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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, 2002
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. ___
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2).
Yes _X_ No ___
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on June 30, 2002 - $420,961,714
Number of Shares of Common Stock
Outstanding on March 7, 2003 - 43,514,317
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 7, 2003 are incorporated by reference in
Part III.
Exhibit Index - See Page 100
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 2
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 2
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 21
Item 4. Submission of Matters to a Vote of Security Holders . . 21
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . 22
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . 24
Item 7a. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . 40
Item 8. Financial Statements and Supplementary Data . . . . . . 41
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . 87
PART III
Item 10. Directors and Executive Officers of the Registrant. . . 87
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 89
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . 89
Item 13. Certain Relationships and Related Transactions. . . . . 89
Item 14. Controls and Procedures . . . . . . . . . . . . . . . . 89
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 90
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
Certifications. . . . . . . . . . . . . . . . . . . . . . . . . . 96
1
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2002
PART I
Item 1. Business and Item 2. Properties
- ------- -------- ------- ----------
OUR BUSINESS
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.
Our executive offices are at 1000 Kensington Tower, 7130 South Lewis,
Tulsa, Oklahoma 74136; our telephone number is (918) 493-7700. We also have
regional offices in Oklahoma City, Oklahoma, Woodward, Oklahoma, Booker, Texas,
Houston, Texas and Casper, Wyoming.
Our primary Internet address is www.unitcorp.com. We make our periodic SEC
Reports (Forms 10-Q and Forms 10-K) and current reports (Form 8-K) available
free of charge through our Web site as soon as reasonably practicable after they
are filed electronically with the SEC. We may from time to time provide
important disclosures to investors by posting them in the investor relations
section of our Web site, as allowed by SEC rules.
Materials we file with the SEC may be read and copied at the SEC's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Information on
the operation of the Public Reference Room may be obtained by calling the SEC at
1-800-SEC-0330. The SEC also maintains an Internet Web site at www.sec.gov that
contains reports, proxy and information statements, and other information
regarding our company that we file electronically with the SEC.
When used in this report, the terms Corporation, Unit, our, we and its
refer to Unit Corporation and, as appropriate, Unit Corporation and/or one or
more of its subsidiaries.
OUR LAND CONTRACT DRILLING BUSINESS
General. Using our 75 drilling rigs, our wholly owned subsidiary, Unit Drilling
Company, drills onshore natural gas and oil wells for a wide range of customers.
Our drilling operations are mainly in the Oklahoma and Texas areas of the
Anadarko and Arkoma Basins, the Texas Gulf Cost and in the East Texas and Rocky
Mountain regions.
2
The following table sets forth, for each of the periods indicated, certain
information concerning our contract drilling operations:
Year Ended December 31,
----------------------------------------------
1998 1999 2000 2001 2002
------ ------ ------ ------ ------
Number of Rigs
Owned at End
of Period 34.0 47.0 50.0 55.0 75.0 (1)
Average Number
of Rigs Owned
During Period 34.0 37.3 47.0 51.8 61.6
Average Number
of Rigs
Utilized 22.9 23.1 39.8 46.3 39.1
Utilization
Rate (2) 67% 62% 85% 90% 63%
Average Revenue
Per Day (3) $6,394 $6,582 $7,432 $9,879 $8,285
Total Footage
Drilled
(Feet in
1000's) 2,203 2,211 3,650 4,008 3,829
Number of Wells
Drilled 198 197 316 361 318
---------------
(1) Includes 20 rigs acquired in August 2002.
(2) We determine our utilization rate on a 365 day year by dividing the number
of rigs used by our total number of rigs.
(3) Represents total revenues from contract drilling operations divided by the
total number of days rigs were used during the period.
Acquisitions. On August 15, 2002 we acquired twenty drilling rigs, spare
drilling equipment and vehicles when we acquired CREC Rig Equipment Company and
CDC Drilling Company. We issued 6,819,748 shares of common stock and paid
$3,813,053 for all the outstanding shares of CREC Rig Acquisition Company and
issued 400,252 shares of common stock and paid $686,947 for all the outstanding
shares of CDC Drilling Company. The twenty rigs range in horsepower from 650 to
2,000 with 15 having a horsepower rating of 1,000 or more. Twelve of the rigs
are SCR electric. Depth capacities range from 12,000 to 25,000 feet.
3
Description of our Drilling Rigs. 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, must
be replaced or rebuilt on a periodic basis, while other components, such as the
substructure, mast and drawworks, can be used 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.
Our rigs have maximum depth capacities ranging from 9,500 to 40,000 feet.
The following table shows the current distribution of our rigs as of March
7, 2003:
Average
Rated
Active Idle Total Drilling
Region Rigs(1) Rigs(1) Rigs Depths(ft)
- ------------------ -------- -------- ------- ----------
Anadarko Basin 35 6 41 16,000
West Texas - 2 2 20,000
Arkoma Basin 6 1 7 17,000
East Texas and
Gulf Coast 11 6 17 19,000
Rocky Mountains 3 5 8 22,000
- -------------------
(1) A rig is active when under contract. An idle rig is one that is not under
contract but is available and marketed.
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.
4
Types of Drilling Contracts We Work Under. Our drilling contracts are
predominantly obtained through competitive bidding and are for a single well.
Terms and payment rates vary depending on the nature and duration of the work,
the equipment and services supplied and other matters. We 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. Our contracts
also contain provisions regarding indemnification against certain types of
claims involving injury to persons, property and for acts of pollution. The
specific terms of these indemnifications are subject to negotiation on a
contract by contract basis.
The type of contract used determines our compensation. The contracts are
generally one of three types: daywork; footage; or turnkey. Additional
compensation may be acquired for special risks and unusual conditions. Under
daywork contracts we provide the drilling rig with the required personnel to the
operator who then supervises the drilling of the well. Our compensation depends
on a negotiated rate for each day of the rig's use. Footage contracts usually
require us to bear some of the drilling costs in addition to providing the rig.
We are paid on a negotiated per foot drilled rate on completion of the well.
Under turnkey contracts we contract to drill the 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 paid when the
contract provisions are completed.
Under turnkey contracts we may incur 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 2002, we
drilled 15 turnkey wells and turnkey revenue represented 4 percent of our
contract drilling revenues as compared to one percent for 2001. We had one
turnkey contract in progress at December 31, 2002. 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.
Customers. During 2002, 10 customers accounted for approximately 43 percent of
our total contract drilling revenues. Approximately 4 percent of our contract
drilling revenues came from drilling operations we conducted 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).
Additional Information. Further information relating to contract drilling
operations can be found in Notes 1, 2 and 10 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
5
OUR OIL AND NATURAL GAS BUSINESS
General. In 1979 we began to develop our exploration and production operations
to diversify our contract drilling revenues. Today, our wholly owned subsidiary,
Unit Petroleum Company, conducts our exploration and production activities. Our
producing oil and natural gas properties, undeveloped leaseholds and related
assets are mainly 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.
When we are the operator of a property, we generally employ our own
drilling rigs.
Well and Leasehold Data. The tables below set forth certain information
regarding our oil and natural gas exploratory and development drilling
operations:
Year Ended December 31,
-------------------------------------------------------
2000 2001 2002
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Wells Drilled:
- --------------
Exploratory:
Oil - - 1 .01 - -
Natural gas 2 1.63 8 3.60 2 .50
Dry - - 5 4.46 5 2.00
-------- -------- -------- -------- -------- --------
2 1.63 14 8.07 7 2.50
-------- -------- -------- -------- -------- --------
Development:
Oil 7 1.45 6 1.06 4 1.91
Natural gas 75 28.51 87 33.51 68 33.25
Dry 17 8.56 18 10.80 17 14.21
-------- -------- -------- -------- -------- --------
99 38.52 111 45.37 89 49.37
-------- -------- -------- -------- -------- --------
Total 101 40.15 125 53.44 96 51.87
======== ======== ======== ======== ======== ========
6
Year Ended December 31,
----------------------------------------------------------
2000 2001 2002
------------------ ------------------ ------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Oil and Natural
Gas Wells
Producing or
Capable of
Producing:
- ---------------
Oil - USA 799 278.06 786 279.06 790 273.34
Oil -
Canada - - - - - -
Gas - USA 2,088 431.11 2,188 457.38 2,449 524.45
Gas -
Canada 64 1.60 64 1.60 65 1.63
-------- -------- -------- -------- -------- --------
Total 2,951 710.77 3,038 738.04 3,304 799.42
======== ======== ======== ======== ======== ========
In December 2002, we acquired 73 producing oil and natural gas wells for
$12.5 million. The properties are in Hemphill County, Texas.
On March 7, 2003, we were participating in the drilling of 7 gross (2.1304
net) wells in the United States.
7
The following table summarizes our oil and natural gas leasehold acreage
for each of the years indicated:
Developed Acreage Undeveloped Acreage
--------------------- ---------------------
Gross Net Gross Net
--------- --------- --------- ---------
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
========= ========= ========= =========
2002:
- -----
USA 585,313 166,397 142,764 79,911
Canada 39,040 976 5,441 3,360
--------- --------- --------- ---------
Total 624,353 167,373 148,205 83,271
========= ========= ========= =========
8
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 years indicated:
Year Ended December 31,
----------------------------------
2000 2001 2002
---------- ---------- ----------
Average Sales Price per Barrel of Oil
Produced:
USA $ 26.95 $ 23.62 $ 21.54
Canada - - -
Average Sales Price per Mcf of Natural
Gas Produced:
USA $ 3.91 $ 4.00 $ 2.87
Canada $ 2.39 $ 4.21 $ 2.11
Oil Production (Mbbls):
USA 488 492 473
Canada - - -
---------- ---------- ----------
Total 488 492 473
========== ========== ==========
Natural Gas Production (MMcf):
USA 19,239 18,819 18,927
Canada 46 45 41
---------- ---------- ----------
Total 19,285 18,864 18,968
========== ========== ==========
Average Production Expense per
Equivalent Mcf:
USA $ 0.74 $ 0.86 $ 0.79
Canada $ 0.42 $ 0.51 $ 0.60
9
Oil and Natural Gas Reserves. The following table sets forth our estimated
proved developed and undeveloped oil and natural gas reserves for each of the
years indicated:
Year Ended December 31,
----------------------------------
2000 2001 2002
---------- ---------- ----------
Oil (Mbbls):
USA 4,183 4,343 4,096
Canada - - -
---------- ---------- ----------
Total 4,183 4,343 4,096
========== ========== ==========
Natural gas (MMcf):
USA 215,196 227,865 244,494
Canada 441 389 317
---------- ---------- ----------
Total 215,637 228,254 244,811
========== ========== ==========
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 terms ranging from
one month to a year. The longer term contracts contain provisions for price
adjustments. Most of these contracts contain provisions for readjustment of
price, termination and other terms customary in the industry.
Additional Information. Further information relating to oil and natural gas
operations can be found in Notes 1 and 10 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
VOLATILE NATURE OF OUR BUSINESS
The prevailing prices for natural gas and oil significantly affect our
revenues, operating results, cash flow and future rate of growth. Because
natural gas makes up the biggest part of our oil and natural gas reserves as
well as the focus of most of our drilling work we do for others, changes in
natural gas prices have a disproportionate impact on our financial results than
do oil price changes. 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
into the first quarter of 2001. Prices then started to decline sharply and by
February 2002, our average price for natural gas was $1.87 per Mcf and our
average oil price was $15.58. Commodity prices have once again increased and the
average natural gas price we received in December 2002 was $3.95 and the average
oil price we received was $25.59. Our average natural gas and oil price for 2002
was $2.87 and $21.54, respectively.
10
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 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. 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. Due to the fall in natural gas prices which
started in February, 2001, 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 until they stabilized in the middle of the second quarter of 2002. Natural
gas and oil prices once again began to rise during the last half of 2002. As a
result, the future extent of the demand for our drilling services is uncertain.
11
COMPETITION
All of our 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 have more experience in the exploration for and production of oil and
natural gas than we have.
OIL AND NATURAL GAS PROGRAMS AND CONFLICTS OF INTEREST
Unit Petroleum Company serves as the general partner of five oil and gas
limited partnerships and five employee oil and gas limited partnerships. We
formed public partnerships in 1979, 1984, 1985 and two 1986. The employee
partnerships not rolled up and formed in each year subsequent to 1999 have had
an interest not exceeding 5 percent 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 total interest the employees have in our oil and natural gas wells
from participating in these partnerships does not exceed one percent. The
limited partners in the employee partnerships are either employees or directors
of Unit or its subsidiaries. On December 31, 2002, nine of the oldest employee
oil and gas limited partnerships were rolled into one of our five remaining oil
and gas limited 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 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.
12
EMPLOYEES
As of March 7, 2003, we had approximately 1,177 employees in our land
contract drilling operations, 62 employees in our oil and natural gas operations
and 52 in our general corporate area. None of our employees are members of 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 also subject to many of these 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, our drilling contracts provide for
the division of responsibilities between us and our customer, and we seek to
obtain indemnification from our drilling customers 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;
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs or delivery
crews and the delivery of equipment.
A 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
13
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
deplete, 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 our oil and natural gas production,
revenues and cash flow from operations. Historically, we have succeeded in
increasing reserves after taking production into account. However, it is
possible that we may not be able to continue to replace reserves. Low prices of
oil and natural gas may also 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
Various state and federal regulations highly affect the production and sale
of oil and natural gas. 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 has been 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 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 is not affected by the Decontrol
Act.
Our sales of natural gas will be 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 are intended by the FERC to foster competition by,
among other things, transforming the role of interstate pipeline companies from
wholesale marketers of natural gas to the primary role of gas transporters. All
natural gas marketing by the pipelines is required to divest 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
must 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
14
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. We do not know 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, 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 will be
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
15
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 is 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 amended or reinterpreted frequently, we are unable to predict
the future cost or impact of complying with those laws.
SAFE HARBOR STATEMENT
This report, including the information we incorporate by reference,
information included in, or incorporated by reference from, future filings by us
with the SEC, 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 statements that may seem to be "forward-looking statements"
within the meaning of federal securities laws. All statements, other than
statements of historical facts, included or incorporated by reference in this
report, 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 to identify forward-looking statements.
These forward-looking statements include, among others, such things as:
. the amount and nature of our future capital expenditures;
. wells to be drilled or reworked;
. prices for oil and gas;
. demand for oil and gas;
. exploitation and exploration prospects;
. estimates of proved oil and gas reserves;
16
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and gas industry;
. business strategy;
. production of oil and gas reserves;
. expansion and growth of our business and operations; and
. drilling rig utilization and drilling rig rates.
These statements are based on certain assumptions and analyses made by us
in light of our experience and our perception of historical trends, current
conditions and expected future developments as well as other factors we believe
are appropriate in the circumstances. However, whether actual results and
developments will conform to our expectations and predictions is subject to a
number of risks and uncertainties which could cause actual results to differ
materially from our expectations, including:
. the risk factors discussed in this prospectus and in the documents we
incorporate by reference;
. general economic, market or business conditions;
. the nature or lack of business opportunities that we pursue;
. demand for our land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
You should not place undue reliance on any these forward-looking
statements. We disclaim any current intention to update forward-looking
information and to release publicly the results of any future revisions we may
make to forward-looking statements to reflect events or circumstances after the
date of this report to reflect the occurrence of unanticipated events.
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 2003 and beyond to differ materially from those that
may be presented 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 our revenues, profitability and 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 we receive for
such natural gas); and the ability of current distribution systems in the United
States to effectively meet the demand for oil and/or natural gas at any given
time, particularly in times of peak demand which may result due to adverse
weather conditions. Oil prices are extremely sensitive to foreign influences 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
17
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 2002 production, a $.10 per Mcf change in what we receive for
our natural gas production would result in a corresponding $147,100 per month
($1,765,000 annualized) change in our pre-tax operating cash flow. A $1.00 per
barrel change in our oil price would have a $36,700 per month ($440,000
annualized) change in our pre-tax operating cash flow. During 2002,
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 the abandonment of a project 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 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:
18
. 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 is not necessarily 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 rely 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 are
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, required by the SEC for use 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 we exceed the ceiling, even
if prices are depressed for only a short period of time. We may be required to
write down the carrying value of our oil and natural gas properties when oil and
natural gas prices are depressed or unusually volatile. If a write-down is
required, it would result in a charge to earnings but would not impact cash flow
19
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 the growth in our 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. We currently have, and will continue to have, a certain amount of
indebtedness. At December 31, 2002, our long-term debt outstanding, all carried
under our bank loan agreement, was $30.5 million. As of December 31, 2002, 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 $40 million in order to
reduce our financing costs.
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.
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 we undertake at any
given time and the cash flow we receive. Generally, our normal operating costs
are those associated with the drilling of oil and natural gas wells, the
acquisition of producing properties, and the costs
20
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 2002.
21
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:
2001 2002
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
First $ 21.3750 $ 16.3000 $ 18.6000 $ 10.2400
Second $ 23.0000 $ 14.5000 $ 20.2500 $ 16.0100
Third $ 15.8000 $ 7.4100 $ 19.2500 $ 13.6500
Fourth $ 14.2400 $ 8.2900 $ 20.4400 $ 16.7100
On March 7, 2003 there were 1,857 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.
22
Item 6. Selected Financial Data
- ------- -----------------------
Year Ended December 31,
----------------------------------------------------------
1998 (1) 1999 (1) 2000 2001 2002
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 97,274 $ 102,352 $ 201,264 $ 259,179 $ 187,636
========== ========== ========== ========== ==========
Net Income $ 1,428 $ 3,048 $ 34,344 $ 62,766 $ 18,244
========== ========== ========== ========== ==========
Earnings Per
Common Share:
Basic $ 0.05 $ 0.10 $ 0.96 $ 1.75 $ 0.47
========== ========== ========== ========== ==========
Diluted $ 0.05 $ 0.10 $ 0.95 $ 1.73 $ 0.47
========== ========== ========== ========== ==========
Total Assets $ 233,096 $ 295,567 $ 346,288 $ 417,253 $ 578,163
========== ========== ========== ========== ==========
Long-Term Debt $ 75,048 $ 67,239 $ 54,000 $ 31,000 $ 30,500
========== ========== ========== ========== ==========
Other Long-Term
Liabilities $ 2,368 $ 2,325 $ 3,597 $ 4,110 $ 5,439
========== ========== ========== ========== ==========
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 2000, 2001 and 2002 activity.
23
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------- ---------------------------------------------------------------
Results of Operations
---------------------
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Summary. Our financial condition and liquidity depends on the cash flow
from our two principal subsidiaries 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. At December 31, 2002, we had cash totaling $497,000 and we had
borrowed $30.5 million of the $40.0 million we have elected to have available
under our loan agreement.
The following is a summary of certain financial information on December 31,
2002 and for the year ended December 31, 2002:
Working Capital . . . . . . . $ 16,867,000
Net Income. . . . . . . . . . $ 18,244,000
Net Cash Provided by
Operating Activities. . . . $ 70,547,000
Long-Term Debt. . . . . . . . $ 30,500,000
Shareholders' Equity. . . . . $ 421,372,000
Ratio of Long-Term Debt to
Total Capitalization. . . . 7%
The following table summarizes certain operating information for the years
ended December 31, 2001 and 2002:
Percent
2001 2002 Change
------------ ------------ --------
Oil Production (Bbls) . . . 492,000 473,000 (4%)
Natural Gas Production (Mcf) 18,864,000 18,968,000 1%
Average Oil Price Received. $ 23.62 $ 21.54 (9%)
Average Natural Gas Price
Received. . . . . . . . . $ 4.00 $ 2.87 (28%)
Average Number of Our
Drilling Rigs in Use
During the Period . . . . 46.3 39.1 (16%)
Our 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 $40 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 $40 million to reduce our financing costs since we are charged a facility fee
of .375 of 1 percent on the amount available but not borrowed. At December 31,
2002, we had borrowed $30.5 million through the bank loan.
24
Each year, on April 1 and October 1, our banks re-determine the loan value
of our assets. This value is mainly based on 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 ends on May 1, 2005
followed by a three-year term loan. Borrowing under our loan agreement totaled
$32.4 million on February 19, 2003.
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. After 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 between the date of
the agreement and 3 days before 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 several conditions, all of which are set out in the
loan agreement.
The interest rate on our bank debt was 2.47 percent at December 31, 2002
and February 19, 2003. 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 balance of our bank
debt being subject to the 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 $30.5 million at
December 31, 2002 and $31.0 million at February 19, 2003.
The loan agreement also 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;
. a ratio of total liabilities, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.65 to 1; and
. working capital provided by operations, as defined in the loan
agreement, cannot be less than $40 million in any year.
We are restricted 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. Additionally, we can pay dividends if our 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 limited
exceptions. The creation or existence of mortgages or liens, other than those in
the
25
ordinary course of business, on any of our property is prohibited unless it
is in favor of our banks.
Hedging. 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 variations have on our cash flow. 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 the first quarter of
2001, our oil hedging transaction yielded an increase in our oil revenues of
$17,200.
During the second quarter of 2001, we entered into a natural gas collar
contract for approximately 36 percent of our June and July 2001 production, at a
floor price of $4.50 and a ceiling price of $5.95. During the third quarter of
2001, we entered into two natural gas collar contracts for approximately 38
percent of our September thru November 2001 natural gas production. Both
contracts had a floor price of $2.50. One contract had a ceiling of $3.68 and
the other contract had a ceiling of $4.25. During the year of 2001, the collar
contracts increased natural gas revenues by $2,030,000.
On April 30, 2002, we entered into a collar contract covering approximately
19 percent of our natural gas production for the periods of April 1, 2002 thru
October 31, 2002. The collar had a floor of $3.00 and a ceiling of $3.98. During
the year of 2002, our natural gas hedging transactions increased natural gas
revenues by $40,300. We did not have any hedging transactions outstanding at
December 31, 2002.
During the first quarter of 2003, we entered into two collar contracts
covering approximately 40 percent of our natural gas production for the periods
of April 1, 2003 thru September 30, 2003. One collar has a floor of $4.00 and a
ceiling of $5.75 and the other collar has a floor of $4.50 and a ceiling of
$6.02. We also entered into two collar contracts covering approximately 25
percent of our oil production for the periods of May 1, 2003 thru December 31,
2003. One collar has a floor of $25.00 and a ceiling of $32.20 and the other
collar has a floor of $26.00 and a ceiling of $31.40.
Self-Insurance. We are self-insured for certain losses relating to workers'
compensation, general liability, property damage and employee medical benefits.
With the recent tightening in the insurance markets our self-insurance levels
have significantly increased. During the August 1, 2002 renewal of most of our
insurance policies, our exposure (i.e. our deductible or retention) per
occurrence we elected to incur ranged from $200,000 for general liability to $1
million for rig physical damage. We have purchased stop-loss coverage in order
to limit, to the extent feasible, our per occurrence and aggregate exposure to
certain claims. There is no assurance that such coverage will adequately protect
us against liability from all potential consequences.
26
Impact of Prices for Our Oil and Natural Gas. Natural gas comprises 91
percent of our total oil and natural gas reserves. Any significant change in
natural gas prices has a material affect on our revenues, cash flow and the
value of our oil and natural gas reserves. 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.
Based on our production in 2002, a $.10 per Mcf change in what we are paid
for our natural gas production would result in a corresponding $147,100 per
month ($1,765,000 annualized) change in our pre-tax operating cash flow. Our
2002 average natural gas price was $2.87 compared to an average natural gas
price of $4.00 received 2001. A $1.00 per barrel change in our oil price would
have a $36,700 per month ($440,000 annualized) change in our pre-tax operating
cash flow. Our 2002 average oil price was $21.54 compared with an average oil
price of $23.62 received in 2001.
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
decline in the carrying value of our oil and natural gas properties. Price
declines can also adversely affect the semi-annual 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.
We sell most of our natural gas production to third parties under
month-to-month contracts. Several of these buyers have experienced financial
complications resulting from the recent investigations into the energy trading
industry. The long-term implications to the energy trading business, as well as
to oil and natural gas producers, because of these investigations remains, to be
determined. Presently we believe that our buyers will be able to perform their
commitments to us. However, we continue to evaluate the information available to
us about these buyers in an effort to reduce any possible future adverse impact
to us.
Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our
capital expenditures are discretionary and directed toward future growth. Our
decision to increase our oil and natural gas reserves through acquisitions or
through drilling depends on the prevailing or expected market conditions,
potential return on investment, future drilling potential and opportunities to
obtain financing under the circumstances involved, all of which provide us with
a large degree of flexibility in deciding when to incur such costs. We drilled
96 wells (51.87 net wells) in 2002 compared to 125 wells (53.44 net wells) in
2001. In December 2002, we acquired 73 producing oil and natural gas wells for
$12.5 million. Our total capital expenditures for oil and natural gas
exploration and acquisitions in 2002 totaled $58.8 million. Based on current
prices, we plan to drill an estimated 140 to 150 wells in 2002 and total capital
expenditures for oil and natural gas exploration and acquisitions is planned to
be around $65 million.
27
Contract Drilling. Our drilling work is subject to many factors that
influence the number of rigs we have working 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, availability and
cost of labor to run our rigs and our ability to supply the equipment needed. We
have not encountered major difficulty in hiring and keeping rig crews, but such
shortages have occurred periodically in the past. If demand for drilling rigs
increases rapidly in the future, shortages of experienced personnel may limit
our ability to increase the number of rigs we could operate.
Most of our contract drilling fleet is targeted to the drilling of natural
gas wells, so changes in natural gas prices influence the demand for our
drilling rigs and the prices we can charge for our contract drilling services.
Low oil and natural gas prices, during most of the 1980's and 1990's, reduced
demand for domestic land contract drilling rigs. In the last half of 1999 and
throughout 2000, as oil and natural gas prices increased, we experienced a big
increase in demand for our rigs. Demand continued to increase until the end of
the third quarter of 2001 and reached a high when 52 of our rigs were working in
July 2001. Because of declining natural gas prices throughout 2001, demand for
our rigs dropped significantly in the fourth quarter of 2001 and stabilized with
between 30 and 35 rigs operating in the first half on 2002. Natural gas and oil
prices once again began to rise during the last half of 2002. With the August
acquisition of 20 rigs described below, the average use of our rigs in 2002 was
39.1 rigs (63 percent) compared with 46.3 rigs (90 percent) for 2001.
As demand for our rigs increased during 2001 so did the dayrates we
received. Our average dayrate reached $11,142 by September of 2001. However, as
demand began to decrease, so did our rates. Our average dayrate in 2002 was
$7,716 compared to $10,044 for 2001. Based on the average utilization of our
rigs in 2002, a $100 per day change in dayrates has a $3,900 per day ($1,424,000
annualized) change in our pre-tax operating cash flow. Utilization and dayrates
for our drilling rigs will depend mainly on the price of natural gas.
Our contract drilling subsidiary provides drilling services for our
exploration and production subsidiary. The contracts for these services are
issued under the same conditions and rates as the contracts we have entered into
with unrelated third parties. Per regulations provided by the Securities and
Exchange Commission, the profit received by our contract drilling segment of
$2,259,000 and $841,000 during 2001 and 2002, respectively, was used to reduce
the carrying value of our oil and natural gas properties rather than being
included in our profits in current operations.
Drilling Acquisitions and Capital Expenditures. On August 15, 2002, we
completed the acquisition of CREC Rig Equipment Company and CDC Drilling
Company, which included twenty drilling rigs, spare drilling equipment and
vehicles, for 7.22 million shares of our common stock and $4.5 million in cash.
Total consideration for the acquisition was valued at $127 million of which $7.7
million went to goodwill and $2.2 million went to deferred tax assets. All of
the rigs are operational and range in horsepower from 650 to 2,000 with 15
having a horsepower rating of 1,000 or more. Depth
28
capacities range from 12,000 to 25,000 feet and twelve of the rigs are SCR
electric. These agreements also give us the exclusive first option to purchase
any additional rigs constructed by one of the sellers within the next three
years. The addition of these twenty rigs brought our fleet to 75. For our
contract drilling operations during 2002, we incurred $139.3 million in capital
expenditures, which included $7.7 million for goodwill and $2.2 million for
deferred tax assets. For the year 2003, we anticipate capital expenditures of
approximately $25 million for our contract drilling operations.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. As
of December 31, 2002, we rolled up nine of our employee partnerships into a
consolidated partnership. After the rollup, we are the general partner for ten
oil and natural gas partnerships which were formed privately and publicly. The
partnership's revenues and costs are shared under formulas prescribed in each
limited partnership agreement. The partnerships repay us for contract drilling,
well supervision and general and administrative expense. 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 third 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
assigned to the related parties. Allocations are based on the related party's
level of activity and are considered by management to be reasonable. During
2000, 2001 and 2002, the total paid to us for all of these fees was $966,000,
$1,107,000 and $929,000, respectively. We expect the fees to be about the same
in 2003. Our proportionate share of assets, liabilities and net income relating
to the oil and natural gas partnerships is included in our consolidated
financial statements.
We own a 40 percent equity interest in a natural gas gathering and
processing company. Our investment, including our share of the equity in the
earnings of this company, totaled $1.8 million at December 31, 2002 and is
reported in other assets in our accompanying balance sheet. From time to time we
may guarantee the debt of this company. However, as of December 31, 2002 and
February 19, 2003, we were not guaranteeing any of the debt of this company.
Outlook. Both of our operating segments are extremely dependent on natural
gas prices. These prices affect not only our production revenues, but also the
future demand and rates for our contract drilling services. On February 19,
2003, the Nymex Henry Hub average contract settle price for the next twelve
months was $5.59. We anticipate that if natural gas prices continue at that
level, there will be an increase in demand for our rigs and an upward movement
on the rates we receive for our contract drilling services. There is a certain
degree of uncertainty as to whether these prices can be sustained. This
uncertainty has, in turn, made it difficult to measure the future use of our
drilling rigs. We would anticipate that if current natural gas prices are, in
fact, maintained we will experience an upward movement in demand for our rigs.
29
Contractual Commitments. We have the following contractual obligations at
December 31, 2002:
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) $ 30,500 $ - $ 5,931 $ 20,333 $ 4,236
Hickman
Note(2) 1,000 1,000 - - -
Retirement
Agreement(3) 1,412 170 600 600 42
Operating
Leases(4) 1,666 663 839 164 -
--------- ------- -------- --------- --------
Total
Contractual
Obligations $ 34,578 $1,833 $ 7,370 $ 21,097 $ 4,278
========= ======= ======== ========= ========
-------------------
(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, 2002, promissory notes in
the aggregate outstanding principal amount of $1.0 million
(See Note 4 of our Consolidated Financial Statements). These
notes were paid in full in January 2003. The notes bore
interest at the Chase Prime Rate, which at December 31, 2002
was 4.25 percent.
(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 monthly payments of $25,000 starting
in July 2003 and continuing through June 2009 (See Note 4 of
our Consolidated Financial Statements).
(4) 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).
30
At December 31, 2002, 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) $ 1,391 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,081 $ 295 Unknown Unknown Unknown
Gas Balancing
Liability(3) $ 1,020 Unknown Unknown Unknown Unknown
Repurchase
Obliga-
tions(4) 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 Consolidated Financial Statements).
(3) In December 2002, we recorded a liability on certain
properties where we believe there is insufficient reserves
available to allow the under-produced owners to recover their
under-production from future production volumes.
31
(4) 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
2003, 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 $14,000 and $1,000 in 2000 and 2002,
respectively, for such limited partners' interests. No
repurchases were made in 2001 (See Note 9 of our Consolidated
Financial Statements).
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-end oil and natural gas prices,
plus the lower of cost or estimated fair value of unproved properties not
included in the costs being amortized, less related income taxes. If the net
capitalized costs of our oil and natural gas properties exceed the ceiling, we
are subject to a 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. Once
incurred, a write-down cannot be reversed even if prices subsequently recover.
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 large 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 chance of a ceiling test
write-down. Based on oil and natural gas prices on December 31, 2002 ($4.42 per
Mcf for natural gas and $29.70 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 prices remain erratic and any
significant declines below quarter-end prices used in the reserve evaluation
could result in a ceiling test write-down in following quarterly reporting
periods.
32
The value of our oil and natural gas reserves is used to determine the loan
value under our bank 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 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 use 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. Our policy is to expense our pro-rata share of
lease operating costs from all wells as incurred. Such expenses relating to the
natural gas balancing position on wells in which we have an imbalance are not
material.
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 suggest 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 us to reduce the carrying value of
property and equipment.
We recognize revenues generated for "daywork" drilling contracts as the
services are performed, which is similar to the percentage of completion method.
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
reasonably determined, however, any profit is recorded only at the time the well
is finished. 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
33
drilling labor costs increased substantially in the summer of 2000 and once
again in the summer of 2001 and when rig dayrates declined in 2002 the labor
rates did not come back down to the levels incurred prior to the increases. 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
- -----------------------------------
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). In the first
quarter of 2003, the effect of the implementation of FAS 143 (unaudited) is
expected to increase liabilities including deferred taxes by $11.7 million,
increase the net book value of our oil and natural gas properties by $13.0
million and we anticipate adjustment to increase net income for the accumulated
effect of a change in accounting principle of $1.3 million.
In April 2002, the FASB issued Statement of Financial Accounting Standards
No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement 13, and Technical Corrections" ("FAS 145"). FAS 145 is effective for
fiscal years beginning after May 15, 2002. This statement eliminates an
inconsistency between the required accounting for sale-leaseback transactions
and the required accounting for certain lease modifications that have economic
effects that are similar to sale-leaseback transactions. This statement also
amends other existing authoritative pronouncements to make various technical
corrections, clarify meanings, or describe their applicability under changed
conditions. We do not expect the adoption of FAS 145 to have a material effect
on our financial position, results of operations or cashflows.
In July 2002, the FASB issued Statement of Financial Accounting Standards
No. 146, "Accounting for Cost Associated with Exit or Disposal Activities" ("FAS
146"). FAS 146 is effective for exit or disposal activities that are initiated
after December 31, 2002. The Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. FAS 146 nullifies Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
34
Activity (including Certain Costs Incurred in a Restructuring)." We do not
expect the adoption of FAS 146 to have a material effect on our financial
position, results of operations or cashflow.
On December 31, 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure - an amendment of FAS 123" ("FAS 148"). FAS 148 provides additional
transition guidance for companies that elect to voluntarily adopt the accounting
provisions of FAS 123, "Accounting For Stock-Based Compensation." FAS 148 does
not change the provisions of FAS 123 that permit entities to continue to apply
the intrinsic value method of APB 25, "Accounting for Stock Issued to Employees"
("APB 25"). Since we apply APB 25, our accounting for stock-based compensation
will not change as a result of FAS 148. FAS 148 does require certain new
disclosures in both annual and interim financial statements. The required annual
disclosures were effective immediately for us and have been included in Note 1
of our financial statements. The new interim disclosure provisions will be
effective for us in the first quarter of 2003.
On November 25, 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others, an interpretation of FASB
Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34"
("FIN 45"). FIN 45 clarifies the requirements of FASB Statement No. 5,
Accounting for Contingencies (FAS 5), relating to the guarantor's accounting
for, and disclosure of, the issuance of certain types of guarantees. For
guarantees that fall within the scope of FIN 45, the Interpretation requires
that guarantors recognize a liability equal to the fair value of the guarantee
upon its issuance. The Interpretation's provisions for initial recognition and
measurement should be applied on a prospective basis to guarantees issued or
modified after December 31, 2002, irrespective of the guarantor's fiscal
year-end. The guarantor's previous accounting for guarantees that were issued
before the date of FIN 45's initial application may not be revised or restated
to reflect the effect of the recognition and measurement provisions of the
Interpretation. The disclosure requirements are effective for financial
statements of both interim and annual periods that end after December 15, 2002.
We have guaranteed liabilities in the past which would fall under the terms of
FIN 45, but we do not have any such guarantees at December 31, 2002.
On January 17, 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN
46"). The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights ("variable interest entities" or "VIEs") and how to
determine when and which business enterprise should consolidate the VIE. This
new model for consolidation applies to an entity which either (1) the equity
investors (if any) do not have a controlling financial interest or (2) the
equity investment at risk is insufficient to finance that entity's activities
without receiving additional subordinated financial support from other parties.
We do not expect the adoption of this standard to have a material impact on our
financial position or results of operations.
35
RESULTS OF OPERATIONS
- ---------------------
2002 versus 2001
- ----------------
Provided below is a comparison of selected operating and financial data for
the year of 2002 versus the year of 2001:
Percent
2001 2002 Change
--------------- --------------- ---------
Total Revenue $ 259,179,000 $ 187,636,000 (28%)
Net Income $ 62,766,000 $ 18,244,000 (71%)
Oil and Natural Gas:
Revenue $ 90,237,000 $ 67,959,000 (25%)
Average natural gas price (Mcf) $ 4.00 $ 2.87 (28%)
Average oil price (Bbl) $ 23.62 $ 21.54 (9%)
Natural gas production (Mcf) 18,864,000 18,968,000 1%
Oil production (Bbl) 492,000 473,000 (4%)
Operating profit
(revenue less operating
costs) $ 68,041,000 $ 47,164,000 (31%)
Operating margin 75% 69%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.91 $ 1.04 14%
Depreciation, depletion and
amortization (includes
$2,083,000 and $346,000
write off of interest
in Shenandoah in 2001
and 2002) $ 22,116,000 $ 23,338,000 6%
Drilling:
Revenue $ 167,042,000 $ 118,173,000 (29%)
Percentage of revenue from
daywork contracts 99% 91%
Average number of rigs in use 46.3 39.1 (16%)
Average dayrate on daywork
contracts $ 10,044 $ 7,716 (23%)
Operating profit
(revenue less operating
costs) $ 76,036,000 $ 26,835,000 (65%)
Operating margin 46% 23%
Depreciation $ 13,888,000 $ 14,684,000 6%
General and Administrative Expense $ 8,476,000 $ 8,712,000 3%
Interest Expense $ 2,818,000 $ 973,000 (65%)
Average Interest Rate 5.7% 3.0% (47%)
Average Long-Term Debt Outstanding $ 44,995,000 $ 24,771,000 (45%)
36
Oil and natural gas revenues, operating profits and operating profit
margins were all negatively affected by lower prices received for both oil and
natural gas during 2002 compared to 2001. Production in equivalent Mcf was
almost the same in 2002 as in 2001. Total operating cost decreased due to lower
gross production taxes resulting from lower revenues. Total depreciation,
depletion and amortization ("DD&A") on our oil and natural gas properties
increased due to the increase in the DD&A rate in 2002, which resulted from
higher development drilling cost per equivalent Mcf. The increase would have
been larger, but included in 2001 DD&A was the write down of our investment in
Shenandoah Resources LTD. of $2.1 million. The remaining balance of our
investment in Shenandoah Resources LTD. of $346,000 was written off in the third
quarter of 2002.
Reduced natural gas prices, especially in the fourth quarter of 2001 and
the first quarter of 2002, caused decreases in operator demand for contract
drilling rigs within our working area and resulted in lower rig use and dayrates
for our rigs. As a result, operating margins declined between 2002 and 2001.
Approximately 9 percent of our total drilling revenues in 2002 came from footage
and turnkey contracts, which had profit margins lower than our daywork
contracts. One percent of our total drilling revenues came from footage and
turnkey contracts in 2001. Contract drilling depreciation increased due to the
acquisition of 20 rigs in August of 2002. The increase was partially offset by
lower rig use.
General and administrative expense was higher in 2002 due to increases in
labor cost, insurance expense and outside contract services. 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 plus accrued interest will be paid in
$25,000 monthly payments starting in July 2003 and continuing through June 2009.
Our total interest expense is lower due to lower interest rates along with a
substantial reduction in our long-term debt.
37
2001 versus 2000
- -------------------
Provided below is a comparison of selected operating and financial data for
the year of 2001 versus the year of 2000:
Percent
2000 2001 Change
--------------- --------------- ---------
Total Revenue $ 201,264,000 $ 259,179,000 29%
Net Income $ 34,344,000 $ 62,766,000 83%
Oil and Natural Gas:
Revenue $ 92,016,000 $ 90,237,000 (2%)
Average natural gas price (Mcf) $ 3.91 $ 4.00 2%
Average oil price (Bbl) $ 26.95 $ 23.62 (12%)
Natural gas production (Mcf) 19,285,000 18,864,000 (2%)
Oil production (Bbl) 488,000 492,000 1%
Operating profit
(revenue less operating
costs) $ 72,262,000 $ 68,041,000 (6%)
Operating margin 79% 75%
Depreciation, depletion and
amortization rate (Mcfe) $ 0.82 $ 0.91 11%
Depreciation, depletion and
amortization (includes
$2,083,000 write off
of interest in
Shenandoah in 2001) $ 18,492,000 $ 22,116,000 20%
Drilling:
Revenue $ 108,075,000 $ 167,042,000 55%
Percentage of revenue from
daywork contracts 85% 99%
Average number of rigs in use 39.8 46.3 16%
Average dayrate on daywork
contracts $ 6,957 $ 10,044 44%
Operating profit
(revenue less operating
costs) $ 24,024,000 $ 76,036,000 217%
Operating margin 22% 46%
Depreciation $ 11,999,000 $ 13,888,000 16%
General and Administrative Expense $ 6,560,000 $ 8,476,000 29%
Interest Expense $ 5,136,000 $ 2,818,000 (45%)
Average Interest Rate 7.9% 5.7% (28%)
Average Long-Term Debt Outstanding $ 62,302,000 $ 44,995,000 (28%)
38
Total revenues and net income were higher in 2001 versus 2000 due to
increases in the use of our drilling rigs, as well as, the dayrates we received
for the use of the drilling rigs.
Oil and natural gas revenues, operating profits and operating profit
margins were all negatively affected by lower natural gas production and drops
in the oil price we received between 2001 and 2000. Total operating cost
increased due to the addition of new wells through development drilling and
increases in ad valorem taxes, workover expenses and compression fees. Operating
margins also decreased due to declines in production on older wells without
corresponding declines in operating expenses. Depreciation, depletion and
amortization ("DD&A") increased in 2001 due to a write down of our investment in
Shenandoah Resources LTD. by $2.1 million and an increase in our DD&A rate per
equivalent Mcf resulting from higher development drilling cost per equivalent
Mcf.
Higher 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. As a result, drilling revenues and operating margins
increased between 2001 and 2000. 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 primarily due to increased utilization and
increases in field labor cost.
General and administrative expense was higher in 2001 because 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. Our total interest expense is
lower due to lower interest rates along with a reduction in our long-term debt.
39
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
received for our oil and natural gas production fluctuated and such fluctuation
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 2002
production, a $.10 per Mcf change in what we are paid for our natural gas
production would result in a corresponding $147,100 per month ($1,765,000
annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our
oil price would have a $36,700 per month ($440,000 annualized) change in our
pre-tax operating cash flow.
In an effort to try and reduce the impact of price fluctuations, over the
past several years we periodically have used hedging strategies to hedge the
price we will receive for a portion of our future oil and natural gas
production. A detailed explanation of those transactions has been included under
hedging in the financial condition portion of management's discussion and
analysis of financial condition and results of operations included above.
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 2002, a one percent change in the floating
rate would change our annual pre-tax cash flow by approximately $248,000.
40
Item 8. Financial Statements and Supplementary Data
- ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
-----------------------
2001 2002
---------- ----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 391 $ 497
Accounts receivable (less allowance for
doubtful accounts of $604 and $1,203) 33,886 33,912
Materials and supplies 5,358 8,794
Income tax receivable 3,198 3,602
Prepaid expenses and other 3,761 4,594
---------- ----------
Total current assets 46,594 51,399
---------- ----------
Property and Equipment:
Drilling equipment 244,698 369,777
Oil and natural gas properties, on
the full cost method 406,491 465,250
Transportation equipment 6,441 6,856
Other 9,231 9,906
---------- ----------
666,861 851,789
Less accumulated depreciation, depletion,
amortization and impairment 304,643 341,031
---------- ----------
Net property and equipment 362,218 510,758
---------- ----------
Other Assets 8,441 16,006
---------- ----------
Total Assets $ 417,253 $ 578,163
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
41
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
-----------------------
2001 2002
---------- ----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
-----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities $ 1,893 $ 1,465
Accounts payable 16,292 21,119
Accrued liabilities 10,616 11,921
Contract advances 240 27
---------- ----------
Total current liabilities 29,041 34,532
---------- ----------
Long-Term Debt 31,000 30,500
---------- ----------
Other Long-Term Liabilities (Note 4) 4,110 5,439
---------- ----------
Deferred Income Taxes 73,940 86,320
---------- ----------
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,
36,006,267 and 43,339,400
shares issued, respectively 7,201 8,668
Capital in excess of par value 141,977 264,180
Retained earnings 130,280 148,524
Treasury stock at cost (30,000 shares) (296) -
---------- ----------
Total shareholders' equity 279,162 421,372
---------- ----------
Total Liabilities and Shareholders' Equity $ 417,253 $ 578,163
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
42
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
--------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 108,075 $ 167,042 $ 118,173
Oil and natural gas 92,016 90,237 67,959
Other 1,173 1,900 1,504
---------- ---------- ----------
Total revenues 201,264 259,179 187,636
---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 84,051 91,006 91,338
Depreciation 11,999 13,888 14,684
Oil and natural gas:
Operating costs 19,754 22,196 20,795
Depreciation, depletion,
amortization and
impairment 18,492 22,116 23,338
General and administrative 6,560 8,476 8,712
Interest 5,136 2,818 973
---------- ---------- ----------
Total expenses 145,992 160,500 159,840
---------- ---------- ----------
Income Before Income Taxes 55,272 98,679 27,796
---------- ---------- ----------
Income Tax Expense:
Current 621 5,609 (3,469)
Deferred 20,307 30,304 13,021
---------- ---------- ----------
Total income taxes 20,928 35,913 9,552
---------- ---------- ----------
Net Income $ 34,344 $ 62,766 $ 18,244
========== ========== ==========
Net Income Per Common Share:
Basic $ 0.96 $ 1.75 $ 0.47
========== ========== ==========
Diluted $ 0.95 $ 1.73 $ 0.47
========== ========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
43
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 2000, 2001 and 2002
Accumulated
Capital Other
In Excess Comprehen-
Common Of Par Retained Sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- ----------- -------- ----------
(In thousands)
Balances,
January 1, 2000 $ 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
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
derivative
instru-
ments
used as
cash flow
hedges - - - 1,258 - 1,258
Adjustment
reclas-
ification -
derivative
settle-
ments - - - (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 CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED
Year Ended December 31, 2000, 2001 and 2002
Accumulated
Capital Other
In Excess Comprehen-
Common Of Par Retained Sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- ----------- -------- ----------
(In thousands)
Balances,
December 31,
2001 $ 7,201 $ 141,977 $130,280 $ - $ (296) $ 279,162
Net Income - - 18,244 - - 18,244
Activity in
employee
compensation
plans
(113,133
shares) 23 1,156 - - 296 1,475
Issuance of
stock for
acquisistion
(7,220,000
shares) 1,444 121,047 - - - 122,491
Other
comprehensive
income (net of
tax):
Change in
value of
cash flow
derivative
instru-
ments
used as
cash flow
hedges - - - 25 - 25
Adjustment
reclas-
ification -
derivative
settle-
ments - - - (25) - (25)
-------- ---------- --------- ----------- -------- ----------
Balances,
December 31,
2002 $ 8,668 $ 264,180 $148,524 $ - $ - $ 421,372
======== ========== ========= =========== ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
45
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands)
Cash Flows From Operating
Activities:
Net Income $ 34,344 $ 62,766 $ 18,244
Adjustments to reconcile
net income to net cash
provided (used) by
operating activities:
Depreciation, depletion,
amortization and
impairment 30,946 36,642 38,657
Equity in net earnings of
unconsolidated investments - (1,148) (745)
Loss (gain) on disposition
of assets (969) (56) (69)
Employee compensation
plans 443 2,873 1,165
Bad debt expense 350 - 603
Deferred tax expense 20,307 30,304 13,021
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (18,500) 6,334 (43)
Materials and supplies (543) (1,556) (3,436)
Prepaid expenses and other (96) (3,533) 2,365
Accounts payable (1,370) (155) 1,784
Accrued liabilities 3,067 929 (350)
Contract advances (179) 61 (213)
Other liabilities (440) (440) (436)
---------- ---------- ----------
Net cash provided by
operating activities 67,360 133,021 70,547
---------- ---------- ----------
The accompanying notes are an integral part of the
consolidated financial statements.
46
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
------------------------------------
2000 2001 2002
---------- ---------- ----------
(In thousands)
Cash Flows From Investing
Activities:
Capital expenditures (including
producing property
acquisitions) $ (60,447) $(108,339) $ (75,225)
Proceeds from disposition of
property and equipment 4,259 2,631 1,949
(Acquisition) disposition
of other assets (2,656) 17 540
---------- ---------- ----------
Net cash used in
investing activities (58,844) (105,691) (72,736)
---------- ---------- ----------
Cash Flows From Financing
Activities:
Borrowings under line of credit 31,200 57,200 36,700
Payments under line of credit (44,439) (79,200) (36,200)
Net payments on notes payable
and other long-term debt (556) (1,000) (1,161)
Proceeds from exercise of
stock options 250 609 413
Book overdrafts (Note 1) 3,108 (4,978) 2,543
Acquisition of treasury stock - (296) -
---------- ---------- ----------
Net cash provided by
(used in) financing
activities (10,437) (27,665) 2,295
---------- ---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (1,921) (335) 106
Cash and Cash Equivalents,
Beginning of Year 2,647 726 391
---------- ---------- ----------
Cash and Cash Equivalents,
End of Year $ 726 $ 391 $ 497
========== ========== ==========
Supplemental Disclosure of Cash
Flow Information:
Cash paid (received) during
the year for:
Interest $ 5,135 $ 2,807 $ 1,053
Income taxes $ 519 $ 7,779 $ (4,585)
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the
consolidated financial statements.
47
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, 2002, Unit had an
interest in a total of 3,304 wells and served as operator of 707 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 2002, 68 of Unit's 75
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.
48
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, 2001 and 2002, book overdrafts of $1.1 million and $3.6
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.
49
Goodwill. Goodwill represents the excess of the cost of the acquisition of
Hickman Drilling Company, CREC Rig Equipment Company and CDC Drilling Company
over the fair value of the net assets acquired. Prior to January 1, 2002
goodwill was amortized on the straight-line method using a 25 year life. Unit
expensed $243,000 annually for the amortization of goodwill. 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 became
effective for the fiscal years starting after December 15, 2001 (January 1, 2002
for Unit). Net goodwill reported in other assets at December 31, 2001 and 2002
was $5,088,000 and $12,794,000, respectively, and is all related to the drilling
segment. Goodwill of $7,009,000 is expected to be deductible for tax purposes.
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 $0.82, $0.91 and $1.04 per Mcfe in
2000, 2001 and 2002, 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 $16.0 million are excluded from the DD&A
calculation. In the event the unamortized cost of oil and natural gas properties
being amortized exceeds the full cost ceiling, as defined by the SEC, the excess
is charged to expense in the period during which such excess occurs. The full
cost ceiling is based principally on the estimated future discounted net cash
flows from Unit's oil and natural gas properties. As discussed in Note 12, such
estimates are imprecise.
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, 2001 and 2002,
Unit recorded $179,000, $2,259,000 and $841,000 of contract drilling profits,
respectively, as a reduction of the carrying value of its oil and natural gas
properties rather than including these profits in current operations.
50
Limited Partnerships. Unit's wholly owned subsidiary, Unit Petroleum
Company, is a general partner in ten 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. Unit estimates its
December 31, 2002 balancing position to be approximately 1.9 Bcf on
under-produced properties and approximately 2.3 Bcf on over-produced properties.
Unit has recorded a receivable of $485,000 on certain wells where we estimated
that insufficient reserves are available for Unit to recover the
under-production from future production volumes. Unit has also recorded a
liability of $1,020,000 on certain properties where we believe there is
insufficient reserves available to allow the under-produced owners to recover
their under-production from future production volumes. 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.
Equity Investments. Unit owns a 40 percent equity interest in a natural gas
gathering and processing company. The investment, including Unit's share of the
equity in the earnings of this company, totaled $1.8 million at December 31,
2002 and is reported in other assets.
51
Employee and Director Stock Based Compensation. Unit applies APB Opinion 25
in accounting for its stock option plans for its employees and directors, which
are explained more fully in Note 6. 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 2000, 2001 and 2002 no compensation expense has been
recognized. Compensation expense included in reported net income is Unit's
matching 401(k) contribution (See Note 6). 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:
2000 2001 2002
--------- --------- ---------
Net Income, as Reported
(In Thousands) $ 34,344 $ 62,766 $ 18,244
Add Stock Based Employee Compensation
Expense Included in Reported Net
Income - Net of Tax 369 671 669
Less Total Stock Based Employee
Compensation Expense Determined
Under Fair Value Based Method
For All Awards (727) (1,615) (1,488)
--------- --------- ---------
Pro Forma Net Income $ 33,986 $ 61,822 $ 17,425
========= ========= =========
Basic Earnings per Share:
As reported $ 0.96 $ 1.75 $ 0.47
========= ========= =========
Pro forma $ 0.95 $ 1.72 $ 0.45
========= ========= =========
Diluted Earnings per Share:
As reported $ 0.95 $ 1.73 $ 0.47
========= ========= =========
Pro forma $ 0.94 $ 1.71 $ 0.45
========= ========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. Unit's estimate of stock volatility in 2000 and 2001 was 0.55 and in 2002
was 0.53, based on previous stock performance. Dividend yield was estimated to
remain at zero with a risk free interest rate of 5.26, 5.41 and 4.24 percent in
2000, 2001 and 2002, 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
and 2002 under the Stock Option Plan were $1,470,000 and $1,669,000,
respectively. No options were issued under the Stock Option Plan in 2001. Under
the Non-Employee
52
Directors' Stock Option Plan the aggregate fair value of options granted
during 2000, 2001 and 2002 were $99,000, $201,000 and $262,000, respectively.
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 $4,583,000 and $3,632,000 for
employer group health insurance and worker's compensation at December 31, 2001
and 2002, respectively. Due to high premium cost, Unit decided to increase its
deductible for general liability claims to $200,000 and to $1.0 million for rig
physical damage claims.
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. During 2001, 30,000
shares were repurchased for $296,000. These shares were used for a portion of
the company match to the 401(k) Employee Thrift Plan. No treasury stock was
owned by Unit at December 31, 2002.
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 2002, one purchaser of Unit's oil and natural gas production
accounted for approximately 11 percent of consolidated revenues. At December 31,
2002 accounts receivable from one oil and natural gas purchaser was
approximately $713,000. In addition, at December 31, 2001 and 2002, Unit had a
concentration of cash of $2.0 million and $3.0 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-
53
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
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.
On April 30, 2002, Unit entered into a collar contract covering
approximately 19 percent of its natural gas production for the periods of April
1, 2002 thru October 31, 2002. The collar had a floor of $3.00 and a ceiling of
$3.98. During the year of 2002, the natural gas hedging transactions increased
natural gas revenues by $40,300. At December 31, 2002, Unit was not holding any
natural gas or oil derivative contracts.
During the first quarter of 2003, Unit entered into two collar contracts
covering approximately 40 percent of its natural gas production for the periods
of April 1, 2003 thru September 30, 2003. One collar has a floor of $4.00 and a
ceiling of $5.75 and the other collar has a floor of $4.50 and a ceiling of
$6.02. Unit also entered into two collar contracts covering approximately 25
percent of its oil production for the periods of May 1, 2003 thru December 31,
2003. One collar has a floor of $25.00 and a ceiling of $32.20 and the other
collar has a floor of $26.00 and a ceiling of $31.40.
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.
54
Impact of Financial Accounting Pronouncements.
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). In
the first quarter of 2003, the effect of the implementation of FAS 143
(unaudited) is expected to increase liabilities including deferred taxes by
$11.7 million, increase the net book value of Unit's oil and natural gas
properties by $13.0 million and the anticipated adjustment to increase net
income for the accumulated effect of a change in accounting principle is
expected to be $1.3 million.
In April 2002, the FASB issued Statement of Financial Accounting Standards
No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement 13, and Technical Corrections" ("FAS 145"). FAS 145 is effective for
fiscal years beginning after May 15, 2002. This statement eliminates an
inconsistency between the required accounting for sale-leaseback transactions
and the required accounting for certain lease modifications that have economic
effects that are similar to sale-leaseback transactions. This statement also
amends other existing authoritative pronouncements to make various technical
corrections, clarify meanings, or describe their applicability under changed
conditions. Unit does not expect the adoption of FAS 145 to have a material
effect on our financial position, results of operations or cashflows.
In July 2002, the FASB issued Statement of Financial Accounting Standards
No. 146, "Accounting for Cost Associated with Exit or Disposal Activities" ("FAS
146"). FAS 146 is effective for exit or disposal activities that are initiated
after December 31, 2002. The Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. FAS 146 nullifies Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)." Unit does not
expect the adoption of FAS 146 to have a material effect on our financial
position, results of operations or cashflows.
On December 31, 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure - an amendment of FAS 123" ("FAS 148"). FAS 148 provides additional
transition guidance for companies that elect to voluntarily adopt the accounting
provisions of FAS 123, "Accounting For Stock-Based Compensation." FAS 148 does
not change the provisions of FAS 123 that permit entities to continue to apply
the intrinsic value method of APB 25, "Accounting for Stock Issued to Employees"
("APB 25"). Since Unit applies APB 25, its accounting for stock-based
compensation will not change as a
55
result of FAS 148. FAS 148 does require certain new disclosures in both
annual and interim financial statements. The required annual disclosures were
effective immediately for Unit and have been included above in Note 1 of the
Company's financial statements. The new interim disclosure provisions will be
effective for Unit in the first quarter of 2003.
On November 25, 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others, an interpretation of FASB
Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34"
("FIN 45"). FIN 45 clarifies the requirements of FASB Statement No. 5,
Accounting for Contingencies ("FAS 5"), relating to the guarantor's accounting
for, and disclosure of, the issuance of certain types of guarantees. For
guarantees that fall within the scope of FIN 45, the Interpretation requires
that guarantors recognize a liability equal to the fair value of the guarantee
upon its issuance. The Interpretation's provisions for initial recognition and
measurement should be applied on a prospective basis to guarantees issued or
modified after December 31, 2002, irrespective of the guarantor's fiscal
year-end. The guarantor's previous accounting for guarantees that were issued
before the date of FIN 45's initial application may not be revised or restated
to reflect the effect of the recognition and measurement provisions of the
Interpretation. The disclosure requirements are effective for financial
statements of both interim and annual periods that end after December 15, 2002.
Unit has guaranteed liabilities in the past which would fall under the terms of
FIN 45, but it does not have any such guarantees at December 31, 2002.
On January 17, 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN
46"). The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights ("variable interest entities" or "VIEs") and how to
determine when and which business enterprise should consolidate the VIE. This
new model for consolidation applies to an entity which either (1) the equity
investors (if any) do not have a controlling financial interest or (2) the
equity investment at risk is insufficient to finance that entity's activities
without receiving additional subordinated financial support from other parties.
Unit does not expect the adoption of this standard to have a material impact on
its financial position or results of operations.
56
NOTE 2 - ACQUISITIONS
- ---------------------
On August 15, 2002, Unit completed the acquisition of CREC Rig Equipment
Company and CDC Drilling Company. Both of these acquisitions were stock purchase
transactions. Unit issued 6,819,748 shares of common stock and paid $3,813,053
for all the outstanding shares of CREC Rig Equipment Company and issued
400,252 shares of common stock and paid $686,947 for all the outstanding shares
of CDC Drilling Company. The assets of the acquired companies included twenty
drilling rigs, spare drilling equipment and vehicles. What we paid in both
transactions was determined through arms-length negotiations between the parties
and only the cash portion of the transaction appears in the investing and
financing activities of Unit's Consolidated Condensed Statement of Cash Flows.
Total consideration given in the acquisition was determined based on the
depth capacity of the rigs, the working condition of the rigs and the ability of
the rigs to enhance Unit's ability to provide services and equipment required by
our customers on a timely basis within the Anadarko and Gulf Coast areas were
the rigs are located. The calculation and allocation of the total consideration
paid for the acquisition are as follows (in thousands):
Calculation of Consideration Paid:
Unit Corporation common stock
(7,220,000 shares at $16.96556 per share) $ 122,491
Cash 4,500
----------
Total consideration $ 126,991
==========
Allocation of Total Consideration Paid:
Drilling rigs $ 112,994
Spare drilling equipment 3,500
Vehicles 636
Deferred tax asset 2,155
Goodwill 7,706
----------
Total consideration $ 126,991
==========
57
Unaudited summary pro forma results of operations for the Company,
reflecting the above acquisitions as if they had occurred at the beginning of
the year ended December 31, 2001 are as follow:
Year Ended Year Ended
December 31, December 31,
2001 2002
-------------- --------------
Revenues $ 311,104,000 $ 215,805,000
============== ==============
Net Income $ 70,457,000 $ 15,320,000
============== ==============
Net Income per
Common Share
(Diluted) $ 1.62 $ 0.34
============== ==============
The pro forma results of operations are not necessarily indicative of the
actual results of operations that would have occurred had the purchase actually
been made at the beginning of the respective periods nor of the results which
may occur in the future.
58
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, 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
============= ============= ==========
For the Year Ended
December 31, 2002:
Basic earnings per
common share $ 18,244,000 38,844,000 $ 0.47
==========
Effect of dilutive
stock options 268,000
------------- -------------
Diluted earnings per
common share $ 18,244,000 39,112,000 $ 0.47
============= ============= ==========
59
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,:
2000 2001 2002
---------- ---------- ----------
Options 144,000 153,000 198,500
========== ========== ==========
Average Exercise Price $ 16.59 $ 16.79 $ 19.01
========== ========== ==========
NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
- -------------------------------------------------------
Long-term debt consisted of the following as of December 31, 2001 and 2002:
2001 2002
---------- ----------
(In thousands)
Revolving Credit and Term Loan,
with Interest at December 31,
2001 and 2002 of 3.3 Percent
and 2.5 Percent, Respectively $ 30,000 $ 30,500
Notes Payable for Hickman
Drilling Company Acquisition
with Interest at December 31,
2001 and 2002 of 4.75 Percent
and 4.25 Percent, Respectively 2,000 1,000
---------- ----------
32,000 31,500
Less Current Portion 1,000 1,000
---------- ----------
Total Long-Term Debt $ 31,000 $ 30,500
========== ==========
At December 31, 2002, 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 $40 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
60
$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 pays an origination fee equal to one percent of the elected loan
commitment annually 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. At December 31, 2002, $1
million remained outstanding on these promissory notes and they were paid in
full in January 2003.
61
Other long-term liabilities consisted of the following as of December 31,
2001 and 2002:
2001 2002
---------- ----------
(In thousands)
Separation Benefit Plan $ 1,959 $ 2,081
Deferred Compensation Plan 1,277 1,391
Retirement Agreement 1,330 1,412
Gas Balancing Liability - 1,020
Natural Gas Purchaser Prepayment 437 -
---------- ----------
5,003 5,904
Less Current Portion 893 465
---------- ----------
Total Other Long-Term Liabilities $ 4,110 $ 5,439
========== ==========
Estimated annual principal payments under the terms of long-term debt and
other long-term liabilities from 2003 through 2007 are $1,465,000, $300,000,
$6,231,000, $10,467,000 and $10,467,000. Based on the borrowing rates currently
available to Unit for debt with similar terms and maturities, long-term debt at
December 31, 2002 approximates its fair value.
62
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:
2000 2001 2002
---------- ---------- ----------
(In thousands)
Income Tax Expense Computed by
Applying the Statutory Rate $ 19,345 $ 34,538 $ 9,739
State Income Tax, Net of
Federal Benefit 1,575 2,859 834
Statutory Depletion and Other 8 (1,484) (1,021)
---------- ---------- ----------
Income tax expense $ 20,928 $ 35,913 $ 9,552
========== ========== ==========
Deferred tax assets and liabilities are comprised of the following at
December 31, 2001 and 2002:
2001 2002
----------- -----------
(In thousands)
Deferred Tax Assets:
Allowance for losses
and nondeductible accruals $ 3,867 $ 3,942
Net operating loss carryforward - 17,752
Statutory depletion carryforward 2,874 4,231
Alternative minimum tax credit
carryforward 5,196 395
----------- -----------
Gross deferred tax assets 11,937 26,320
Deferred Tax Liability:
Depreciation, depletion and
amortization (83,720) (110,598)
----------- -----------
Net deferred tax liability (71,783) (84,278)
Current Deferred Tax Asset 2,157 2,042
----------- -----------
Non-Current - Deferred Tax Liability $ (73,940) $ (86,320)
=========== ===========
63
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, 2002, Unit has an excess statutory depletion carryforward
of approximately $11,135,000, which may be carried forward indefinitely and is
available to reduce future taxable income, subject to statutory limitations. At
December 31, 2002, Unit has net operating loss carryforwards of approximately
$46,700,000 which expire from 2019 to 2022.
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. No shares were issued under the Plan in 2000,
2001 and 2002.
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 typically 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.
64
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 2000 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
Granted 160,000 19.03
Exercised (59,400) 5.67
----------- ----------
Outstanding at December 31, 2002 632,700 $ 11.08
=========== ==========
OUTSTANDING OPTIONS
AT DECEMBER 31, 2002
---------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 2.75 - $ 4.00 236,500 4.3 years $ 3.42
$ 7.25 - $10.00 94,200 4.1 years $ 8.58
$11.31 - $14.06 6,500 7.3 years $ 13.61
$16.69 - $19.04 295,500 9.0 years $ 17.95
65
EXERCISABLE OPTIONS
AT DECEMBER 31, 2002
-------------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
------------------------------------ ----------- -----------
$ 2.75 - $ 4.00 196,000 $ 3.36
$ 7.25 - $10.00 91,700 $ 8.61
$11.31 - $14.06 3,200 $ 13.18
$16.69 - $19.04 64,200 $ 17.05
Options for 407,900, 329,300 and 355,100 shares were exercisable with
weighted average exercise prices of $4.24, $6.25 and $7.28 at December 31, 2000,
2001 and 2002, 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.
66
Activity pertaining to the Directors' Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
----------- ----------
Outstanding at January 1, 2000 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
Granted 21,000 20.10
Exercised (2,500) 1.75
----------- ----------
Outstanding at December 31, 2002 94,000 $ 12.14
=========== ==========
OUTSTANDING AND
EXERCISABLE OPTIONS
AT DECEMBER 31, 2002
---------------------------------------
WEIGHTED
AVERAGE WEIGHTED
NUMBER REMAINING AVERAGE
EXERCISE OF CONTRACTUAL EXERCISE
PRICES SHARES LIFE PRICE
----------------------- ----------- ----------- -----------
$ 2.88 - $ 3.75 15,000 1.0 years $ 3.40
$ 6.87 - $ 9.00 30,000 5.0 years $ 7.76
$12.19 - $17.54 28,000 8.0 years $ 15.53
$20.10 - $20.10 21,000 9.3 years $ 20.10
67
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 58,353, 35,016 and
87,452 shares of common stock and recognized expense of $595,000, $1,082,000 and
$1,079,000 in 2000, 2001 and 2002, 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
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, 2000, 2001 and 2002 totaled $1,536,000, $1,277,000 and $1,391,000,
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 $558,000, $589,000 and $619,000 in 2000, 2001 and 2002,
respectively, for benefits associated with anticipated payments from both
separation plans.
Unit has 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 Unit. 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
68
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.
NOTE 7 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
Unit formed private limited partnerships (the "Partnerships") with certain
qualified employees, officers and directors from 1984 through 2002, 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. On December 31, 2002, Unit rolled up nine of
the private limited partnerships and consolidated them into one partnership.
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:
2000 2001 2002
--------- --------- ---------
(In thousands)
Contract Drilling $ 296 $ 416 $ 209
Well Supervision and Other Fees $ 478 $ 498 $ 510
General and Administrative
Expense Reimbursement $ 192 $ 193 $ 210
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.
69
A subsidiary of Unit paid the Partnerships, for which Unit or a subsidiary
is the general partner, $6,000, $3,000 and $1,000 during the years ended
December 31, 2000, 2001 and 2002, respectively, for purchases of natural gas
production.
NOTE 8 - SHAREHOLDER RIGHTS PLAN
- --------------------------------
Unit maintains a Shareholder Rights Plan (the "Plan") designed to deter
coercive or unfair takeover tactics, to prevent a person or group from gaining
control of Unit without offering fair value to all shareholders and to deter
other abusive takeover tactics, which are not in the best interest of
shareholders.
Under the terms of the Plan, each share of common stock is accompanied by
one right, which given certain acquisition and business combination criteria,
entitles the shareholder to purchase from Unit one one-hundredth of a newly
issued share of Series A Participating Cumulative Preferred Stock at a price
subject to adjustment by Unit or to purchase from an acquiring company certain
shares of its common stock or the surviving company's common stock at 50 percent
of its value.
The rights become exercisable 10 days after Unit learns that an acquiring
person (as defined in the Plan) has acquired 15 percent or more of the
outstanding common stock of Unit or 10 business days after the commencement of a
tender offer, which would result in a person owning 15 percent or more of such
shares. Unit can redeem the rights for $0.01 per right at any date prior to the
earlier of (i) the close of business on the 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 $663,000, $647,000, $192,000, $151,000 and $13,000 in
2003, 2004, 2005, 2006 and 2007, respectively. Total rent expense incurred by
the Company was $535,000, $582,000 and $678,000 in 2000, 2001 and 2002,
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 $14,000 and $1,000 in
2000 and 2002, 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.
70
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
- --------------------------------------
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.
71
2000 2001 2002
---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 108,075 $ 167,042 $ 118,173
Oil and natural gas 92,016 90,237 67,959
Other 1,173 1,900 1,504
---------- ---------- ----------
Total revenues $ 201,264 $ 259,179 $ 187,636
========== ========== ==========
Operating Income (1):
Contract drilling $ 12,025 $ 62,148 $ 12,151
Oil and natural gas 53,770 45,925 23,826
---------- ---------- ----------
Total operating income 65,795 108,073 35,977
General and administrative
expense (6,560) (8,476) (8,712)
Interest expense (5,136) (2,818) (973)
Other income (expense)- net 1,173 1,900 1,504
---------- ---------- ----------
Income before income taxes $ 55,272 $ 98,679 $ 27,796
========== ========== ==========
Identifiable Assets (2):
Contract drilling $ 141,324 $ 183,471 $ 299,655
Oil and natural gas 198,251 220,476 261,440
---------- ---------- ----------
Total identifiable assets 339,575 403,947 561,095
Corporate assets 6,713 13,306 17,068
---------- ---------- ----------
Total assets $ 346,288 $ 417,253 $ 578,163
========== ========== ==========
72
2000 2001 2002
---------- ---------- ----------
(In thousands)
Capital Expenditures:
Contract drilling $ 22,045 $ 51,280 $ 139,298 (3)
Oil and natural gas 39,884 56,933 58,778
Other 3,324 539 516
---------- ---------- ----------
Total capital expenditures $ 65,253 $ 108,752 $ 198,592
========== ========== ==========
Depreciation, Depletion,
Amortization and Impairment:
Contract drilling $ 11,999 $ 13,888 $ 14,684
Oil and natural gas 18,492 22,116 23,338
Other 455 638 635
---------- ---------- ----------
Total depreciation,
depletion, amortization
and impairment $ 30,946 $ 36,642 $ 38,657
========== ========== ==========
- ----------------------
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not
include non-operating revenues, general corporate expenses, interest
expense or income taxes.
(2) Identifiable assets are those used in Unit's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements,
furniture and equipment.
(3) Includes $7.7 million for goodwill and $2.2 million for deferred tax
assets.
73
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- -------------------------------------------------------------------
Summarized quarterly financial information for 2001 and 2002 is as follows:
THREE MONTHS ENDED
------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ----------- ------------ -----------
(In thousands except per share amounts)
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(2) $ 19,172 $ 18,048 $ 15,631 $ 9,915
=========== =========== =========== ===========
Earnings per
common share:
Basic (3) $ 0.53 $ 0.50 $ 0.43 $ 0.28
=========== =========== =========== ===========
Diluted $ 0.53 $ 0.50 $ 0.43 $ 0.27
=========== =========== =========== ===========
Year Ended
December 31, 2002:
Revenues $ 38,730 $ 44,753 $ 48,272 $ 55,881
=========== =========== =========== ===========
Gross profit(1) $ 6,515 $ 10,295 $ 8,107 $ 11,060
=========== =========== =========== ===========
Income before
income taxes $ 4,254 $ 8,297 $ 6,022 $ 9,223
=========== =========== =========== ===========
Net income(2) $ 2,642 $ 5,108 $ 3,708 $ 6,786
=========== =========== =========== ===========
Earnings per
common share:
Basic (3) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== =========== ===========
Diluted (4) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== =========== ===========
- ------------------
(1) Gross profit excludes other revenues, general and administrative
expense and interest expense.
(2) The net income for the three months ended December 31, 2001 and 2002
includes a tax benefit of $1.5 million and $1.1 million, respectively,
relating to an increase in the estimated amount of statutory depletion
carryforward.
74
(3) Due to the effect of rounding basic earnings per share for the year's
four quarters does not equal the annual earnings per share.
(4) Due to the effect of price changes of Unit's stock, diluted earnings
per share for the year's four quarters, which includes the effect of
potential dilutive common shares calculated during each quarter, does
not equal the annual diluted earnings per share, which includes the
effect of such potential dilutive common shares calculated for the
entire year.
75
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)
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 acquired $ 5,522 $ 16 $ 5,538
Producing properties acquired 3,752 45 3,797
Exploration 2,409 - 2,409
Development 28,140 - 28,140
----------- --------- -----------
Total costs incurred $ 39,823 $ 61 $ 39,884
=========== ========= ===========
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 acquired $ 7,503 $ 21 $ 7,524
Producing properties acquired 1,419 - 1,419
Exploration 9,336 - 9,336
Development 38,359 295 38,654
----------- --------- -----------
Total costs incurred $ 56,617 $ 316 $ 56,933
=========== ========= ===========
76
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2002:
Capitalized costs:
Proved properties $ 448,331 $ 895 $ 449,226
Unproved properties 15,692 332 16,024
----------- --------- -----------
464,023 1,227 465,250
Accumulated depreciation,
depletion, amortization
and impairment (218,956) (520) (219,476)
----------- --------- -----------
Net capitalized costs $ 245,067 $ 707 $ 245,774
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 5,330 $ 152 $ 5,482
Producing properties acquired 13,379 - 13,379
Exploration 6,591 - 6,591
Development 33,319 7 33,326
----------- --------- -----------
Total costs incurred $ 58,619 $ 159 $ 58,778
=========== ========= ===========
77
The results of operations for producing activities are provided below.
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Revenues $ 88,461 $ 110 $ 88,571
Production costs (16,457) (19) (16,476)
Depreciation, depletion,
amortization and impairment (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
=========== ========= ===========
2002:
Revenues $ 64,534 $ 87 $ 64,621
Production costs (17,300) (25) (17,325)
Depreciation, depletion
and amortization (22,685) (45) (22,730)
----------- --------- -----------
24,549 17 24,566
Income tax expense (8,436) (5) (8,441)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 16,113 $ 12 $ 16,125
=========== ========= ===========
78
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)
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
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
79
USA CANADA TOTAL
---------------- ---------------- ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------- -------- ------- -------- ------- --------
(In thousands)
2002:
Proved developed and
undeveloped reserves:
Beginning of year 4,343 227,865 - 389 4,343 228,254
Revision of previous
estimates (166) (10,543) - (31) (166) (10,574)
Extensions, discoveries
and other additions 230 29,541 - - 230 29,541
Purchases of minerals
in place 192 16,558 - - 192 16,558
Sales of minerals in
place (30) - - - (30) -
Production (473) (18,927) - (41) (473) (18,968)
------- -------- ------- -------- ------- --------
End of Year 4,096 244,494 - 317 4,096 244,811
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 2,753 150,419 - 338 2,753 150,757
End of year 2,951 168,049 - 317 2,951 168,366
80
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 its reserves as prepared by its 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.
81
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)
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
=========== ========= ===========
2002:
Future cash flows $1,256,434 $ 1,400 $1,257,834
Future production and
development costs (386,206) (309) (386,515)
Future income tax expenses (250,413) (233) (250,646)
----------- --------- -----------
Future net cash flows 619,815 858 620,673
10% annual discount for
estimated timing of cash flows (275,015) (344) (275,359)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 344,800 $ 514 $ 345,314
=========== ========= ===========
82
The principal sources of changes in the standardized measure of discounted
future net cash flows were as follows (unaudited):
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2000:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (72,005) $ (91) $ (72,096)
Net changes in prices and
production costs 647,313 1,854 649,167
Revisions in quantity
estimates and changes in
production timing 44,991 (324) 44,667
Extensions, discoveries and
improved recovery, less
related costs 184,624 - 184,624
Purchases of minerals in place 23,144 - 23,144
Sales of minerals in place (3,469) - (3,469)
Accretion of discount 19,881 51 19,932
Net change in income taxes (293,357) (581) (293,938)
Other - net (43,760) 53 (43,707)
----------- --------- -----------
Net change 507,362 962 508,324
Beginning of year 167,225 477 167,702
----------- --------- -----------
End of year $ 674,587 $ 1,439 $ 676,026
=========== ========= ===========
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
=========== ========= ===========
83
USA CANADA TOTAL
----------- --------- -----------
(In thousands)
2002:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (47,230) $ (62) $ (47,292)
Net changes in prices and
production costs 230,934 363 231,297
Revisions in quantity
estimates and changes in
production timing (49,000) (110) (49,110)
Extensions, discoveries and
improved recovery, less
related costs 60,957 - 60,957
Purchases of minerals in place 23,334 - 23,334
Sales of minerals in place (150) - (150)
Accretion of discount 23,080 39 23,119
Net change in income taxes (84,843) (59) (84,902)
Other - net 10,441 37 10,478
----------- --------- -----------
Net change 167,523 208 167,731
Beginning of year 177,277 306 177,583
----------- --------- -----------
End of year $ 344,800 $ 514 $ 345,314
=========== ========= ===========
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
($29.70) and natural gas ($4.42) 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.
84
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.
85
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, 2001 and 2002, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002, 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 19, 2003
86
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 68 President, Chief Executive Officer,
Chief Operating Officer and Director
Earle Lamborn 68 Senior Vice President, Drilling and
Director
Philip M. Keeley 61 Senior Vice President, Exploration and
Production
Larry D. Pinkston 48 Executive Vice President, Treasurer and
Chief Financial Officer
Mark E. Schell 45 Senior Vice President, 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 Cotton 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. From August 16, 2000
until August 23,2002 Mr. Nikkel also served as a director of Shenandoah
Resources LTD., a Canadian company. Shenandoah Resources LTD. filed for
creditors protection (Initial Application Order Under The Companies' Creditor
Arrangement Act) in April, 2002 with the Court of Queen's Bench of Alberta,
Judicial District of Calgary. Mr. Nikkel received a Bachelor of Science degree
in Geology and Mathematics from Texas Christian University.
87
Mr. Lamborn has been actively involved in the oil field for over 50 years,
joining Unit's predecessor in 1952 prior to its becoming a publicly-held
corporation. He was elected Vice President, Drilling in 1973 and to his current
position as Senior Vice President, Drilling and director in 1979.
Mr. Keeley joined Unit in November 1983 as Senior Vice President,
Exploration and Production. Prior to that time, Mr. Keeley co-founded (with Mr.
Nikkel) Nike Exploration Company in January 1982 and, until November 2001,
served as Executive Vice President and a director of that company. From 1977
until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation, serving
first as Manager of Land and from 1979 as Vice President and a director. Before
joining Cotton, Mr. Keeley was employed for four years by Apexco, Inc. as
Manager of Land and prior thereto he was employed by Texaco, Inc. for nine
years. He received a Bachelor of Arts degree in Petroleum Land Management from
the University of Oklahoma.
Mr. Pinkston joined Unit in December 1981. He had served as Corporate
Budget Director and Assistant Controller prior to being appointed Controller in
February 1985. He has been Treasurer since December 1986 and was elected to the
position of Vice President and Chief Financial Officer in May 1989. In December
2002, he was elected to the additional position of Executive Vice President. He
holds a Bachelor of Science Degree in Accounting from East Central University of
Oklahoma and is a Certified Public Accountant.
Mr. Schell joined Unit in January 1987, as its Secretary and General
Counsel. In December 2002, he was elected to the additional position as Senior
Vice President. 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.
88
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 2003 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 2003 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 2003 annual meeting of stockholders.
ITEM 14. Controls and Procedures
- -------- ----------------------
a) Evaluation of disclosure controls and procedures. Within the 90 day
period prior to the filing date of this Annual Report on Form 10-K, our
management, under the supervision and with the participation of the our Chief
Executive Officer and Chief Financial Officer, evaluated the effectiveness of
the design and operation of the company's disclosure controls and procedures.
Based on that evaluation, our Chief Executive Officer and Chief Financial
Officer believe that:
i) the company's disclosure controls and procedures are designed to ensure
that information required to be disclosed by the company in the reports it files
or submits under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC's rules and
forms; and
ii) the company's disclosure controls and procedures operate such that
important information flows to appropriate collection and disclosure points in a
timely manner and is effective to ensure that such information is accumulated
and communicated to the company's management, and made known to our Chief
Executive Officer and Chief Financial Officer, particularly during the period
when this Annual Report on Form 10-K was prepared, as appropriate to allow
timely decision regarding the required disclosure.
b) Changes in internal controls. There have been no significant changes in
the company's internal controls or in other factors that could significantly
affect the company's internal controls subsequent to their evaluation, nor have
there been any corrective actions with regard to significant deficiencies or
material weaknesses.
89
PART IV
Item 15. 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, 2001 and 2002
Consolidated Statements of Operations for the years ended
December 31, 2000, 2001 and 2002
Consolidated Statements of Changes in Shareholders' Equity
for the years ended December 31, 2000, 2001 and 2002
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 2001 and 2002 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, 2000, 2001 and 2002:
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:
--------
2.6.1 Amended and Restated Stock Purchase Agreement dated as
of June 24, 2002 by and among Unit Corporation, George
B. Kaiser and Kaiser Francis Oil Company (incorporated
herein by reference to Exhibit 99.1 to Form 8-K dated
August 27,2002).
2.6.2 Amended and Restated Share Purchase Agreement dated as
of June 24, 200, by and among Unit Corporation, Kaiser
Francis Charitable Income Trust B and Kaiser Francis
Oil Company (incorporated herein by reference to
Exhibit 99.2 to Form 8-K dated August 27,2002).
90
3.1 Restated Certificate of Incorporation of Unit Corporation
(file as Exhibit 3.1 to Form S-3 (file No. 333-83551), which
is incorporated herein by reference).
3.2 By-Laws of Unit Corporation (filed as Exhibit 3.2 to Unit's
Form 8-K to Form S-3 (file No. 333-83551), 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).
4.2.8 Second Amendment of the Rights Agreement, dated August 14,
2002, between the Company and Mellon Shareholder Services LLC,
as Rights Agent (filed herein).
10.1.25 Loan Agreement dated July 24, 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).
10.2.21* 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).
91
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).
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).
10.2.30* 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).
10.2.32 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).
10.2.35 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).
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).
92
10.2.41 Unit 2002 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 21, 2001).
10.2.42 Unit 2003 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:
On November 5, 2002 we filed a report on Form 8-K under
item 9. This report disclosed that the Principal Executive
Officer, John G. Nikkel, and Principal Financial Officer,
Larry D. Pinkston, of Unit Corporation, had filed with the
SEC certifications pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
93
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, 2000 $ 583 $ 350 $ 14 $ 919
========== ========== ========== ==========
Year ended
December 31, 2001 $ 919 $ - $ 315 $ 604
========== ========== ========== ==========
Year ended
December 31, 2002 $ 604 $ 603 $ 4 $ 1,203
========== ========== ========== ==========
Deferred Tax Asset Valuation Allowance:
Balance
Balance at At
Beginning End of
Description of Period Additions Deductions Period
----------- ---------- ---------- ---------- ----------
(In thousands)
Year ended
December 31, 2000 $ 335 $ - $ 335 $ -
========== ========== ========== ==========
Year ended
December 31, 2001 $ - $ - $ - $ -
========== ========== ========== ==========
Year ended
December 31, 2002 $ - $ - $ - $ -
========== ========== ========== ==========
94
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 12, 2003 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 12th day of March, 2003.
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
- ------------------------------- Executive Vice President, Chief Financial
LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz
- ------------------------------- Controller
STANLEY W. BELITZ
/s/ J. Michael Adcock
- ------------------------------- Director
J. MICHAEL ADCOCK
/s/ Don Cook
- ------------------------------- Director
DON COOK
/s/ William B. Morgan
- ------------------------------- Director
WILLIAM B. MORGAN
/s/ John S. Zink
- ------------------------------- Director
JOHN S. ZINK
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
95
CERTIFICATIONS
--------------
I, John G. Nikkel, certify that:
1. I have reviewed this annual report on Form 10-K of Unit Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
96
Date: March 12, 2003 By: /s/ John G. Nikkel
------------------ ------------------------------
JOHN G. NIKKEL
President, Chief Executive
Officer, Chief Operating
Officer and Director
97
CERTIFICATIONS
I, Larry D. Pinkston, certify that:
1. I have reviewed this annual report on Form 10-K of Unit Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
98
Date: March 12, 2003 By: /s/ Larry D. Pinkston
------------------ ------------------------------
LARRY D. PINKSTON
Executive Vice President,
Chief Financial Officer and
Treasurer
99
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
------- ---------------------------------------------- -----
4.2.8 Second Amendment of the Rights Agreement, dated
August 14, 2002, between the Company and Mellon
Shareholder Services LLC, as Rights Agent.
10.2.42 Unit 2003 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
100