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F O R M 1 0 - K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
-------- ----------
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
--------------- -----
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange
------------------- on which registered
Common Stock, par value -------------------
$.20 per share New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes _X_ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (Section 229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant's
knowledge, in definitive proxy or information statements incorporated by
reference in PART III of this Form 10-K or any amendment to this Form 10-K.
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 16 2001 - $467,971,160
Number of Shares of Common Stock
Outstanding on March 16 2001 - 35,934,791
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the
Annual Meeting of Stockholders to be held May 2, 2001 are incorporated by
reference in Part III.
Exhibit Index - See Page 85
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 2
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 2
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 22
Item 4. Submission of Matters to a Vote of Security Holders . . 22
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . 23
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . 25
Item 7a. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . 32
Item 8. Financial Statements and Supplementary Data . . . . . . 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . 75
PART III
Item 10. Directors and Executive Officers of the Registrant. . . 75
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 77
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . 77
Item 13. Certain Relationships and Related Transactions. . . . . 77
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 78
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
1
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2000
PART I
Item 1. Business and Item 2. Properties
- ------- -------- ------- ----------
GENERAL
Through our wholly owned subsidiaries, we contract to drill onshore
oil and natural gas wells for others and explore, develop, acquire and
produce oil and natural gas properties for our self. We were founded in
1963 as a contract drilling company. Today our contract drilling
operations and our exploration and production operations are carried out
primarily in the natural gas producing provinces of the Oklahoma and Texas
areas of the Anadarko and Arkoma Basins and the Texas Gulf Cost. Our
contract drilling operations are also engaged in the East Texas and Rocky
Mountain region.
Our executive offices are located at 1000 Kensington Tower, 7130 South
Lewis, Tulsa, Oklahoma 74136; telephone number (918) 493-7700. We also
have regional offices in Oklahoma City, Oklahoma, Woodward, Oklahoma,
Booker, Texas, Houston, Texas and Casper, Wyoming. When used in this
report, the terms Corporation, Unit, our, we and its refer to Unit
Corporation and, at times, Unit Corporation and/or one or more of its
subsidiaries.
LAND CONTRACT DRILLING OPERATIONS
We drill onshore natural gas and oil wells for a wide range of
customers through our wholly owned subsidiary Unit Drilling Company. A land
drilling rig consists, in part, of engines, drawworks or hoists, derrick or
mast, substructure, pumps to circulate the drilling fluid, blowout
preventers and drill pipe. We conduct an active maintenance and
replacement program under which components are upgraded on an individual
basis. Over the life of a typical rig, due to the normal wear and tear of
operating 24 hours a day, several of the major components, such as engines,
mud pumps and drill pipe, are replaced or rebuilt on a periodic basis,
while other components, such as the substructure, mast and drawworks, can
be utilized for extended periods of time with proper maintenance. We also
own additional equipment used in the operation of our rigs, including large
air compressors, trucks and other support equipment.
On September 30, 1999, we completed the acquisition of 13 land
drilling rigs from Parker Drilling Company and Parker Drilling Company
North America, Inc., for $40 million and one million shares of our common
stock.
2
On December 29, 2000, we purchased a 750 horsepower diesel electric rig
with a 13,500 foot depth capacity for $3.2 million and at December 31,
2000, we were completing the construction of two additional rigs.
At December 31, 2000, our drilling rig fleet consisted of 50 rigs with
depth capacities ranging from 9,500 to 40,000 feet of which 34 were located
in the Anadarko and Arkoma Basins of Oklahoma and Texas while nine were
located in the East Texas and Gulf Coast Region and seven in the Rocky
Mountain region.
In January 2001, we purchased a 1,000 horse power diesel electric rig
with a 16,000 foot depth capacity for $3.2 million. This new rig is working
in the Gulf Coast region. In February 2001, we purchased a 1,000 horse
power mechanical rig, also with a 16,000 foot depth capacity, for $2.5
million. This rig will be moved from Alaska to the Rocky Mountain region
in the second quarter of 2001. The addition of these two rigs brings our
fleet to 52 rigs.
At present, we do not have a shortage of drilling rig related
equipment. During 1996 and through 1997, we increased our drill pipe
acquisitions since certain grades of drill pipe were in high demand due to
increased rig utilization. However, at any given time our ability to use
all of our rigs will depend on the availability of qualified labor,
drilling supplies and equipment as well as demand.
3
The following table sets forth, for each of the periods indicated,
certain information concerning our contract drilling operations:
Year Ended December 31,
------------------------------------------------
1996 1997 1998 1999 2000
------ ------ ------ ------ ------
Number of Rigs Owned
At End of Period 24.0 34.0 (1) 34.0 47.0 (2) 50.0 (3)
Average Number of Rigs
Owned During Period 22.7 25.1 34.0 37.3 47.0
Average Number of Rigs
Utilized (4) 14.7 20.0 22.9 23.1 39.8
Utilization Rate (4) 65% 80% 67% 62% 85%
Average Revenue
Per Day (5) $5,351 $6,309 $6,394 $6,582 $7,432
Total Footage Drilled
(Feet in 1000's) 1,468 1,736 2,203 2,211 3,650
Number of Wells
Drilled 130 167 198 197 316
- ----------------------
(1) Includes 10 rigs acquired in the fourth quarter of 1997.
(2) Includes 13 rigs acquired in September 1999.
(3) Includes one rig acquired at the 2000 year-end and two additional rigs
that were completing construction.
(4) Utilization rates are based on a 365-day year and are calculated by
dividing the number of rigs utilized by the total number of rigs owned
during the period, including stacked rigs. A rig is considered utilized
when it is operating or being moved, assembled or dismantled under
contract.
(5) Represents total revenues from contract drilling operations divided by
the total number of days rigs were being utilized for the period.
As of February 7, 2001, 47 of our drilling rigs were operating under
contract.
4
The following table sets forth, as of March 16, 2001, the type and
approximate depth capability of each of our drilling rigs:
Approximate Depth
Rig# Type Capability (feet)
----- --------------------------- -----------------
1 BDW 650 13,000
2 BDW 650 13,000
3 BDW 650 13,500
4 Gardner Denver 500 12,500
5 U-15 Unit Rig 11,000
6 BDW 800 17,000
8 Gardner Denver 800 16,000
9 BDW 800 17,000
10 BDW 450T 9,500
11 Gardner Denver 700 15,000
12 BDW 800 16,000
14 Gardner Denver 700 15,000
15 Mid-Continent 914-C 20,000
16 U-15 Unit Rig 11,000
17 Brewster N-75 15,000
18 BDW 650 12,500
19 Gardner Denver 500 12,000
20 Gardner Denver 700 15,000
21 Gardner Denver 700 15,000
22 BDW 800 16,000
23 Gardner Denver 700 14,000
24 Gardner Denver 700 14,000
25 Gardner Denver 700 15,000
26 National 610 E 13,500
27 BDW 650 13,000
28 Continental Emsco D-3 16,000
29 Brewster N-75A 15,000
30 BDW 1350-M 20,000
31 Shufelt 12,500
32 Brewster N-75 15,000
33 BDW 800 16,000
34 National 110-UE 20,000
35 Continental Emsco C-1 20,000
36 Gardner Denver 1500-E 25,000
37 Mid-Continent 914-EC 20,000
38 Mid-Continent 1220-EB 25,000
39 Mid-Continent U-36-A 12,000
40 BDW 800 16,000
112 Ideco E-3000 25,000
166 OIME E-3000 25,000
180 OIME E-3000 30,000
182 OIME E-3000 30,000
184 OIME E-3000 30,000
201 OIME E-4000 40,000
203 OIME E-2000 25,000
232 Continental Emsco D-3 II 16,000
233 Continental Emsco C-1 III 20,000
234 Continental Emsco D-3 II 16,000
235 Continental Emsco C-1 II 20,000
236 Gardner Denver 800 16,000
237 Continental Emsco C-1 II 20,000
254 OIME E-2000 25,000
5
During most of the past 17 years, our contract drilling operations
encountered significant competition due to depressed levels of activity.
In the last half of 1999 and throughout 2000, as oil and natural gas prices
began to increase, the demand for our contract drilling services increased.
Although we experienced an increase in demand for our drilling services and
our dayrates and utilization have increased, we anticipate that competition
within the industry will, for the foreseeable future, continue to adversely
affect us.
Drilling Contracts. Most of our drilling contracts are obtained
through competitive bidding. Generally, our contracts are for a single
well with the terms and rates varying depending upon the nature and
duration of the work, the equipment and services supplied and other
matters. The contracts obligate us to pay certain operating expenses,
including wages of drilling personnel, maintenance expenses and incidental
rig supplies and equipment. Usually, the contracts are subject to
termination by the customer on short notice upon payment of a fee. We
generally indemnify our customers against certain types of claims by our
employees and claims arising from surface pollution caused by spills of
fuel, lubricants and other solvents within our control. Customers
generally indemnify us against claims arising from other surface and
subsurface pollution other than claims resulting from our gross negligence.
Our contracts generally compensate us on a daywork, footage or turnkey
basis with additional compensation for special risks and unusual
conditions. Under daywork contracts, we provide the drilling rig with the
required personnel to the operator who supervises the drilling of the
contracted well. Our compensation is based on a negotiated rate for each
day the rig is utilized. Footage contracts usually require us to bear some
of the drilling costs in addition to providing the rig. We are compensated
on a negotiated rate, per foot drilled, upon completion of the well. Under
turnkey contracts, we contract to drill a well for a lump sum amount to a
specified depth and provide most of the equipment and services required.
We bear the risk of drilling the well to the contract depth and are
compensated when the contract provisions have been satisfied.
Turnkey drilling operations, in particular, might result in losses if
we underestimate the costs of drilling a well or if unforeseen events
occur. To date, we have not experienced significant losses in performing
turnkey contracts. For 2000, turnkey revenue represented approximately 9
percent of our contract drilling revenues as compared to 21 percent for
1999 and we did not have any turnkey contracts in progress at December 31,
2000. Because the proportion of turnkey drilling is dictated by market
conditions and the desires of customers using our services, we can't
predict whether the portion of drilling conducted on a turnkey basis will
increase or decrease in the future.
Customers. During 2000, 10 contract drilling customers accounted for
approximately 42 percent of our total contract drilling revenues.
Approximately 4 percent of our total contract drilling revenues were
generated from drilling on oil and natural gas properties of which we were
the operator (including properties owned by limited partnerships for which
we acted as general partner).
6
Further information relating to contract drilling operations is
presented in Notes 1, 2 and 10 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
OIL AND NATURAL GAS OPERATIONS
In 1979, we began to develop our exploration and production operations
to diversify our contract drilling revenues. Our wholly owned subsidiary,
Unit Petroleum Company, conducts our exploration and production activities.
As of December 31, 2000, we had estimated net proved reserves of 4,183
Mbbls and 215,637 MMcf. Our producing oil and natural gas interests,
undeveloped leaseholds and related assets are located primarily in
Oklahoma, Texas, Louisiana and New Mexico and, to a lesser extent, in
Arkansas, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi,
Illinois, Michigan, Nebraska and Canada. As of December 31, 2000, we had
an interest in a total of 2,887 wells in the United States, 667 of which we
served as the operator. We also had an interest in 64 wells located in
Canada. Our technical staff generates the majority of our development and
exploration prospects. When we are the operator of a property, we
generally employ our own drilling rigs and our own engineering staff
supervises the drilling operation.
We intend to continue the growth in our oil and natural gas operations
utilizing funds generated from operations and our bank loan agreement.
7
Well and Leasehold Data. The tables below set forth certain
information regarding our oil and natural gas exploration and development
drilling activities for the periods indicated:
Year Ended December 31,
--------------------------------------------------------
1998 1999 2000
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Wells Drilled:
- --------------
Exploratory:
Oil - - - - - -
Natural gas - - - - 2 1.63
Dry 1 .26 - - - -
-------- -------- -------- -------- -------- --------
Total 1 .26 - - 2 1.63
======== ======== ======== ======== ======== ========
Development:
Oil 6 1.13 1 .48 7 1.45
Natural gas 62 22.71 55 19.23 75 28.51
Dry 27 11.85 10 5.47 17 8.56
-------- -------- -------- -------- -------- --------
Total 95 35.69 66 25.18 99 38.52
======== ======== ======== ======== ======== ========
Oil and Natural
Gas Wells
Producing or
Capable of
Producing:
- ---------------
Oil - USA 841 214.70 783 224.10 799 278.06
Oil - Canada - - - - - -
Gas - USA 1,960 370.70 1,950 403.50 2,088 431.11
Gas - Canada 64 1.60 64 1.60 64 1.60
-------- -------- -------- -------- -------- --------
Total 2,865 587.00 2,797 629.20 2,951 710.77
======== ======== ======== ======== ======== ========
On February 7, 2001, Unit was participating in the drilling of 4
gross (2.36 net) wells in the United States.
8
The following table summarizes our oil and natural gas leasehold
acreage as of the end of each of the years indicated:
Developed Acreage Undeveloped Acreage
--------------------- ---------------------
Gross Net Gross Net
--------- --------- --------- ---------
1998:
- -----
USA 628,241 142,543 52,958 35,371
Canada 39,040 976 22,763 22,763
--------- --------- --------- ---------
667,281 143,519 75,721 58,134
========= ========= ========= =========
1999:
- -----
USA 548,011 142,472 55,989 35,245
Canada 39,040 976 25,293 25,293
--------- --------- --------- ---------
Total 587,051 143,448 81,282 60,538
========= ========= ========= =========
2000:
- -----
USA 564,780 153,507 61,487 39,480
Canada 39,040 976 26,243 13,121
--------- --------- --------- ---------
Total 603,820 154,463 87,730 52,601
========= ========= ========= =========
9
Price and Production Data. The following table sets forth our average
sales price, oil and natural gas production volumes and average production
cost per equivalent Mcf [1 barrel (Bbl) of oil = 6 thousand cubic feet
(Mcf) of natural gas] of production for the periods indicated:
Year Ended December 31,
---------------------------------
1998 1999 2000
---------- ---------- ----------
Average Sales Price per Barrel of Oil
Produced:
USA $ 12.77 $ 17.48 $ 26.95
Canada - - -
Average Sales Price per Mcf of Natural
Gas Produced:
USA $ 1.91 $ 2.05 $ 3.91
Canada $ 1.46 $ 1.81 $ 2.39
Oil Production (Mbbls):
USA 486 424 488
Canada - - -
---------- ---------- ----------
Total 486 424 488
========== ========== ==========
Natural Gas Production (MMcf):
USA 17,694 17,402 19,239
Canada 38 35 46
---------- ---------- ----------
Total 17,732 17,437 19,285
========== ========== ==========
Average Production Expense per
Equivalent Mcf:
USA $ .62 $ .59 $ .74
Canada $ .54 $ .56 $ .42
10
Reserves. The following table sets forth our estimated proved
developed and undeveloped oil and natural gas reserves at the end of each
of the years indicated:
Year Ended December 31,
---------------------------------
1998 1999 2000
---------- ---------- ----------
Oil (Mbbls):
USA 3,629 4,527 4,183
Canada - - -
---------- ---------- ----------
Total 3,629 4,527 4,183
========== ========== ==========
Natural gas (MMcf):
USA 175,884 186,770 215,196
Canada 523 569 441
---------- ---------- ----------
Total 176,407 187,339 215,637
========== ========== ==========
Further information relating to oil and natural gas operations is
presented in Notes 1, 10 and 12 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
VOLATILE NATURE OF OUR OIL AND NATURAL GAS MARKETS;
FLUCTUATIONS IN PRICES
Our revenues, operating results, cash flows and future rate of growth
are significantly affected by the prevailing prices for natural gas and
oil. Historically, oil and natural gas prices and markets have been
volatile, and they are likely to continue to be volatile. Oil and natural
gas prices increased substantially in the last half of 1999 and throughout
2000. However, and despite the recent price improvements, it is possible
that such prices could again decline. Price declines had a significant
negative impact on our financial results for 1998 and the first six months
of 1999. We incurred a net loss for the two quarterly periods ending March
31 and June 30, 1999 before incurring net income for the two quarterly
periods ending September 30 and December 31, 1999. Although we had net
income for the twelve months ended December 31, 1999 and significant
increases in net income in 2000, depressed prices in the future would, as
noted, have a negative impact on our future financial results. Because our
oil and natural gas reserves are predominantly natural gas, changes in
natural gas prices would have a disproportionate impact on our financial
results.
11
Prices for oil and natural gas are subject to wide fluctuations in
response to relatively minor changes in the supply of and demand for oil
and natural gas, market uncertainty and a variety of additional factors
that are beyond our control. These factors include:
. political conditions in oil producing regions, including the
Middle East;
. the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
. the price of foreign imports;
. actions of governmental authorities;
. the domestic and foreign supply of oil and natural gas;
. the level of consumer demand;
. weather conditions;
. domestic and foreign government regulations;
. the price, availability and acceptance of alternative fuels; and
. overall economic conditions.
These factors and the volatile nature of the energy markets make it
impossible to predict with any certainty the future prices of oil and
natural gas.
Our oil and condensate production is sold at or near our wells under
purchase contracts at prevailing prices in accordance with arrangements
customary in the oil industry. Our natural gas production is sold to
intrastate and interstate pipelines as well as to independent marketing
firms under contracts with original terms ranging from one month to several
years at prices primarily determined on a daily basis. Most of these
contracts contain provisions for readjustment of price, termination and
other terms customary in the industry.
Our contract drilling operations are dependent on the level of demand
in our operating markets. Both short-term and long-term trends in oil and
natural gas prices affect the demand. Because oil and natural gas prices
are volatile, the level of demand for our services can also be volatile.
Decreased oil and natural gas prices during 1998 and early 1999 adversely
affected our contract drilling activity by lowering the demand for our rigs
and reducing the rates we charged for our rigs. With the increase in oil
and natural gas prices in the last half of 1999 and all of 2000 our
dayrates and rig utilization have increased substantially.
12
Although oil and natural gas prices have recently improved, we expect
that in the near term our customers will continue a cautious approach to
exploration and development spending until price gains prove to be
sustainable. Decreases from current oil and natural gas prices would
depress the level of exploration and production activity. This in turn
would likely result in a decline in our contract drilling revenues, cash
flows and profitability. As a result, the future demand for our drilling
services is uncertain.
COMPETITION
All of our lines of business are highly competitive. Competition in
onshore contract drilling traditionally involves such factors as price,
efficiency, condition of equipment, availability of labor and equipment,
reputation and customer relations. Some of our competitors in the onshore
contract drilling business are substantially larger than we are and have
appreciably greater financial and other resources. As a result of the
increase in demand for onshore contract drilling services over the past
year and a half, previous surpluses of certain types of drilling rigs in
the industry have been eliminated and the inventories of certain components
such as specific grades of drill pipe have been depleted from continued
use. The competitive environment within which we operate is uncertain and
extremely price oriented.
Our oil and natural gas operations likewise encounter strong
competition from major oil companies, independent operators and others.
Many of these competitors have appreciably greater financial, technical and
other resources and are more experienced in the exploration for and
production of oil and natural gas than we are.
OIL AND NATURAL GAS PROGRAMS
Our subsidiary, Unit Petroleum Company, serves as the general partner
of four oil and gas limited partnerships and 12 employee oil and gas
limited partnerships. Each year we form an employee partnership which
acquires an interest, ranging from 2.5% to 15% of our interest, in most oil
and natural gas drilling activities and purchases of producing oil and
natural gas properties that we do that year. The limited partners in the
employee partnerships are either employees or directors of Unit or its
subsidiaries. Our subsidiary, Questa Oil and Gas Co., also formed five
private limited partnerships from 1981 to 1993. We repurchased the limited
partner's interest in three of five of the Questa partnerships in the
fourth quarter of 2000 and the three partnerships were dissolved.
Under the terms of the partnership agreements, the general partner has
broad discretionary authority to manage the business and operations of the
partnership, including the authority to make decisions on such matters as
the partnership's participation in a drilling location or a property
acquisition, the partnership's expenditure of funds and the distribution of
funds to partners. Because the business activities of the limited partners
on the one hand, and the general partner on the other hand, are not the
same, conflicts of interest will exist and it is not possible to eliminate
entirely such conflicts. Additionally, conflicts of interest may arise
13
when we are the operator of an oil and natural gas well and also provide
contract drilling services. In such cases, these drilling operations are
done pursuant to contracts containing terms and conditions comparable to
those contained in our drilling contracts with non-affiliated operators.
Although we have no formal procedures for resolving such conflicts, we
believe we fulfill our responsibility to each contracting party and comply
fully with the terms of the agreements which regulate such conflicts.
EMPLOYEES
As of February 7, 2000, we had approximately 1,038 employees in our
land contract drilling operations, 54 employees in our oil and natural gas
operations and 52 in our general corporate area. None of our employees are
represented by a union or labor organization nor have our operations ever
been interrupted by a strike or work stoppage. We consider relations with
our employees to be satisfactory.
OPERATING AND OTHER RISKS
Our drilling operations are subject to many hazards inherent in the
drilling industry, including blowouts, cratering, explosions, fires, loss
of well control, loss of hole, damaged or lost drilling equipment and
damage or loss from inclement weather. Our exploration and production
operations are subject to these and similar risks. Any of these events
could result in personal injury or death, damage to or destruction of
equipment and facilities, suspension of operations, environmental damage
and damage to the property of others. Generally, drilling contracts
provide for the division of responsibilities between a drilling company and
its customer, and we seek to obtain indemnification from our drilling
customers by contract for some of these risks. To the extent that we are
unable to transfer these risks to drilling customers by contract or
indemnification agreements, we seek protection through insurance. However,
we cannot assure you that our insurance or our indemnification agreements,
if any, will adequately protect us against liability from all of the
consequences of the hazards described above. The occurrence of an event
not fully insured or indemnified against, or the failure of a customer to
meet its indemnification obligations, could result in substantial losses to
us. In addition, we cannot assure you that insurance will be available to
cover any or all of these risks. Even if available, the insurance might
not be adequate to cover all of our losses, or we might decide against
obtaining that insurance because of high premiums or other costs.
Exploration and development operations involve numerous risks that may
result in dry holes, the failure to produce oil and natural gas in
commercial quantities and the inability to fully produce discovered
reserves. The cost of drilling, completing and operating wells is
substantial and uncertain. Our operations may be curtailed, delayed or
cancelled as a result of many things beyond our control, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
14
. adverse weather conditions;
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs or delivery
crews and the delivery of equipment.
The majority of the wells in which we own an interest are operated by
other parties. As a result, we have little control over the operations of
such wells which can act to increase our risk. Operators of these wells
may act in ways that are not in our best interests.
Our future performance depends upon our ability to find or acquire
additional oil and natural gas reserves that are economically recoverable.
In general, production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. Unless we successfully replace the reserves that we
produce, our reserves will decline, resulting eventually in a decrease in
oil and natural gas production and lower revenues and cash flow from
operations. Historically, we have succeeded in increasing reserves after
taking production into account through exploitation, development and
exploration. We have conducted such activities on our existing oil and
natural gas properties as well as on newly acquired properties. We may not
be able to continue to replace reserves from such activities at acceptable
costs. Low prices of oil and natural gas may further limit the kinds of
reserves that can economically be developed. Lower prices also decrease
our cash flow and may cause us to decrease capital expenditures.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which we conduct
activities impose restrictions on the drilling, production, transportation
and sale of oil and natural gas.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory
Commission (the "FERC") regulates the interstate transportation and the
sale in interstate commerce for resale of natural gas. The FERC's
jurisdiction over interstate natural gas sales was substantially modified
by the Natural Gas Policy Act under which the FERC continued to regulate
the maximum selling prices of certain categories of gas sold in "first
sales" in interstate and intrastate commerce. Effective January 1, 1993,
however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act")
deregulated natural gas prices for all "first sales" of natural gas.
Because "first sales" include typical wellhead sales by producers, all
natural gas produced from our natural gas properties is being sold at
market prices, subject to the terms of any private contracts which may be
in effect. The FERC's jurisdiction over natural gas transportation was not
affected by the Decontrol Act.
15
Our sales of natural gas are affected by intrastate and interstate gas
transportation regulation. Beginning in 1985, the FERC adopted regulatory
changes that have significantly altered the transportation and marketing of
natural gas. These changes were intended by the FERC to foster competition
by, among other things, transforming the role of interstate pipeline
companies from wholesale marketers of natural gas to the primary role of
gas transporters. All natural gas marketing by the pipelines was required
to be divested to a marketing affiliate, which operates separately from the
transporter and in direct competition with all other merchants. As a
result of the various omnibus rulemaking proceedings in the late 1980s and
the individual pipeline restructuring proceedings of the early to mid-
1990s, the interstate pipelines are now required to provide open and
nondiscriminatory transportation and transportation-related services to all
producers, natural gas marketing companies, local distribution companies,
industrial end users and other customers seeking service. Through similar
orders affecting intrastate pipelines that provide similar interstate
services, the FERC expanded the impact of open access regulations to
intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to
affiliated or non-affiliated companies; (2) further development of rules
governing the relationship of the pipelines with their marketing
affiliates; (3) the publication of standards relating to the use of
electronic bulletin boards and electronic data exchange by the pipelines to
make available transportation information on a timely basis and to enable
transactions to occur on a purely electronic basis; (4) further review of
the role of the secondary market for released pipeline capacity and its
relationship to open access service in the primary market; and (5)
development of policy and promulgation of orders pertaining to its
authorization of market-based rates (rather than traditional cost-of-
service based rates) for transportation or transportation-related services
upon the pipeline's demonstration of lack of market control in the relevant
service market. It remains to be seen what effect the FERC's other
activities will have on the access to markets, the fostering of competition
and the cost of doing business.
As a result of these changes, sellers and buyers of natural gas have
gained direct access to the particular pipeline services they need and are
better able to conduct business with a larger number of counter parties.
We believe these changes generally have improved the access to markets for
natural gas while, at the same time, substantially increasing competition
in the natural gas marketplace. We cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt or what effect
subsequent regulations may have on production and marketing of natural gas
from our properties.
In the past, Congress has been very active in the area of natural gas
regulation. However, as discussed above, the more recent trend has been in
favor of deregulation and the promotion of competition in the natural gas
industry. Thus, in addition to "first sales" deregulation, Congress also
repealed incremental pricing requirements and natural gas use restraints
previously applicable. There are other legislative proposals pending in the
16
Federal and State legislatures which, if enacted, would significantly
affect the petroleum industry. At the present time, it is impossible to
predict what proposals, if any, might actually be enacted by Congress or
the various state legislatures and what effect, if any, these proposals
might have on the production and marketing of natural gas by us. Similarly,
and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue or what the
ultimate effect will be on the production and marketing of natural gas by
us cannot be predicted.
Our sales of oil and natural gas liquids are not regulated and are at
market prices. The price received from the sale of these products is
affected by the cost of transporting the products to market. Much of that
transportation is through interstate common carrier pipelines. Effective
as of January 1, 1995, the FERC implemented regulations generally
grandfathering all previously approved interstate transportation rates and
establishing an indexing system for those rates by which adjustments are
made annually based on the rate of inflation, subject to certain conditions
and limitations. These regulations may tend to increase the cost of
transporting oil and natural gas liquids by interstate pipeline, although
the annual adjustments may result in decreased rates in a given year. These
regulations have generally been approved on judicial review. Every five
years, the FERC will examine the relationship between the annual change in
the applicable index and the actual cost changes experienced by the oil
pipeline industry. We are not able to predict with certainty what effect,
if any, these relatively new federal regulations or the periodic review of
the index by the FERC will have on us.
Federal, state, and local agencies have promulgated extensive rules
and regulations applicable to our oil and natural gas exploration,
production and related operations. Oklahoma, Texas and other states
require permits for drilling operations, drilling bonds and the filing of
reports concerning operations and impose other requirements relating to the
exploration of oil and natural gas. Many states also have statutes or
regulations addressing conservation matters including provisions for the
unitization or pooling of oil and natural gas properties, the establishment
of maximum rates of production from oil and natural gas wells and the
regulation of spacing, plugging and abandonment of such wells. The statutes
and regulations of some states limit the rate at which oil and natural gas
can be produced from our properties. The federal and state regulatory
burden on the oil and natural gas industry increases our cost of doing
business and affects its profitability. Because these rules and regulations
are frequently amended or reinterpreted, we are unable to predict the
future cost or impact of complying with those laws.
17
SAFE HARBOR STATEMENT OF FURTHER ACTIVITY
Statements in this document as well as information contained in
written material, press releases and oral statements issued by or on behalf
of us contain, or may contain, certain "forward-looking statements" within
the meaning of federal securities laws. All statements, other than
statements of historical facts, included in this document which address
activities, events or developments which we expect or anticipate will or
may occur in the future are forward-looking statements. The words
"believes," "intends," "expects," "anticipates," "projects," "estimates,"
"predicts" and similar expressions are also intended to identify forward-
looking statements. These forward-looking statements include, among
others, such things as:
. year 2001 plans;
. the amount and nature of future capital expenditures;
. wells to be drilled or reworked;
. oil and natural gas prices and demand;
. exploitation and exploration prospects;
. estimates of proved oil and natural gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and natural gas
industry;
. business strategy;
. production of oil and natural gas reserves;
. expansion and growth of our business and operations; and
. drilling rig utilization, revenues and costs.
These statements are based on certain assumptions and analyses made by
us in light of our experience and our perception of historical trends,
current conditions and expected future developments as well as other
factors we believe are appropriate in the circumstances. However, whether
actual results and developments will conform to our expectations and
predictions is subject to a number of risks and uncertainties which could
cause actual results to differ materially from our expectations, including:
. the risk factors discussed in this document;
. general economic, market or business conditions;
. the nature or lack of business opportunities that may be presented to
and pursued by us;
. demand for land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any forward-looking statements made
by us, the following discussion outlines certain factors that in the future
could cause our consolidated results for 2001 and beyond to differ
materially from those that may be set forth in any such forward-looking
statement made by or on behalf of us.
18
Commodity Prices
The prices we receive for our oil and natural gas production have a
direct impact on our revenues, profitability and cash flow as well as our
ability to meet our projected financial and operational goals. The prices
for natural gas and crude oil are heavily dependent on a number of factors
beyond our control, including the demand for oil and/or natural gas;
current weather conditions in the continental United States which can
greatly influence the demand for natural gas at any given time as well as
the price to be received for such natural gas; and the ability of current
distribution systems in the United States to effectively meet the demand
for oil and or natural gas at any given time, particularly in times of peak
demand which may result due to adverse weather conditions. Oil prices are
extremely sensitive to foreign influences that may be based on political,
social or economic underpinnings, any one of which could have an immediate
and significant effect on the price and supply of oil. In addition, prices
of both natural gas and oil are becoming more and more influenced by
trading on the commodities markets which, at times, has tended to increase
the volatility associated with these prices resulting, at times, in large
differences in such prices even on a month-to-month basis. All of these
factors, especially when coupled with the fact that much of our product
prices are determined on a daily basis, can, and at times do, lead to wide
fluctuations in the prices we receive.
Based upon the results of our operations for 2000 we estimate that a
change of $0.10/Mcf in the average price of natural gas and a change of
$1.00/Bbl in the price of crude oil throughout such period would have
resulted in approximate changes in net income before income taxes of
$1,797,000 and $455,000, respectively. During 2000, substantially all of
our natural gas and crude oil volumes were sold at market responsive
prices.
In order to reduce our exposure to short-term fluctuations in the
price of oil and natural gas, we sometimes enter into hedging or swap
arrangements. Our hedging or swap arrangements apply to only a portion of
our production and provide only partial price protection against declines
in oil and natural gas prices. These hedging or swap arrangements may
expose us to risk of financial loss and limit the benefit to us of
increases in prices.
Customer Demand
Demand for our drilling services is dependent almost entirely on the
needs of third parties. Based on past history, such parties' requirements
are subject to a number of factors, independent of any subjective factors,
that directly impact the demand for our drilling rigs. These include the
availability of funds to such third parties to carry out their drilling
operations during any given time period which, in turn, are often subject
to downward revision based on decreases in the then current prices of oil
and natural gas. Many of our customers are small to mid-size oil and
natural gas companies whose drilling budgets tend to be susceptible to the
influences of current price fluctuations. Other factors that affect our
ability to work our drilling rigs are: the weather which, under adverse
circumstances, can delay or even cause a project to be abandoned by an
19
operator; the competition faced by us in securing the award of a drilling
contract in a given area; our experience and recognition in a new market
area; and the availability of labor to run our drilling rigs.
Uncertainty Of Oil and Natural Gas Reserves and Well Performance
There are numerous uncertainties inherent in estimating quantities of
proved reserves and their values, including many factors beyond our
control. The reserve data included in this document represent only
estimates. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves depend on a number of variable factors, including
historical production from the area compared with production from other
producing areas, and assumptions concerning:
. the effects of regulations by governmental agencies;
. future oil and natural gas prices;
. future operating costs;
. severance and excise taxes;
. development costs; and
. workover and remedial costs.
Some or all of these assumptions may vary considerably from actual
results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, classifications of those reserves based on risk of recovery,
and estimates of the future net cash flows from reserves prepared by
different engineers or by the same engineers but at different times may
vary substantially. Accordingly, reserve estimates may be subject to
downward or upward adjustment. Actual production, revenues and expenditures
with respect to our reserves will likely vary from estimates, and those
variances may be material.
The information regarding discounted future net cash flows included in
this document should not be considered as the current market value of the
estimated oil and natural gas reserves attributable to our properties. As
required by the SEC, the estimated discounted future net cash flows from
proved reserves are based on prices and costs as of the date of the
estimate, while actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by the following
factors:
. the amount and timing of actual production;
. supply and demand for oil and natural gas;
. increases or decreases in consumption; and
. changes in governmental regulations or taxation.
20
In addition, the 10% discount factor, which is required by the SEC to
be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with our
operations or the oil and natural gas industry in general.
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the SEC. Under these
rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved
reserves, discounted at 10%. Application of the ceiling test generally
requires pricing future revenue at the unescalated prices in effect as of
the end of each fiscal quarter and requires a write-down for accounting
purposes if the ceiling is exceeded, even if prices were depressed for only
a short period of time. We may be required to write down the carrying value
of our oil and natural gas properties when oil and natural gas prices are
depressed or unusually volatile. If a write-down is required, it would
result in a charge to earnings but would not impact cash flow from
operating activities. Once incurred, a write-down of oil and natural gas
properties is not reversible at a later date.
We are continually identifying and evaluating opportunities to acquire
oil and natural gas properties, including acquisitions that would be
significantly larger than those consummated to date by us. We cannot
assure you that we will successfully consummate any acquisition, that we
will be able to acquire producing oil and natural gas properties that
contain economically recoverable reserves or that any acquisition will be
profitably integrated into our operations.
Debt and Bank Borrowing
We have experienced and expect to continue to experience substantial
working capital needs due to our growth in drilling operations and our
active exploration, development and exploitation programs. Historically,
we have funded our working capital needs through a combination of
internally generated cash flow, equity financing and borrowings under our
bank loan agreement. As a result of our significant working capital
requirements, we currently have, and will continue to have, a certain
amount of indebtedness. At December 31, 2000, our long-term debt
outstanding was $54.0 million. As of December 31, 2000, we had a total
loan commitment of $100 million, but we elected to limit the amount
available for borrowing under our bank loan agreement to $70 million to
reduce cost. The amount outstanding under our bank loan agreement at
December 31, 2000 was $52.0 million.
Our level of indebtedness, the cash flow needed to satisfy our
indebtedness and the covenants governing our indebtedness could:
. limit funds available for financing capital expenditures, our drilling
program or other activities or cause us to curtail these activities;
. limit our flexibility in planning for or reacting to changes in our
business;
. place us at a competitive disadvantage to some of our competitors that
21
are less leveraged than us;
. make us more vulnerable during periods of low oil and natural gas
prices or in the event of a downturn in our business; and
. prevent us from obtaining additional financing on acceptable terms or
limit amounts available under our existing or any future credit
facilities.
Our ability to meet our debt service obligations will depend on our
future performance. We cannot assure you that we will be able to meet our
debt service requirements. In addition, lower oil and natural gas prices
could result in future reductions in the amount available for borrowing
under our bank loan agreement, reducing our liquidity and even triggering
mandatory loan repayments.
If the requirements of our indebtedness are not satisfied, a default
would be deemed to occur and our lenders would be entitled to accelerate
the payment of the outstanding indebtedness. If this occurs, we cannot
assure you that we would have sufficient funds available or could obtain
the financing required to meet our obligations.
The amount of our existing debt as well as its future debt is, to a
large extent, a function of the costs associated with the projects
undertaken by us at any given time and the cash flow received by us.
Generally, the costs incurred by us in our normal operations are those
associated with the drilling of oil and natural gas wells, the acquisition
of producing properties, and the costs associated with the maintenance or
expansion of our drilling rig fleet. To some extent, these costs,
particularly the first two items, are discretionary and we maintain a
degree of control regarding the timing and/or the need to incur the same.
However, in some cases, unforeseen circumstances may arise, such as in the
case of an unanticipated opportunity to acquire a large producing property
package or the need to replace a costly rig component due to an unexpected
loss, which could force us to incur increased debt above that which we had
expected or forecasted. Likewise, for many of the reasons mentioned above,
our cash flow may not be sufficient to cover our current cash requirements
which would then require us to increase our debt either through bank
borrowings or otherwise.
Item 3. Legal Proceedings
- ------- -----------------
We are a party to various legal proceedings arising in the ordinary
course of our business, none of which, in our opinion, will result in
judgments which would have a material adverse effect on our financial
position, operating results or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
- ------- ---------------------------------------------------
No matters were submitted to our security holders during the fourth
quarter of 2000.
22
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- ------- ------------------------------------------------------------------
Matters
-------
Our common stock is traded on the New York Stock Exchange under the
symbol "UNT." The following table sets forth the high and low sale prices
per share of our common stock as reported in the New York Stock Exchange
composite transactions, for the periods indicated:
1999 2000
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
First $ 7 $ 3 1/2 $ 11 1/2 $ 6 5/8
Second $ 8 1/4 $ 4 7/8 $ 14 9/16 $ 9
Third $ 9 $ 6 3/4 $ 16 1/4 $ 11 13/16
Fourth $ 7 3/4 $ 4 7/8 $ 19 7/16 $ 12 3/8
As of February 7, 2001 our common stock was held by 2,158 holders of
record.
We have not declared nor paid any cash dividends on shares of our
common stock since organization and currently intend to continue our policy
of retaining earnings from our operations. We are prohibited by certain
loan agreement provisions from declaring and paying dividends (other than
stock dividends) during any fiscal year in excess of 25 percent of our
consolidated net income of the preceding fiscal year, and only if working
capital provided from operations during the prior year is equal to or
greater than 175 percent of current maturities of long-term debt at the end
of the prior year.
23
Item 6. Selected Financial Data
- ------- -----------------------
Year Ended December 31,
----------------------------------------------------------
1996(1) 1997(1) 1998(1) 1999(1) 2000
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 75,751 $ 96,478 $ 97,274 $ 102,352 $ 201,264
========== ========== ========== ========== ==========
Income From
Continuing
Operations $ 9,359 $ 12,330 $ 1,428 $ 3,048 $ 34,344
========== ========== ========== ========== ==========
Net Income $ 9,359 $ 12,330 $ 1,428 $ 3,048 $ 34,344
========== ========== ========== ========== ==========
Earnings Per
Common Share:
Basic $ .38 $ .47 $ .05 $ .10 $ .96
========== ========== ========== ========== ==========
Diluted $ .38 $ .46 $ .05 $ .10 $ .95
========== ========== ========== ========== ==========
Total Assets $ 147,734 $ 213,416 $ 233,096 $ 295,567 $ 346,288
========== ========== ========== ========== ==========
Long-Term Debt $ 42,255 $ 55,480 $ 75,048 $ 67,239 $ 54,000
========== ========== ========== ========== ==========
Other Long-Term
Liabilities $ 2,360 $ 2,363 $ 2,368 $ 2,325 $ 3,597
========== ========== ========== ========== ==========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
========== ========== ========== ========== ==========
--------------------
(1) Restated for the merger with Questa Oil and Gas Co.
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1998, 1999 and 2000 activity.
24
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------- ---------------------------------------------------------------
Results of Operations
---------------------
Financial Condition and Liquidity
- ---------------------------------
On March 20, 2000, we completed the acquisition, by merger, of Questa
Oil and Gas Co.("Questa") under which Questa became a wholly owned
subsidiary of Unit Corporation. In the merger, each of Questa's
outstanding shares of common stock (excluding treasury shares) was
converted into .95 shares of our common stock. We issued approximately 1.8
million shares as a result of this merger. The merger has been accounted
for as a pooling of interests and, accordingly, all amounts within this
document have been restated, unless otherwise noted, as if the companies
had been combined during the periods presented.
Our bank loan agreement provides for a total loan facility of $100
million. Each year on April 1 and October 1 our banks redetermine our
available borrowing value. This value is primarily determined by an amount
equal to a percentage of the discounted future value of our oil and natural
gas reserves, as determined by the banks. An additional amount, limited to
$20 million, is added to the borrowing value for a percentage of the value
of a portion of our drilling rig fleet. Our loan agreement provides for a
revolving credit facility which terminates on May 1, 2002 followed by a
three year term loan. Borrowings under our loan agreement totaled $52
million at December 31, 2000 and $50 million at February 7, 2001. The
latest borrowing value computation determined the full amount of the loan
facility could be available to us, however, in order to reduce cost, we
elected to set the borrowing value at $70 million for the current borrowing
value period. We are charged a facility fee of .375 of 1 percent on any
unused portion of the available borrowing value. The loan agreement also
contains covenants which require us to maintain
. consolidated tangible net worth of at least $75 million,
. a current ratio of not less than 1 to 1,
. a ratio of long-term debt, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.2 to 1,
. a ratio of total liabilities, as defined in the loan agreement, to
consolidated tangible net worth not greater than 1.65 to 1, and
. working capital provided by operations, as defined in the loan
agreement, cannot be less than $18 million in any year.
The interest rate on our bank debt was 7.82 percent at December 31,
2000 and 6.72 percent at February 7, 2001. At our election, any portion of
our outstanding bank debt may be fixed at the London Interbank Offered Rate
("Libor Rate"), as adjusted, depending on the level of our debt as a
percentage of the available borrowing value. The Libor Rate may be fixed
for periods of up to 30, 60, 90 or 180 days with the remainder of our bank
25
debt being subject to the Chase Manhattan Bank, N. A. prime rate. During
any Libor Rate funding period, we may not pay any part of the outstanding
principal balance which is subject to the Libor Rate. Borrowings subject
to the Libor Rate were $47.0 million at December 31, 2000 and $50.0 million
at February 7, 2001.
Our shareholders' equity at December 31, 2000 was $214.5 million
giving us a ratio of long-term debt-to-total capitalization of 20 percent.
Our primary source of funds consists of the cash flow from our operations
and borrowings under our bank loan agreement. Net cash provided by our
operations in 2000 was $67.4 million compared to $24.7 million in 1999. We
had working capital of $13.3 million at December 31, 2000. Our total 2000
capital expenditures were $65.3 million, of which $39.9 million was spent
in our oil and natural gas operations. This segment's capital expenditures
consisted primarily of $30.5 million for exploration and development
drilling and $3.8 million for producing property acquisitions. Capital
expenditures for our contract drilling operations totaled $22.0 and
consisted primarily of $3.0 million to rebuild three of our drilling rigs,
$3.2 million to acquire one rig and $1.5 million to start construction on
two additional rigs. We also acquired $3.3 million in new drill pipe with
the remainder of our drilling capital expenditures for major components for
our rig fleet. We anticipate that we will spend approximately $20 million
in 2001 for drilling rig equipment.
As natural gas and oil prices increased during the last six months of
1999 and throughout 2000, we increased the drilling activity in our
exploration and production operation with the result that we drilled 101
wells during 2000 as compared to a total of 51 wells during the 1999. If
oil and natural gas prices remain favorable, we plan to drill an estimated
130 wells and spend approximately $65 million drilling or buying oil and
natural gas properties in 2001.
Most of our capital expenditures are discretionary and directed toward
our future growth. Current operations do not depend on our ability to
obtain funds outside of our loan agreement and our anticipated cash flow.
Future decisions by us to acquire or drill on oil and natural gas
properties will depend on prevailing or anticipated market conditions,
potential return on investment, future drilling potential and the
availability of opportunities to obtain financing under the circumstances
involved, thus providing us with a large degree of flexibility in
determining when and if to incur such costs.
On September 30, 1999, we completed the acquisition of 13 land
drilling rigs from Parker Drilling Company and Parker Drilling Company
North America, Inc., for 1,000,000 shares of our common stock and
$40,000,000 in cash. The cash part of this acquisition was funded through
a public offering of 7,000,000 shares of our common stock which closed on
September 29, 1999. We received proceeds of $50.1 million from the
offering net of commission fees and other costs.
On November 20, 1997, we acquired Hickman Drilling Company pursuant to
an agreement and plan of merger entered into by and between us, Hickman
Drilling Company and all of the holders of the outstanding capital stock of
Hickman Drilling Company. As part of this acquisition, the former
26
shareholders of Hickman held, as of December 31, 2000, promissory notes in
the aggregate outstanding principal amount of $3.0 million. These notes are
payable in equal annual installments on January 2, 2001 through January 2,
2003. The notes bear interest at the Chase Prime Rate which at December 31,
2000 was 9.5 percent and February 7, 2001 was 8.5 percent. At February 7,
2001, the promissory notes outstanding totaled $2.0 million.
Due to a settlement agreement which terminated at December 31, 1997,
we have a liability of $877,000 at December 31, 2000, representing proceeds
received from a natural gas purchaser as prepayment for natural gas. The
$877,000 is payable in equal annual payments on June 1, 2001 and June 1,
2002.
The average price we received for our oil in 2000 increased 54 percent
from the price we received in 1999 and our December 2000 oil price was 10
percent higher than the oil price we received in December 1999. Natural
gas prices remain volatile, but increased substantially during the year.
Our average natural gas price in 2000 was 91 percent higher than our
average 1999 price and our December 2000 natural gas price was 239 percent
higher than our December 1999 price. For the year, the average natural gas
price we received was $3.91 per Mcf and the average oil price we received
was $26.95 per barrel. Natural gas prices are influenced by weather
conditions and supply imbalances, particularly in the domestic market, and
by world wide oil price levels. Domestic oil price levels continue to be
primarily influenced by world market developments. Since natural gas
comprises approximately 90 percent of our total oil and natural gas
reserves, natural gas prices have a significant effect on the value of our
oil and natural gas reserves and large natural gas price declines could
cause us to reduce the carrying value of our oil and natural gas
properties. Any price decreases, if sustained, would also adversely affect
our future cash flow by reducing our oil and natural gas revenues and, if
continued over an extended period, could lessen not only the demand for our
contract drilling rigs but also the rate we would receive. Any declines in
natural gas and oil prices could also adversely affect the semi-annual
determination of the loan value under our bank loan agreement since this
determination is based on the value of our oil and natural gas reserves and
our drilling rigs. Such a reduction would reduce the amount available to
us under our loan agreement which, in turn, may affect our ability to carry
out our capital projects.
Generally, during the past 17 years, our contract drilling operations
have encountered significant competition, as reduced oil and natural gas
prices during most of the period created a reduction in the demand for
domestic land contract drilling rigs. However, in the last half of 1999 and
throughout 2000 as oil and natural gas prices increased we experienced a
substantial increase in demand for our rigs bringing our utilization rates
above 90 percent for the last five months of 2000. Even with the increase
in demand, we anticipate that competition within our industry will, for the
foreseeable future, continue to influence the use of our drilling rigs. In
addition to competition, our ability to use our drilling rigs at any given
time depends on a number of other factors, including the continued
strengthening of the price of both oil and natural gas, the availability of
labor and our ability to supply the type of equipment required.
27
At December 31, 2000, we had tax net operating loss carryforwards
("NOL's") of approximately $39.5 million, the benefit of which has been
recognized in our financial statements as we believe it to be more likely
than not that we will use these NOL's. Should we be unable to generate
sufficient income in future years to allow the use of all the NOL's, a
charge to expense will be required to give recognition to any loss of the
NOL's.
At December 31, 2000, one of our subsidiaries owned 4,949,500 shares
of common stock and 1,800,000 warrants in Shenandoah Resources Ltd., which
is a Canadian oil and natural gas exploration and production company. The
investment of $2,426,000 is part of other assets in our consolidated
balance sheet.
Effects of Inflation
- --------------------
In the previous 17 years the effects of inflation on our operations
have been minimal due to low inflation rates and moderate demand for
contract drilling services. In the last half of 1999 and throughout 2000,
as drilling rig day rates and drilling rig utilization increased, the
impact of inflation has increased as the availability of equipment and
third party services have decreased. Due to industry wide demand for
qualified labor, contract drilling labor cost increased substantially in
the summer of 2000. How inflation will effect us in the future will depend
on additional increases, if any, we realize in our drilling rig rates and
the prices we receive for our oil and natural gas. If industry activity
continues to increase, shortages in support equipment such as drill pipe,
third party services and qualified labor could occur resulting in
additional corresponding increases in our material and labor costs. These
conditions may limit our ability to realize improvements in operating
profits.
New Accounting Pronouncements
- -----------------------------------
On June 15, 1998, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (FAS 133). The statement
has subsequently been amended by FASB statements No. 137 and No. 138 and
establishes new accounting and reporting standards for derivative
instruments. We will be required to adopt this statement in the first
quarter of 2001. This statement will require us to recognize all
derivatives as either assets or liabilities on the balance sheet and
measure the effectiveness of the hedges, or the degree that the gain (loss)
for the hedging instrument offsets the loss (gain) on the hedged item, at
fair value for each reporting period. The effective portion of the gain or
loss on the derivative instrument will be recognized in other comprehensive
income as a component of our equity until the hedged item is recognized in
earnings. The ineffective portion of the derivative's change in fair value
is required to be recognized in earnings during the period the change in
value occurs. We have evaluated all of our transactions that could
potentially be classified as derivative instruments under FAS 133. The
adoption of FAS 133 will not have a significant effect on our results of
operations or financial position.
28
Results of Operations
- ---------------------
2000 versus 1999
- ----------------
Net income for 2000 was $34,344,000, compared with $3,048,000 for
1999. This increase resulted primarily from increases in our natural gas
and oil prices and production volumes. Higher oil and natural gas prices
also elevated the demand for our drilling rigs, resulting in increased
utilization of our rigs, dayrates and net income.
Our oil and natural gas revenues increased 99 percent in 2000 due to a
91 percent and 54 percent rise in the average prices we received for
natural gas and oil, respectively. For the year, natural gas production
increased by 11 percent and oil production increased by 15 percent when
compared to 1999. Production grew as we drilled 101 gross wells (40.2 net
wells) in 2000, compared to 51 gross wells (21.4 net wells) in 1999.
Natural gas production for the fourth quarter of 2000 exceeded 1999's
fourth quarter production by 11 percent.
In 2000, revenues from our contract drilling operations increased by
95 percent as the average number of our drilling rigs being used increased
from 23.1 in 1999 to 39.8 in 2000. Revenues per rig per day increased 13
percent between the comparative years. The acquisition of the Parker
drilling rigs added 6.5 rigs to our utilization rate in the fourth quarter
of 1999 and 9.0 rigs to our 2000 utilization at dayrates substantially
higher than those achieved in our other marketing area. Our rigs excluding
those acquired from Parker added 9.3 rigs to utilization and added an
additional 10 percent to their revenue per rig per day. Daywork revenues
represented 75 percent of our total drilling revenues in 2000 and 61
percent in 1999.
Operating margins (revenues less operating costs) for our oil and
natural gas operations were 79 percent in 2000 and 67 percent in 1999.
This increase resulted primarily from the increase in the average oil and
natural gas prices we received. Total operating costs between the
comparative years increased 31 percent due primarily to the 113 percent
increase in production taxes incurred as a result of higher revenues and to
a lesser extent from the addition of new wells through development
drilling.
Our contract drilling operating margins increased from 14 percent in
1999 to 22 percent in 2000. The additional operating margin was generally
due to additional revenue received per day and an increase in the number of
rigs utilized. Our contract drilling operating cost per rig per day
increased $109 in 2000 as total contract drilling operating costs were up
76 percent in 2000 versus 1999 primarily due to increased utilization.
Contract drilling depreciation increased 75 percent due to the impact
of higher depreciation per operating day associated with the newly acquired
29
Parker rigs and an overall increase in our rig utilization. Depreciation,
depletion and amortization ("DD&A") of our oil and natural gas properties
increased 8 percent due to additional production volumes. The average DD&A
rate per Mcfe decreased 4 percent to $0.82 in 2000.
General and administrative expenses increased 14 percent as certain
employee costs, outside contract services and office expenses increased due
to the growth in both of our operating segments. Interest expense
decreased 3 percent as our average outstanding debt decreased 14 percent
during 2000. The average interest rate increased from 7.0 percent in 1999
to 7.9 percent in 2000.
On May 3, 1999, our contract drilling offices in Moore, Oklahoma were
struck by a tornado destroying two buildings and damaging various vehicles
and drilling equipment. In May 1999, we received $500,000 of insurance
proceeds for the destroyed buildings, and, as a result, in the second
quarter of 1999, we recognized a gain of $315,000 recorded as part of other
revenues. During the first quarter of 2000, we received the final
insurance proceeds totaling $987,000 for the contents of the destroyed
buildings, damaged equipment and clean up costs. From these proceeds, we
recognized a gain of $599,000 recorded as part of other revenues in the
first quarter of 2000.
1999 versus 1998
- ----------------
Net income for 1999 was $3,048,000, compared with $1,428,000 in 1998.
Lower natural gas and oil prices in the first half of 1999 reduced both the
demand for our drilling rigs and the rates we received for the drilling
rigs that were operating. As a result of the merger with Questa, the oil
and gas properties of Questa were restated from the successful efforts
method of accounting to the full cost method of accounting used by Unit
Corporation. As part of this restatement, in 1998, the value of Questa's
oil and natural gas properties were impaired due to low prices at the end
of the third quarter of 1998; therefore, the Questa properties were written
down $2.6 million.
Our oil and natural gas revenues increased 7 percent in 1999 due to a
7 percent and 37 percent increase in the average prices we received for
natural gas and oil, respectively. For the year, natural gas production
decreased by 2 percent and oil production decreased by 13 percent when
compared to 1998. Our oil production declined because we in recent years
emphasized the drilling of development wells aimed at replacing and
increasing our natural gas reserves. Our natural gas production decreased
because we curtailed our development drilling program during the first half
of 1999 while oil and natural gas prices were depressed. As prices began
to improve during the last six months of 1999, our natural gas production
increased as we increased our drilling program. Natural gas production for
the fourth quarter of 1999 exceeded 1998's fourth quarter production by 4
percent.
In 1999, revenues from our contract drilling operations increased by 4
percent as the average number of drilling rigs being used increased from
22.9 in 1998 to 23.1 in 1999. Revenues per rig per day increased 3 percent
30
between the comparative years. During the first nine months of 1999 as
compared to the same period of 1998, our average drilling rig utilization
was down 22 percent and our average revenues per rig per day was down 4
percent. The acquisition of the Parker drilling rigs added 6.5 rigs to our
utilization rate in the fourth quarter of 1999 at dayrates substantially
higher than those achieved in our other marketing area. As a result, that
acquisition had a strong impact on our contract drilling fourth quarter and
year-end operating results, adding $5.6 million in revenues. Daywork
revenues represented 61 percent of our total drilling revenues in 1999 and
64 percent in 1998.
Operating margins (revenues less operating costs) for our oil and
natural gas operations were 67 percent in 1999 and 64 percent in 1998.
This increase resulted primarily from the increase in the average oil and
natural gas prices we received and a 2 percent decrease in operating costs
between the comparative years.
Our contract drilling operating margins decreased from 18 percent in
1998 to 14 percent in 1999. This reduction was generally due to decreases
during the first nine months of 1999 in both daily drilling rig revenue
rates and utilization and increases in operating costs. Total contract
drilling operating costs were up 9 percent in 1999 versus 1998 due to
increased labor costs and related benefit costs, including workers'
compensation.
Contract drilling depreciation increased 19 percent due to the impact
of higher depreciation per operating day associated with the newly acquired
Parker rigs. Depreciation, depletion and amortization ("DD&A") of our oil
and natural gas properties decreased 13 percent. Total DD&A was higher in
1998 due to the write down of Questa's oil and natural gas properties in
the third quarter of 1998, as discussed above. Decreases in production as
previously discussed also reduced DD&A in 1999. The average DD&A rate per
Mcfe increased 5 percent to $0.85 in 1999.
General and administrative expenses increased 4 percent as certain
employee benefit costs and outside services increased. Interest expense
increased 6 percent as our average outstanding debt increased 11 percent
during 1999. The average interest rate decreased from 7.1 percent in 1998
to 7.0 percent in 1999.
On May 3, 1999, our contract drilling offices in Moore, Oklahoma were
struck by a tornado destroying two buildings and damaging various vehicles
and drilling equipment. In May 1999, we received $500,000 of insurance
proceeds for the destroyed buildings, and as a result, in the second
quarter of 1999, we recognized a gain of $315,000 recorded as part of other
revenues.
31
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
- -------- ----------------------------------------------------------
Our operations are exposed to market risks primarily as a result of
changes in commodity prices and interest rates.
Commodity Price Risk - Our major market risk exposure is in the
pricing of our oil and natural gas production. The price we receive is
primarily driven by the prevailing worldwide price for crude oil and market
prices applicable to our natural gas production. Historically, prices we
have received for our oil and natural gas production have been volatile and
such volatility is expected to continue.
To reduce the impact of price fluctuations, we periodically use hedging
strategies to hedge the price we will receive for a portion of our future
oil and natural gas production. In the first quarter of 2000, we entered
into swap transactions in an effort to lock in a portion of our production
at the higher oil prices which currently existed. These transactions
applied to approximately 50 percent of our daily oil production covering
the period from April 1, 2000 to July 31, 2000 and 25 percent of our daily
oil production for August and September of 2000, at prices ranging from
$24.42 to $27.01. We have also entered into a collar contract for
approximately 25 percent of our daily production for the period covering
November 1, 2000 to February 28, 2001. The collar has a floor of $26.00
and a ceiling of $33.00 and we are receiving $0.86 per barrel for entering
into the collar transaction. During 2000, the sum of these hedging
transactions yielded a reduction in our oil revenues of $465,000.
Interest Rate Risk - Our interest rate exposure relates to our long-
term debt, all of which bears interest at variable rates based on the prime
rate or the London Interbank Offered Rate ("Libor rate"). At our election,
borrowings under our revolving credit and term loan may be fixed at the
Libor rate for periods up to 180 days. Historically, we have not utilized
any financial instruments, such as interest rate swaps, to attempt to
manage the exposure to increases in interest rates. However, we may
consider the use of such financial instruments in the future based on our
assessment of future interest rates. The impact on annual cash flow before
taxes of a one percent change in the floating rate based on our average
outstanding long-term debt in 2000 would have been approximately $628,000.
32
Item 8. Financial Statements and Supplementary Data
- ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
----------------------
1999 2000
---------- ----------
Restated,
See Note 2)
(In thousands)
ASSETS
- ------
Current Assets:
Cash and cash equivalents $ 2,647 $ 726
Accounts receivable (less allowance for
doubtful accounts of $583 and $919) 22,070 40,220
Materials and supplies 3,259 3,802
Prepaid expenses and other 2,510 1,269
---------- ----------
Total current assets 30,486 46,017
---------- ----------
Property and Equipment:
Drilling equipment 177,238 196,736
Oil and natural gas properties, on
the full cost method 312,269 349,707
Transportation equipment 3,502 5,803
Other 7,694 8,801
---------- ----------
500,703 561,047
Less accumulated depreciation, depletion,
amortization and impairment 241,649 270,690
---------- ----------
Net property and equipment 259,054 290,357
---------- ----------
Other Assets 6,027 9,914
---------- ----------
Total Assets $ 295,567 $ 346,288
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
33
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
----------------------
1999 2000
---------- ----------
(Restated,
See Note 2)
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
- -----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities $ 2,027 $ 1,627
Accounts payable 14,682 21,012
Accrued liabilities 8,517 9,854
Contract advances 358 179
---------- ----------
Total current liabilities 25,584 32,672
---------- ----------
Long-Term Debt 67,239 54,000
---------- ----------
Other Long-Term Liabilities (Note 4) 2,325 3,597
---------- ----------
Deferred Income Taxes 20,914 41,479
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value,
5,000,000 shares authorized, none issued - -
Common stock, $.20 par value,
40,000,000 and 75,000,000 shares
authorized, 35,641,307 and 35,768,344
shares issued, respectively 7,128 7,154
Capital in excess of par value 139,207 139,872
Retained earnings 33,170 67,514
---------- ----------
Total shareholders' equity 179,505 214,540
---------- ----------
Total Liabilities and Shareholders' Equity $ 295,567 $ 346,288
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
34
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
-------------------------------------
1998 1999 2000
---------- ---------- ----------
(Restated, (Restated,
See Note 2) See Note 2)
(In thousands except per share amounts)
Revenues:
Contract drilling $ 53,528 $ 55,479 $ 108,075
Oil and natural gas 43,346 46,225 92,016
Other 400 648 1,173
---------- ---------- ----------
Total revenues 97,274 102,352 201,264
---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 43,729 47,721 84,051
Depreciation 5,766 6,851 11,999
Oil and natural gas:
Operating costs 15,464 15,084 19,754
Depreciation, depletion,
amortization and
impairment 19,564 17,114 18,492
General and administrative 5,543 5,750 6,560
Interest 4,950 5,268 5,136
---------- ---------- ----------
Total expenses 95,016 97,788 145,992
---------- ---------- ----------
Income Before Income Taxes 2,258 4,564 55,272
---------- ---------- ----------
Income Tax Expense:
Current 214 29 621
Deferred 616 1,487 20,307
---------- ---------- ----------
Total income taxes 830 1,516 20,928
---------- ---------- ----------
Net Income $ 1,428 $ 3,048 $ 34,344
========== ========== ==========
Net Income Per Common Share:
Basic $ .05 $ .10 $ .96
========== ========== ==========
Diluted $ .05 $ .10 $ .95
========== ========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
35
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1998, 1999 and 2000
(1998 and 1999 Restated, See Note 2)
Capital
In
Excess
Common Of Par Retained Treasury
Stock Value Earnings Stock Total
-------- ---------- --------- -------- ----------
(In thousands)
Balances,
January 1, 1998 $ 5,468 $ 81,837 $ 28,694 $ (156) $ 115,843
Net income - - 1,428 - 1,428
Activity in employee
compensation plans
(48,329 shares) 10 144 - 156 310
Retirement of Shares - (58) - - (58)
Purchase of treasury
Stock (25,000
shares) - - - (131) (131)
Questa purchase of
treasury shares - (8) - - (8)
-------- ---------- --------- -------- ----------
Balances,
December 31, 1998 5,478 81,915 30,122 (131) 117,384
Net income - - 3,048 - 3,048
Activity in employee
compensation plans
(252,511 shares) 50 680 - 131 861
Sale of Common Stock
(7,000,000 shares) 1,400 48,682 - - 50,082
Issuance of stock for
acquisition
(1,000,000
shares) 200 7,938 - - 8,138
Questa purchase of
treasury shares - (8) - - (8)
-------- ---------- --------- -------- ----------
Balances,
December 31, 1999 7,128 139,207 33,170 - 179,505
Net income - - 34,344 - 34,344
Activity in employee
compensation plans
(135,419 shares) 26 665 - - 691
-------- ---------- --------- -------- ----------
Balances,
December 31, 2000 $ 7,154 $ 139,872 $ 67,514 $ - $ 214,540
======== ========== ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
36
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------
1998 1999 2000
---------- ---------- ----------
(Restated, (Restated,
See Note 2) See Note 2)
(In thousands)
Cash Flows From Operating
Activities:
Net Income $ 1,428 $ 3,048 $ 34,344
Adjustments to reconcile
net income to net cash
provided (used) by
operating activities:
Depreciation, depletion,
amortization and
impairment 25,681 24,285 30,946
Loss (gain) on disposition
of assets 17 (400) (969)
Employee stock compensation
plans 561 436 443
Bad debt expense - 255 350
Deferred tax expense 616 1,487 20,307
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 6,425 (8,450) (18,500)
Materials and supplies 244 49 (543)
Prepaid expenses and other (441) 140 (96)
Accounts payable 882 2,667 (1,370)
Accrued liabilities 60 1,590 3,067
Contract advances 205 48 (179)
Other liabilities (447) (442) (440)
---------- ---------- ----------
Net cash provided by
operating activities 35,231 24,713 67,360
---------- ---------- ----------
The accompanying notes are an integral part of the
consolidated financial statements
37
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
------------------------------------
1998 1999 2000
---------- ---------- ----------
(Restated, (Restated,
See Note 2) See Note 2)
(In thousands)
Cash Flows From Investing
Activities:
Capital expenditures (including
producing property
acquisitions $ (56,290) $ (69,503) $ (60,447)
Proceeds from disposition of
property and equipment 964 1,438 4,259
(Acquisition) disposition
of other assets (93) 91 (2,656)
---------- ---------- ----------
Net cash used in
investing activities (55,419) (67,974) (58,844)
---------- ---------- ----------
Cash Flows From Financing
Activities:
Borrowings under line of credit 53,475 61,600 31,200
Payments under line of credit (32,900) (68,400) (44,439)
Net payments on notes payable
and other long-term debt (495) (1,090) (556)
Proceeds from sale of
common stock (21) 50,136 250
Book overdrafts (Note 1) - 2,974 3,108
Acquisition of treasury stock (131) - -
---------- ---------- ----------
Net cash provided by
(used in) financing
activities 19,928 45,220 (10,437)
---------- ---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (260) 1,959 (1,921)
Cash and Cash Equivalents,
Beginning of Year 948 688 2,647
---------- ---------- ----------
Cash and Cash Equivalents,
End of Year $ 688 $ 2,647 $ 726
========== ========== ==========
Supplemental Disclosure of Cash
Flow Information:
Cash paid during the year for:
Interest $ 4,199 $ 5,850 $ 5,135
Income taxes $ 617 $ 30 $ 519
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the
consolidated financial statements
38
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Principles of Consolidation
The consolidated financial statements include the accounts of Unit
Corporation and its directly and indirectly wholly owned subsidiaries
("Unit"). The investment in limited partnerships is accounted for on the
proportionate consolidation method, whereby Unit's share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business
Unit is engaged in the land contract drilling of natural gas and oil
wells and the exploration, development, acquisition and production of oil
and natural gas properties. Unit's current contract drilling operations
are focused primarily in the natural gas producing provinces of the
Oklahoma and Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf
Coast and the Rocky Mountain regions. Unit's primary exploration and
production operations are also conducted in the Anadarko and Arkoma Basins
and in the Texas Gulf Coast area with additional properties in the Permian
Basin. The majority of its contact drilling and exploration and production
activities are oriented toward drilling for and producing natural gas. At
December 31, 2000, Unit had an interest in a total of 2,951 wells and
served as operator of 667 of those wells. Unit provides land contract
drilling services for a wide range of customers using the drilling rigs,
which it owns and operates. In 2000, all of Unit's 47 rigs owned
throughout the year 2000 were in operation. Unit acquired another rig at
the end of the year and two more rigs were under construction, making the
total rig count 50, at December 31, 2000.
Drilling Contracts
Unit recognizes revenues generated from "daywork" drilling contracts
as the services are performed, which is similar to the percentage of
completion method. Under "footage" and "turnkey" contracts, Unit bears the
risk of completion of the well therefore, revenues and expenses are
recognized using the completed contract method. The duration of all three
types of contracts range typically from 20 to 90 days. The entire amount
of a loss, if any, is recorded when the loss is determinable. The costs of
uncompleted drilling contracts include expenses incurred to date on
"footage" or "turnkey" contracts, which are still in process at the end of
the period, and are included in other current assets.
39
Cash Equivalents and Book Overdrafts
Unit includes as cash equivalents, certificates of deposits and all
investments with maturities at date of purchase of three months or less
which are readily convertible into known amounts of cash. Book overdrafts
are checks that have been issued prior to the end of the period, but not
presented to Unit's bank for payment prior to the end of the period. At
December 31, 1999 and 2000, book overdrafts of $3.0 million and $6.1
million have been included in accounts payable.
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. Renewals and betterments are capitalized
while repairs and maintenance are expensed. Depreciation of drilling
equipment is recorded using the units-of-production method based on
estimated useful lives, including a minimum provision of 20 percent of the
active rate when the equipment is idle. Unit uses the composite method of
depreciation for drill pipe and collars and calculates the depreciation by
footage actually drilled compared to total estimated remaining footage.
Depreciation of other property and equipment is computed using the straight-
line method over the estimated useful lives of the assets ranging from 3 to
15 years.
Realization of the carrying value of property and equipment is
reviewed for possible impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable.
Assets are determined to be impaired if a forecast of undiscounted
estimated future net operating cash flows directly related to the asset
including disposal value if any, is less than the carrying amount of the
asset. If any asset is determined to be impaired, the loss is measured as
the amount by which the carrying amount of the asset exceeds its fair
value. An estimate of fair value is based on the best information
available, including prices for similar assets. Changes in such estimates
could cause Unit to reduce the carrying value of property and equipment.
When property and equipment components are disposed of, the cost and
the related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For
dispositions of drill pipe and drill collars, an average cost for the
appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.
40
Goodwill
Goodwill represents the excess of the cost of the acquisition of
Hickman Drilling Company over the fair value of the net assets acquired and
is being amortized on the straight-line method over 25 years. Goodwill is
evaluated periodically for impairment, when it appears an impairment may
have occurred. If an impairment is determined, the amount of such
impairment is calculated based on the estimated fair market value of the
related assets. Net goodwill reported in other assets at December 31, 1999
and 2000 was $5,575,000 and $5,331,000, respectively with accumulated
amortization at December 31, 1999 and 2000 of $507,000 and $750,000,
respectively.
Oil and Natural Gas Operations
Unit accounts for its oil and natural gas exploration and development
activities on the full cost method of accounting prescribed by the
Securities and Exchange Commission ("SEC"). Accordingly, all productive
and non-productive costs incurred in connection with the acquisition,
exploration and development of oil and natural gas reserves are capitalized
and amortized on a composite units-of-production method based on proved oil
and natural gas reserves. Unit capitalizes internal costs that can be
directly identified with its acquisition, exploration and development
activities. Independent petroleum engineers annually review Unit's
determination of its oil and natural gas reserves. The average composite
rates used for depreciation, depletion and amortization ("DD&A") were
$0.81, $0.85 and $0.82 per Mcfe in 1998, 1999 and 2000, respectively. The
calculation of DD&A includes estimated future expenditures to be incurred
in developing proved reserves and estimated dismantlement and abandonment
costs, net of estimated salvage values. Unit's unproved properties
totaling $11.0 million are excluded from the DD&A calculation. In the
event the unamortized cost of oil and natural gas properties being
amortized exceeds the full cost ceiling, as defined by the SEC, the excess
is charged to expense in the period during which such excess occurs. The
full cost ceiling is based principally on the estimated future discounted
net cash flows from Unit's oil and natural gas properties. As discussed in
Note 12, such estimates are imprecise. As part of the merger with Questa,
the oil and gas properties of Questa were restated from the successful
effort method of accounting to the full cost method of accounting used by
Unit Corporation. As part of this restatement, in 1998, the value of
Questa's oil and natural gas properties were impaired due to low prices at
the end of the third quarter of 1998; therefore, the properties were
written down $2.6 million.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties
in which Unit has an interest or on properties in which a partnership, of
which Unit is a general partner, has an interest. Accordingly, in 1998 and
2000, Unit recorded $437,000 and $179,000 of contract drilling profits,
respectively, as a reduction of the carrying value of its oil and natural
41
gas properties rather than including these profits in current operations.
No contract drilling profits were realized on such interests in 1999.
Limited Partnerships
Unit's wholly owned subsidiary, Unit Petroleum Company, is a general
partner in sixteen oil and natural gas limited partnerships sold privately
and publicly. Some of Unit's officers, directors and employees own the
interests in most of these partnerships. Unit's wholly owned subsidiary,
Questa Oil and Gas Co., is a general partner in two additional oil and
natural gas limited partnerships sold privately. Unit shares partnership
revenues and costs in accordance with formulas prescribed in each limited
partnership agreement. The partnerships also reimburse Unit for certain
administrative costs incurred on behalf of the partnerships.
Income Taxes
Measurement of current and deferred income tax liabilities and assets
is based on provisions of enacted tax law; the effects of future changes in
tax laws or rates are not included in the measurement. Valuation
allowances are established where necessary to reduce deferred tax assets to
the amount expected to be realized. Income tax expense is the tax payable
for the year and the change during that year in deferred tax assets and
liabilities.
Natural Gas Balancing
Unit uses the sales method for recording natural gas sales. This
method allows for recognition of revenue, which may be more or less than
our share of pro-rata production from certain wells. Based upon the 2000
average natural gas price received of $3.91 per Mcf, Unit estimates its
balancing position to be approximately $6.9 million on under-produced
properties and approximately $6.0 million on over-produced properties.
Unit's policy is to expense the pro-rata share of lease operating costs
from all wells as incurred. Such expenses relating to the balancing
position on wells in which Unit has imbalances are not material.
Employee and Director Stock Based Compensation
Unit applies APB Opinion 25 in accounting for its stock option plans
for its employees and directors. Under this standard, no compensation
expense is recognized for grants of options, which include an exercise
price equal to or greater than the market price of the stock on the date of
grant. Accordingly, based on Unit's grants in 1998, 1999 and 2000 no
compensation expense has been recognized. As provided by Financial
Accounting Standard No. 123 "Accounting for Stock-Based Compensation," Unit
has disclosed the pro forma effects of recording compensation for such
option grants based on fair value in Note 6 to the financial statements.