
and amortization (19,756) (40) (19,796)
----------- --------- -----------
48,418 127 48,545
Income tax expense (17,621) (40) (17,661)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 30,797 $ 87 $ 30,884
=========== ========= ===========
75
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)
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
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 place (326) (1,509) - - (326) (1,509)
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
76
USA CANADA TOTAL
---------------- --------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- ------- ------- --------
(In thousands)
2001:
Proved developed and
undeveloped reserves:
Beginning of year 4,183 215,196 - 441 4,183 215,637
Revision of previous
estimates (214) (24,253) - (7) (214) (24,260)
Extensions,
discoveries and
other additions 861 54,521 - - 861 54,521
Purchases of minerals
in place 8 1,246 - - 8 1,246
Sales of minerals
in place (3) (26) - - (3) (26)
Production (492) (18,819) - (45) (492) (18,864)
------- -------- ------- ------- ------- --------
End of Year 4,343 227,865 - 389 4,343 228,254
======= ======== ======= ======= ======= ========
Proved developed
reserves:
Beginning of year 3,222 162,718 - 389 3,222 163,107
End of year 2,753 150,419 - 338 2,753 150,757
77
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.
78
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)
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
=========== ========= ===========
2001:
Future cash flows $ 676,051 $ 975 $ 677,026
Future production and
development costs (279,499) (341) (279,840)
Future income tax expenses (94,037) (134) (94,171)
----------- --------- -----------
Future net cash flows 302,515 500 303,015
10% annual discount for
estimated timing of cash flows (125,238) (194) (125,432)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 177,277 $ 306 $ 177,583
=========== ========= ===========
79
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows (unaudited):
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
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
=========== ========= ===========
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
=========== ========= ===========
80
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2001:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (68,174) $ (167) $ (68,341)
Net changes in prices and
production costs (768,295) (1,600) (769,895)
Revisions in quantity
estimates and changes in
production timing (32,705) 13 (32,692)
Extensions, discoveries and
improved recovery, less
related costs 54,127 - 54,127
Purchases of minerals in place 1,217 - 1,217
Sales of minerals in place (220) - (220)
Accretion of discount 99,953 205 100,158
Net change in income taxes 271,421 524 271,945
Other - net (54,634) (108) (54,742)
----------- --------- -----------
Net change (497,310) (1,133) (498,443)
Beginning of year 674,587 1,439 676,026
----------- --------- -----------
End of year $ 177,277 $ 306 $ 177,583
=========== ========= ===========
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
($17.71) and natural gas ($2.51) 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.
81
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.
82
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,
2000 and 2001, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, 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 20, 2002
83
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 of our executive officers. 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
- ---------------- --- ----------------------------------------
John G. Nikkel 67 President, Chief Executive Officer,
Chief Operating Officer and Director
Earle Lamborn 67 Senior Vice President, Drilling and
Director
Philip M. Keeley 60 Senior Vice President, Exploration
and Production
Larry D. Pinkston 47 Vice President, Treasurer and Chief
Financial Officer
Mark E. Schell 44 General Counsel and Secretary
Mr. Nikkel joined Unit in 1983 as its President and a director. On
July 1, 2001, Mr. Nikkel was elected to the additional office of Chief
Executive Officer. 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.1
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.
84
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 until
December 2001 served as the 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 2002
annual meeting of stockholders.
85
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 2002 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 2002 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 2002 annual meeting of stockholders.
86
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, 2000 and 2001
Consolidated Statements of Operations for the years ended
December 31, 1999, 2000 and 2001
Consolidated Statements of Changes in Shareholders' Equity for
the years ended December 31, 1999, 2000 and 2001
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 2000 and 2001
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,
1999, 2000 and 2001:
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).
87
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).
3.1.5 Certificate of Correction of the Amended and Restated
Certificate of Incorporation of Unit Corporation (filed as
Exhibit 3.1 to Unit's Form 8-K dated August 23, 2001, which
is incorporated herein by reference).
3.2 By-Laws of Unit Corporation (filed as Exhibit 3.2 to Unit's
Form 8-K dated August 23, 2001, which is incorporated herein
by reference).
4.1 Form of Promissory Note 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).
4.2.7 First Amendment of Rights Agreement dated May 19, 1995,
between the Company and Mellon Shareholder Services LLC, as
Rights Agent (filed as Exhibit 4 to Unit's Form 8-K dated
August 23, 2001, which is incorporated herein by reference).
89
10.1.25 Loan Agreement dated July 7, 2001 (filed as an Exhibit to
Unit's Quarterly Report under cover of Form 10-Q for the
quarter ended June 30, 2001, 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).
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).
89
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).
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).
90
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 as an Exhibit to Unit's Annual
Report under the cover of Form 10-K for the year ended
December 31, 2000).
10.2.39* Form of Unit Corporation Key Employee Change of Control
Contract (filed as an Exhibit to Unit's Annual Report under
the cover of Form 10-K for the year ended December 31, 2000).
10.2.40 Form of Indemnification Agreement entered into between the
Company and its executive officers and directors (filed as
Exhibit 10 to Unit's Form 8-K dated August 23, 2001, which is
incorporated herein by reference).
10.2.41 Unit 2002 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed herein).
21 Subsidiaries of the Registrant (filed herewith).
23 Consent of Independent Accountants (filed herewith).
99.2 Separation Agreement, dated May 11, 2001, between the
Registrant and Mr. Kirchner (filed as Exhibit 99.A4 to Unit's
Form 8-K dated May 18, 2001, which is incorporated herein by
reference).
* 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, 2001.
91
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, 1999 $ 434 $ 305 $ 15 $ 583
========== ========== ========== ==========
Year ended
December 31, 2000 $ 583 $ 350 $ 14 $ 919
========== ========== ========== ==========
Year ended
December 31, 2001 $ 919 $ - $ 315 $ 604
========== ========== ========== ==========
Deferred Tax Asset Valuation Allowance:
Balance
Balance at At
Beginning End of
Description of period Additions Deductions Period
----------- ---------- ---------- ---------- ----------
(In thousands)
Year ended
December 31, 1999 $ 530 $ - $ 195 $ 335
========== ========== ========== ==========
Year ended
December 31, 2000 $ 335 $ - $ 335 $ -
========== ========== ========== ==========
Year ended
December 31, 2001 $ - $ - $ - $ -
========== ========== ========== ==========
92
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 7, 2002 By: /s/ John G. Nikkel
----------------- ---------------------------
JOHN G. NIKKEL
President and Chief Executive 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 20th day of March, 2001.
Name Title
- ------------------------------- -----------------------------------
/s/ King P. Kirchner
- ------------------------------- Chairman of the Board and Director
KING P. KIRCHNER
/s/ John G. Nikkel
- ------------------------------- President and Chief Executive Officer
JOHN G. NIKKEL Chief Operating 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
- ------------------------------- Director
JOHN S. ZINK
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
93
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
- ------ ----------------------------------------------- -----
10.2.41 Unit 2002 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
93