Back to GetFilings.com
F O R M 1 0-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
-------- ----------
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
--------------- -----
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange
------------------- on which registered
Common Stock, par value -------------------
$.20 per share New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes _X_ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (Section 229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant's
knowledge, in definitive proxy or information statements incorporated by
reference in PART III of this Form 10-K or any amendment to this Form 10-K.
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 7, 2002 - $390,907,479
Number of Shares of Common Stock
Outstanding on March 7, 2002 - 36,074,419
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the
Annual Meeting of Stockholders to be held May 1, 2002 are incorporated by
reference in Part III.
Exhibit Index - See Page 94
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 2
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 2
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 22
Item 4. Submission of Matters to a Vote of Security Holders . . 22
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . 23
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . 25
Item 7a. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . 38
Item 8. Financial Statements and Supplementary Data . . . . . . 40
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . 84
PART III
Item 10. Directors and Executive Officers of the Registrant. . . 84
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 86
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . 86
Item 13. Certain Relationships and Related Transactions. . . . . 86
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 88
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
1
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2001
PART I
Item 1. Business and Item 2. Properties
- ------- -------- ------- ----------
GENERAL
Through our wholly owned subsidiaries, we contract to drill onshore
oil and natural gas wells for others and explore, develop, acquire and
produce oil and natural gas properties for our self. We were founded in
1963 as a contract drilling company. Today our contract drilling
operations and our exploration and production operations are carried out
primarily in the natural gas producing provinces of the Oklahoma and Texas
areas of the Anadarko and Arkoma Basins and the Texas Gulf Cost. Our
contract drilling operations are also engaged in the East Texas and Rocky
Mountain region.
Our executive offices are located at 1000 Kensington Tower, 7130 South
Lewis, Tulsa, Oklahoma 74136; telephone number (918) 493-7700. We also
have regional offices in Oklahoma City, Oklahoma, Woodward, Oklahoma,
Booker, Texas, Houston, Texas and Casper, Wyoming. When used in this
report, the terms Corporation, Unit, our, we and its refer to Unit
Corporation and, at times, Unit Corporation and/or one or more of its
subsidiaries.
LAND CONTRACT DRILLING OPERATIONS
We drill onshore natural gas and oil wells for a wide range of
customers through our wholly owned subsidiary Unit Drilling Company. A land
drilling rig consists, in part, of engines, drawworks or hoists, derrick or
mast, substructure, pumps to circulate the drilling fluid, blowout
preventers and drill pipe. Over the life of a typical rig, due to the
normal wear and tear of operating 24 hours a day, several of the major
components, such as engines, mud pumps and drill pipe, are replaced or
rebuilt on a periodic basis, while other components, such as the
substructure, mast and drawworks, can be utilized for extended periods of
time with proper maintenance. We also own additional equipment used in the
operation of our rigs, including large air compressors, trucks and other
support equipment.
While natural gas prices were high in early 2001, we continued to add
to our rig fleet. In January 2001, we purchased a 750 horse power diesel
electric rig with a 13,000 foot depth capacity for $3.2 million. In
February 2001, we purchased a 1,000 horse power, winterized mechanical rig,
with a 16,000 foot depth capacity, for $2.5 million. In May we acquired two
diesel electric rigs with depth capacities of 16,000 and 20,000 feet, for
$7.8 million. We also acquired a 16,000 foot depth capacity diesel electric
rig. This rig will, depending on industry conditions and additional capital
2
requirements, be placed in service when conditions warrant. The addition of
these five rigs brings our fleet to 55 at December 31, 2001, 54 of which
are currently capable of operating. Our rigs have depth capacities ranging
from 9,500 to 40,000 feet. As of March 1, 2002 twenty-nine of our rigs
were located in the Anadarko Basin of Oklahoma and Texas, 6 in the Arkoma
Basins of Oklahoma while 12 were located in the East Texas and Gulf Coast
Region and 8 in the Rocky Mountain region. As of February 20, 2002, 34 of
our drilling rigs were operating under contract.
At present, we do not have a shortage of drilling rig related
equipment. However, at any given time our ability to use all of our rigs
is dependent on a number of conditions, including the availability of
qualified labor, drilling supplies and equipment as well as demand.
3
The following table sets forth, for each of the periods indicated,
certain information concerning our contract drilling operations:
Year Ended December 31,
-----------------------------------------------------------
1997 1998 1999 2000 2001
------ ------ ------ ------ ------
Number of Rigs
Owned at End
of Period 34.0 (1) 34.0 47.0 (2) 50.0 (3) 55.0 (4)
Average Number
of Rigs Owned
During Period 25.1 34.0 37.3 47.0 51.8
Average Number
of Rigs
Utilized (5) 20.0 22.9 23.1 39.8 46.3
Utilization
Rate (5) 80% 67% 62% 85% 90%
Average Revenue
Per Day (6) $6,309 $6,394 $6,582 $7,432 $9,879
Total Footage
Drilled
(Feet in
1000's) 1,736 2,203 2,211 3,650 4,008
Number of Wells
Drilled 167 198 197 316 361
- ---------------
(1) Includes 10 rigs acquired in the fourth quarter of 1997.
(2) Includes 13 rigs acquired in September 1999.
(3) Includes one rig acquired at the 2000 year-end and two additional rigs
that were completing construction.
(4) Includes 5 rigs acquired during the first 7 months of 2001.
(5) Utilization rates are based on a 365-day year and are calculated by
dividing the number of rigs utilized by the total number of rigs owned
during the period, including stacked rigs. A rig is considered utilized
when it is operating or being moved, assembled or dismantled under
contract.
(6) Represents total revenues from contract drilling operations divided by
the total number of days rigs were being utilized for the period.
4
The following table sets forth, as of February 20, 2002, the type and
approximate depth capability of each of our drilling rigs:
Approximate
Depth
Capability
Rig# Type (feet)
----- --------------------------- -----------
1 BDW 650 13,000
2 BDW 650 13,000
3 BDW 650 13,500
4 Gardner Denver 500 11,000
5 U-15 Unit Rig 11,000
6 BDW 800 16,000
8 Gardner Denver 800 16,000
9 BDW 800 16,000
10 BDW 450T 9,500
11 Gardner Denver 700 15,000
12 BDW 800 16,000
14 Gardner Denver 700 15,000
15 Mid-Continent 914-C 20,000
16 U-15 Unit Rig 11,000
17 Brewster N-75 15,000
18 BDW 650 12,500
19 Gardner Denver 500 12,000
20 Gardner Denver 700 15,000
21 Gardner Denver 700 15,000
22 BDW 800 16,000
23 Gardner Denver 700 14,000
24 Gardner Denver 700 14,000
25 Gardner Denver 700 15,000
26 National 610 E 13,500
27 BDW 650 13,000
28 Continental Emsco D-3 16,000
29 Brewster N-75A 15,000
30 BDW 1350-M 20,000
31 Shufelt 600 12,500
32 Brewster N-75 15,000
33 BDW 800 16,000
34 National 110-UE 20,000
35 Continental Emsco C-1 20,000
36 Gardner Denver 1500-E 25,000
37 Mid-Continent 914-EC 20,000
38 Mid-Continent 1220-EB 25,000
39 Mid-Continent U-36-A 12,000
40 BDW 800 16,000
100 National 80-UE 16,000 (1)
101 Continental Emsco D-3 16,000
102 Continental Emsco A-1500 20,000
112 Ideco E-3000 25,000
166 OIME E-3000 25,000
180 OIME E-3000 25,000
182 OIME E-3000 30,000
184 OIME E-3000 30,000
201 OIME E-4000 40,000
203 OIME E-2000 25,000
232 Continental Emsco D-3 II 16,000
233 Continental Emsco C-1 III 20,000
234 Continental Emsco D-3 II 16,000
235 Continental Emsco C-1 II 20,000
236 Gardner Denver 800 16,000
237 Continental Emsco C-1 II 20,000
254 OIME E-2000 25,000
5
(1) Rig 100 was acquired in 2001 and will not be refurbished and marketed
by us until industry conditions improve.
During most of the past 18 years, our contract drilling operations
encountered significant competition due to depressed levels of activity.
In the last half of 1999 through the first half of 2001, as oil and natural
gas prices increased, the demand for our contract drilling services
increased rapidly. However starting in October 2001 we began to experience
rapidly declining demand for our rigs as the prices of natural gas began to
fall from the high prices reached in January, 2001. We anticipate that
competition within the industry will, for the foreseeable future, continue
to adversely affect us.
Drilling Contracts. Our drilling contracts are predominantly obtained
through competitive bidding. Normally, our contracts are for a single well
with the terms and rates varying depending upon the nature and duration of
the work, the equipment and services supplied and other matters. The
contracts obligate us to pay certain operating expenses, including wages of
drilling personnel, maintenance expenses and incidental rig supplies and
equipment. Usually, the contracts are subject to termination by the
customer on short notice upon payment of a fee. These contracts also
specify certain provisions regarding indemnification against certain types
of claims involving injury to persons, property and for acts of pollution.
The specific provisions regarding the responsibility for, the extent of and
the type of claims covered is subject to negotiation on a contract by
contract basis.
Our compensation under a contract is based on the type of contract
used. The contracts we use are generally one of three types: a daywork; a
footage; or a turnkey contract. Additional compensation may also be
involved for special risks and unusual conditions. Under daywork
contracts, we provide the drilling rig with the required personnel to the
operator who supervises the drilling of the contracted well. Our
compensation is based on a negotiated rate for each day the rig is
utilized. Footage contracts usually require us to bear some of the
drilling costs in addition to providing the rig. We are compensated on a
negotiated rate, per foot drilled, upon completion of the well. Under
turnkey contracts, we contract to drill a well for a lump sum amount to a
specified depth and provide most of the equipment and services required.
We bear the risk of drilling the well to the contract depth and are
compensated when the contract provisions have been satisfied.
Drilling operations under a turnkey contract, in particular, may
result in us incurring losses if we underestimate the costs to drill the
well or if unforeseen events occur. To date, we have not experienced
significant losses in performing turnkey contracts. In 2001, we drilled one
turnkey well and turnkey revenue represented less than one percent of our
contract drilling revenues as compared to 9 percent for 2000. We had one
turnkey contract in progress at December 31, 2001. Because market
conditions as well as the desires of our customers determine the use of
turnkey contracts, we can't predict whether the portion of drilling
conducted on a turnkey basis will increase or decrease in the future.
6
Customers. During 2001, 10 contract drilling customers accounted for
approximately 49 percent of our total contract drilling revenues.
Approximately 4 percent of our total contract drilling revenues were
generated from drilling operations performed on oil and natural gas
properties of which we were the operator (including properties owned by
limited partnerships for which we acted as general partner).
Further information relating to contract drilling operations is
presented in Notes 1 and 10 of Notes to Consolidated Financial Statements
set forth in Item 8 hereof.
OIL AND NATURAL GAS OPERATIONS
In 1979, we began to develop our exploration and production operations
to diversify our contract drilling revenues. Our wholly owned subsidiary,
Unit Petroleum Company, conducts our exploration and production activities.
As of December 31, 2001, we had estimated net proved reserves of 4,343
Mbbls and 228,254 MMcf. Our producing oil and natural gas interests,
undeveloped leaseholds and related assets are located primarily in
Oklahoma, Texas, Louisiana and New Mexico and, to a lesser extent, in
Arkansas, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi,
Illinois, Michigan, Nebraska and Canada. As of December 31, 2001, we had
an interest in a total of 2,974 wells in the United States, 688 of which we
are also the operator of. We also had an interest in 64 wells located in
Canada.
Our technical staff generates the majority of our development and
exploration prospects. When we are the operator of a property, we
generally employ our own drilling rigs and our own engineering staff
supervises the drilling operation.
7
Well and Leasehold Data. The tables below set forth certain
information regarding our oil and natural gas exploration and development
drilling activities for the periods indicated:
Year Ended December 31,
--------------------------------------------------------
1999 2000 2001
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Wells Drilled:
- --------------
Exploratory:
Oil - - - - 1 .01
Natural gas - - 2 1.63 8 3.60
Dry - - - - 5 4.46
-------- -------- -------- -------- -------- --------
Total - - 2 1.63 14 8.07
======== ======== ======== ======== ======== ========
Development:
Oil 1 .48 7 1.45 6 1.06
Natural gas 55 19.23 75 28.51 87 33.51
Dry 10 5.47 17 8.56 18 10.80
-------- -------- -------- -------- -------- --------
Total 66 25.18 99 38.52 111 45.37
======== ======== ======== ======== ======== ========
Oil and Natural
Gas Wells
Producing or
Capable of
Producing:
- ---------------
Oil - USA 783 224.10 799 278.06 786 279.06
Oil -
Canada - - - - - -
Gas - USA 1,950 403.50 2,088 431.11 2,188 457.38
Gas -
Canada 64 1.60 64 1.60 64 1.60
-------- -------- -------- -------- -------- --------
Total 2,797 629.20 2,951 710.77 3,038 738.04
======== ======== ======== ======== ======== ========
On February 20, 2002, Unit was participating in the drilling of 3
gross (1.99 net) wells in the United States.
8
The following table summarizes our oil and natural gas leasehold
acreage as of the end of each of the years indicated:
Developed Acreage Undeveloped Acreage
--------------------- ---------------------
Gross Net Gross Net
--------- --------- --------- ---------
1999:
- -----
USA 548,011 142,472 55,989 35,245
Canada 39,040 976 25,293 25,293
--------- --------- --------- ---------
Total 587,051 143,448 81,282 60,538
========= ========= ========= =========
2000:
- -----
USA 564,780 153,507 61,487 39,480
Canada 39,040 976 26,243 13,121
--------- --------- --------- ---------
Total 603,820 154,483 87,730 52,601
========= ========= ========= =========
2001:
- -----
USA 567,731 155,890 110,489 69,229
Canada 39,040 976 7,273 3,636
--------- --------- --------- ---------
Total 606,771 156,866 117,762 72,865
========= ========= ========= =========
9
Price and Production Data. The following table sets forth our average
sales price, oil and natural gas production volumes and average production
cost per equivalent Mcf [1 barrel (Bbl) of oil = 6 thousand cubic feet
(Mcf) of natural gas] of production for the periods indicated:
Year Ended December 31,
---------------------------------
1999 2000 2001
---------- ---------- ----------
Average Sales Price per Barrel of Oil
Produced:
USA $ 17.48 $ 26.95 $ 23.62
Canada - - -
Average Sales Price per Mcf of Natural
Gas Produced:
USA $ 2.05 $ 3.91 $ 4.00
Canada $ 1.81 $ 2.39 $ 4.21
Oil Production (Mbbls):
USA 424 488 492
Canada - - -
---------- ---------- ----------
Total 424 488 492
========== ========== ==========
Natural Gas Production (MMcf):
USA 17,402 19,239 18,819
Canada 35 46 45
---------- ---------- ----------
Total 17,437 19,285 18,864
========== ========== ==========
Average Production Expense per
Equivalent Mcf:
USA $ .59 $ .74 $ .86
Canada $ .56 $ .42 $ .51
10
Reserves. The following table sets forth our estimated proved
developed and undeveloped oil and natural gas reserves at the end of each
of the years indicated:
Year Ended December 31,
---------------------------------
1999 2000 2001
---------- ---------- ----------
Oil (Mbbls):
USA 4,527 4,183 4,343
Canada - - -
---------- ---------- ----------
Total 4,527 4,183 4,343
========== ========== ==========
Natural gas (MMcf):
USA 186,770 215,196 227,865
Canada 569 441 389
---------- ---------- ----------
Total 187,339 215,637 228,254
========== ========== ==========
Further information relating to oil and natural gas operations is
presented in Notes 1, 10 and 12 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
VOLATILE NATURE OF OUR OIL AND NATURAL GAS MARKETS;
FLUCTUATIONS IN PRICES
Our revenues, operating results, cash flows and future rate of growth
are significantly affected by the prevailing prices for natural gas and
oil. Historically, oil and natural gas prices have been volatile, and we
expect that they will continue to be volatile. Oil and natural gas prices
increased substantially in the last half of 1999 and throughout 2000 and by
January 2001, the average price we received for natural gas reached $9.35
per Mcf. Prices however, started to decline sharply thereafter and by
September 2001, the average price we received for natural gas was $2.05 per
Mcf. The average price we received for oil reached a high of $28.13 per
barrel in February 2001. Oil prices then started to decline and we
received the lowest average price of the year for oil of $16.28 per barrel
in December 2001.1
Because natural gas makes up the biggest part of our oil and natural
gas reserves, changes in natural gas prices have a disproportionate impact
on our financial results than do oil price changes.
11
Prices for oil and natural gas are subject to wide fluctuations in
response to relatively minor changes in the supply of and demand for oil
and natural gas, market uncertainty and a variety of additional factors
that are beyond our control. These factors include:
. political conditions in oil producing regions, including the
Middle East;
. the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
. the price of foreign imports;
. actions of governmental authorities;
. the domestic and foreign supply of oil and natural gas;
. the level of consumer demand;
. United States storage levels of natural gas;
. weather conditions;
. domestic and foreign government regulations;
. the price, availability and acceptance of alternative fuels; and
. overall economic conditions.
These factors and the volatile nature of the energy markets make it
impossible to predict with any certainty the future prices of oil and
natural gas.
Our oil production is sold at or near our wells under purchase
contracts at prevailing prices in accordance with arrangements customary in
the oil industry. Our natural gas production is sold to intrastate and
interstate pipelines as well as to independent marketing firms under
contracts with original terms ranging from one month to several years at
prices primarily determined on a daily basis. Most of these contracts
contain provisions for readjustment of price, termination and other terms
customary in the industry.
Our contract drilling operations are dependent on the level of demand
in our operating markets. Both short-term and long-term trends in oil and
natural gas prices affect demand. Because oil and natural gas prices are
volatile, the level of demand for our services can also be volatile.
Decreased oil and natural gas prices during 1998 and early 1999 adversely
affected our contract drilling activity by lowering the demand for our rigs
and reducing the rates we were able to charge for our drilling services.
With the increase in oil and natural gas prices starting in the last half
of 1999 and continuing through January 2001 our dayrates and rig
utilization increased substantially.
12
Natural gas prices began to fall in February, 2001, and as a result, we
began to experience less demand for our drilling rigs starting in October,
2001 and the rates received for our rigs also began to fall. We expect
that in the near term our customers will continue a cautious approach to
exploration and development spending until prices again begin to rise. As
a result, the future extent of the demand for our drilling services is
uncertain.
COMPETITION
All of our lines of business are highly competitive. Competition in
onshore contract drilling traditionally involves such factors as price,
efficiency, condition of equipment, availability of labor and equipment,
reputation and customer relations. Some of our competitors in the onshore
contract drilling business are substantially larger than we are and have
appreciably greater financial and other resources. The competitive
environment within which we operate is uncertain and extremely price
oriented.
Our oil and natural gas operations likewise encounter strong
competition from major oil companies, independent operators and others.
Many of these competitors have appreciably greater financial, technical and
other resources and are more experienced in the exploration for and
production of oil and natural gas than we are.
OIL AND NATURAL GAS PROGRAMS AND CONFLICTS OF INTEREST
Our subsidiary, Unit Petroleum Company, serves as the general partner
of five oil and gas limited partnerships and 13 employee oil and gas
limited partnerships. Each year we form an employee partnership which
acquires an interest, ranging from 2.5% to 15% of our interest, in most of
the oil and natural gas wells we drill or acquire for our own account
during that particular year. The limited partners in the employee
partnerships are either employees or directors of Unit or its subsidiaries.
One of the companies we acquired, Questa Oil and Gas Co., also served as
the general partner of five private limited partnerships. We repurchased
the limited partners' interest in three of the five Questa partnerships in
the fourth quarter of 2000 and three of the partnerships were dissolved. In
the first quarter of 2001, we purchased additional interests in the
remaining two Questa partnerships and subsequently dissolved one of those
partnerships.
Under the terms of our partnership agreements, the general partner has
broad discretionary authority to manage the business and operations of the
partnership, including the authority to make decisions on such matters as
the partnership's participation in a drilling location or a property
acquisition, the partnership's expenditure of funds and the distribution of
funds to partners. Because the business activities of the limited partners
on the one hand, and the general partner on the other hand, are not the
same, conflicts of interest will exist and it is not possible to entirely
eliminate such conflicts. Additionally, conflicts of interest may arise
when we are the operator of an oil and natural gas well and also provide
contract drilling services. In such cases, these drilling operations are
13
done under contracts containing terms and conditions comparable to those
contained in our drilling contracts with non-affiliated operators. We
believe we fulfill our responsibility to each contracting party and comply
fully with the terms of the agreements which regulate such conflicts.
EMPLOYEES
As of February 20, 2002, we had approximately 949 employees in our
land contract drilling operations, 58 employees in our oil and natural gas
operations and 51 in our general corporate area. None of our employees are
represented by a union or labor organization nor have our operations ever
been interrupted by a strike or work stoppage. We consider relations with
our employees to be satisfactory.
OPERATING AND OTHER RISKS
Our drilling operations are subject to the many hazards inherent in
the drilling industry, including injury or death to personnel, blowouts,
cratering, explosions, fires, loss of well control, loss of hole, damaged
or lost drilling equipment and damage or loss from inclement weather. Our
exploration and production operations are subject to these and similar
risks. Any of these events could result in personal injury or death,
damage to or destruction of equipment and facilities, suspension of
operations, environmental damage and damage to the property of others.
Generally, drilling contracts provide for the division of responsibilities
between a drilling company and its customer, and we seek to obtain
indemnification from our drilling customers by contract for some of these
risks. To the extent that we are unable to transfer these risks to our
drilling customers, we seek protection through insurance. However, our
insurance or our indemnification agreements, if any, may not adequately
protect us against liability from all of the consequences of the hazards
described above. In addition, even if we have insurance coverage we may
still have a degree of exposure based on the amount of our deductible. The
occurrence of an event not fully insured or indemnified against, or the
failure of a customer to meet its indemnification obligations, could result
in substantial losses to us. In addition, we may not be able to obtain
insurance to cover any or all of these risks. Even if available, the
insurance might not be adequate to cover all of our losses, or we might
decide against obtaining that insurance because of high premiums or other
costs.
Exploration and development operations involve numerous risks that may
result in dry holes, the failure to produce oil and natural gas in
commercial quantities and the inability to fully produce discovered
reserves. The cost of drilling, completing and operating wells is
substantial and uncertain. Our operations may be curtailed, delayed or
cancelled as a result of many things beyond our control, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
. adverse weather conditions;
14
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs or delivery
crews and the delivery of equipment.
The majority of the wells in which we own an interest are operated by
other parties. As a result, we have little control over the operations of
such wells which can act to increase our risk. Operators of these wells
may act in ways that are not in our best interests.
Our future performance depends upon our ability to find or acquire
additional oil and natural gas reserves that are economically recoverable.
In general, production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. Unless we successfully replace the reserves that we
produce, our reserves will decline, resulting eventually in a decrease in
oil and natural gas production and lower revenues and cash flow from
operations. Historically, we have succeeded in increasing reserves after
taking production into account through our oil and natural gas operations.
However, it is possible that we may not be able to continue to replace
reserves from such activities. Low prices of oil and natural gas may
further limit the kinds of reserves that we can economically develop.
Lower prices also decrease our cash flow and may cause us to decrease
capital expenditures.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which we conduct
activities impose restrictions on the drilling, production, transportation
and sale of oil and natural gas.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory
Commission (the "FERC") regulates the interstate transportation and the
sale in interstate commerce for resale of natural gas. The FERC's
jurisdiction over interstate natural gas sales was substantially modified
by the Natural Gas Policy Act under which the FERC continued to regulate
the maximum selling prices of certain categories of gas sold in "first
sales" in interstate and intrastate commerce. Effective January 1, 1993,
however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act")
deregulated natural gas prices for all "first sales" of natural gas.
Because "first sales" include typical wellhead sales by producers, all
natural gas produced from our natural gas properties is being sold at
market prices, subject to the terms of any private contracts which may be
in effect. The FERC's jurisdiction over natural gas transportation was not
affected by the Decontrol Act.
Our sales of natural gas are affected by intrastate and interstate gas
transportation regulation. Beginning in 1985, the FERC adopted regulatory
changes that have significantly altered the transportation and marketing of
natural gas. These changes were intended by the FERC to foster competition
by, among other things, transforming the role of interstate pipeline
15
companies from wholesale marketers of natural gas to the primary role of
gas transporters. All natural gas marketing by the pipelines was required
to be divested to a marketing affiliate, which operates separately from the
transporter and in direct competition with all other merchants. As a
result of the various omnibus rulemaking proceedings in the late 1980s and
the individual pipeline restructuring proceedings of the early to mid-
1990s, the interstate pipelines are now required to provide open and
nondiscriminatory transportation and transportation-related services to all
producers, natural gas marketing companies, local distribution companies,
industrial end users and other customers seeking service. Through similar
orders affecting intrastate pipelines that provide similar interstate
services, the FERC expanded the impact of open access regulations to
intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to
affiliated or non-affiliated companies; (2) further development of rules
governing the relationship of the pipelines with their marketing
affiliates; (3) the publication of standards relating to the use of
electronic bulletin boards and electronic data exchange by the pipelines to
make available transportation information on a timely basis and to enable
transactions to occur on a purely electronic basis; (4) further review of
the role of the secondary market for released pipeline capacity and its
relationship to open access service in the primary market; and (5)
development of policy and promulgation of orders pertaining to its
authorization of market-based rates (rather than traditional cost-of-
service based rates) for transportation or transportation-related services
upon the pipeline's demonstration of lack of market control in the relevant
service market. It remains to be seen what effect the FERC's other
activities will have on the access to markets, the fostering of competition
and the cost of doing business.
As a result of these changes, sellers and buyers of natural gas have
gained direct access to the particular pipeline services they need and are
better able to conduct business with a larger number of counter parties.
We believe these changes generally have improved the access to markets for
natural gas while, at the same time, substantially increasing competition
in the natural gas marketplace. We cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt or what effect
subsequent regulations may have on production and marketing of natural gas
from our properties.
In the past, Congress has been very active in the area of natural gas
regulation. However, as discussed above, the more recent trend has been in
favor of deregulation and the promotion of competition in the natural gas
industry. Thus, in addition to "first sales" deregulation, Congress also
repealed incremental pricing requirements and natural gas use restraints
previously applicable. There are other legislative proposals pending in the
Federal and State legislatures which, if enacted, would significantly
affect the petroleum industry. At the present time, it is impossible to
predict what proposals, if any, might actually be enacted by Congress or
the various state legislatures and what effect, if any, these proposals
might have on the production and marketing of natural gas by us. Similarly,
16
and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue or what the
ultimate effect will be on the production and marketing of natural gas by
us cannot be predicted.
Our sales of oil and natural gas liquids are not regulated and are at
market prices. The price received from the sale of these products is
affected by the cost of transporting the products to market. Much of that
transportation is through interstate common carrier pipelines. Effective
as of January 1, 1995, the FERC implemented regulations generally
grandfathering all previously approved interstate transportation rates and
establishing an indexing system for those rates by which adjustments are
made annually based on the rate of inflation, subject to certain conditions
and limitations. These regulations may tend to increase the cost of
transporting oil and natural gas liquids by interstate pipeline, although
the annual adjustments may result in decreased rates in a given year. These
regulations have generally been approved on judicial review. Every five
years, the FERC will examine the relationship between the annual change in
the applicable index and the actual cost changes experienced by the oil
pipeline industry. We are not able to predict with certainty what effect,
if any, these relatively new federal regulations or the periodic review of
the index by the FERC will have on us.
Federal, state, and local agencies have promulgated extensive rules
and regulations applicable to our oil and natural gas exploration,
production and related operations. Oklahoma, Texas and other states
require permits for drilling operations, drilling bonds and the filing of
reports concerning operations and impose other requirements relating to the
exploration of oil and natural gas. Many states also have statutes or
regulations addressing conservation matters including provisions for the
unitization or pooling of oil and natural gas properties, the establishment
of maximum rates of production from oil and natural gas wells and the
regulation of spacing, plugging and abandonment of such wells. The statutes
and regulations of some states limit the rate at which oil and natural gas
can be produced from our properties. The federal and state regulatory
burden on the oil and natural gas industry increases our cost of doing
business and affects its profitability. Because these rules and regulations
are frequently amended or reinterpreted, we are unable to predict the
future cost or impact of complying with those laws.
SAFE HARBOR STATEMENT OF FURTHER ACTIVITY
Statements in this document as well as information contained in
written material, press releases and oral statements issued by or on behalf
of us contain, or may contain, certain "forward-looking statements" within
the meaning of federal securities laws. All statements, other than
statements of historical facts, included in this document which address
activities, events or developments which we expect or anticipate will or
may occur in the future are forward-looking statements. The words
"believes," "intends," "expects," "anticipates," "projects," "estimates,"
"predicts" and similar expressions are also intended to identify forward-
looking statements. These forward-looking statements include, among
others, such things as:
17
. our year 2002 plans;
. the amount and nature of our future capital expenditures;
. the number of wells we intend to drill or rework;
. demand for our oil and natural gas and the price we will be paid for
such production;
. our oil and natural gas prospects;
. estimates of our proved oil and natural gas reserves;
. reserve potential;
. development and infill drilling potential;
. expansion and other development trends of the oil and natural gas
industry;
. our business strategy;
. production of our oil and natural gas reserves;
. expansion and growth of our business and operations; and
. the use of our drilling rig services and what we will be paid for such
services.
These statements are based on certain assumptions and analyses made by
us in light of our experience and our perception of historical trends,
current conditions and expected future developments as well as other
factors we believe are appropriate in the circumstances.2 However, whether
actual results and developments will conform to our expectations and
predictions is subject to a number of risks and uncertainties which could
cause actual results to differ materially from our expectations, including:
. the risk factors discussed in this document;
. general economic, market or business conditions;
. the nature or lack of business opportunities that may be presented to
and pursued by us;
. demand for our land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any forward-looking statements made
by us, the following discussion outlines certain factors that in the future
could cause our consolidated results for 2002 and beyond to differ
materially from those that may be set forth in any such forward-looking
statement made by or on behalf of us.
Commodity Prices
The prices we receive for our oil and natural gas production have a
direct impact on the amount of our revenues, our profitability and the
amount of our cash flow as well as our ability to meet our projected
financial and operational goals. The prices for natural gas and crude oil
are heavily dependent on a number of factors beyond our control, including
the demand for oil and/or natural gas; current weather conditions in the
continental United States (which can greatly influence the demand for
natural gas at any given time as well as the price to be received for such
natural gas); and the ability of current distribution systems in the United
States to effectively meet the demand for oil and or natural gas at any
18
given time, particularly in times of peak demand which may result due to
adverse weather conditions. Oil prices are extremely sensitive to foreign
influences that may be based on political, social or economic
underpinnings, any one of which could have an immediate and significant
effect on the price and supply of oil. In addition, prices of both natural
gas and oil are becoming more and more influenced by trading on the
commodities markets which, at times, has tended to increase the volatility
associated with these prices resulting, at times, in large differences in
such prices even on a month-to-month basis. All of these factors,
especially when coupled with the fact that much of our product prices are
determined on a daily basis, can, and at times do, lead to wide
fluctuations in the prices we receive.
Based on our 2001 production, a $.10 per Mcf change in what we are
paid for our natural production would result in a corresponding $146,000
per month ($1,752,000 annualized) change in our pre-tax cash flow. A $1.00
per barrel change in our oil price would have a $33,000 per month ($396,000
annualized) change in our pre-tax cash flow. During 2001, substantially all
of our natural gas and crude oil volumes were sold at market responsive
prices.
In order to reduce our exposure to short-term fluctuations in the
price of oil and natural gas, we sometimes enter into hedging or swap
arrangements. Our hedging or swap arrangements apply to only a portion of
our production and provide only partial price protection against declines
in oil and natural gas prices. These hedging or swap arrangements may
expose us to risk of financial loss and limit the benefit to us of
increases in prices.
Drilling Customer Demand
Demand for our drilling services is dependent almost entirely on the
needs of third parties. Based on past history, such parties' requirements
are subject to a number of factors, independent of any subjective factors,
that directly impact the demand for our drilling rigs. These include the
availability of funds to such third parties to carry out their drilling
operations during any given time period which, in turn, are often subject
to downward revision based on decreases in the then current prices of oil
and natural gas. Many of our customers are small to mid-size oil and
natural gas companies whose drilling budgets tend to be susceptible to the
influences of current price fluctuations. Other factors that affect our
ability to work our drilling rigs are: the weather which, under adverse
circumstances, can delay or even cause a project to be abandoned by an
operator; the competition faced by us in securing the award of a drilling
contract in a given area; our experience and recognition in a new market
area; and the availability of labor to run our drilling rigs.
Uncertainty Of Oil and Natural Gas Reserves
There are numerous uncertainties inherent in estimating quantities of
proved reserves and their values, including many factors beyond our
control. The reserve data included in this document represent only
estimates. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of oil and natural gas that cannot be
19
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves depend on a number of variable factors, including
historical production from the area compared with production from other
producing areas, and assumptions concerning:
. the effects of regulations by governmental agencies;
. future oil and natural gas prices;
. future operating costs;
. severance and excise taxes;
. development costs; and
. workover and remedial costs.
Some or all of these assumptions may vary considerably from actual
results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, classifications of those reserves based on risk of recovery,
and estimates of the future net cash flows from reserves prepared by
different engineers or by the same engineers but at different times may
vary substantially. Accordingly, reserve estimates may be subject to
downward or upward adjustment. Actual production, revenues and expenditures
with respect to our reserves will likely vary from estimates, and those
variances may be material.
The information regarding discounted future net cash flows included in
this document should not be considered as the current market value of the
estimated oil and natural gas reserves attributable to our properties. As
required by the SEC, the estimated discounted future net cash flows from
proved reserves are based on prices and costs as of the date of the
estimate, while actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by the following
factors:
. the amount and timing of actual production;
. supply and demand for oil and natural gas;
. increases or decreases in consumption; and
. changes in governmental regulations or taxation.
In addition, the 10% discount factor, which is required by the SEC to
be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with our
operations or the oil and natural gas industry in general.
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the SEC. Under these
rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved
reserves, discounted at 10%. Application of the ceiling test generally
requires pricing future revenue at the unescalated prices in effect as of
the end of each fiscal quarter and requires a write-down for accounting
purposes if the ceiling is exceeded, even if prices were depressed for only
a short period of time. We may be required to write down the carrying value
20
of our oil and natural gas properties when oil and natural gas prices are
depressed or unusually volatile. If a write-down is required, it would
result in a charge to earnings but would not impact cash flow from
operating activities. Once incurred, a write-down of oil and natural gas
properties is not reversible at a later date.
We are continually identifying and evaluating opportunities to acquire
oil and natural gas properties, including acquisitions that would be
significantly larger than those consummated to date by us. We cannot
assure you that we will successfully consummate any acquisition, that we
will be able to acquire producing oil and natural gas properties that
contain economically recoverable reserves or that any acquisition will be
profitably integrated into our operations.
Debt and Bank Borrowing
We have experienced and expect to continue to experience substantial
working capital needs due to our growth in drilling operations and our
active exploration and development programs. Historically, we have funded
our working capital needs through a combination of internally generated
cash flow, equity financing and borrowings under our bank loan agreement.
As a result of our working capital requirements, we currently have, and
will continue to have, a certain amount of indebtedness. At December 31,
2001, our long-term debt outstanding was $31.0 million. As of December 31,
2001, we had a total loan commitment of $100 million, but we elected to
limit the amount available for borrowing under our bank loan agreement to
$60 million to reduce cost. The amount outstanding under our bank loan
agreement at December 31, 2001 was $30.0 million.
Our level of debt, the cash flow needed to satisfy our indebtedness
and the covenants governing our indebtedness could:
. limit funds otherwise available for financing our capital
expenditures, our drilling program or other activities or cause us to
curtail these activities;
. limit our flexibility in planning for or reacting to changes in our
business;
. place us at a competitive disadvantage to some of our competitors that
are less leveraged than us;
. make us more vulnerable during periods of low oil and natural gas
prices or in the event of a downturn in our business; and
. prevent us from obtaining additional financing on acceptable terms or
limit amounts available under our existing or any future credit
facilities.
Our ability to meet our debt service obligations will depend on our
future performance. If the requirements of our indebtedness are not
satisfied, a default would be deemed to occur and our lenders would be
entitled to accelerate the payment of the outstanding indebtedness. If
this occurs, we would not have sufficient funds available nor would we be
able to obtain the financing required to meet our obligations.
21
The amount of our existing debt as well as its future debt is, to a
large extent, a function of the costs associated with the projects
undertaken by us at any given time and the cash flow received by us.
Generally, the costs incurred by us in our normal operations are those
associated with the drilling of oil and natural gas wells, the acquisition
of producing properties, and the costs associated with the maintenance or
expansion of our drilling rig fleet. To some extent, these costs,
particularly the first two items, are discretionary and we maintain a
degree of control regarding the timing and/or the need to incur the same.
However, in some cases, unforeseen circumstances may arise, such as in the
case of an unanticipated opportunity to acquire a large producing property
package or the need to replace a costly rig component due to an unexpected
loss, which could force us to incur increased debt above that which we had
expected or forecasted. Likewise, for many of the reasons mentioned above,
our cash flow may not be sufficient to cover our current cash requirements
which would then require us to increase our debt either through bank
borrowings or otherwise.
Item 3. Legal Proceedings
- ------- -----------------
We are a party to various legal proceedings arising in the ordinary
course of our business, none of which, in our opinion, will result in
judgments which would have a material adverse effect on our financial
position, operating results or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
- ------- ---------------------------------------------------
No matters were submitted to our security holders during the fourth
quarter of 2001.
22
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- ------- ------------------------------------------------------------------
Matters
-------
Our common stock trades on the New York Stock Exchange under the
symbol "UNT." The following table identifies the high and low sales prices
per share of our common stock for the periods indicated:
2000 2001
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
First $ 11.5000 $ 6.6250 $ 21.3750 $ 16.3000
Second $ 14.5625 $ 9.0000 $ 23.0000 $ 14.5000
Third $ 16.2500 $ 11.8125 $ 15.8000 $ 7.4100
Fourth $ 19.4375 $ 12.3750 $ 14.2400 $ 8.2900
On February 20, 2002, there were 1,985 record holders of our common
stock.
We have never paid cash dividends on our common stock and currently
intend to continue our policy of retaining earnings from our operations.
Our loan agreement prohibits us from declaring and paying dividends (other
than stock dividends) in any fiscal year in an amount greater than 25
percent of our preceding year's consolidated net income and then only if
our working capital provided from operations for the previous year was
equal to or greater than 175 percent of the current maturities of our long-
term debt at the end of the previous year.
23
Item 6. Selected Financial Data
- ------- -----------------------
Year Ended December 31,
----------------------------------------------------------
1997 (1) 1998 (1) 1999 (1) 2000 2001
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 96,478 $ 97,274 $ 102,352 $ 201,264 $ 259,179
========== ========== ========== ========== ==========
Net Income $ 12,330 $ 1,428 $ 3,048 $ 34,344 $ 62,766
========== ========== ========== ========== ==========
Earnings Per
Common Share:
Basic $ .47 $ .05 $ .10 $ .96 $ 1.75
========== ========== ========== ========== ==========
Diluted $ .46 $ .05 $ .10 $ .95 $ 1.73
========== ========== ========== ========== ==========
Total Assets $ 213,416 $ 233,096 $ 295,567 $ 346,288 $ 417,253
========== ========== ========== ========== ==========
Long-Term Debt $ 55,480 $ 75,048 $ 67,239 $ 54,000 $ 31,000
========== ========== ========== ========== ==========
Other Long-Term
Liabilities $ 2,363 $ 2,368 $ 2,325 $ 3,597 $ 4,110
========== ========== ========== ========== ==========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
========== ========== ========== ========== ==========
----------------------
(1) Restated for the merger with Questa Oil and Gas Co.
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1999, 2000 and 2001 activity.
24
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------- ---------------------------------------------------------------
Results of Operations
---------------------
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Our financial condition and liquidity, for current operations, depends
on our cash flow from operating activities and borrowings under our bank
loan agreement. Our cash flow is influenced mainly by the prices we receive
for our natural gas production, the demand for and the dayrates we receive
for our drilling rigs and, to a lesser extent, the prices we receive for
our oil production. Our loan agreement provides for a revolving credit
facility, which terminates on May 1, 2005 followed by a three-year term
loan. At December 31, 2001, we had borrowed $30.0 million, which was 50
percent of the amount available, as elected by us on October 1, 2001, and
represented 30 percent of the loan value of our assets as determined by our
banks on October 1, 2001. Most of our capital expenditures are
discretionary and directed toward future growth.
Our Oil and Natural Gas Operations. Natural gas comprises
approximately 90 percent of our total oil and natural gas reserves. Any
appreciable change in natural gas prices has a significant affect on our
revenues, cash flow and the value of our oil and natural gas reserves. Such
price changes also influence the demand for our natural gas production, our
drilling rigs (since they are used mainly to drill natural gas wells) and
the amount we can charge for our contract drilling services.
Based on our 2001 production, a $.10 per Mcf change in what we are
paid for our natural production would result in a corresponding $146,000
per month ($1,752,000 annualized) change in our pre-tax cash flow. Our 2001
average natural gas price declined from a high of $9.35 per Mcf in January
to $2.05 per Mcf in September (an 78 percent decrease) before recovering to
$2.16 per Mcf in December. For the year, our average natural gas price was
$4.00 per Mcf. A $1.00 per barrel change in our oil price would have a
$33,000 per month ($396,000 annualized) change in our pre-tax cash flow. We
received the highest average oil price for the year during February at
$28.13 per barrel. For the balance of the year oil prices declined
resulting in our lowest average oil price of $16.28 per barrel in December.
Our average oil price for the year was $23.62 per barrel.
Generally, prices and demand for domestic natural gas are influenced
by weather conditions, supply imbalances and by world wide oil price
levels. Domestic oil prices are primarily influenced by world oil market
developments. All of these factors are beyond our control and we can not
predict nor measure their future influence on the prices we will receive.
Because natural gas prices have such a significant affect on the value
of our oil and natural gas reserves declines in these prices can result in
a reduction of the carrying value of our oil and natural gas properties.
Likewise, price declines can also adversely affect the semi-annual
25
determination of the amount available for us to borrow under our bank loan
agreement since that determination is based mainly on the value of our oil
and natural gas reserves. Such a reduction could limit our ability to
carry out our planned capital projects.
Hedging Activities. Periodically we hedge the prices we will receive
for a portion of our future natural gas and oil production. We do so in an
attempt to reduce the impact and uncertainty that price fluctuations have
on our cash flow. In the first quarter of 2000, we entered into swap
transactions to lock in a portion of our oil production at higher oil
prices. These transactions applied to approximately 50 percent of our daily
oil production covering the period from April 1, 2000 to July 31, 2000 and
25 percent of our daily oil production for August and September of 2000 at
prices ranging from $24.42 to $27.01. We entered into a collar contract
covering approximately 25 percent of our daily oil production from November
1, 2000 through February 28, 2001. The collar had a floor of $26.00 per
barrel and a ceiling of $33.00 per barrel and we received $0.86 per barrel
for entering into the transaction. During 2000, the net effect of our oil
hedging transactions for oil reduced our oil revenues by $465,000. We did
not have any hedging transactions for natural gas in 2000. During the first
quarter of 2001, our oil hedging transaction yielded an increase in our oil
revenues of $17,200.
We entered into a natural gas collar contract for approximately 36
percent of our June and July 2001 natural gas production at a floor price
of $4.50 and a ceiling price of $5.95. We also entered into two natural
gas collar contracts for approximately 38 percent of our September through
November 2001 natural gas production. Both contracts had a floor price of
$2.50. One contract had a ceiling price of $3.68 and the other contract had
a ceiling price of $4.25. For the year our natural gas collar contracts
added $2,030,000 to our natural gas revenues. We did not have any hedging
transactions outstanding at December 31, 2001 nor on February 20, 2002.
Contract Drilling Operations. Our drilling operations are subject to
many factors that influence the number of rigs we have working at any one
time as well as the costs and revenues associated with such work. These
factors include competition from other drilling contractors, the prevailing
prices for natural gas and oil, the availability of labor to operate our
rigs and our ability to supply the type of equipment required. We have not
encountered major difficulty in hiring and retaining rig crews, but such
shortages have occurred periodically in the past. If demand for drilling
rigs was to increase rapidly in the future, shortages of experienced
personnel would limit our ability to increase the number of rigs we could
operate.
Low oil and natural gas prices during most of the 1980's and 1990's
reduced demand for domestic land contract drilling rigs. However, in the
last half of 1999 and throughout 2000, as oil and natural gas prices
increased, we experienced a substantial increase in demand for our rigs.
Our average utilization of 44.6 rigs (95 percent) in January 2001 increased
to 51.9 rigs (96 percent) in July before dropping to 33.5 rigs (62 percent)
in December 2001. Our average utilization for the year was 46.3 rigs (90
percent).
26
As demand for our rigs increased during the year so did the dayrates
we received. Our average dayrate in January was $8,176 and by September it
had increased to $11,142. However, as demand began to decrease so did our
rates and by December our average dayrate was $9,594. That rate has
continued to fall into the first quarter of 2002. Based on the average
utilization rate we achieved in 2001, a $100 per day change in dayrates has
a $4,630 per day ($1,690,000 annualized) change in our pre-tax operating
cash flow.
We anticipate that for the first half of 2002 the number of our rigs
operating will range in the mid to high thirties and dayrates will continue
to decline early in the first quarter before stabilizing. Utilization and
dayrates for the last half of 2002 and beyond will depend mainly on the
price of natural gas during the first half of 2002 and beyond. Even if
demand increases in 2002, we anticipate that competition will continue to
influence our operations.
Bank Loan Agreement. On July 24, 2001, we signed a $100 million bank
loan agreement. At our election the amount currently available for us to
borrow is set at $60 million. Although the current value of our assets
would have allowed us to have access to the full $100 million, we elected
to set the loan commitment at $60 million in order to reduce financing
costs since we are charged a facility fee of .375 of 1 percent on the
amount available but not borrowed.
Each year on April 1 and October 1 our banks redetermine the loan
value of our assets. This value is primarily determined to be an amount
equal to a percentage of the discounted future value of our oil and natural
gas reserves, as determined by the banks. In addition, an amount
representing a part of the value of our drilling rig fleet, limited to $20
million, is added to the loan value. Our loan agreement provides for a
revolving credit facility which terminates on May 1, 2005 followed by a
three-year term loan. Borrowing under our loan agreement totaled $30.0
million at December 31, 2001 and $28.0 million on February 20, 2002.
Borrowings under the revolving credit facility bear interest at the
Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London
Interbank Offered Rates ("Libor Rate") plus 1.00 to 1.50 percent depending
on the level of debt as a percentage of the total loan value. Subsequent
to May 1, 2005, borrowings under the loan agreement bear interest at the
Prime Rate or the Libor Rate plus 1.25 to 1.75 percent depending on the
level of debt as a percentage of the total loan value. In addition, the
loan agreement allows us to select, at any time between the date of the
agreement and 3 days prior to the start of the term loan, a fixed rate for
the amount outstanding under the credit facility. Our ability to select the
fixed rate option is subject to a number of conditions, all of which are
more fully set out in the loan agreement.
The interest rate on our bank debt was 3.3 percent at December 31,
2001 and 3.0 percent on February 20, 2002. At our election, any portion of
our outstanding bank debt may be fixed at the Libor Rate, as adjusted
depending on the level of our debt as a percentage of the amount available
for us to borrow. The Libor Rate may be fixed for periods of up to 30, 60,
90 or 180 days with the remainder of our bank debt being subject to the
27
Prime Rate. During any Libor Rate funding period, we may not pay any part
of the outstanding principal balance which is subject to the Libor Rate.
Borrowings subject to the Libor Rate were $28.0 million at December 31,
2001 and February 20, 2002.
The loan agreement requires us to maintain consolidated net worth of
at least $125 million, a current ratio of not less than 1 to 1, a ratio of
long-term debt, as defined in the loan agreement, to consolidated tangible
net worth not greater than 1.2 to 1 and a ratio of total liabilities, as
defined in the loan agreement, to consolidated tangible net worth not
greater than 1.65 to 1. In addition, working capital provided by our
operations, as defined in the loan agreement, cannot be less than $40
million in any year. We are prohibited from paying dividends (other than
stock dividends) during any fiscal year in excess of 25 percent of our
consolidated net income from the preceding fiscal year and we can pay
dividends only if working capital provided from our operations during the
preceding year is equal to or greater than 175 percent of current
maturities of long-term debt at the end of the preceding year. We also
cannot incur additional debt except in certain very limited exceptions and
the creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any of our property is prohibited unless it
is in favor of our banks.
Shareholders' Equity, Working Capital and Capital Expenditures. Our
shareholders' equity at December 31, 2001 was $279.2 million giving us a
ratio of long-term debt-to-total capitalization of 10 percent. Net cash
provided by operations in 2001 was $133.0 million compared to $67.4 million
in 2000. We had working capital of $17.6 million at December 31, 2001. Our
total 2001 capital expenditures were $108.8 million ($400,000 net in
accounts payable), of which $56.9 million was spent on our oil and natural
gas operations, $51.3 million was spent on our drilling segment and
$539,000 was spent primarily on furniture and fixtures and leasehold
improvements.
Additional Oil and Gas Information. Our decisions on whether we try
to increase our oil and natural gas reserves through acquisitions or
through drilling depends on the prevailing or anticipated market
conditions, potential return on investment, future drilling potential and
the availability of opportunities to obtain financing under the
circumstances involved, all of which tend to provide us with a large degree
of flexibility in determining when and if to incur such costs. As a result
of the high natural gas prices during the last half of 2000 and into the
first half of 2001, there were not many opportunities during 2001 to
acquire producing properties at prices we consider attractive. As a result
we spent $48.0 million on exploration and development drilling, $7.5
million for undeveloped leasehold and only $1.4 million for producing
property acquisitions. We drilled 125 wells in 2001 as compared with 101
wells in 2000. Based on current prices, for 2002, we plan to drill an
estimated 140 wells and have total capital expenditures of approximately
$65 million for exploration, development drilling and acquisition of oil
and natural gas properties.
28
On March 20, 2000, we completed the acquisition, by merger, of Questa
Oil and Gas Co.("Questa") under which Questa became a wholly owned
subsidiary of Unit Corporation. In the merger, each of Questa's
outstanding shares of common stock (excluding treasury shares) was
converted into .95 shares of our common stock. We issued approximately 1.8
million shares as a result of this merger. The merger was accounted for as
a pooling of interests and, accordingly, all amounts prior to the merger
were restated, unless otherwise noted, as if the companies had been
combined during the periods presented.
Additional Drilling Information. While natural gas prices were high
in early 2001, we continued to add to our rig fleet. In January 2001, we
purchased a 750 horse power diesel electric rig with a 13,000 foot depth
capacity for $3.2 million. This rig was working in our Gulf Coast region at
December 31, 2001. In February 2001, we purchased a 1,000 horse power,
winterized mechanical rig, with a 16,000 foot depth capacity, for $2.5
million. This rig was under contract in our Rocky Mountain region on
December 31, 2001. In May we acquired two diesel electric rigs with depth
capacities of 16,000 and 20,000 feet, for $7.8 million. These two rigs are
both working in our Gulf Coast region. We also acquired a 16,000 foot depth
capacity diesel electric rig. This rig will, depending on industry
conditions and additional capital requirements, be placed in service when
conditions warrant. The addition of these five rigs brings our fleet to
55, 54 of which are currently capable of operating. During 2001, we spent
$38.7 million for new drilling rigs, drilling rig components and
refurbishments of existing rigs, $11.6 million for new drill pipe and
collars and $1.0 million for transportation equipment. For 2002 we
anticipate that we will spend approximately $20 million on our drilling
operations.
Our contract drilling segment provides drilling services for our
exploration and production segment. The contracts for these services are
issued under the same conditions and rates as the contracts that we are in
with unrelated parties. The profit received by our contract drilling
segment of $179,000 and $2,259,000 in 2000 and 2001, respectively, for this
work was used to reduce the carrying value of our oil and natural gas
properties rather than being included in our profits in current operations.
29
Contractual Commitments. We have various contractual obligations at
December 31, 2001, which are as follows:
Payments Due by Period
-----------------------------------------------
Less
Contractual Than 1 2-3 4-5 After 5
Obligations Total Year Years Years Years
------------- --------- ------- -------- --------- --------
(In thousands)
Bank Debt(1) $ 30,000 $ - $ - $ 15,833 $14,167
Hickman
Note(2) 2,000 1,000 1,000 - -
Retirement
Agreement(3) 1,330 20 470 600 240
Gas Purchaser
Prepay-
ment(4) 437 437 - - -
Operating
Leases(5) 2,306 654 1,296 344 12
--------- ------- -------- --------- --------
Total
Contractual
Obligations $ 36,073 $2,111 $ 2,766 $ 16,777 $14,419
========= ======= ======== ========= ========
-------------------
(1) See Previous Discussion in Management Discussion and Analysis
regarding bank debt.
(2) On November 20, 1997, we acquired Hickman Drilling Company
pursuant to an agreement and plan of merger entered into by and
between us, Hickman Drilling Company and all of the holders of
the outstanding capital stock of Hickman Drilling Company. As
part of this acquisition, the former shareholders of Hickman
held, as of December 31, 2001, promissory notes in the aggregate
outstanding principal amount of $2.0 million (See Note 4 of our
Consolidated Financial Statements). These notes are payable in
equal annual installments on January 2, 2002 and January 2, 2003.
The notes bear interest at the Chase Prime Rate, which at
December 31, 2001 and February 20, 2002 was 4.75 percent. At
February 20, 2002 the promissory notes outstanding totaled $1.0
million.
(3) In the second quarter of 2001, we recorded $1.3 million in
additional employee benefit expenses for the present value of a
separation agreement made in connection with the retirement of
King Kirchner from his position as Chief Executive Officer. The
liability associated with this expense, including accrued
interest, will be paid in $25,000 monthly payments starting in
July 2003 and continuing through June 2009 (See Note 4 of our
Consolidated Financial Statements).
(4) Due to a settlement agreement, which terminated at December 31,
1997, we have a liability of $437,000 at December 31, 2001,
included in current portion of long-term debt on our Consolidated
30
Balance Sheet, representing proceeds received from a natural gas
purchaser as prepayment for natural gas. The $437,000 is payable on
June 1, 2002.
(5) We lease office space in Tulsa, Houston and Woodward under the
terms of operating leases expiring through January 31, 2007 (See
Note 9 of our Consolidated Financial Statements).
At December 31, 2001, we also have the following commitments and
contingencies that could create, increase or accelerate our liabilities:
Amount of Commitment Expiration
Per Period
-------------------------------------
Total
Amount
Committed Less
Other Or Than 1 2-3 4-5 After 5
Commitments Accrued Year Years Years Years
--------------- --------- -------- -------- -------- --------
(In thousands)
Deferred
Compensation
Agreement(1) $ 1,277 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 1,959 $ 436 Unknown Unknown Unknown
Repurchase
Obliga-
tions(3) Unknown Unknown Unknown Unknown Unknown
(1) We provide a salary deferral plan which allows participants to
defer the recognition of salary for income tax purposes until
actual distribution of benefits, which occurs at either
termination of employment, death or certain defined unforeseeable
emergency hardships. We recognize payroll expense and record a
liability, included in other long-term liabilities in our
Consolidated Balance Sheet, at the time of deferral (See Note 6
of our Consolidated Financial Statements).
(2) Effective January 1, 1997, We adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible
employees whose employment with us is involuntarily terminated
or, in the case of an employee who has completed 20 years of
service, voluntarily or involuntarily terminated, to receive
benefits equivalent to 4 weeks salary for every whole year of
service completed with Unit up to a maximum of 104 weeks. To
receive payments the recipient must waive any claims against us
in exchange for receiving the separation benefits. On October
28, 1997, we adopted a Separation Benefit Plan for Senior
Management ("Senior Plan"). The Senior Plan provides certain
officers and key executives of Unit with benefits generally
equivalent to the Separation Plan. The Compensation Committee of
the Board of Directors has absolute discretion in the selection
of the individuals covered in this plan (See Note 6 of our
31
Consolidated Financial Statements).
(3) We formed The Unit 1984 Oil and Gas Limited Partnership and the
1986 Energy Income Limited Partnership along with private limited
partnerships (the "Partnerships") with certain qualified
employees, officers and directors from 1984 through 2002, with a
subsidiary of ours serving as General Partner. The Partnerships
were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as
co-general partner with us in any additional limited partnerships
formed during that year. The Partnerships participated on a
proportionate basis with us in most drilling operations and most
producing property acquisitions commenced by us for our own
account during the period from the formation of the Partnership
through December 31 of each year. These partnership agreements
require, upon the election of a limited partner, that we
repurchase the limited partner's interest at amounts to be
determined by appraisal in the future. Such repurchases in any
one year are limited to 20 percent of the units outstanding. We
made repurchases of $10,000 and $14,000 in 1999 and 2000,
respectively, for such limited partners' interests. No
repurchases were made in 2001 (See Note 9 of our Consolidated
Financial Statements).
Oil and Natural Gas Limited Partnerships. We are the general partner
for eighteen oil and natural gas partnerships which were formed privately
and publicly. The partnership's revenues and costs are shared in accordance
with formulas prescribed in each limited partnership agreement. The
partnerships reimburse us for contract drilling, well supervision and
general and administrative expense reimbursements. Related party
transactions for contract drilling and well supervision fees are the
related party's share of such costs. These costs are billed on the same
basis as billings to unrelated parties for similar services. General and
administrative reimbursements consist of direct general and administrative
expense incurred on the related party's behalf as well as indirect expenses
allocated to the related parties. Such allocations are based on the
related party's level of activity and are considered by management to be
reasonable. During the 1999, 2000 and 2001, the total paid to us for all
of these fees was $694,000, $966,000 and $1,107,000, respectively. Our
proportionate share of assets, liabilities and net income relating to the
oil and natural gas partnerships is included in our consolidated financial
statements.
At December 31, 2001, we owned a 40 percent equity interest in a
natural gas gathering and processing company. Our balance sheet investment
and equity in the company totaled $1.6 million at December 31, 2001. At
December 31, 2001 and February 20, 2002, we were not guaranteeing any
indebtedness of the gas gathering and processing company.
At December 31, 2001, one of our subsidiaries owned 4,949,500 shares
of common stock and 1,800,000 warrants of Shenandoah Resources Ltd., a
Canadian oil and natural gas exploration and production company. The
investment of $346,000 is part of other assets in our consolidated balance
sheet and was written down by $2.1 million during 2001.
32
Critical Accounting Policies. We account for our oil and natural gas
exploration and development activities using the full cost method of
accounting. Under this method, all costs incurred in the acquisition,
exploration and development of oil and natural gas properties are
capitalized. At the end of each quarter, the net capitalized costs of our
oil and natural gas properties is limited to the lower of unamortized cost
or a ceiling. The ceiling is defined as the sum of the present value (10
percent discount rate) of estimated future net revenues from proved
reserves, based on period-ending oil and natural gas prices, plus the lower
of cost or estimated fair value of unproved properties included in the
costs being amortized less related income tax. If the net capitalized costs
of our oil and natural gas properties exceed the ceiling, we are subject to
a ceiling test write-down to the extent of such excess. A ceiling test
write-down is a non-cash charge to earnings. If required, it reduces
earnings and impacts stockholders' equity in the period of occurrence and
results in lower depreciation, depletion and amortization expense in future
periods.
The risk that we will be required to write-down the carrying value of
our oil and natural gas properties increases when oil and natural gas
prices are depressed or if we have substantial downward revisions in our
estimated proved reserves. Application of these rules during periods of
relatively low oil or natural gas prices, even if temporary, increases the
probability of a ceiling test write-down. Based on oil and natural gas
prices in effect on December 31, 2001 ($2.51 per Mcf for natural gas and
$17.71 per barrel for oil), the unamortized cost of our domestic oil and
natural gas properties did not exceed the ceiling of our proved oil and
natural gas reserves. Natural gas pricing has been erratic since year-end
and any significant declines below year-end prices used in the reserve
evaluation would likely result in a ceiling test write-down in subsequent
quarterly reporting periods.
The value of our oil and natural gas reserves is used to determine the
loan value under our loan agreement. This value is affected by both price
changes and the measurement of reserve volumes. Oil and natural gas
reserves cannot be measured exactly. Our estimate of oil and natural gas
reserves require extensive judgments of our reservoir engineering data and
are generally less precise than other estimates made in connection with
financial disclosures. Assigning monetary values to such estimates does not
reduce the subjectivity and changing nature of such reserve estimates.
Indeed the uncertainties inherent in the disclosure are compounded by
applying additional estimates of the rates and timing of production and the
costs that will be incurred in developing and producing the reserves. We
utilizes Ryder Scott Company, independent petroleum consultants, to review
our reserves as prepared by our reservoir engineers.
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. Renewals and betterments are capitalized
while repairs and maintenance are expensed. Realization of the carrying
value of property and equipment is reviewed for possible impairment
whenever events or changes in circumstances indicate that the carrying
amount may not be recoverable. Assets are determined to be impaired if a
forecast of undiscounted estimated future net operating cash flows directly
33
related to the asset including disposal value if any, is less than the
carrying amount of the asset. If any asset is determined to be impaired,
the loss is measured as the amount by which the carrying amount of the
asset exceeds its fair value. An estimate of fair value is based on the
best information available, including prices for similar assets. Changes in
such estimates could cause Unit to reduce the carrying value of property
and equipment.
Under "footage" and "turnkey" contracts, we bear the risk of
completion of the well, so revenues and expenses are recognized using the
completed contract method. The entire amount of a loss, if any, is recorded
when the loss can be determined. The costs of uncompleted drilling
contracts include expenses incurred to date on "footage" or "turnkey"
contracts, which are still in process at the end of the period, and are
included in other current assets.
EFFECTS OF INFLATION
- --------------------
In the 18 years prior to the last half of 1999, the effects of
inflation on our operations was minimal due to low inflation rates and
moderate demand for contract drilling services. However, starting in the
last half of 1999 and throughout 2000 and the first three quarters of 2001,
as drilling rig dayrates and utilization increased, the impact of inflation
increased as the availability of used equipment and third party services
decreased. Due to industry-wide demand for qualified labor, contract
drilling labor costs increased substantially in the summer of 2000 and once
again in the summer of 2001. How inflation will affect us in the future
will depend on additional increases, if any, realized in our drilling rig
rates and the prices we receive for our oil and natural gas. If industry
activity recovers and returns to levels achieved in early 2001, shortages
in support equipment such as drill pipe, third party services and qualified
labor could occur resulting in additional corresponding increases in our
material and labor costs. These conditions may limit our ability to
realize improvements in operating profits.
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------------
On January 1, 2001, we adopted Statement of Financial Accounting
Standard No. 133 (subsequently amended by Financial Accounting Standard
No.'s 137 and 138), "Accounting for Derivative Instruments and Hedging
Activities" (FAS 133). This statement requires all derivatives to be
recognized on the balance sheet and measured at fair value. If a
derivative is designated as a cash flow hedge, we are required to measure
the effectiveness of the hedge, or the degree that the gain (loss) for the
hedging instrument offsets the loss (gain) on the hedged item, at each
reporting period. The effective portion of the gain (loss) on the
derivative instrument is recognized in other comprehensive income as a
component of equity and subsequently reclassified into earnings when the
forecasted transaction affects earnings. The ineffective portion of a
derivative's change in fair value is required to be recognized in earnings
immediately. Derivatives that do not qualify for hedge treatment under FAS
133 must be recorded at fair value with gains (losses) recognized in
34
earnings in the period of change. We periodically enter into derivative
commodity instruments to hedge our exposure to price fluctuations on oil
and natural gas production. Such instruments include regulated natural gas
and crude oil futures contracts traded on the New York Mercantile Exchange
(NYMEX) and over-the-counter swaps and basic hedges with major energy
derivative product specialists. At December 31, 2001, we were not holding
any natural gas or oil derivative contracts.
On July 20, 2001, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 142, "Goodwill and
Other Intangible Assets" (FAS 142). For goodwill and intangible assets
already recorded in the financial statements, FAS 142 ends the amortization
of goodwill and certain intangible assets and subsequently requires, at
least annually, that an impairment test be performed on such assets to
determine whether the fair value has changed. We expensed $243,000
annually for the amortization of goodwill, and the unamortized balance of
goodwill is $5,088,000 at December 31, 2001. FAS 142 is effective for the
fiscal years starting after December 15, 2001 (January 1, 2002 for us). We
do not believe the future impact from the adoption of FAS 142 on our
financial position or results of operation will be material.
In July 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS
143). FAS 143 is effective for fiscal years beginning after June 15, 2002
(January 1, 2003 for us) and establishes an accounting standard requiring
the recording of the fair value of liabilities associated with the
retirement of long-lived assets (mainly plugging and abandonment costs for
our depleted wells) in the period in which the liability is incurred (at
the time the wells are drilled). We have not yet determined the effect of
the adoption of FAS 143 on our financial position or results of operations.
In August 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" (FAS 144). FAS 144 is effective for fiscal years beginning after
December 15, 2001 (January 1, 2002 for us). This statement supersedes
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of" and amends Accounting Principles Board Opinion No. 30 for the
accounting and reporting of discontinued operations, as it relates to long-
lived assets. We do not believe the future impact from the adoption of FAS
144 on our financial position or results of operations will be material.
35
RESULTS OF OPERATIONS
- ---------------------
2001 versus 2000
- ----------------
Net income for 2001 was $62,766,000, compared with $34,344,000 for
2000. This increase was due to increases in the use of our drilling rigs,
as well as, the dayrates we received for the use of the drilling rigs.
High natural gas prices in the last quarter of 2000 and the first quarter
of 2001 increased the demand for our drilling rigs which in turn pushed
contract drilling dayrates higher.
Our oil and natural gas revenues decreased 2 percent in 2001 when
compared with 2000. The average natural gas prices we received in 2001
increased 2 percent, but this increase was offset by a 2 percent reduction
in our natural gas production. The average oil price we received dropped
12 percent while oil production increased one percent between the
comparative years. We drilled 125 gross wells (53.4 net wells) in 2001,
compared to 101 gross wells (40.2 net wells) in 2000.
In 2001, revenues from our contract drilling operations increased by
55 percent as the average number of our drilling rigs being used increased
from 39.8 in 2000 to 46.3 in 2001. Revenues per rig per day increased 33
percent between the comparative years. Daywork revenues represented 88
percent of our total drilling revenues in 2001 and 75 percent in 2000.
Operating margins (revenues less operating costs) for our oil and
natural gas operations were 75 percent in 2001 and 79 percent in 2000.
This decrease resulted mainly from declines in production on older wells
without corresponding declines in operating expenses. Total operating cost
increased 12 percent and was due mainly to the addition of new wells
through development drilling and increases in ad valorem taxes, workover
expenses and compression fees.
Our contract drilling operating margins increased from 22 percent in
2000 to 46 percent in 2001. The additional operating margin was generally
due to additional revenue received per day and an increase in the number of
rigs being used. Our contract drilling operating cost per rig per day
decreased $400 in 2001 when compared with 2000 as increased usage reduced
the impact of our fixed indirect drilling expenses. Total contract drilling
operating costs were up 8 percent in 2001 versus 2000 primarily due to
increased utilization and increases in field labor cost.
Contract drilling depreciation increased 16 percent due to higher rig
utilization. Depreciation, depletion and amortization ("DD&A") of our oil
and natural gas properties increased 20 percent due primarily to a $2.1
million impairment of our investment in a company which has oil and natural
gas properties located in Canada and from a 11 percent increase in the
average DD&A rate per Mcfe to $0.91 in 2001 from $0.82 Mcfe in 2000.
General and administrative expenses increased 29 percent. In the
second quarter of 2001, we recorded $1.3 million in additional employee
benefit expenses for the present value of a separation agreement made in
36
connection with the retirement of King Kirchner from his position as Chief
Executive Officer. The liability associated with this expense plus accrued
interest will be paid in $25,000 monthly payments starting in July 2003 and
continuing through June 2009. Interest expense decreased 45 percent as our
average outstanding debt decreased 28 percent during 2001. The average
interest rate decreased from 7.9 percent in 2000 to 5.7 percent in 2001.
2000 versus 1999
- ----------------
Net income for 2000 was $34,344,000, compared with $3,048,000 for
1999. This improvement was mainly due to increases in our natural gas and
oil prices and production volumes. Higher oil and natural gas prices also
elevated the demand for our drilling rigs, resulting in increased
utilization of our rigs, dayrates and net income.
Our oil and natural gas revenues increased 99 percent in 2000 due to a
91 percent and 54 percent rise in the average prices we received for
natural gas and oil, respectively. For the year, natural gas production
increased by 11 percent and oil production increased by 15 percent when
compared to 1999. Production grew as we drilled 101 gross wells (40.2 net
wells) in 2000 compared to 51 gross wells (21.4 net wells) in 1999. Natural
gas production for the fourth quarter of 2000 exceeded 1999's fourth
quarter production by 11 percent.
In 2000, revenues from our contract drilling operations increased by
95 percent as the average number of our drilling rigs being used increased
from 23.1 in 1999 to 39.8 in 2000. Revenues per rig per day increased 13
percent between the comparative years. The acquisition of the Parker
drilling rigs added 6.5 rigs to our utilization rate in the fourth quarter
of 1999 and 9.0 rigs to our 2000 utilization at dayrates substantially
higher than those achieved in our other marketing area. Our rigs,
excluding those acquired from Parker, added 9.3 rigs to utilization and
added an additional 10 percent to their revenue per rig per day. Daywork
revenues represented 75 percent of our total drilling revenues in 2000 and
61 percent in 1999.
Operating margins (revenues less operating costs) for our oil and
natural gas operations were 79 percent in 2000 and 67 percent in 1999.
This increase resulted primarily from the increase in the average oil and
natural gas prices we received. Total operating costs between the
comparative years increased 31 percent due primarily to the 113 percent
increase in production taxes incurred as a result of higher revenues and to
a lesser extent from the addition of new wells through development
drilling.
Our contract drilling operating margins increased from 14 percent in
1999 to 22 percent in 2000. The additional operating margin was generally
due to additional revenue received per day and an increase in the number of
rigs utilized. Our contract drilling operating cost per rig day increased
$109 in 2000 as total contract drilling operating costs were up 76 percent
in 2000 versus 1999 primarily due to increased utilization.
37
Contract drilling depreciation increased 75 percent due to the impact
of higher depreciation per operating day associated with the newly acquired
Parker rigs and an overall increase in our rig utilization. Depreciation,
depletion and amortization ("DD&A") of our oil and natural gas properties
increased 8 percent due to additional production volumes. The average DD&A
rate per Mcfe decreased 4 percent to $0.82 in 2000.
General and administrative expenses increased 14 percent as certain
employee costs, outside contract services and office expenses increased due
to the growth in both of our operating segments. Interest expense
decreased 3 percent as our average outstanding debt decreased 14 percent
during 2000. The average interest rate increased from 7.0 percent in 1999
to 7.9 percent in 2000.
On May 3, 1999, our contract drilling office in Moore, Oklahoma was
struck by a tornado destroying two buildings and damaging various vehicles
and drilling equipment. In May 1999, we received $500,000 of insurance
proceeds for the destroyed buildings, and, as a result, in the second
quarter of 1999, we recognized a gain of $315,000 recorded as part of other
revenues. During the first quarter of 2000, we received the final
insurance proceeds totaling $987,000 for the contents of the destroyed
buildings, damaged equipment and clean up costs. From these proceeds, we
recognized a gain of $599,000 recorded as part of other revenues in the
first quarter of 2000.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
- -------- ----------------------------------------------------------
Our operations are exposed to market risks primarily as a result of
changes in commodity prices and interest rates.
Commodity Price Risk. Our major market risk exposure is in the price
we receive for our oil and natural gas production. The price we receive is
primarily driven by the prevailing worldwide price for crude oil and market
prices applicable to our natural gas production. Historically, prices we
have received for our oil and natural gas production have been volatile and
such volatility is expected to continue. The price of natural gas also
effects the demand for our rigs and the amount we can charge for the use of
the rigs. Based on our 2001 production, a $.10 per Mcf change in what we
are paid for our natural gas production would result in a corresponding
$146,000 per month ($1,752,000 annualized) change in our pre-tax cash flow.
A $1.00 per barrel change in our oil price would have a $33,000 per month
($396,000 annualized) change in our pre-tax cash flow.
Periodically we hedge the prices we will receive for a portion of our
future natural gas and oil production. We do so in an attempt to reduce
the impact and uncertainty that price fluctuations have on our cash flow.
In the first quarter of 2000, we entered into swap transactions to lock in
a portion of our oil production at higher oil prices. These transactions
applied to approximately 50 percent of our daily oil production covering
the period from April 1, 2000 to July 31, 2000 and 25 percent of our daily
oil production for August and September of 2000 at prices ranging from
$24.42 to $27.01. We entered into a collar contract covering approximately
25 percent of our daily oil production from November 1, 2000 through
38
February 28, 2001. The collar had a floor of $26.00 per barrel and a
ceiling of $33.00 per barrel and we received $0.86 per barrel for entering
into the transaction. During 2000, the net effect of our oil hedging
transactions for oil reduced our oil revenues by $465,000. We did not have
any hedging transactions for natural gas in 2000. During the first quarter
of 2001, our oil hedging transaction yielded an increase in our oil
revenues of $17,200.
We entered into a natural gas collar contract for approximately 36
percent of our June and July 2001 natural gas production at a floor price
of $4.50 and a ceiling price of $5.95. We also entered into two natural
gas collar contracts for approximately 38 percent of our September through
November 2001 natural gas production. Both contracts had a floor price of
$2.50. One contract had a ceiling price of $3.68 and the other contract had
a ceiling price of $4.25. For the year our natural gas collar contracts
added $2,030,000 to our natural gas revenues. We did not have any hedging
transactions outstanding at December 31, 2001 nor on February 20, 2002.
Interest Rate Risk. Our interest rate exposure relates to our long-
term debt, all of which bears interest at variable rates based on the prime
rate or the London Interbank Offered Rate ("Libor Rate"). At our election,
borrowings under our revolving credit and term loan may be fixed at the
Libor Rate for periods up to 180 days. Historically, we have not utilized
any financial instruments, such as interest rate swaps, to manage our
exposure to increases in interest rates. However, we may use such
financial instruments in the future should our assessment of future
interest rates warrant such use. Based on our average outstanding long-term
debt in 2001, a one percent change in the floating rate would change our
annual cash flow before income taxes by approximately $450,000.
39
Item 8. Financial Statements and Supplementary Data
- ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
----------------------
2000 2001
---------- ----------
(In thousands)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 726 $ 391
Accounts receivable (less allowance for
doubtful accounts of $919 and $604) 40,220 33,886
Materials and supplies 3,802 5,358
Income tax receivable - 3,198
Prepaid expenses and other 1,269 3,761
---------- ----------
Total current assets 46,017 46,594
---------- ----------
Property and Equipment:
Drilling equipment 196,736 244,698
Oil and natural gas properties, on
the full cost method 349,707 406,491
Transportation equipment 5,803 6,441
Other 8,801 9,231
---------- ----------
561,047 666,861
Less accumulated depreciation, depletion,
amortization and impairment 270,690 304,643
---------- ----------
Net property and equipment 290,357 362,218
---------- ----------
Other Assets 9,914 8,441
---------- ----------
Total Assets $ 346,288 $ 417,253
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
40
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
----------------------
2000 2001
---------- ----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
- -----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities $ 1,627 $ 1,893
Accounts payable 21,012 16,292
Accrued liabilities 9,854 10,616
Contract advances 179 240
---------- ----------
Total current liabilities 32,672 29,041
---------- ----------
Long-Term Debt 54,000 31,000
---------- ----------
Other Long-Term Liabilities (Note 4) 3,597 4,110
---------- ----------
Deferred Income Taxes 41,479 73,940
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value,
5,000,000 shares authorized, none issued - -
Common stock, $.20 par value,
75,000,000 shares authorized,
35,768,344 and 36,006,267
shares issued, respectively 7,154 7,201
Capital in excess of par value 139,872 141,977
Retained earnings 67,514 130,280
Treasury stock at cost (30,000 shares) - (296)
---------- ----------
Total shareholders' equity 214,540 279,162
---------- ----------
Total Liabilities and Shareholders' Equity $ 346,288 $ 417,253
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
41
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
-------------------------------------
1999 2000 2001
---------- ---------- ----------
(Restated,
See Note 2)
(In thousands except per share amounts)
Revenues:
Contract drilling $ 55,479 $ 108,075 $ 167,042
Oil and natural gas