Back to GetFilings.com
F O R M 1 0-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
-------- ----------
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
--------------- -----
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange
------------------- on which registered
Common Stock, par value -------------------
$.20 per share New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes _X_ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in PART III of this
Form 10-K or any amendment to this Form 10-K. ___
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
Yes _X_ No ___
-
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on June 30, 2003 - $669,121,359
Number of Shares of Common Stock
Outstanding on March 11, 2004 - 45,709,568
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 5, 2004 are incorporated by reference in
Part III.
Exhibit Index - See Page 113
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 2
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 2
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 26
Item 4. Submission of Matters to a Vote of Security Holders . . 26
PART II
Item 5. Market for the Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of
Equity Securities . . . . . . . . . . . . . . . . . . 27
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 28
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . 29
Item 7a. Quantitative and Qualitative Disclosure about
Market Risk . . . . . . . . . . . . . . . . . . . . . 47
Item 8. Financial Statements and Supplementary Data . . . . . . 48
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . 104
Item 9a. Controls and Prodedures . . . . . . . . . . . . . . . . 104
PART III
Item 10. Directors and Executive Officers of the Registrant. . . 105
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 105
Item 12. Security Ownership of Certain Beneficial Owners,
Management and Related Shareholder Matters. . . . . . 105
Item 13. Certain Relationships and Related Transactions. . . . . 105
Item 14. Principal Accounting Fees and Services. . . . . . . . . 105
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 105
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
1
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2003
PART I
Item 1. Business and Item 2. Properties
- ------- -------- ------- ----------
OUR BUSINESS
Through our two principal wholly owned subsidiaries, Unit Drilling Company
and Unit Petroleum Company, 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 own account.
We were founded in 1963 as a contract drilling company.
Our executive offices are at 1000 Kensington Tower, 7130 South Lewis,
Tulsa, Oklahoma 74136; our telephone number is (918) 493-7700.
Our primary Internet address is www.unitcorp.com. We make our periodic SEC
Reports (Forms 10-Q and Forms 10-K) and current reports (Form 8-K) available
free of charge through our Web site as soon as reasonably practicable after they
are filed electronically with the SEC. In addition, we post on our Web site
copies of the various corporate governance documents that we have adopted. We
may from time to time provide important disclosures to investors by posting them
in the investor relations section of our Web site, as allowed by SEC rules.
Materials we file with the SEC may be read and copied at the SEC's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Information on
the operation of the Public Reference Room may be obtained by calling the SEC at
1-800-SEC-0330. The SEC also maintains an Internet Web site at www.sec.gov that
contains reports, proxy and information statements, and other information
regarding our company that we file electronically with the SEC.
When used in this report, the terms Corporation, Company, Unit, our, we and
its refer to Unit Corporation and, as appropriate, Unit Corporation and/or one
or more of its subsidiaries.
OUR LAND CONTRACT DRILLING BUSINESS
General. Using our 88 drilling rigs, our wholly owned subsidiary, Unit Drilling
Company, drills onshore natural gas and oil wells for a wide range of customers.
Our drilling operations are mainly in the Oklahoma and Texas areas of the
Anadarko and Arkoma Basins, the Texas Gulf Coast and in the East Texas and Rocky
Mountain regions.
2
The following table sets forth, for each of the periods indicated, certain
information concerning our contract drilling operations:
Year Ended December 31,
--------------------------------------------------
1999 2000 2001 2002 2003
------ ------ ------ ------ ------
Number of Rigs
Owned at End
of Period 47.0 50.0 55.0 75.0 88.0
Average Number
of Rigs Owned
During Period 37.3 47.0 51.8 61.6 75.9
Average Number
of Rigs
Utilized 23.1 39.8 46.3 39.1 62.9
Utilization
Rate (1) 62% 85% 90% 63% 83%
Average Revenue
Per Day (2) $6,582 $7,432 $9,879 $8,285 $7,972
Total Footage
Drilled
(Feet in
1000's) 2,211 3,650 4,008 3,829 6,580
Number of Wells
Drilled 197 316 361 318 530
---------------
(1) We determine our utilization rate on a 365 day year by dividing the number
of rigs used by our total number of rigs.
(2) Represents total revenues from contract drilling operations divided by the
total number of days rigs were used during the period.
Acquisitions. On December 8, 2003, we acquired SerDrilco Incorporated and its
subsidiary, Service Drilling Southwest LLC, a U.S. land drilling company located
in Borger, Texas for $35.0 million in cash. The terms of the acquisition include
an earn-out provision allowing the sellers to obtain one-half of the cash flow
in excess of $10 million for each of the three years following the acquisition.
SerDrilco, a private, Tulsa-based drilling company, has been operating in the
Anadarko Basin in the Texas Panhandle for more than 50 years. Equipment acquired
through the SerDrilco acquisition includes 12 rigs which range from 650
horsepower to 1,700 horsepower with depth capacities rated from 6,500 feet to
18,000 feet, a fleet of 12 trucks and a district office and equipment yard in
and near Borger, Texas.
During November of 2003, we completed the construction of a 1,500
horsepower diesel electric rig with a depth capacity of 20,000 feet. The rig is
operating for our Mid-Continent Division in Western Oklahoma.
3
Description of our Drilling Rigs. A land drilling rig consists, in part, of
engines, drawworks or hoists, derrick or mast, substructure, pumps to circulate
the drilling fluid, blowout preventers and drill pipe. Over the life of a
typical rig, due to the normal wear and tear of operating 24 hours a day,
several of the major components, such as engines, mud pumps and drill pipe, must
be replaced or rebuilt on a periodic basis. Other components, such as the
substructure, mast and drawworks, can be used for extended periods of time with
proper maintenance. We also own additional equipment used in the operation of
our rigs, including large air compressors, trucks and other support equipment.
Our rigs have maximum depth capacities ranging from 9,500 to 40,000 feet.
The following table shows the current distribution of our rigs as of March
1, 2004:
Average
Rated
Contracted Idle Total Drilling
Region Rigs Rigs Rigs Depths(ft)
- ------------------ ----------- ------- ------- ----------
Anadarko Basin 59 1 60 16,000
Arkoma Basin 7 -- 7 16,000
East Texas and
Gulf Coast 13 -- 13 18,000
Rocky Mountains 8 -- 8 22,000
At present, we do not have a shortage of drilling rig related equipment.
However, at any given time, our ability to use all of our rigs is dependent on a
number of conditions, including the availability of qualified labor, drilling
supplies and equipment as well as demand. As utilization in the industry has
improved throughout most of 2003, it has become increasingly difficult to find
additional qualified labor for our drilling rigs. More opportunities for field
employees to find work in our regions of operation has increased the competition
for qualified labor among drilling contractor. If rig utilization remains at its
current rate or increases, we expect this competition for qualified labor will
continue to have an adverse effect on our drilling operations in the future and
result in higher operating costs.
Types of Drilling Contracts We Work Under. Our drilling contracts are
predominantly obtained through competitive bidding and are for a single well.
Terms and payment rates vary depending on the nature and duration of the work,
the equipment and services supplied and other matters. We pay certain operating
expenses, including wages of drilling personnel,
4
maintenance expenses and incidental rig supplies and equipment. Usually the
contracts are subject to termination by the customer on short notice on payment
of a fee. Our contracts also contain provisions regarding indemnification
against certain types of claims involving injury to persons, property and for
acts of pollution. The specific terms of these indemnifications are subject to
negotiation on a contract by contract basis.
The type of contract used determines our compensation. The contracts are
generally one of three types: daywork; footage; or turnkey. Additional
compensation may be acquired for special risks and unusual conditions. Under
daywork contracts we provide the drilling rig with the required personnel to the
operator who then supervises the drilling of the well. Our compensation depends
on a negotiated rate for each day of the rig's use. Footage contracts usually
require us to bear some of the drilling costs in addition to providing the rig.
We are paid on a negotiated per foot drilled rate on completion of the well.
Under turnkey contracts we contract to drill the well for a lump sum amount to a
specified depth and provide most of the equipment and services required. We bear
the risk of drilling the well to the contract depth and are paid when the
contract provisions are completed.
Under turnkey contracts we may incur losses if we underestimate the
costs to drill the well or if unforeseen events occur. To date, we have not
experienced significant losses in performing turnkey contracts. In 2003, we
drilled six turnkey wells and turnkey revenue represented 1% of our contract
drilling revenues as compared to 15 turnkey wells and turnkey revenue
representing 4% for 2002. We did not have any turnkey contracts in progress at
December 31, 2003. Because market conditions as well as the desires of our
customers determine the use of turnkey contracts, we can't predict whether the
portion of drilling conducted on a turnkey basis will increase or decrease in
the future.
Customers. During 2003, 10 customers accounted for approximately 53% of our
total contract drilling revenues. Chesapeake Operating, Inc. was our largest
customer providing 15% of our total contract drilling revenues. Our contract
drilling operations drilled 43 wells in 2003 which were operated by our
exploration and production segment. These wells also have working interests
which are owned by limited partnerships for which we acted as general partner.
As required by the Securities and Exchange Commission, the profit received by
our contract drilling segment of $841,000 and $1,883,000 during 2002 and 2003,
respectively, was used to reduce the carrying value of our oil and natural gas
properties rather than being included in our profits in current operations.
Additional Information. Further information relating to contract drilling
operations can be found in Notes 1, 2 and 10 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
5
OUR OIL AND NATURAL GAS BUSINESS
General. In 1979 we began to develop our exploration and production operations
to diversify our contract drilling revenues. Today, our wholly owned subsidiary
conducts our exploration and production activities. Our producing oil and
natural gas properties, undeveloped leaseholds and related assets are mainly in
Oklahoma, Texas, Louisiana and New Mexico and, to a lesser extent, in Arkansas,
North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi, Illinois,
Michigan, Nebraska and Canada.
The following table presents certain information regarding the company's
oil and gas operations as of December 31, 2003.
Average Daily
Production
-----------------------
Number of
Gross Number of
Property/Area Wells Net Wells Mcf Bbls
------------- ---------- ---------- ---------- ----------
Western Division
(includes the Rocky
Mountain Region,
New Mexico, Western
and Southern Texas
and the Gulf Coast
Region) 981 254.44 13,600 880
East Division
(consists principally
of the Appalachian
Region, Arkansas,
parts of East Texas
and Eastern Oklahoma 553 146.04 17,100 40
Central Division
(consist principally
of Kansas, the rest
of Oklahoma and
Texas Panhandle
Areas) 1,794 427.91 25,800 480
Canada 65 1.63 100 --
---------- ---------- ---------- ----------
Total 3,393 830.02 56,600 1,400
========== ========== ========== ==========
When we are the operator of a property, we generally employ our own
drilling rigs.
6
Acquisition. On January 30, 2004, we acquired the outstanding common stock
of PetroCorp Incorporated for $182.1 million in cash. PetroCorp Incorporated
explored and developed oil and natural gas properties primarily in Texas and
Oklahoma. Approximately 84% of the oil and natural gas properties acquired in
the acquisition are located in the Mid-Continent and Permian basins, while 6%
are located in the Rocky Mountains and 10% are located in the Gulf Coast basin.
The acquired properties increase our reserve base by approximately 56.7 billion
equivalent cubic feet of natural gas and provide additional locations for
development drilling in the future. With the acquisition of PetroCorp
Incorporated we also entered into a new $150 million credit facility to replace
our existing loan agreement as more fully discussed in Note 4 to the
Consolidated Financial Statements in Item 8 hereof.
Well and Leasehold Data. The tables below set forth certain information
regarding our oil and natural gas exploratory and development drilling
operations:
Year Ended December 31,
----------------------------------------------------------
2001 2002 2003
------------------ ------------------ ------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Wells Drilled:
- --------------
Exploratory:
Oil 1 .01 -- -- -- --
Natural gas 8 3.60 2 0.50 3 1.84
Dry 5 4.46 5 2.00 1 1.00
-------- -------- -------- -------- -------- --------
14 8.07 7 2.50 4 2.84
-------- -------- -------- -------- -------- --------
Development:
Oil 6 1.06 4 1.91 5 2.13
Natural gas 87 33.51 68 33.25 120 46.22
Dry 18 10.80 17 14.21 20 10.38
-------- -------- -------- -------- -------- --------
111 45.37 89 49.37 145 58.73
-------- -------- -------- -------- -------- --------
Total 125 53.44 96 51.87 149 61.57
======== ======== ======== ======== ======== ========
7
Year Ended December 31,
----------------------------------------------------------
2001 2002 2003
------------------ ------------------ ------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Oil and Natural
Gas Wells
Producing or
Capable of
Producing:
- ---------------
Oil - USA 786 279.06 790 273.34 803 280.40
Oil -
Canada -- -- -- -- -- --
Gas - USA 2,188 457.38 2,449 524.45 2,525 547.99
Gas -
Canada 64 1.60 65 1.63 65 1.63
-------- -------- -------- -------- -------- --------
Total 3,038 738.04 3,304 799.42 3,393 830.02
======== ======== ======== ======== ======== ========
On March 1, 2004, we were participating in the drilling of 14 gross (7.1
net) wells in the United States.
Cost incurred for development drilling includes $9.7 million, $10.8 million
and $20.4 million in 2001, 2002 and 2003, respectively, to develop booked proved
undeveloped reserves.
8
The following table summarizes our oil and natural gas leasehold acreage
for each of the years indicated:
Developed Undeveloped
Acreage Acreage
--------------------- ---------------------
Gross Net Gross Net
--------- --------- --------- ---------
2001:
- -----
USA 567,731 155,890 110,489 69,229
Canada 39,040 976 7,273 3,636
--------- --------- --------- ---------
Total 606,771 156,866 117,762 72,865
========= ========= ========= =========
2002:
- -----
USA 585,313 166,397 142,764 79,911
Canada 39,040 976 5,441 3,360
--------- --------- --------- ---------
Total 624,353 167,373 148,205 83,271
========= ========= ========= =========
2003(1):
- -------
USA 600,872 173,674 159,663 90,862
Canada 39,040 976 4,162 2,624
--------- --------- --------- ---------
Total 639,912 174,650 163,825 93,486
========= ========= ========= =========
- ----------------
(1) Approximately 80% of the net undeveloped acres are covered by leases that
will expire in each of the years 2004 - 2006 unless drilling or production
otherwise extends the terms of the leases.
Future development costs estimated to be expended to develop our proved
undeveloped reserves in the USA in 2004, 2005 and 2006, as disclosed in our
December 31, 2003 reserve report, are $33.8 million, $29.3 million and $3.3
million, respectively. No similar future development costs have been estimated
for Canada.
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 years indicated:
Year Ended December 31,
----------------------------------
2001 2002 2003
---------- ---------- ----------
Average Sales Price per Barrel of Oil
Produced:
USA price before hedging $ 23.58 $ 21.54 $ 26.94
Effect of hedging 0.04 -- --
---------- ---------- ----------
USA price including hedging $ 23.62 $ 21.54 $ 26.94
========== ========== ==========
Canada $ -- $ -- $ --
========== ========== ==========
Average Sales Price per Mcf of Natural
Gas Produced:
USA price before hedging $ 3.89 $ 2.87 $ 4.87
Effect of hedging 0.11 -- --
---------- ---------- ----------
USA price including hedging $ 4.00 $ 2.87 $ 4.87
========== ========== ==========
Canada price before hedging $ 4.21 $ 2.11 $ 4.49
Effect of hedging -- -- --
---------- ---------- ----------
Canada price including hedging $ 4.21 $ 2.11 $ 4.49
========== ========== ==========
Oil Production (Mbbls):
USA 492 473 516
Canada -- -- --
---------- ---------- ----------
Total 492 473 516
========== ========== ==========
Natural Gas Production (MMcf):
USA 18,819 18,927 20,610
Canada 45 41 38
---------- ---------- ----------
Total 18,864 18,968 20,648
========== ========== ==========
10
Average Production Cost per
Equivalent Mcf:
USA $ 0.86 $ 0.79 $ 0.90
Canada $ 0.51 $ 0.60 $ 0.56
Oil and Natural Gas Reserves. The following table sets forth our estimated
proved developed and undeveloped oil and natural gas reserves for each of the
years indicated:
Year Ended December 31,
----------------------------------
2001 2002 2003
---------- ---------- ----------
Oil (Mbbls):
USA 4,343 4,096 5,141
Canada -- -- --
---------- ---------- ----------
Total 4,343 4,096 5,141
========== ========== ==========
Natural gas (MMcf):
USA 227,865 244,494 253,542
Canada 389 317 650
---------- ---------- ----------
Total 228,254 244,811 254,192
========== ========== ==========
Our oil production is sold at or near our wells under purchase contracts at
prevailing prices in accordance with arrangements customary in the oil industry.
Our natural gas production is sold to intrastate and interstate pipelines as
well as to independent marketing firms under contracts with terms generally
ranging from one month to a year. Most of these contracts contain provisions for
readjustment of price, termination and other terms customary in the industry.
Additional Information. Further information relating to oil and natural gas
operations can be found in Notes 1, 10, 12 and 13 of Notes to Consolidated
Financial Statements set forth in Item 8 hereof.
VOLATILE NATURE OF OUR BUSINESS
The prevailing prices for natural gas and oil significantly affect our
revenues, operating results, cash flow and future rate of growth. Because
natural gas makes up the biggest part of our oil and natural gas reserves as
well as the focus of most of the drilling work we do for others, changes in
natural gas prices have a larger impact on us than changes in oil prices.
Historically, oil and natural gas prices have been volatile, and we expect them
to continue to be so.
11
The following table shows the highest and lowest average monthly natural
gas and oil price we received by quarter for each of the periods indicated:
Average Monthly Average Monthly
Natural Gas Price per Mcf Oil Price per Bbl
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
2001:
First $ 9.35 $ 4.82 $ 28.13 $ 26.20
Second $ 4.92 $ 3.69 $ 26.63 $ 23.78
Third $ 3.45 $ 2.05 $ 24.66 $ 23.35
Fourth $ 2.42 $ 2.08 $ 18.99 $ 16.28
2002:
First $ 2.11 $ 1.87 $ 19.60 $ 15.58
Second $ 3.03 $ 2.98 $ 23.44 $ 22.07
Third $ 2.97 $ 2.47 $ 23.57 $ 23.01
Fourth $ 3.95 $ 3.35 $ 25.59 $ 21.90
2003:
First $ 8.38 $ 4.18 $ 32.72 $ 27.74
Second $ 5.59 $ 4.22 $ 27.10 $ 24.56
Third $ 4.63 $ 4.36 $ 27.41 $ 23.62
Fourth $ 5.06 $ 4.06 $ 27.48 $ 26.31
Prices for oil and natural gas are subject to wide fluctuations in response
to relatively minor changes in the supply of and demand for oil and natural gas,
market uncertainty and a variety of additional factors that are beyond our
control. These factors include:
. political conditions in oil producing regions, including the Middle
East;
. the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
. the price of foreign imports;
. actions of governmental authorities;
. the domestic and foreign supply of oil and natural gas;
. the level of consumer demand;
. United States storage levels of natural gas; . the ability to transport
to key markets;
12
. weather conditions;
. domestic and foreign government regulations;
. the price, availability and acceptance of alternative fuels; and
. overall economic conditions.
These factors and the volatile nature of the energy markets make it
impossible to predict with any certainty the future prices of oil and natural
gas.
Our contract drilling operations are dependent on the level of demand in
our operating markets. Both short-term and long-term trends in oil and natural
gas prices affect demand. Because oil and natural gas prices are volatile, the
level of demand for our services can also be volatile. Natural gas prices
started to fall in February, 2001. As a result, we started to receive less
demand for our drilling rigs starting in October, 2001 and the rates received
for our rigs also began to fall until they reached a low of $7,275 per day in
February of 2003. As natural gas and oil prices once again began to rise during
the last half of 2002 and in the second quarter of 2003 through the remainder of
the year both demand for our rigs and dayrates began to improve. In December
2003, the average dayrate of the 76 drilling rigs that we owned prior to the
SerDrilco acquisition was approximately $8,200 per day. The 12 rigs added in
December 2003 had a dayrate of approximately $7,500 resulting in an average
dayrate of $8,130 for all 88 rigs in December 2003. Since short-term and
long-term trends in oil and natural gas prices affect the demand for our rigs,
future demand and dayrates received for our drilling services is uncertain.
13
COMPETITION
All of our businesses are highly competitive. Competition in onshore
contract drilling traditionally involves such factors as price, efficiency,
condition of equipment, availability of labor and equipment, reputation and
customer relations. Some of our competitors in the onshore contract drilling
business are substantially larger than we are and have appreciably greater
financial and other resources. The competitive environment within which we
operate is uncertain and price oriented.
Our oil and natural gas operations likewise encounter strong competition
from major oil companies, independent operators and others. Many of these
competitors have appreciably greater financial, technical and other resources
and have more experience in the exploration for and production of oil and
natural gas than we have.
OIL AND NATURAL GAS PROGRAMS AND CONFLICTS OF INTEREST
Unit Petroleum Company serves as the general partner of 10 oil and gas
limited partnerships. Four were formed for investment by third parties and six
(the employee partnerships) were formed to allow employees of Unit and its
subsidiaries and directors of Unit to participate in Unit Petroleum's oil and
gas exploration and production operations. The partnerships for the third party
investments were formed in 1984, 1985 and 1986. An additional third party
partnership, the 1979 Oil and Gas Limited Partnership was dissolved on July 1,
2003. Employee partnerships have been formed for each year beginning with 1984.
The employee partnerships formed in 1984 through 1990 were consolidated
into a single consolidating partnership in 1993 and the employee partnerships
formed in 1991 through 1999 were also consolidated into the consolidating
partnership in 2002. The consolidation of the 1991 through the 1999 employee
partnerships at the end of last year was done by the general partners under the
authority contained in the respective partnership agreements and did not involve
any vote, consent or approval by the limited partners. The employee partnerships
have each had a set annual percentage (ranging from 1% to 15%) of our interest
in most of the oil and natural gas wells we drill or acquire for our own account
during the particular year for which the partnership was formed. The total
interest the employees have in our oil and natural gas wells by participating in
these partnerships does not exceed one percent.
Under the terms of our partnership agreements, the general partner has
broad discretionary authority to manage the business and operations of the
partnership, including the authority to make decisions on such matters as the
partnership's participation in a drilling location or a property acquisition,
the partnership's expenditure of funds and the distribution of funds to
partners. Because the business activities of the limited partners on the one
hand and the general partner on the other hand are not the same, conflicts of
interest will exist and it is not possible to entirely eliminate such conflicts.
Additionally, conflicts of interest may arise when we are the operator of an oil
and natural gas well and also provide contract drilling services. In such cases,
these drilling operations are under contracts containing terms and conditions
14
comparable to those contained in our drilling contracts with non-affiliated
operators. We believe we fulfill our responsibility to each contracting party
and comply fully with the terms of the agreements which regulate such conflicts.
These partnerships are further described in Notes 1 and 7 to Consolidated
Financial Statements set forth in Item 8 hereof.
EMPLOYEES
As of March 1, 2004, we had approximately 1,882 employees in our land
contract drilling operations, 70 employees in our oil and natural gas operations
and 60 in our general corporate area. None of our employees are members of a
union or labor organization nor have our operations ever been interrupted by a
strike or work stoppage. We consider relations with our employees to be
satisfactory.
OPERATING AND OTHER RISKS
Our drilling operations are subject to the many hazards inherent in the
drilling industry, including injury or death to personnel, blowouts, cratering,
explosions, fires, loss of well control, loss of hole, damaged or lost drilling
equipment and damage or loss from inclement weather. Our exploration and
production operations are also subject to many of these similar risks. Any of
these events could result in personal injury or death, damage to or destruction
of equipment and facilities, suspension of operations, environmental damage and
damage to the property of others.
Generally, our drilling contracts provide for the division of
responsibilities between us and our customer, and we seek to obtain
indemnification from our drilling customers for some of these risks. To the
extent that we are unable to transfer these risks to our drilling customers, we
seek protection through insurance. However, our insurance or our indemnification
agreements, if any, may not adequately protect us against liability from the
consequences of the hazards described above. In addition, even if we have
insurance coverage, we may still have a degree of exposure based on the amount
of our deductible. The occurrence of an event not fully insured or indemnified
against, or the failure of a customer to meet its indemnification obligations,
could result in substantial losses to us. In addition, we may not be able to
obtain insurance to cover any or all of these risks. Even if available, the
insurance might not be adequate to cover all of our losses, or we might decide
against obtaining that insurance because of high premiums or other costs.
Exploration and development operations involve numerous risks that may
result in dry holes, the failure to produce oil and natural gas in commercial
quantities and the inability to fully produce discovered reserves. The cost of
drilling, completing and operating wells is substantial and uncertain. Our
operations may be curtailed, delayed or cancelled as a result of many things
beyond our control, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
. adverse weather conditions;
15
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs or drilling
crews and the delivery of equipment.
A majority of the wells in which we own an interest are operated by other
parties. As a result, we have little control over the operations of such wells
which can act to increase our risk. Operators of these wells may act in ways
that are not in our best interests.
Our future performance depends upon our ability to find or acquire
additional oil and natural gas reserves that are economically recoverable. In
general, production from oil and natural gas properties declines as reserves
deplete, with the rate of decline depending on reservoir characteristics. Unless
we successfully replace the reserves that we produce, our reserves will decline,
resulting eventually in a decrease in our oil and natural gas production,
revenues and cash flow from operations. Historically, we have succeeded in
increasing reserves after taking production into account. However, it is
possible that we may not be able to continue to replace reserves. Low prices of
oil and natural gas may also limit the kinds of reserves that we can
economically develop. Lower prices also decrease our cash flow and may cause us
to decrease capital expenditures.
GOVERNMENTAL REGULATIONS
Various state and federal regulations affect the production and sale of oil
and natural gas. All states in which we conduct activities impose restrictions
on the drilling, production, transportation and sale of oil and natural gas.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission
(the "FERC") regulates the interstate transportation and the sale in interstate
commerce for resale of natural gas. The FERC's jurisdiction over interstate
natural gas sales has been substantially modified by the Natural Gas Policy Act
under which the FERC continued to regulate the maximum selling prices of certain
categories of gas sold in "first sales" in interstate and intrastate commerce.
Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act") deregulated natural gas prices for all "first sales" of natural
gas. Because "first sales" include typical wellhead sales by producers, all
natural gas produced from our natural gas properties is sold at market prices,
subject to the terms of any private contracts which may be in effect. The FERC's
jurisdiction over natural gas transportation is not affected by the Decontrol
Act.
Our sales of natural gas will be affected by intrastate and interstate gas
transportation regulation. Beginning in 1985, the FERC adopted regulatory
changes that have significantly altered the transportation and marketing of
natural gas. These changes are intended by the FERC to foster competition by,
among other things, transforming the role of interstate pipeline companies from
wholesale marketers of natural gas to the primary role of gas transporters. All
natural gas marketing by the pipelines is required to divest to a marketing
affiliate, which operates separately from
16
the transporter and in direct competition with all other merchants. As a
result of the various omnibus rulemaking proceedings in the late 1980s and the
individual pipeline restructuring proceedings of the early to mid-1990s, the
interstate pipelines must provide open and nondiscriminatory transportation and
transportation-related services to all producers, natural gas marketing
companies, local distribution companies, industrial end users and other
customers seeking service. Through similar orders affecting intrastate pipelines
that provide similar interstate services, the FERC expanded the impact of open
access regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (1) the large-scale divestiture
of interstate pipeline-owned gas gathering facilities to affiliated or
non-affiliated companies; (2) further development of rules governing the
relationship of the pipelines with their marketing affiliates; (3) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis; (4) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the
primary market; and (5) development of policy and promulgation of orders
pertaining to its authorization of market-based rates (rather than traditional
cost-of-service based rates) for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in the
relevant service market. We do not know what effect the FERC's other activities
will have on the access to markets, the fostering of competition and the cost of
doing business.
As a result of these changes, sellers and buyers of natural gas have gained
direct access to the particular pipeline services they need and are better able
to conduct business with a larger number of counter parties. We believe these
changes generally have improved the access to markets for natural gas while, at
the same time, substantially increasing competition in the natural gas
marketplace. We cannot predict what new or different regulations the FERC and
other regulatory agencies may adopt or what effect subsequent regulations may
have on production and marketing of natural gas from our properties.
In the past, Congress has been very active in the area of natural gas
regulation. However, as discussed above, the more recent trend has been in favor
of deregulation and the promotion of competition in the natural gas industry.
Thus, in addition to "first sales" deregulation, Congress also repealed
incremental pricing requirements and natural gas use restraints previously
applicable. There are other legislative proposals pending in the Federal and
State legislatures which, if enacted, would significantly affect the petroleum
industry. At the present time, it is impossible to predict what proposals, if
any, might actually be enacted by Congress or the various state legislatures and
what effect, if any, these proposals might have on the production and marketing
of natural gas by us. Similarly, and despite the trend toward federal
deregulation of the natural gas industry, whether or to what extent that trend
will continue or what the
17
ultimate effect will be on the production and marketing of natural gas by
us cannot be predicted.
Our sales of oil and natural gas liquids are not regulated and are at
market prices. The price received from the sale of these products will be
affected by the cost of transporting the products to market. Much of that
transportation is through interstate common carrier pipelines. Effective as of
January 1, 1995, the FERC implemented regulations generally grandfathering all
previously approved interstate transportation rates and establishing an indexing
system for those rates by which adjustments are made annually based on the rate
of inflation, subject to certain conditions and limitations. These regulations
may tend to increase the cost of transporting oil and natural gas liquids by
interstate pipeline, although the annual adjustments may result in decreased
rates in a given year. These regulations have generally been approved on
judicial review. Every five years, the FERC will examine the relationship
between the annual change in the applicable index and the actual cost changes
experienced by the oil pipeline industry. We are not able to predict with
certainty what effect, if any, these relatively new federal regulations or the
periodic review of the index by the FERC will have on us.
Federal, state, and local agencies have promulgated extensive rules and
regulations applicable to our oil and natural gas exploration, production and
related operations. Oklahoma, Texas and other states require permits for
drilling operations, drilling bonds and the filing of reports concerning
operations and impose other requirements relating to the exploration of oil and
natural gas. Many states also have statutes or regulations addressing
conservation matters including provisions for the unitization or pooling of oil
and natural gas properties, the establishment of maximum rates of production
from oil and natural gas wells and the regulation of spacing, plugging and
abandonment of such wells. The statutes and regulations of some states limit the
rate at which oil and natural gas is produced from our properties. The federal
and state regulatory burden on the oil and natural gas industry increases our
cost of doing business and affects its profitability. Because these rules and
regulations are amended or reinterpreted frequently, we are unable to predict
the future cost or impact of complying with those laws.
SAFE HARBOR STATEMENT
This report, including information included in, or incorporated by
reference from, future filings by us with the SEC, as well as information
contained in written material, press releases and oral statements issued by or
on behalf of us, contain, or may contain, certain statements that are
"forward-looking statements" within the meaning of federal securities laws. All
statements, other than statements of historical facts, included or incorporated
by reference in this report, which address activities, events or developments
which we expect or anticipate will or may occur in the future are
forward-looking statements. The words "believes," "intends," "expects,"
"anticipates," "projects," "estimates," "predicts" and similar expressions are
used to identify forward-looking statements.
18
These forward-looking statements include, among others, such things as:
. the amount and nature of our future capital expenditures;
. wells to be drilled or reworked;
. prices for oil and gas;
. demand for oil and gas;
. exploitation and exploration prospects;
. estimates of proved oil and gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and gas industry;
. business strategy;
. production of oil and gas reserves;
. expansion and growth of our business and operations; and
. drilling rig utilization and drilling rig rates.
These statements are based on certain assumptions and analyses made by us
in light of our experience and our perception of historical trends, current
conditions and expected future developments as well as other factors we believe
are appropriate in the circumstances. However, whether actual results and
developments will conform to our expectations and predictions is subject to a
number of risks and uncertainties which could cause actual results to differ
materially from our expectations, including:
. the risk factors discussed in this annual report and in the documents we
incorporate by reference;
. general economic, market or business conditions;
. the nature or lack of business opportunities that we pursue;
. demand for our land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
You should not place undue reliance on any of these forward-looking
statements. We disclaim any current intention to update forward-looking
information and to release publicly the results of any future revisions we may
make to forward-looking statements to reflect events or circumstances after the
date of this report to reflect the occurrence of unanticipated events.
In order to provide a more thorough understanding of the possible effects
of some of these influences on any forward-looking statements made by us, the
following discussion outlines certain factors that in the future could cause our
consolidated results for 2004 and beyond to differ materially from those that
may be presented in any such forward-looking statement made by or on behalf of
us.
Commodity Prices. The prices we receive for our oil and natural gas production
have a direct impact on our revenues, profitability and our cash flow as well as
our ability to meet our projected financial and operational goals. The prices
for natural gas and crude oil are heavily dependent on a number of factors
beyond our control, including the demand for oil and/or natural gas; current
weather conditions in the continental United States
19
(which can greatly influence the demand for natural gas at any given time
as well as the price we receive for such natural gas; the amount and timing of
liquid natural gas imports; and the ability of current distribution systems in
the United States to effectively meet the demand for oil and/or natural gas at
any given time, particularly in times of peak demand which may result due to
adverse weather conditions. Oil prices are extremely sensitive to foreign
influences on political, social or economic underpinnings, any one of which
could have an immediate and significant effect on the price and supply of oil.
In addition, prices of both natural gas and oil are becoming more and more
influenced by trading on the commodities markets which, at times, has tended to
increase the volatility associated with these prices resulting, at times, in
large differences in such prices even on a month-to-month basis. All of these
factors, especially when coupled with the fact that much of our product prices
are determined on a daily basis, can, and at times do, lead to wide fluctuations
in the prices we receive.
Based on our 2003 production, a $.10 per Mcf change in what we receive for
our natural gas production would result in a corresponding $160,300 per month
($1,923,600 annualized) change in our pre-tax operating cash flow. A $1.00 per
barrel change in our oil price would have a $40,000 per month ($480,000
annualized) change in our pre-tax operating cash flow. During 2003,
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 and are more fully
discussed in the Management's Discussion and Analysis of Financial Condition and
Results of Operations in Item 7 hereof.
Drilling Customer Demand. Demand for our drilling services is dependent almost
entirely on the needs of third parties. Based on past history, such parties'
requirements are subject to a number of factors, independent of any subjective
factors, that directly impact the demand for our drilling rigs. These include
the availability of funds to such third parties to carry out their drilling
operations during any given time period which, in turn, are often subject to
downward revision based on decreases in the then current prices of oil and
natural gas. Many of our customers are small to mid-size oil and natural gas
companies whose drilling budgets tend to be susceptible to the influences of
current price fluctuations. Other factors that affect our ability to work our
drilling rigs are: the weather which, under adverse circumstances, can delay or
even cause the abandonment of a project by an operator; the competition faced by
us in securing the award of a drilling contract in a given area; our experience
and recognition in a new market area; and the availability of labor to run our
drilling rigs.
20
Uncertainty of Oil and Natural Gas Reserves. There are numerous uncertainties
inherent in estimating quantities of proved reserves and their values, including
many factors beyond our control. The reserve data included in this document
represent only estimates. Reservoir engineering is a subjective and inexact
process of estimating underground accumulations of oil and natural gas that
cannot be measured in an exact manner. Estimates of economically recoverable oil
and natural gas reserves depend on a number of variable factors, including
historical production from the area compared with production from other
producing areas, and assumptions concerning:
. the effects of regulations by governmental agencies;
. future oil and natural gas prices;
. future operating costs;
. severance and excise taxes;
. development costs; and
. workover and remedial costs.
Some or all of these assumptions may vary considerably from actual results.
For these reasons, estimates of the economically recoverable quantities of oil
and natural gas attributable to any particular group of properties,
classifications of those reserves based on risk of recovery, and estimates of
the future net cash flows from reserves prepared by different engineers or by
the same engineers but at different times may vary substantially. Accordingly,
reserve estimates may be subject to downward or upward adjustment. Actual
production, revenues and expenditures with respect to our reserves will likely
vary from estimates, and those variances may be material.
The information regarding discounted future net cash flows included in this
document is not necessarily the current market value of the estimated oil and
natural gas reserves attributable to our properties. As required by the SEC, the
estimated discounted future net cash flows from proved reserves are determined
based on prices and costs as of the date of the estimate. Actual future prices
and costs may be materially higher or lower. Actual future net cash flows also
are affected by the following factors:
. the amount and timing of production;
. supply and demand for oil and natural gas;
. increases or decreases in consumption; and
. changes in governmental regulations or taxation.
In addition, the 10% discount factor, required by the SEC for use in
calculating discounted future net cash flows for reporting purposes, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with our operations or the oil and
natural gas industry in general.
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the SEC. Under these rules,
capitalized costs of proved oil and natural gas properties may not exceed the
present value of estimated future net revenues from proved reserves, discounted
at 10%. Application of the ceiling test generally
21
requires pricing future revenue at the unescalated prices in effect as of
the end of each fiscal quarter and requires a write-down for accounting purposes
if we exceed the ceiling, even if prices are depressed for only a short period
of time. We may be required to write down the carrying value of our oil and
natural gas properties when oil and natural gas prices are depressed or
unusually volatile. If a write-down is required, it would result in a charge to
earnings but would not impact cash flow from operating activities. Once
incurred, a write-down of oil and natural gas properties is not reversible at a
later date.
We are continually identifying and evaluating opportunities to acquire oil
and natural gas properties, including acquisitions that would be significantly
larger than those consummated to date by us. We cannot assure you that we will
successfully consummate any acquisition, that we will be able to acquire
producing oil and natural gas properties that contain economically recoverable
reserves or that any acquisition will be profitably integrated into our
operations.
Debt and Bank Borrowing. We have experienced and expect to continue to
experience substantial working capital needs due to the growth in our drilling
operations and our active exploration and development programs. Historically, we
have funded our working capital needs through a combination of internally
generated cash flow, equity financing and borrowings under our bank loan
agreement. We currently have, and will continue to have, a certain amount of
indebtedness. At December 31, 2003, our long-term debt outstanding was $400,000.
With the acquisition of PetroCorp Incorporated (as further discussed in Note 12
of the Notes to Consolidated Financial Statements) on January 30, 2004, we
signed a new loan agreement with a total loan commitment of $150 million, but we
elected to limit the amount available for borrowing under our bank loan
agreement to $120 million in order to reduce our financing costs. After the
PetroCorp acquisition our outstanding debt on February 18, 2004 was $90.0
million.
Our level of debt, the cash flow needed to satisfy our debt and the loan
covenants could:
. limit funds otherwise available for financing our capital expenditures,
our drilling program or other activities or cause us to curtail these
activities;
. limit our flexibility in planning for or reacting to changes in our
business;
. place us at a competitive disadvantage to some of our competitors that
are less leveraged than us;
. make us more vulnerable during periods of low oil and natural gas prices
or in the event of a downturn in our business; and
. prevent us from obtaining additional financing on acceptable terms or
limit amounts available under our existing or any future credit
facilities.
22
Our ability to meet our debt service obligations will depend on our future
performance. If the requirements of our indebtedness are not satisfied, a
default would be deemed to occur and our lenders would be entitled to accelerate
the payment of the outstanding indebtedness. If this occurs, we would not have
sufficient funds available nor would we be able to obtain the financing required
to meet our obligations.
The amount of our existing debt as well as our future debt is, to a large
extent, a function of the costs associated with the projects we undertake at any
given time and the cash flow we receive. Generally, our normal operating costs
are those associated with the drilling of oil and natural gas wells, the
acquisition of producing properties, and the costs 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, if our cash flow should prove to be insufficient to cover our current
cash requirements we would need to increase our debt either through bank
borrowings or otherwise.
23
Executive Officers. The table below and accompanying footnotes set forth
certain information concerning each of our executive officers as of March 15,
2004.
NAME AGE POSITION HELD
- ---------------- --- -------------------------------------------
John G. Nikkel 69 Chairman of the Board since August 1, 2003
Director since 1983
Chief Executive Officer since July 1, 2001
President and Chief Operating Officer from
1983 to August 1, 2003
Larry D. Pinkston 49 Director since January 15, 2004
President since August 1, 2003
Chief Operating Officer since February 24,
2004
Vice President and Chief Financial Officer
from May 1989 to February 24, 2004
Mark E. Schell 46 Senior Vice President since December 2002
General Counsel and Corporate Secretary
since January 1987
Philip M. Keeley(1) 62 Senior Vice President, Exploration and
Production since 1983
David T. Merrill 43 Chief Financial Officer and Treasurer
since February 24,2004
Vice President of Finance from August
2003 to February 24,2004
- ------------------
(1) Mr. Keeley has announced his plans to retire effective April, 15, 2004
Mr. Nikkel joined Unit as its President, Chief Operating Officer and a
director in 1983. He was elected its Chief Executive Officer in July, 2001 and
Chairman of the Board in August, 2003. He currently holds the position of
Chairman of the Board and Chief Executive Officer. From 1976 until January, 1982
when he co-founded Nike Exploration Company, Mr. Nikkel was an officer and
director of Cotton Petroleum Corporation, serving as the President of Cotton
from 1979 until his departure. Prior to joining Cotton, Mr. Nikkel was employed
by Amoco Production Company for 18 years, last serving as Division Geologist for
Amoco's Denver Division. Mr. Nikkel presently serves as President and a director
of Nike Exploration Company. From August 16, 2000 until August 23, 2002 Mr.
Nikkel, in connection with Unit's investment in the company, also served as a
director of Shenandoah Resources Ltd., a Canadian company. Shenandoah Resources
Ltd. filed for creditors protection under The Companies' Creditor Arrangement
Act in April 2002 with the Court of Queen's Bench of Alberta, Judicial District
of Calgary. Mr. Nikkel received a Bachelor of Science degree in Geology and
Mathematics from Texas Christian University.
24
Mr. Pinkston joined Unit in December, 1981. He had served as Corporate
Budget Director and Assistant Controller prior to being appointed Controller in
February, 1985. In December, 1986 he was elected Treasurer of the company and
was elected to the position of Vice President and Chief Financial Officer in
May, 1989. In August, 2003, he was elected to the position of President of the
company as well as its Chief Financial Officer. In February, 2004, in addition
to his position as President, he was elected to the office of Chief Operating
Officer. He was elected as director of the company by the Board in January,
2004. Mr. Pinkston holds the offices of President and Chief Operating Officer.
He holds a Bachelor of Science Degree in Accounting from East Central University
of Oklahoma and is a Certified Public Accountant.
Mr. Keeley joined Unit in November 1983 as Senior Vice President,
Exploration and Production. Prior to that time, Mr. Keeley co-founded (with Mr.
Nikkel) Nike Exploration Company in January 1982 and, until November 2001,
served as Executive Vice President and a director of that company. From 1977
until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation, serving
first as Manager of Land and from 1979 as Vice President and a director. Before
joining Cotton, Mr. Keeley was employed for four years by Apexco, Inc. as
Manager of Land and prior thereto he was employed by Texaco, Inc. for nine
years. He received a Bachelor of Arts degree in Petroleum Land Management from
the University of Oklahoma.
Mr. Schell joined Unit in January 1987, as its Secretary and General
Counsel. In December 2002, he was elected to the additional position as Senior
Vice President. From 1979 until joining Unit, Mr. Schell was Counsel, Vice
President and a member of the Board of Directors of C&S Exploration, Inc. He
received a Bachelor of Science degree in Political Science from Arizona State
University and his Juris Doctorate degree from the University of Tulsa Law
School. He is a member of the Oklahoma and American Bar Association as well as
being a member of the American Corporate Counsel Association and the American
Society of Corporate Secretaries.
Mr. Merrill joined Unit in August 2003 and served as its Vice President,
Finance until February, 2004 when he was elected to the position of Chief
Financial Officer and Treasurer. From May 1999 through August 2003, Mr. Merrill
served as Senior Vice President, Finance with TV Guide Networks, Inc. From July
1996 through May 1999 he was a Senior Manager with Deloitte & Touche LLP. From
July 1994 through July 1996 he was Director of Financial Reporting and Special
Projects for MAPCO, Inc. He began his career as an auditor with Deloitte,
Haskins & Sells in 1983. Mr. Merrill received a Bachelor of Business
Administration Degree in Accounting from the University of Oklahoma and is a
Certified Public Accountant.
25
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 2004.
26
PART II
Item 5. Market for the Registrant's Common Equity, Related Stockholder
- ------- -----------------------------------------------------------------
Matters and Issuer Purchases of Equity Securities
-------------------------------------------------
Our common stock trades on the New York Stock Exchange under the symbol
"UNT." The following table identifies the high and low sales prices per share of
our common stock for the periods indicated:
2002 2003
------------------------- -------------------------
QUARTER High Low High Low
------- ----------- ----------- ----------- -----------
First $ 18.60 $ 10.24 $ 21.99 $ 16.30
Second $ 20.93 $ 16.01 $ 23.39 $ 19.14
Third $ 19.25 $ 13.65 $ 22.60 $ 18.68
Fourth $ 20.44 $ 16.71 $ 24.51 $ 18.40
On March 1, 2004 there were 1,763 record holders of our common stock.
We have never paid cash dividends on our common stock and currently intend
to continue our policy of retaining earnings from our operations. Our loan
agreement prohibits us from declaring and paying dividends (other than stock
dividends) in any fiscal year in an amount greater than 25% of our preceding
year's consolidated net income.
27
Item 6. Selected Financial Data
- ------- -----------------------
Year Ended December 31,
----------------------------------------------------------
1999 (1) 2000 2001 2002 2003
---------- ---------- ---------- ---------- ----------
(In thousands except per share amounts)
Revenues $ 102,352 $ 201,264 $ 259,179 $ 187,636 $ 302,584
========== ========== ========== ========== ==========
Income Before Change
in Accounting
Principle $ 3,048 $ 34,344 $ 62,766 $ 18,244 $ 48,864
========== ========== ========== ========== ==========
Net Income $ 3,048 $ 34,344 $ 62,766 $ 18,244 $ 50,189
========== ========== ========== ========== ==========
Income Before Change
in Accounting
Principle per
Common Share:
Basic $ 0.10 $ 0.96 $ 1.75 $ 0.47 $ 1.12
========== ========== ========== ========== ==========
Diluted $ 0.10 $ 0.95 $ 1.73 $ 0.47 $ 1.12
========== ========== ========== ========== ==========
Net Income per
Common Share:
Basic $ 0.10 $ 0.96 $ 1.75 $ 0.47 $ 1.15
========== ========== ========== ========== ==========
Diluted $ 0.10 $ 0.95 $ 1.73 $ 0.47 $ 1.15
========== ========== ========== ========== ==========
Total Assets $ 295,567 $ 346,288 $ 417,253 $ 578,163 $ 712,925
========== ========== ========== ========== ==========
Long-Term Debt $ 67,239 $ 54,000 $ 31,000 $ 30,500 $ 400
========== ========== ========== ========== ==========
Other Long-Term
Liabilities $ 2,325 $ 3,597 $ 4,110 $ 5,439 $ 17,893
========== ========== ========== ========== ==========
Cash Dividends
Per Common Share $ -- $ -- $ -- $ -- $ --
========== ========== ========== ========== ==========
- ----------------------
(1) Restated for the merger with Questa Oil and Gas Co.
See Item 7. Management's Discussion of Financial Condition and Results of
Operations for a review of 2001, 2002 and 2003 activity.
28
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------- ---------------------------------------------------------------
Results of Operations
---------------------
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Summary. Our financial condition and liquidity depends on the cash flow from our
two principal subsidiaries and borrowings under our bank loan agreement. Our
cash flow is influenced mainly by the prices we receive for our natural gas
production, the demand for and the dayrates we receive for our drilling rigs
and, to a lesser extent, the prices we receive for our oil production. At
December 31, 2003, we had cash totaling $598,000 and we had borrowed $400,000
under our loan agreement.
Over the last six months of 2003 the average monthly natural gas price we
received excluding the impact of hedging, ranged from $4.06 in October to $5.06
in December and the average Nymex Henry Hub daily price for the same time period
ranged from $4.79 to $7.00. With the average Nymex contract settle price for the
next twelve months at $5.40 on February 18, 2004, we expect natural gas prices
to remain at levels that will increase demand for our rigs and provide upward
movement on the rates we receive for our contract drilling services. There is,
however, no assurance that these prices will actually be sustained throughout
2004.
The following is a summary of certain financial information as of December
31, 2003 and for the year ended December 31, 2003:
Working Capital . . . . . . . $ 20,931,000
Long-Term Debt. . . . . . . . $ 400,000
Shareholders' Equity. . . . . $ 515,768,000
Ratio of Long-Term Debt to
Total Capitalization. . . . --%
Net Income. . . . . . . . . . $ 50,189,000
Net Cash Provided by
Operating Activities. . . . $ 121,712,000
29
The following table summarizes certain operating information for the years
ended December 31, 2002 and 2003:
Percent
2002 2003 Change
------------ ------------ --------
Oil Production (Bbls) . . . 473,000 516,000 9%
Natural Gas Production (Mcf) 18,968,000 20,648,000 9%
Average Oil Price Received. $ 21.54 $ 26.94 25%
Average Natural Gas Price
Received. . . . . . . . . $ 2.87 $ 4.87 70%
Average Number of Our
Drilling Rigs in Use
During the Period . . . . 39.1 62.9 61%
In December 2003, we acquired SerDrilco Incorporated for $35.0 million in
cash. To finance the acquisition we sold 2.0 million shares of common stock for
net proceeds of $42.1 million.
Our Bank Loan Agreement. At December 31, 2003, we had a $100 million bank loan
agreement consisting of a revolving credit facility through May 1, 2005 and a
term loan thereafter, maturing on May 1, 2008. On January 30, 2004, in
conjunction with our acquisition of PetroCorp Incorporated, we replaced our loan
agreement with a revolving credit facility totaling $150 million having a four
year term ending January 30, 2008. Borrowings under the new credit facility are
limited to a commitment amount. Although the current value of our assets under
the latest loan value computation supported the full $150 million, we elected to
set the loan commitment at $120 million in order to reduce financing costs since
we are charged a commitment fee of .375 of 1% on the amount available but not
borrowed. We paid origination, agency and syndication fees of $515,000 at the
inception of the new agreement, $40,000 of which will be paid annually and the
remainder of the fees amortized over the four year life of the loan. Following
the acquisition of PetroCorp Incorporated our borrowings were $90.0 million on
February 18, 2004.
The loan value under our current credit facility is subject to a
semi-annual re-determination on May 10 and November 10 of each year, beginning
May 10, 2004. The calculation is based primarily on the sum of a percentage of
the discounted future value of our oil and natural gas reserves, as determined
by the banks. In addition, an amount representing a part of the value of our
drilling rig fleet, limited to $20 million, is added to the loan value.
Provisions are also in the agreement which allow for one requested special
re-determination of the borrowing base by either the lender or us between each
scheduled re-determination date if conditions warrant such a request.
At our election, any portion of the debt outstanding may be fixed at a
Eurodollar Rate for 30, 60, 90 or 180 day terms. During any Eurodollar Rate
funding period the outstanding principal balance of the note to which such
Eurodollar Rate option applies may be repaid upon three days prior notice to the
Administrative Agent. Interest on the Eurodollar Rate is computed at the
Eurodollar Base Rate applicable for the interest period
30
plus 1.00% to 1.50% depending on the level of debt as a percentage of the
total loan value and is payable at the end of each term or every 90 days
whichever is less. Borrowings not under the Eurodollar Rate bear interest at the
JPMorgan Chase Prime Rate payable at the end of each month and the principal
borrowed may be paid anytime in part or in whole without premium or penalty. At
February 18, 2004, all of our $90.0 million debt was subject to the Eurodollar
Rate.
The loan agreement includes prohibitions against:
. the payment of dividends (other than stock dividends) during any fiscal
year in excess of 25% of our consolidated net income for the preceding
fiscal year,
. the incurrence of additional debt with certain very limited exceptions
and
. the creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any of our property, except in favor of
our banks.
The loan agreement also requires that at the end of each quarter:
. consolidated net worth of at least $350 million,
. a current ratio (as defined in the loan agreement) of not less than 1 to
1 and
. a leverage ratio of long-term debt to consolidated EBITDA (as defined in
the loan agreement) for the most recently ended rolling four fiscal
quarters of no greater than 3.25 to 1.0.
Hedging. Periodically we hedge the prices we will receive for a portion of our
future natural gas and oil production. We do so in an attempt to reduce the
impact and uncertainty that price variations have on our cash flow. We entered
into a collar contract covering approximately 25% of our daily oil production
for January and February of 2001. The collar had a floor of $26.00 per barrel
and a ceiling of $33.00 per barrel and we received $0.86 per barrel for entering
into the transaction. During the first quarter of 2001, our oil hedging
transaction yielded an increase in our oil revenues of $17,200.
During the second quarter of 2001, we entered into a natural gas collar
contract for approximately 36% of our June and July 2001 production, at a floor
price of $4.50 and a ceiling price of $5.95. During the third quarter of 2001,
we entered into two natural gas collar contracts for approximately 38% of our
September through November 2001 natural gas production. Both contracts had a
floor price of $2.50. One contract had a ceiling of $3.68 and the other contract
had a ceiling of $4.25. During the year of 2001, the collar contracts increased
natural gas revenues by $2,030,000.
On April 30, 2002, we entered into a collar contract covering approximately
19% of our natural gas production for the periods of April 1, 2002 through
October 31, 2002. The collar had a floor of $3.00 and a ceiling of $3.98. During
the year of 2002, our natural gas hedging transactions increased natural gas
revenues by $40,300. We did not have any hedging transactions outstanding at
December 31, 2002.
31
During the first quarter of 2003, we entered into two collar contracts
covering approximately 40% of our natural gas production for the periods of
April 1, 2003 through September 30, 2003. One collar had a floor of $4.00 and a
ceiling of $5.75 and the other collar had a floor of $4.50 and a ceiling of
$6.02. We also entered into two collar contracts covering approximately 25% of
our oil production for the periods of May 1, 2003 through December 31, 2003. One
collar had a floor of $25.00 and a ceiling of $32.20 and the other collar had a
floor of $26.00 and a ceiling of $31.40. During the year of 2003, the collar
contracts decreased natural gas revenues by $6,000 and oil revenues by $5,000.
We did not have any hedging transactions outstanding at December 31, 2003.
In January 2004, we entered into a natural gas collar covering
approximately 14% of our estimated natural gas production. The transaction
covers the periods of April through October of 2004 and has a floor of $4.50 and
a ceiling of $6.76. We also entered into an oil hedge covering approximately 40%
of our estimated oil production. The transaction covers the periods of February
through December of 2004 and has an average price of $31.40.
Self-Insurance. We are self-insured for certain losses relating to workers'
compensation, general liability, property damage and employee medical benefits.
The exposure (i.e. our deductible or retention) per occurrence ranges from
$200,000 for general liability to $1 million for rig physical damage. We have
purchased stop-loss coverage in order to limit, to the extent feasible, our per
occurrence and aggregate exposure to certain claims. There is no assurance that
such coverage will adequately protect us against liability from all potential
consequences. Following the acquisition of SerDrilco we have continued to use
its ERISA governed occupational injury benefit plan to cover its employees in
lieu of covering them under an insured Texas workers' compensation plan.
Impact of Prices for Our Oil and Natural Gas. With the acquisition of PetroCorp
Incorporated (as further discussed in Note 12 of the Notes to Consolidated
Financial Statements), natural gas comprises 86% of our total oil and natural
gas reserves. Before the acquisition, natural gas comprised 89% of our reserves.
Any significant change in natural gas prices has a material affect on our
revenues, cash flow and the value of our oil and natural gas reserves.
Generally, prices and demand for domestic natural gas are influenced by weather
conditions, supply imbalances and by world wide oil price levels. Domestic oil
prices are primarily influenced by world oil market developments. All of these
factors are beyond our control and we can not predict nor measure their future
influence on the prices we will receive.
Based on our production in 2003, a $.10 per Mcf change in what we are paid
for our natural gas production would result in a corresponding $160,300 per
month ($1,923,600 annualized) change in our pre-tax operating cash flow. Our
2003 average natural gas price was $4.87 compared to an average natural gas
price of $2.87 for 2002. A $1.00 per barrel change in our oil price would have a
$40,000 per month ($480,000 annualized) change in our pre-tax operating cash
flow based on our production in 2003. Our
32
2003 average oil price was $26.94 compared with an average oil price of
$21.54 received in 2002.
Because natural gas prices have such a significant affect on the value of
our oil and natural gas reserves, declines in these prices can result in a
decline in the carrying value of our oil and natural gas properties. Price
declines can also adversely affect the semi-annual determination of the amount
available for us to borrow under our bank loan agreement since that
determination is based mainly on the value of our oil and natural gas reserves.
Such a reduction could limit our ability to carry out our planned capital
projects.
We sell most of our natural gas production to third parties under
month-to-month contracts. Several of these buyers have experienced financial
complications resulting from the recent investigations into the energy trading
industry. The long-term implications to the energy trading business, as well as
to oil and natural gas producers, because of these investigations remains, to be
determined. We continue to evaluate the information available to us about our
buyers and try to reduce any possible future adverse impact to us. Presently we
believe that our buyers will be able to perform their commitments to us. For
2003, purchases by Cinergy Marketing & Trading LP accounted for approximately
17% of our oil and natural gas revenues while purchases by Centerpoint Energy
Gas accounted for approximately 16% of our oil and natural gas revenues. We own
a 16.7% limited partner interest in Eagle Energy Partners I LP, whose purchases,
which are competitively marketed, accounted for 6% of our oil and natural gas
revenues in 2003. We have increased our sales to Eagle Energy Partners I LP
since we first started selling natural gas to them in August, 2003. For the
period August through December 2003 Eagle has purchased 16% of our oil and
natural gas revenues and they marketed approximately 37% of the natural gas
volumes we sold for ourselves and third parties during the same five month
period.
Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital
expenditures are discretionary and directed toward future growth. Our decision
to increase our oil and natural gas reserves through acquisitions or through
drilling depends on the prevailing or expected market conditions, potential
return on investment, future drilling potential and opportunities to obtain
financing under the circumstances involved, all of which provide us with a large
degree of flexibility in deciding when to incur such costs. We drilled 149 wells
(61.57 net wells) in 2003 compared to 96 wells (51.87 net wells) in 2002. Our
total capital expenditures for oil and natural gas exploration and acquisitions
in 2003 totaled $73.3 million excluding capitalized cost for the recording of
the plugging liability associated with our wells. Based on current prices, we
plan to drill an estimated 165 to 175 wells in 2004 and total capital
expenditures for oil and natural gas exploration and acquisitions is planned to
be around $95 million.
Contract Drilling. Our drilling work is subject to many factors that influence
the number of rigs we have working as well as the costs and revenues associated
with such work. These factors include competition from other drilling
contractors, the prevailing prices for natural gas and oil, availability and
cost of labor to run our rigs and our ability to supply
33
the equipment needed. We have not encountered major difficulty in hiring
and keeping rig crews, but such shortages have occurred periodically in the
past. If demand for drilling rigs increases rapidly in the future, shortages of
experienced personnel may limit our ability to increase the number of rigs we
could operate.
Most of our contract drilling fleet is targeted to the drilling of natural
gas wells, so changes in natural gas prices influence the demand for our
drilling rigs and the prices we can charge for our contract drilling services.
In the last half of 1999 and throughout 2000, as oil and natural gas prices
increased, we experienced a big increase in demand for our rigs. Demand
continued to increase until the end of the third quarter of 2001 and reached a
high when 52 of our rigs were working in July 2001. Because of declining natural
gas prices throughout 2001, demand for our rigs dropped significantly in the
fourth quarter of 2001 and stabilized with between 30 and 35 rigs operating in
the first half of 2002. The rates received for our rigs also began to fall until
they reached a low of $7,275 per day in February of 2003. Natural gas and oil
prices once again began to rise during the last half of 2002 and in the second
quarter of 2003 through the remainder of the year both demand for our rigs and
dayrates continued to improve. In December 2003 the average dayrate on the 75
rig fleet owned by us throughout 2003 was approximately $8,200 per day and the
12 Service rigs added in December 2003 had a dayrate of approximately $7,500
making the average dayrate for the 88 rig fleet $8,130 in December 2003. The
average use of our rigs in 2003 was 62.9 rigs (83%) compared with 39.1 rigs
(63%) for 2002. Our average dayrate in 2003 was $7,808 compared to $7,716 for
2002. Based on the average utilization of our rigs in 2003, a $100 per day
change in dayrates has a $6,290 per day ($2,296,000 annualized) change in our
pre-tax operating cash flow. Utilization and dayrates for our drilling rigs will
depend mainly on the price of natural gas.
Our contract drilling subsidiary provides drilling services for our
exploration and production subsidiary. The contracts for these services are
issued under the same conditions and rates as the contracts we have entered into
with unrelated third parties. During 2003, we drilled 43 wells for our
exploration and production subsidiary. Per regulations provided by the
Securities and Exchange Commission, the profit received by our contract drilling
segment of $841,000 and $1,883,000 during 2002 and 2003, respectively, was used
to reduce the carrying value of our oil and natural gas properties rather than
being included in our profits in current operations.
Drilling Acquisitions and Capital Expenditures. On December 8, 2003, we acquired
SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC for
$35.0 million in cash. The terms of the acquisition include an earn-out
provision allowing the sellers to obtain one-half of the cash flow in excess of
$10 million for each of the three years following the acquisition. The assets of
SerDrilco Incorporated included 12 drilling rigs, spare drilling equipment, a
fleet of 12 larger trucks and trailers, various other vehicles and a district
office and an equipment yard in and near Borger, Texas. For our contract
drilling operations during 2003, we incurred $71.9 million in capital
expenditures, which includes $35.0 million in cash and $10.9 million for
goodwill resulting from
34
deferred tax liabilities recorded in connection with the SerDrilco
acquisition. For the year 2004, we have budgeted capital expenditures of
approximately $30 million for our contract drilling operations.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We are
the general partner for 10 oil and natural gas partnerships which were formed
privately and publicly. The partnership's revenues and costs are shared under
formulas prescribed in each limited partnership agreement. The partnerships
repay us for contract drilling, well supervision and general and administrative
expense. Related party transactions for contract drilling and well supervision
fees are the related party's share of such costs. These costs are billed on the
same basis as billings to unrelated third parties for similar services. General
and administrative reimbursements consist of direct general and administrative
expense incurred on the related party's behalf as well as indirect expenses
assigned to the related parties. Allocations are based on the related party's
level of activity and are considered by management to be reasonable. During
2001, 2002 and 2003, the total paid to us for all of these fees was $1,107,000,
$929,000 and $873,000, respectively. We expect the fees to be about the same in
2004. Our proportionate share of assets, liabilities and net income relating to
the oil and natural gas partnerships is included in our consolidated financial
statements.
We own a 40% equity interest in Superior Pipeline Company LLC, an Oklahoma
Limited Liability Company. Superior is a natural gas gathering and processing
company. Our investment, including our share of the equity in the earnings of
this company, totaled $3.0 million at December 31, 2003 and is reported in other
assets in our accompanying balance sheet. During 2003, Superior Pipeline Company
LLC purchased $3.3 million of our natural gas production and paid $64,000 for
our natural gas liquids. We paid this company $39,000 for gathering and
compression services.
We also own a 16.7% limited partnership interest in Eagle Energy
Partnership I, L.P. ("Eagle"), carried at cost, for $2.5 million. Eagle is
engaged in the purchase and sale of natural gas, electricity (or similar
electricity based products), future commodities, and the performance of
scheduling and nomination services for both energy related commodities and
similar energy management functions. Eagle was marketing approximately 46% of
the natural gas volumes we sell for ourselves and third parties in December 2003
and during February 2004 they are marketing 48%.
35
Contractual Commitments. We have the following contractual obligations at
December 31, 2003:
Payments Due by Period
--------------------------------------------------
Less
Contractual Than 1 2-3 4-5 After 5
Obligations Total Year Years Years Years
------------- --------- -------- -------- --------- --------
(In thousands)
Bank Debt(1) $ 400 $ -- $ -- $ 400 $ --
Retirement
Agreement(2) 1,650 300 600 600 150
Operating
Leases(3) 3,555 719 1,424 954 458
--------- -------- -------- --------- --------
Total
Contractual
Obligations $ 5,605 $ 1,019 $ 2,024 $ 1,954 $ 608
========= ======== ======== ========= ========
-------------------
(1) See Previous Discussion in Management Discussion and Analysis
regarding bank debt. The obligation is presented in accordance with
the terms of the loan agreement signed on January 30, 2004.
(2) In the second quarter of 2001, we recorded $1.3 million in additional
employee benefit expenses for the present value of a separation
agreement made in connection with the retirement of King Kirchner from
his position as Chief Executive Officer. The liability associated with
this expense, including accrued interest, will be paid in monthly
payments of $25,000 starting in July 2003 and continuing through June
2009. The liability as presented above is undiscounted.
(3) We lease office space in Tulsa and Woodward, Oklahoma and Houston,
Texas under the terms of operating leases expiring through January 31,
2010 along with leasing space on short-term commitments to stack
excess rig equipment and production inventory. In the first quarter of
2003, we renegotiated our rental agreement for the Tulsa office
reducing the price per square foot while adding additional space and
lengthening the term of the agreement to January 31, 2010.
At December 31, 2003, we also have the following commitments and
contingencies that could create, increase or accelerate our liabilities:
Amount of Commitment Expiration
Per Period
------------------------------------------
Total
Amount
Committed Less
Other or Than 1 2-3 4-5 After 5
Commitments Accrued Year Years Years Years
----------------- --------- -------- -------- -------- ---------
(In thousands)
Deferred
Compensation
Agreement(1) $ 1,829 Unknown Unknown Unknown Unknown
Separation
Benefit
Agreement(2) $ 2,545 $ 412 Unknown Unknown Unknown
Plugging
Liability(3) $ 11,994 $ 303 $ 481 $ 882 $ 10,328
Gas Balancing
Liability(4) $ 1,191 Unknown Unknown Unknown Unknown
Repurchase
Obliga-
tions(5) Unknown Unknown Unknown Unknown Unknown
(1) We provide a salary deferral plan which allows participants to defer
the recognition of salary for income tax purposes until actual
distribution of benefits, which occurs at either termination of
employment, death or certain defined unforeseeable emergency
hardships. We recognize payroll expense and record a liability,
included in other long-term liabilities in our Consolidated Balance
Sheet, at the time of deferral.
(2) Effective January 1, 1997, we adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees
whose employment with us is involuntarily terminated or, in the case
of an employee who has completed 20 years of service, voluntarily or
involuntarily terminated, to receive benefits equivalent to 4 weeks
salary for every whole year of service completed with Unit up to a
maximum of 104 weeks. To receive payments the recipient must waive any
claims against us in exchange for receiving the separation benefits.
On October 28, 1997, we adopted a Separation Benefit Plan for Senior
Management ("Senior Plan"). The Senior Plan provides certain officers
and key executives of Unit with benefits generally equivalent to the
Separation Plan. The Compensation Committee of the Board of Directors
has absolute discretion in the selection of the individuals covered in
this plan.
(3) On January 1, 2003 we adopted Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair
value of liabilities associated with the retirement of
37
long-lived assets (mainly plugging and abandonment costs for our
depleted wells) in the period in which the liability is incurred (at
the time the wells are drilled or acquired).
(4) We have a liability recorded for certain properties where we believe
there are insufficient reserves available to allow the under-produced
owners to recover their under-production from future production
volumes.
(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986
Energy Income Limited Partnership along with private limited
partnerships (the "Partnerships") with certain qualified employees,
officers and directors from 1984 through 2004, with a subsidiary of
ours serving as General Partner. The Partnerships were formed for the
purpose of conducting oil and natural gas acquisition, drilling and
development operations and serving as co-general partner with us in
any additional limited partnerships formed during that year. The
Partnerships participated on a proportionate basis with us in most
drilling operations and most producing property acquisitions commenced
by us for our own account during the period from the formation of the
Partnership through December 31 of that year. These partnership
agreements require, upon the election of a limited partner, that we
repurchase the limited partner's interest at amounts to be determined
by appraisal in the future. Such repurchases in any one year are
limited to 20% of the units outstanding. We made repurchases of $1,000
and $106,000 in 2002 and 2003, respectively, for such limited
partners' interests. No repurchases were made in 2001.
Critical Accounting Policies. We account for our oil and natural gas exploration
and development activities using the full cost method of accounting. Under this
method, all costs incurred in the acquisition, exploration and development of
oil and natural gas properties are capitalized. At the end of each quarter, the
net capitalized costs of our oil and natural gas properties is limited to the
lower of unamortized cost or a ceiling. The ceiling is defined as the sum of the
present value (10% discount rate) of estimated future net revenues from proved
reserves, based on period-end oil and natural gas prices adjusted for hedging,
plus the lower of cost or estimated fair value of unproved properties not
included in the costs being amortized, less related income taxes. If the net
capitalized costs of our oil and natural gas properties exceed the ceiling, we
are subject to a write-down to the extent of such excess. A ceiling test
write-down is a non-cash charge to earnings. If required, it reduces earnings
and impacts shareholders' equity in the period of occurrence and results in
lower depreciation, depletion and amortization expense in future periods. Once
incurred, a write-down cannot be reversed even if prices subsequently recover.
The risk that we will be required to write-down the carrying value of our
oil and natural gas properties increases when oil and natural gas prices are
depressed or if we have large downward revisions in our estimated proved
reserves. Application of these rules during periods of relatively low oil or
natural gas prices, even if temporary, increases the chance of a ceiling test
write-down. Based on oil and natural gas prices on December 31, 2003 ($5.67 per
Mcf for natural gas and $32.52 per barrel for
38
oil), the unamortized cost of our domestic oil and natural gas properties
did not exceed the ceiling of our proved oil and natural gas reserves. Natural
gas prices remain erratic and any significant declines below prices used in the
reserve evaluation could result in a ceiling test write-down in following
quarterly reporting periods.
The value of our oil and natural gas reserves is used to determine the
borrowing base under our loan agreement with our banks. This amount is affected
by both price changes and the measurement of reserve volumes. Oil and natural
gas reserves cannot be measured exactly. Our estimate of oil and natural gas
reserves require extensive judgments of our reservoir engineering data and are
less precise than other estimates made in connection with financial disclosures.
Assigning monetary values to such estimates does not reduce the subjectivity and
changing nature of such reserve estimates. Indeed the uncertainties inherent in
the disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves.
We use the sales method for recording natural gas sales. This method allows
for recognition of revenue, which may be more or less than our share of pro-rata
production from certain wells. Our policy is to expense our pro-rata share of
lease operating costs from all wells as incurred. Such expenses relating to the
natural gas balancing position on wells in which we have an imbalance are not
material.
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. Renewals and betterments are capitalized while
repairs and maintenance are expensed. Realization of the carrying value of
property and equipment is reviewed for possible impairment whenever events or
changes in circumstances suggest the carrying amount may not be recoverable.
Assets are determined to be impaired if a forecast of undiscounted estimated
future net operating cash flows directly related to the asset including disposal
value if any, is less than the carrying amount of the asset. If any asset is
determined to be impaired, the loss is measured as the amount by which the
carrying amount of the asset exceeds its fair value. An estimate of fair value
is based on the best information available, including prices for similar assets.
Changes in such estimates could cause us to reduce the carrying value of
property and equipment.
We recognize revenues and expense generated from "daywork" drilling
contracts as the services are performed, since we do not bear the risk of
completion of the well. Under "footage" and "turnkey" contracts, we bear the
risk of completion of the well, so revenues and expenses are recognized when the
well is substantially completed. Under this method, substantial completion is
determined when the well bore reaches the negotiated depth as stated in the
contract. The entire amount of a loss, if any, is recorded when the loss can be
reasonably determined, however, any profit is recorded only at the time the well
is finished. The costs of uncompleted drilling contracts include expenses
incurred to date on "footage" or "turnkey" contracts, which are still in process
at the end of the period, and are included in other current assets.
39
EFFECTS OF INFLATION
- --------------------
The effect of inflation in the oil and natural gas industry is primarily
driven by the prices realized for oil and natural gas. Increased commodity
prices increase demand for contract drilling rigs and services which support
higher rig activity. This in turn affects the overall demand for our rigs and
the dayrates we can obtain for our contract drilling services. Before 1999, the
effect of inflation on our operations was minimal due to low inflation rates,
relatively low natural gas and oil prices and moderate demand for our contract
drilling services. Over the last four years natural gas and oil prices have been
more volatile, and during periods of higher utilization we have experienced
increases in labor cost and the cost of services to support our rigs. During
this same period when commodity prices did decline labor rates did not come back
down to the levels incurred before the increases. If natural gas prices
increased substantially for a long period, 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.
How inflation will affect us in the future will depend on additional increases,
if any, realized in our drilling rig rates and the prices we receive for our oil
and natural gas.
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------------
On January 1, 2003 we adopted Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 establishes an
accounting standard requiring the recording of the fair value of liabilities
associated with the retirement of long-lived assets. We own oil and natural gas
properties which require expenditures to plug and abandon the wells when the oil
and natural gas reserves in the wells are depleted. These expenditures under FAS
143 are recorded in the period in which the liability is incurred (at the time
the wells are drilled or acquired). We do not have any assets restricted for the
purpose of settling the plugging liabilities.
The effect of this change increased net property, plant and equipment by
$13.0 million and liabilities, including deferred tax liabilities, by $11.7
million at January 1, 2003 and decreased net income for the year ended December
31, 2003 by $148,000 ($0.00 per share). The financial statements for the year
ended December 31, 2002 have not been restated and the cumulative effect of the
change of $1.3 million net of tax ($0.03 per share) is shown as a one-time
addition to income in the first quarter of 2003.
40
On January 17, 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN
46"). The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights ("variable interest entities" or "VIEs") and how to
determine when and which business enterprise should consolidate the VIE. This
new model for consolidation applies to an entity which either (1) the equity
investors (if any) do not have a controlling financial interest or (2) the
equity investment at risk is insufficient to finance that entity's activities
without receiving additional subordinated financial support from other parties.
FIN 46, as amended, was effective for us in the fourth quarter of 2003 as it
applies to entities created after February 1, 2003. The adoption of FIN 46 with
respect to these entities, did not have an impact on our financial position or
results of operations. For entities created prior to February 1, 2003, which are
not special purpose entities, as defined in FIN 46, we will have to adopt FIN
46, as amended, in the quarter ending March 31, 2004. We are still evaluating
FIN 46 with regard to these types of entities in which we have an ownership
interest, primarily our oil and gas partnerships and our equity investment in
Superior pipeline. FIN 46 may require full consolidation of these entities which
would increase our total assets with an offsetting minority interest for the
percentage not owned by Unit. There will be no net impact to our results of
operations from the adoption of FIN 46.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (FAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (FAS 142) were issued by the FASB in June
2001 and became effective for us on July 1, 2001 and January 1, 2002,
respectively. FAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for using the purchase method. Additionally, FAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. FAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under FAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. Depending on how the accounting and disclosure literature is
applied, oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract oil and natural gas reserves for
both undeveloped and developed leaseholds may be classified separately from oil
and gas properties, as intangible assets on our balance sheets. In addition, the
notes to our financial statements would include the disclosures required by FAS
141 and 142 regarding intangibles. To date, we, like many other oil and gas
companies, have included oil and gas extraction rights as part of the oil and
gas properties, even after FAS 141 and 142 became effective.
Our results of operations and cash flows would not be affected, since these
oil and gas mineral extraction rights would continue to be amortized in
accordance with full cost accounting rules.
At December 31, 2002 and 2003, we had undeveloped leaseholds of
approximately $13.2 million and $14.8 million, respectively that would be
classified on our balance sheets as "intangible undeveloped leasehold" and
41
developed leaseholds of an estimated $18.1 million and $24.6 million,
respectively that would be classified as "intangible developed leasehold" if the
interpretations were applied. This classification would require us to make the
disclosures set forth under FAS 142 related to these interests.
We intend to continue to classify our oil and gas mineral extraction rights
as tangible oil and gas properties until further guidance is provided.
42
RESULTS OF OPERATIONS
- ---------------------
2003 versus 2002
- ----------------
Provided below is a comparison of selected operating and financial data for
the year of 2002 versus the year of 2003:
Percent
2002 2003 Change
--------------- --------------- ---------
Total Revenue $ 187,636,000 $ 302,584,000 61%
Income Before Change in Accounting
Principle $ 18,244,000 $ 48,864,000 168%
Net Income $ 18,244,000 $ 50,189,000 175%
Oil and Natural Gas:
Revenue $ 67,959,000 $ 116,609,000 72%
Average natural gas price (Mcf) $ 2.87 $ 4.87 70%
Average oil price (Bbl) $ 21.54 $ 26.94 25%
Natural gas production (Mcf) 18,968,000 20,648,000 9%
Oil production (Bbl) 473,000 516,000 9%
Depreciation, depletion and
amortization rate (Mcfe) $ 1.04 $ 1.14 10%
Depreciation, depletion and
amortization ($346,000
write off of interest in
Shenandoah in 2002) $ 23,338,000 $ 27,343,000 17%
Drilling:
Revenue $ 118,173,000 $ 183,146,000 55%
Percentage of revenue from
daywork contracts 91% 98%
Average number of rigs in use 39.1 62.9 61%
Average dayrate on daywork
contracts $ 7,716 $ 7,808 1%
Depreciation $ 14,684,000 $ 23,644,000 61%
General and Administrative Expense $ 8,712,000 $ 9,222,000 6%
Interest Expense $ 973,000 $ 693,000 (29%)
Average Interest Rate 3.0% 2.2% (27%)
Average Long-Term Debt Outstanding $ 24,771,000 $ 20,722,000 (16%)
43
Oil and natural gas revenues and net income were all positively affected by
the higher prices we received for both our oil and natural gas during 2003 as
compared to 2002. Production for both oil and natural gas was also up between
the comparative years. Total operating cost increased primarily from higher
gross production taxes resulting from higher revenues. Total depreciation,
depletion and amortization ("DD&A") on our oil and natural gas properties
increased due to higher production volumes and an increase in the DD&A rate in
2003, which resulted from higher development drilling cost per equivalent Mcf.
Operator demand for our rigs increased gradually throughout 2003 as natural
gas prices increased in 2003 versus 2002 and resulted in higher rig use and
dayrates for our rigs. Higher dayrates were offset by higher rig expense as we
experienced a 121% increase in ad valorem taxes on our rigs and a 175% increase
in worker's compensation expense. We expect both of these expenses, along with
increased demand for quality labor within the industry, to keep upward pressure
on rig costs throughout 2004. Approximately 2% of our total drilling revenues in
2003 came from footage and turnkey contracts, which had profit margins lower
than our daywork contracts. Nine percent of our total drilling revenues came
from footage and turnkey contracts in 2002. Contract drilling depreciation
increased due to the acquisition of 20 rigs in August of 2002 and additional rig
use.
General and administrative expense was higher in 2003 due to an increase in
general liability insurance, director and officer insurance and increased
corporate administrative cost. Our total interest expense is lower due to lower
interest rates and a substantial reduction in our average long-term debt. Income
tax expense increased 202% primarily due to a 180% increase in income before
income taxes. Our effective tax rate for 2002 was 34.4% versus 37.2% in 2003.
The impact of higher statutory depletion and other permanent differences reduced
by the impact of state income taxes was the cause for the lower effective tax
rate in 2002.
Net income includes $1.3 million of income due to an accumulated change in
accounting principle for the implementation of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair value of
liabilities associated with the retirement of long-lived assets. We own oil and
natural gas properties which require expenditures to plug and abandon the wells
when the oil and natural gas reserves in the wells are depleted. These
expenditures under FAS 143 are recorded in the period in which the liability is
incurred (at the time the wells are drilled or acquired). The financial
statements for the year ended December 31, 2002 have not been restated and the
cumulative effect of the change of $1.3 million net of tax ($0.03 per share) is
shown as a one-time addition to income in 2003.
44
2002 versus 2001
- -------------------
Provided below is a comparison of selected operating and financial data for
the year of 2002 versus the year of 2001:
Percent
2001 2002 Change
--------------- --------------- ---------
Total Revenue $ 259,179,000 $ 187,636,000 (28%)
Net Income $ 62,766,000 $ 18,244,000 (71%)
Oil and Natural Gas:
Revenue $ 90,237,000 $ 67,959,000 (25%)
Average natural gas price (Mcf) $ 4.00 $ 2.87 (28%)
Average oil price (Bbl) $ 23.62 $ 21.54 (9%)
Natural gas production (Mcf) 18,864,000 18,968,000 1%
Oil production (Bbl) 492,000 473,000 (4%)
Depreciation, depletion and
amortization rate (Mcfe) $ 0.91 $ 1.04 14%
Depreciation, depletion and
amortization (includes
$2,083,000 and $346,000
write off of interest
in Shenandoah in 2001
and 2002, respectively) $ 22,116,000 $ 23,338,000 6%
Drilling:
Revenue $ 167,042,000 $ 118,173,000 (29%)
Percentage of revenue from
daywork contracts 99% 91%
Average number of rigs in use 46.3 39.1 (16%)
Average dayrate on daywork
contracts $ 10,044 $ 7,716 (23%)
Depreciation $ 13,888,000 $ 14,684,000 6%
General and Administrative Expense $ 8,476,000 $ 8,712,000 3%
Interest Expense $ 2,818,000 $ 973,000 (65%)
Average Interest Rate 5.7% 3.0% (47%)
Average Long-Term Debt Outstanding $ 44,995,000 $ 24,771,000 (45%)
45
Oil and natural gas revenues, net income were all negatively affected by
lower prices received for both oil and natural gas during 2002 compared to 2001.
Production in equivalent Mcf was almost the same in 2002 as in 2001. Total
operating cost decreased due to lower gross production taxes resulting from
lower revenues. Total DD&A on our oil and natural gas properties increased due
to the increase in the DD&A rate in 2002, which resulted from higher development
drilling cost per equivalent Mcf. The increase would have been larger, but
included in 2001 DD&A was the write down of our investment in Shenandoah
Resources LTD. In 2001 Shenandoah started experiencing financial difficulties
and its stock price declined, so we took a write down in our investment of $2.1
million to reduce the carrying value to the market value of Shenandoah's stock.
In August 2002, the assets of Shenandoah were liquidated for the benefit of the
secured creditors and, as a result, our remaining investment of $346,000 in
Shenandoah was written off.
Reduced natural gas prices, especially in the fourth quarter of 2001 and
the first quarter of 2002, caused decreases in operator demand for contract
drilling rigs within our working area and resulted in lower rig use and dayrates
for our rigs. Total drilling operating costs were relatively unchanged between
the two years. Approximately 9% of our total drilling revenues in 2002 came from
footage and turnkey contracts, which had profit margins lower than our daywork
contracts. One percent of our total drilling revenues came from footage and
turnkey contracts in 2001. Contract drilling depreciation increased due to the
acquisition of 20 rigs in August of 2002. The increase was partially offset by
lower rig use.
General and administrative expense was higher in 2002 due to increases in
labor cost, insurance expense and outside contract services. In the second
quarter of 2001, we recorded $1.3 million in additional employee benefit
expenses for the present value of a separation agreement made in connection with
the retirement of King Kirchner from his position as Chief Executive Officer.
The liability associated with this expense plus accrued interest will be paid in
$25,000 monthly payments starting in July 2003 and continuing through June 2009.
Our total interest expense is lower due to lower interest rates along with a
substantial reduction in our long-term debt. Income tax expense decreased 73%
primarily due to a 72% decrease in income before income taxes.
46
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
- -------- ----------------------------------------------------------
Our operations are exposed to market risks primarily as a result of changes
in commodity prices and interest rates.
Commodity Price Risk. Our major market risk exposure is in the price we receive
for our oil and natural gas production. The price we receive is primarily driven
by the prevailing worldwide price for crude oil and market prices applicable to
our natural gas production. Historically, prices we received for our oil and
natural gas production fluctuated and such fluctuation is expected to continue.
The price of natural gas also effects the demand for our rigs and the amount we
can charge for the use of the rigs. Based on our 2003 production, a $.10 per Mcf
change in what we are paid for our natural gas production would result in a
corresponding $160,300 per month ($1,923,600 annualized) change in our pre-tax
cash flow. A $1.00 per barrel change in our oil price would have a $40,000 per
month ($480,000 annualized) change in our pre-tax operating cash flow.
In an effort to try and reduce the impact of price fluctuations, over the
past several years we periodically have used hedging strategies to hedge the
price we will receive for a portion of our future oil and natural gas
production. A detailed explanation of those transactions has been included under
hedging in the financial condition portion of management's discussion and
analysis of financial condition and results of operations included above.
Interest Rate Risk. Our interest rate exposure relates to our long-term debt,
all of which bears interest at variable rates based on the JPMorgan Chase Prime
Rate or the Eurodollar Rate. At our election, borrowings under our revolving
credit facility may be fixed at the Eurodollar Rate for periods up to 180 days.
Historically, we have not utilized any financial instruments, such as interest
rate swaps, to manage our exposure to increases in interest rates. However, we
may use financial instruments in the future should our assessment of future
interest rates warrant there use. Based on our average outstanding long-term
debt in 2003, a 1% change in the floating rate would change our annual pre-tax
cash flow by approximately $207,000.
47
Item 8. Financial Statements and Supplementary Data
- ------- --------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
------------------------
2002 2003
---------- ----------
(In thousands)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 497 $ 598
Accounts receivable (less allowance for
doubtful accounts of $1,203 and $1,223) 33,912 58,807
Materials and supplies 8,794 8,023
Income tax receivable 3,602 112
Prepaid expenses and other 4,594 5,202
---------- ----------
Total current assets 51,399 72,742
---------- ----------
Property and Equipment:
Drilling equipment 369,777 424,321
Oil and natural gas properties, on
the full cost method:
Proved Properties 449,226 528,110
Undeveloped Leasehold not being
amortized 16,024 17,486
Transportation equipment 6,856 9,828
Other 9,906 14,535
---------- ----------
851,789 994,280
Less accumulated depreciation, depletion,
amortization and impairment 341,031 385,219
---------- ----------
Net property and equipment 510,758 609,061
---------- ----------
Goodwill 12,794 23,722
Other Assets 3,212 7,400
---------- ----------
Total Assets $ 578,163 $ 712,925
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
48
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
------------------------
2002 2003
---------- ----------
(In thousands)
LIABILITIES AND SHAREHOLDERS' EQUITY
-----------------------------------
Current Liabilities:
Current portion of long-term
debt and other liabilities (Note 4) $ 1,465 $ 1,015
Accounts payable 21,119 32,871
Accrued liabilities 11,921 15,921
Contract advances 27 2,004
---------- ----------
Total current liabilities 34,532 51,811
---------- ----------
Long-Term Debt (Note 4) 30,500 400
---------- ----------
Other Long-Term Liabilities (Note 4) 5,439 17,893
---------- ----------
Deferred Income Taxes (Note 5) 86,320 127,053
---------- ----------
Commitments and Contingencies (Note 9)
Shareholders' Equity:
Preferred stock, $1.00 par value,
5,000,000 shares authorized, none issued -- --
Common stock, $.20 par value,
75,000,000 shares authorized,
43,339,400 and 45,592,012
shares issued, respectively 8,668 9,117
Capital in excess of par value 264,180 307,938
Retained earnings 148,524 198,713
---------- ----------
Total shareholders' equity 421,372 515,768
---------- ----------
Total Liabilities and Shareholders' Equity $ 578,163 $ 712,925
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
49
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
--------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands except per share amounts)
Revenues:
Contract drilling $ 167,042 $ 118,173 $ 183,146
Oil and natural gas 90,237 67,959 116,609
Other 1,900 1,504 2,829
---------- ---------- ----------
Total revenues 259,179 187,636 302,584
---------- ---------- ----------
Expenses:
Contract drilling:
Operating costs 91,006 91,338 138,762
Depreciation 13,888 14,684 23,644
Oil and natural gas:
Operating costs 22,196 20,795 25,169
Depreciation, depletion,
amortization and
impairment 22,116 23,338 27,343
General and administrative 8,476 8,712 9,222
Interest 2,818 973 693
---------- ---------- ----------
Total expenses 160,500 159,840 224,833
---------- ---------- ----------
Income Before Income Taxes and
Change in Accounting Principle 98,679 27,796 77,751
---------- ---------- ----------
Income Tax Expense:
Current 5,609 (3,469) --
Deferred 30,304 13,021 28,887
---------- ---------- ----------
Total income taxes 35,913 9,552 28,887
---------- ---------- ----------
Income Before Change in
Accounting Principle 62,766 18,244 48,864
Cumulative Effect of Change
in Accounting Principle (Net
of Income Tax of $811) -- -- 1,325
---------- ---------- ----------
Net Income $ 62,766 $ 18,244 $ 50,189
========== ========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
50
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME - CONTINUED
Year Ended December 31,
--------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands except per share amounts)
Basic Earnings Per Common
Share:
Income before change in
accounting principle $ 1.75 $ 0.47 $ 1.12
Cumulative effect of change
in accounting principle
net of income tax -- -- 0.03
---------- ---------- ----------
Net income $ 1.75 $ 0.47 $ 1.15
========== ========== ==========
Diluted Earnings Per Common
Share:
Income before change in
accounting principle $ 1.73 $ 0.47 $ 1.12
Cumulative effect of change
in accounting principle
net of income tax -- -- 0.03
---------- ---------- ----------
Net income $ 1.73 $ 0.47 $ 1.15
========== ========== ==========
Pro Forma Amounts Assuming
Retroactive Application of
Change in Accounting
Principle:
Net income $ 62,662 $ 18,115
========== ==========
Basic earnings per share $ 1.74 $ 0.47
========== ==========
Diluted earnings per share $ 1.73 $ 0.46
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements.
51
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 2001, 2002 and 2003
Accumulated
Capital Other
In Excess Comprehen-
Common of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- -------- ----------
(In thousands except share amounts)
Balances,
January 1, 2001 $ 7,154 $ 139,872 $ 67,514 $ -- $ -- $ 214,540
Net Income -- -- 62,766 -- -- 62,766
Activity in
employee
compensation
plans
(237,923
shares) 47 2,105 -- -- -- 2,152
Purchase of
treasury
shares
(30,000
shares) -- -- -- -- (296) (296)
Other
comprehen-
sive income
(net of
tax of $771
and $771):
Change in
value of
cash flow
deriva-
tive
instru-
ments
used as
cash
flow hedges -- -- -- 1,258 -- 1,258
Adjustment
reclas-
ification -
deriva-
tive
settle-
ments -- -- -- (1,258) -- (1,258)
-------- ---------- --------- --------- -------- ----------
Balances,
December 31, 2001 $ 7,201 $ 141,977 $130,280 $ -- $ (296) $ 279,162
======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
52
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED
Year Ended December 31, 2001, 2002 and 2003
Accumulated
Capital Other
In Excess Comprehen-
Common of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- -------- ----------
(In thousands except share amounts)
Balances,
January 1, 2002 $ 7,201 $ 141,977 $130,280 $ -- $ (296) $ 279,162
Net Income -- -- 18,244 -- -- 18,244
Activity in
employee
compensation
plans
(113,133
shares) 23 1,156 -- -- 296 1,475
Issuance of
stock
for
acquisition
(7,220,000
shares) 1,444 121,047 -- -- -- 122,491
Other
comprehen-
sive income
(net of tax
of $15
and $15):
Change in
value of
cash flow
deriva-
tive
instr-
uments
used as
cash flow
hedges -- -- -- 25 -- 25
Adjustment
reclas-
ification -
deriva-
tive
settle-
ments -- -- -- (25) -- (25)
-------- ---------- --------- --------- -------- ----------
Balances,
December 31, 2002 $ 8,668 $ 264,180 $148,524 $ -- $ -- $ 421,372
======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
53
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - CONTINUED
Year Ended December 31, 2001, 2002 and 2003
Accumulated
Capital Other
In Excess Comprehen-
Common of Par Retained sive Treasury
Stock Value Earnings Income Stock Total
-------- ---------- --------- --------- -------- ----------
(In thousands except share amounts)
Balances,
January 1, 2003 $ 8,668 $ 264,180 $148,524 $ -- $ -- $ 421,372
Net Income -- -- 50,189 -- -- 50,189
Activity in
employee
compensation
plans
(252,612
shares) 49 2,018 -- -- -- 2,067
Issuance of
2,000,000
shares
of common
stock) 400 41,740 -- -- -- 42,140
Other
comprehen-
sive income
(net of
tax of $3
and $3):
Change in
value of
cash flow
deriva-
tive
instru-
ments
used as
cash
flow hedges -- -- -- (4) -- (4)
Adjustment
reclas-
ifica-
tion -
deriva-
tive
settle-
ments -- -- -- 4 -- 4
-------- ---------- --------- --------- -------- ----------
Balances,
December 31, 2003 $ 9,117 $ 307,938 $198,713 $ -- $ -- $ 515,768
======== ========== ========= ========= ======== ==========
The accompanying notes are an integral part of the
consolidated financial statements
54
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands)
Cash Flows From Operating
Activities:
Net Income $ 62,766 $ 18,244 $ 50,189
Adjustments to reconcile
net income to net cash
provided (used) by
operating activities:
Depreciation, depletion,
amortization and
impairment 36,642 38,657 51,783
Equity in net earnings of
unconsolidated investments (1,148) (745) (1,516)
Loss (gain) on disposition
of assets (56) (69) 51
Employee stock compensation
plans 2,873 1,165 1,415
Bad debt expense -- 603 645
Plugging liability -
cumulative effect -
net of accretion -- -- (1,624)
Deferred tax expense 30,304 13,021 28,887
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 6,334 (43) (25,540)
Materials and supplies (1,556) (3,436) 771
Prepaid expenses and other (3,533) 2,365 4,240
Accounts payable (155) 1,784 6,148
Accrued liabilities 929 (350) 4,286
Contract advances 61 (213) 1,977
Other liabilities (440) (436) --
---------- ---------- ----------
Net cash provided by
operating activities 133,021 70,547 121,712
---------- ---------- ----------
The accompanying notes are an integral part of the
consolidated financial statements
55
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands)
Cash Flows From Investing
Activities:
Capital expenditures (including
producing property and
contract drilling
acquisitions) $(108,339) $ (75,225) $(131,162)
Proceeds from disposition of
property and equipment 2,631 1,949 1,625
(Acquisition) disposition
of other assets 17 540 (2,562)
---------- ---------- ----------
Net cash used in
investing activities (105,691) (72,736) (132,099)
---------- ---------- ----------
Cash Flows From Financing
Activities:
Borrowings under line of credit 57,200 36,700 65,200
Payments under line of credit (79,200) (36,200) (95,300)
Net payments on notes payable
and other long-term debt (1,000) (1,161) (1,105)
Proceeds from exercise of
stock options 609 413 452
Proceeds from sale of common
stock -- -- 42,140
Book overdrafts (Note 1) (4,978) 2,543 (899)
Acquisition of treasury stock (296) -- --
---------- ---------- ----------
Net cash provided by
(used in) financing
activities (27,665) 2,295 10,488
---------- ---------- ----------
Net Increase (Decrease) in Cash
and Cash Equivalents (335) 106 101
Cash and Cash Equivalents,
Beginning of Year 726 391 497
---------- ---------- ----------
Cash and Cash Equivalents,
End of Year $ 391 $ 497 $ 598
========== ========== ==========
Supplemental Disclosure of Cash
Flow Information:
Cash paid (received) during
the year for:
Interest $ 2,807 $ 1,053 $ 660
Income taxes $ 7,779 $ (4,585) $ (3,495)
See Note 2 for non-cash investing activities.
The accompanying notes are an integral part of the
consolidated financial statements
56
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
Principles of Consolidation. The consolidated financial statements include the
accounts of Unit Corporation and its directly and indirectly wholly owned
subsidiaries ("Unit"). The investment in limited partnerships is accounted for
on the proportionate consolidation method, whereby Unit's share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business. Unit is engaged in the land contract drilling of natural gas
and oil wells and the exploration, development, acquisition and production of
oil and natural gas properties. Unit's current contract drilling operations are
focused primarily in the natural gas producing provinces of the Oklahoma and
Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf Coast and the
Rocky Mountain regions. Unit's primary exploration and production operations are
also conducted in the Anadarko and Arkoma Basins and in the Texas Gulf Coast
area with additional properties in the Permian Basin. The majority of its
contract drilling and exploration and production activities are oriented toward
drilling for and producing natural gas. At December 31, 2003, Unit had an
interest in a total of 3,393 wells and served as operator of 753 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 2003, 84 of Unit's 88
rigs performed contract drilling services.
Drilling Contracts. Unit recognizes revenues and expenses generated from
"daywork" drilling contracts as the services are performed, since the Company
does not bear the risk of completion of the well. Under "footage" and "turnkey"
contracts, Unit bears the risk of completion of the well therefore, revenues and
expenses are recognized when the well is substantially completed. Under this
method, substantial completion is determined when the well bore reaches the
negotiated depth as stated in the contract. The duration of all three types of
contracts range typically from 20 to 90 days, but some of our daywork contracts
in the Rocky Mountains can range up to one year. The entire amount of a loss, if
any, is recorded when the loss is determinable. The costs of uncompleted
drilling contracts include expenses incurred to date on "footage" or "turnkey"
contracts, which are still in process at the end of the period, and are included
in other current assets.
57
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, 2002 and 2003, book overdrafts of $3.6 million and $2.7
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 improvements 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% 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.
58
Goodwill. Goodwill represents the excess of the cost of the acquisition of
Hickman Drilling Company, CREC Rig Equipment Company, CDC Drilling Company and
SerDrilco Incorporated over the fair value of the net assets acquired. Prior to
January 1, 2002 goodwill was amortized on the straight-line method using a 25
year life. Unit expensed $243,000 annually for the amortization of goodwill. On
July 20, 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets" ("FAS 142"). For goodwill and intangible assets recorded in
the financial statements, FAS 142 ends the amortization of goodwill and certain
intangible assets and subsequently requires, at least annually, that an
impairment test be performed on such assets to determine whether the fair value
has decreased. FAS 142 became effective for the fiscal years starting after
December 15, 2001 (January 1, 2002 for Unit). Goodwill is all related to the
drilling segment. The 2002 increase in the carrying amount of goodwill of
$7,706,000 came from the goodwill acquired in the acquisition of CREC Rig
Equipment Company and CDC Drilling Company and the 2003 increase in the carrying
amount of goodwill of $10,928,000 came from the goodwill acquired in the
acquisition of SerDrilco Incorporated. Both acquisitions are more fully
discussed in Note 2. Goodwill of $7,009,000 is expected to be deductible for tax
purposes. The following table shows the adjusted net income and earnings per
share resulting from the removal of the amortization expense (net of income tax)
recognized in the prior periods:
2001 2002 2003
--------- --------- ---------
(In thousands except per
share amounts)
Adjusted Net Income:
Reported net income $ 62,766 $ 18,244 $ 50,189
Add back: goodwill amortized - net
of income tax 88 -- --
--------- --------- ---------
Adjusted net income $ 62,854 $ 18,244 $ 50,189
========= ========= =========
Basic Earnings per Share:
Reported net income $ 1.75 $ 0.47 $ 1.15
Add back: goodwill amortized - net
of income tax -- -- --
--------- --------- ---------
Adjusted net income $ 1.75 $ 0.47 $ 1.15
========= ========= =========
Diluted Earnings per Share:
Reported net income $ 1.73 $ 0.47 $ 1.15
Add back: goodwill amortized - net
of income tax -- -- --
--------- --------- ---------
Adjusted net income $ 1.73 $ 0.47 $ 1.15
========= ========= =========
59
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 $0.91, $1.04 and $1.14 per Mcfe in
2001, 2002 and 2003, 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 $17.5 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 13, such
estimates are imprecise.
No gains or losses are recognized on the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
Unit's contract drilling subsidiary provides drilling services for its
exploration and production subsidiary. The contracts for these services are
issued under the same conditions and rates as the contracts entered into with
unrelated third parties. During 2003, the contract drilling subsidiary drilled
43 wells for our exploration and production subsidiary. As required by the
Securities and Exchange Commission, the profit received by our contract drilling
segment of $2,259,000, $841,000 and $1,883,000 during 2001, 2002 and 2003,
respectively, was used to reduce the carrying value of our oil and natural gas
properties rather than being included in our profits in current operations.
Limited Partnerships. Unit's wholly owned subsidiary, Unit Petroleum Company, is
a general partner in 10 oil and natural gas limited partnerships sold privately
and publicly. Some of Unit's officers, directors and employees own the interests
in most of these partnerships. Unit shares partnership revenues and costs in
accordance with formulas prescribed in each limited partnership agreement. The
partnerships also reimburse Unit for certain administrative costs incurred on
behalf of the partnerships.
Income Taxes. Measurement of current and deferred income tax liabilities and
assets is based on provisions of enacted tax law; the effects of future changes
in tax laws or rates are not included in the measurement. Valuation allowances
are established where necessary to reduce deferred tax assets to the amount
expected to be realized. Income tax expense is the tax payable for the year and
the change during that year in deferred tax assets and liabilities.
60
Natural Gas Balancing. Unit uses the sales method for recording natural gas
sales. This method allows for recognition of revenue, which may be more or less
than our share of pro-rata production from certain wells. Unit estimates its
December 31, 2003 balancing position to be approximately 1.8 Bcf on
under-produced properties and approximately 2.3 Bcf on over-produced properties.
Unit has recorded a receivable of $562,000 on certain wells where we estimated
that insufficient reserves are available for Unit to recover the
under-production from future production volumes. Unit has also recorded a
liability of $1,191,000 on certain properties where we believe there is
insufficient reserves available to allow the under-produced owners to recover
their under-production from future production volumes. Unit's policy is to
expense the pro-rata share of lease operating costs from all wells as incurred.
Such expenses relating to the balancing position on wells in which Unit has
imbalances are not material.
Investments. Unit owns a 40% equity interest in Superior Pipeline Company LLC, a
natural gas gathering and processing company. The investment, including Unit's
share of the equity in the earnings of this company, totaled $3.0 million at
December 31, 2003 and is reported in other assets.
Unit also owns a 16.7% interest carried at cost in Eagle Energy Partnership
I, L.P. ("Eagle") for $2.5 million. Eagle is engaged in the purchase and sale of
natural gas, electricity (or similar electricity based products), future
commodities, and the performance of scheduling and nomination services for both
energy related commodities and similar energy management functions.
Employee and Director Stock Based Compensation. Unit's stock-based compensation
plans, which are explained more fully in Note 6, are accounted for under the
recognition and measurement principles of APB Opinion 25 "Accounting for Stock
Issued to Employees," and related interpretations. 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 2001, 2002 and 2003 no
compensation expense has been recognized. Compensation expense included in
reported net income is Unit's matching 401(k) contribution which was made in
Unit common stock. The following table illustrates the effect on net income and
earnings per share if Unit had applied the fair value recognition provisions of
FASB Statement No. 123, "Accounting for Stock-Based Compensation," to
stock-based employee compensation.
61
2001 2002 2003
--------- --------- ---------
Net Income, as Reported
(In Thousands) $ 62,766 $ 18,244 $ 50,189
Add Stock Based Employee Compensation
Expense Included in Reported Net
Income - Net of Tax 671 669 858
Less Total Stock Based Employee
Compensation Expense Determined
Under Fair Value Based Method
For All Awards (1,615) (1,488) (2,114)
--------- --------- ---------
Pro Forma Net Income $ 61,822 $ 17,425 $ 48,933
========= ========= =========
Basic Earnings per Share:
As reported $ 1.75 $ 0.47 $ 1.15
========= ========= =========
Pro forma $ 1.72 $ 0.45 $ 1.12
========= ========= =========
Diluted Earnings per Share:
As reported $ 1.73 $ 0.47 $ 1.15
========= ========= =========
Pro forma $ 1.71 $ 0.45 $ 1.12
========= ========= =========
The fair value of each option granted is estimated using the Black-Scholes
model. Unit's estimate of stock volatility in 2001, 2002 and 2003 was 0.55, 0.53
and 0.52, respectively, based on previous stock performance. Dividend yield was
estimated to remain at zero with a risk free interest rate of 5.41% in 2001 and
4.24% in 2002 and 2003. Expected life ranged from 1 to 10 years based on prior
experience depending on the vesting periods involved and the make up of
participating employees. The aggregate fair value of options granted during 2002
and 2003 under the Stock Option Plan were $1,669,000 and $1,617,000,
respectively. No options were issued under the Stock Option Plan in 2001. Under
the Non-Employee Directors' Stock Option Plan the aggregate fair value of
options granted during 2001 was $201,000 and $262,000 in 2002 and 2003.
Self Insurance. Unit utilizes self insurance programs for employee group health
and worker's compensation. Self insurance costs are accrued based upon the
aggregate of estimated liabilities for reported claims and claims incurred but
not yet reported. Accrued liabilities include $3,632,000 and $7,990,000 for
employer group health insurance and worker's compensation at December 31, 2002
and 2003, respectively. Unit's exposure (i.e. deductible or retention) per
occurrence ranged from $200,000 for general liability to $1 million for rig
physical damage. Unit has purchased stop-loss coverage
62
in order to limit, to the extent feasible, its per occurrence and aggregate
exposure to certain claims. Following the acquisition of SerDrilco, Unit
continued to use SerDrilco's ERISA governed occupational injury benefit plan to
cover the SerDrilco employees in lieu of covering them under an insured Texas
workers' compensation plan.
Treasury Stock. On August 30, 2001, Unit's Board of Directors authorized the
purchase of up to one million shares of Unit's common stock. The timing of stock
purchases are made at the discretion of management. During 2001, 30,000 shares
were repurchased for $296,000. These shares were used for a portion of the
company match to the 401(k) Employee Thrift Plan. No treasury stock was owned by
Unit at December 31, 2002 and 2003.
Financial Instruments and Concentrations of Credit Risk. Financial instruments,
which potentially subject Unit to concentrations of credit risk, consist
primarily of trade receivables with a variety of national and international oil
and natural gas companies. Unit does not generally require collateral related to
receivables. Such credit risk is considered by management to be limited due to
the large number of customers comprising Unit's customer base. During 2003,
Chesapeake Operating, Inc. was our largest drilling customer and provided 15% of
our total contract drilling revenues. Purchases by Cinergy Marketing & Trading
LP accounted for approximately 17% of Unit's oil and natural gas revenues in
2003 while purchases by Centerpoint Energy Gas accounted for approximately 16%
of Unit's oil and natural gas revenues. Unit owns a 16.7% in Eagle Energy
Partners I LP, whose purchases accounted for 6% of Unit's oil and natural gas
revenues in 2003. In addition, at December 31, 2002 and 2003, Unit had a
concentration of cash of $3.0 million and $3.5 million, respectively, with one
bank.
Hedging Activities. On January 1, 2001, Unit adopted Statement of Financial
Accounting Standard No. 133 (subsequently amended by Financial Accounting
Standard No.'s 137 and 138), "Accounting for Derivative Instruments and Hedging
Activities" ("FAS 133"). This statement requires all derivatives to be
recognized on the balance sheet and measured at fair value. If a derivative is
designated as a cash flow hedge, Unit is required to measure the effectiveness
of the hedge, or the degree that the gain (loss) for the hedging instrument
offsets the loss (gain) on the hedged item, at each reporting period. The
effective portion of the gain (loss) on the derivative instrument is recognized
in other comprehensive income as a component of equity and subsequently
reclassified into earnings when the forecasted transaction affects earnings. The
ineffective portion of a derivative's change in fair value is required to be
recognized in earnings immediately. Derivatives that do not qualify for hedge
treatment under FAS 133 must be recorded at fair value with gains (losses)
recognized in earnings in the period of change.
Unit periodically enters into derivative commodity instruments to hedge its
exposure to price fluctuations on oil and natural gas production. Such
instruments include regulated natural gas and crude oil futures contracts traded
on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps and basic
hedges with major energy derivative product specialists. Initial adoption of
this standard was not material.
63
Unit entered into a collar contract for approximately 25% of its daily
production for January and February of 2001. The collar had a floor of $26.00
and a ceiling of $33.00 and Unit received $0.86 per barrel for entering into the
collar transaction. During the first quarter of 2001, the net effect of this
hedging transaction yielded an increase in oil revenues of $17,200.
During the second quarter of 2001, Unit entered into a natural gas collar
contract for approximately 36% of its June and July 2001 natural gas production,
at a floor price of $4.50 and a ceiling price of $5.95. During the third quarter
of 2001, Unit entered into two natural gas collar contracts for approximately
38% of its September through November 2001 natural gas production. Both
contracts had a floor price of $2.50. One contract had a ceiling price of $3.68
and the other contract had a ceiling price of $4.25. During 2001 natural gas
collar contracts added $2,030,000 to Unit's natural gas revenues.
On April 30, 2002, Unit entered into a collar contract covering
approximately 19% of its natural gas production for the periods of April 1, 2002
through October 31, 2002. The collar had a floor of $3.00 and a ceiling of
$3.98. During the year of 2002, the natural gas hedging transactions increased
natural gas revenues by $40,300. At December 31, 2002, Unit was not holding any
natural gas or oil derivative contracts.
During the first quarter of 2003, Unit entered into two collar contracts
covering approximately 40% of its natural gas production for the periods of
April 1, 2003 through September 30, 2003. One collar had a floor of $4.00 and a
ceiling of $5.75 and the other collar had a floor of $4.50 and a ceiling of
$6.02. Unit also entered into two collar contracts covering approximately 25% of
its oil production for the periods of May 1, 2003 through December 31, 2003. One
collar had a floor of $25.00 and a ceiling of $32.20 and the other collar had a
floor of $26.00 and a ceiling of $31.40. During the year 2003, the collar
contracts decreased natural gas revenues by $6,000 and oil revenues by $5,000.
We did not have any hedging transactions outstanding at December 31, 2003.
Accounting Estimates. The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Impact of Financial Accounting Pronouncements.
On January 1, 2003 the company adopted Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143
establishes an accounting standard requiring the recording of the fair value of
liabilities associated with the retirement of long-lived assets. The company
owns oil and natural gas properties which require expenditures to plug and
abandon the wells when the oil and natural gas reserves in the wells are
depleted. These expenditures under FAS 143 are recorded in the
64
period in which the liability is incurred (at the time the wells are
drilled or acquired). The company does not have any assets restricted for the
purpose of settling the plugging liabilities.
The following table shows the activity for the year ending December 31,
2003 relating to the company's retirement obligation for plugging liability:
Short-Term Long-Term
Plugging Plugging
Liability Liability
------------- -------------
(In Thousands)
Plugging Liability 1/1/03 $ 203 $ 10,632
Accretion of Discount 8 505
Liability Incurred in the Period -- 719
Liability Settled in the Period (65) (120)
Liability Sold (36) (10)
Reclassification of Liability
From Long- to Short-Term 193 (193)
Revision of Estimate -- 158
------------- -------------
Plugging Liability 12/31/03 $ 303 $ 11,691
============= =============
The effect of this change increased net property, plant and equipment by
$13.0 million and liabilities, including deferred tax liabilities, by $11.7
million at January 1, 2003 and decreased net income for the year ended December
31, 2003 by $148,000 ($0.00 per share). The financial statements for the year
ended December 31, 2002 have not been restated and the cumulative effect of the
change of $1.3 million net of tax ($0.03 per share) is shown as a one-time
addition to income in the first quarter of 2003.
65
The following table shows the adjusted net income and earnings per share
resulting from the accretion of the discount and change in the depreciation,
depletion and amortization (both net of income tax) as if the plugging liability
had been recognized in the prior year ended periods:
2000 2001 2002
------------ ------------ ------------
(In thousands except per share amounts)
Adjusted Net Income:
Reported net income $ 34,344 $ 62,766 $ 18,244
Add back:
Decrease in depreciation,
depletion and amortiza-
tion - net of income
tax 80 156 167
Deduct:
Accretion of discount -
net of income tax (231) (260) (296)
------------ ------------ ------------
Adjusted net income $ 34,193 $ 62,662 $ 18,115
============ ============ ============
Basic Earnings per Share:
Reported net income $ 0.96 $ 1.75 $ 0.47
Net adjustment to income
from change in accounting
principle -- (0.01) --
------------ ------------ ------------
Adjusted basic earnings
per share $ 0.96 $ 1.74 $ 0.47
============ ============ ============
Diluted Earnings per Share:
Reported net income $ 0.95 $ 1.73 $ 0.47
Net adjustment to income
from change in accounting
principle -- -- (0.01)
------------ ------------ ------------
Adjusted diluted earnings
per share $ 0.95 $ 1.73 $ 0.46
============ ============ ============
If FAS 143 had been applied at January 1, 2000 and December 31, 2000, 2001
and 2002, the plugging liability would have been $8.0 million, $8.7 million,
$9.7 million and $10.8 million, respectively, assuming the liability was
measured using the information, assumptions and interest rates used as of the
adoption date of January 1, 2003.
On January 17, 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities, an interpretation of ARB 51" ("FIN
46"). The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights ("variable interest entities" or "VIEs") and how to
determine when and which business enterprise should consolidate
66
the VIE. This new model for consolidation applies to an entity which either
(1) the equity investors (if any) do not have a controlling financial interest
or (2) the equity investment at risk is insufficient to finance that entity's
activities without receiving additional subordinated financial support from
other parties. FIN 46, as amended, was effective for Unit in the fourth quarter
of 2003 as it applies to entities created after February 1, 2003. The adoption
of FIN 46 with respect to these entities, did not have an impact on Unit's
financial position or results of operations. For entities created prior to
February 1, 2003, which are not special purpose entities, as defined in FIN 46,
Unit will have to adopt FIN 46, as amended, in the quarter ending March 31,
2004. Unit is still evaluating FIN 46 with regard to these types of entities in
which it has an ownership interest, primarily oil and gas partnerships and its
equity investment in Superior pipeline. FIN 46 may require full consolidation of
these entities which would increase total assets with an offsetting minority
interest for the percentage not owned by Unit. There will be no net impact to
results of operations from the adoption of FIN 46.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (FAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (FAS 142) were issued by the FASB in June
2001 and became effective for Unit on July 1, 2001 and January 1, 2002,
respectively. FAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for using the purchase method. Additionally, FAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. FAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under FAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. Depending on how the accounting and disclosure literature is
applied, oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract oil and natural gas reserves for
both undeveloped and developed leaseholds may be classified separately from oil
and gas properties, as intangible assets on our balance sheets. In addition, the
notes to the Unit's financial statements would include the disclosures required
by FAS 141 and 142 regarding intangibles. To date, Unit, like many other oil and
gas companies, has included oil and gas extraction rights as part of the oil and
gas properties, even after FAS 141 and 142 became effective.
Unit's results of operations and cash flows would not be affected, since
these oil and gas mineral extraction rights would continue to be amortized in
accordance with full cost accounting rules.
At December 31, 2002 and 2003, Unit had undeveloped leaseholds of
approximately $13.2 million and $14.8 million, respectively that would be
classified on its balance sheet as "intangible undeveloped leasehold" and
developed leaseholds of an estimated $18.1 million and $24.6 million,
respectively that would be classified as "intangible developed leasehold" if the
interpretations were applied. This classification would require Unit to make the
disclosures set forth under FAS 142 related to these interests.
67
Unit intends to continue to classify its oil and gas mineral extraction
rights as tangible oil and gas properties until further guidance is provided.
NOTE 2 - ACQUISITIONS
- ---------------------
On December 8, 2003, Unit acquired SerDrilco Incorporated and its
subsidiary, Service Drilling Southwest LLC, for $35.0 million in cash. The terms
of the acquisition include an earn-out provision allowing the sellers to obtain
one-half of the cash flow in excess of $10 million for each of the three years
following the acquisition. The assets of SerDrilco Incorporated included 12
drilling rigs, spare drilling equipment, a fleet of 12 larger trucks and
trailers, various other vehicles and a district office and equipment yard in and
near Borger, Texas. The results of operations for the acquired entity are
included in the statement of operations for the period beginning December 8,
2003 and continuing through December 31, 2003.
Total consideration given in the acquisition was determined based on the
depth capacity of the rigs, the working condition of the rigs and the ability of
the rigs to enhance Unit's ability to provide services and equipment required by
our customers on a timely basis within the Anadarko Basin of Western Oklahoma
and the Texas Panhandle. Unit acquired SerDrilco Incorporated's tax basis in the
property acquired, so a deferred tax liability and goodwill of $10.9 million was
recognized in the recording of the acquisition. The allocation of the total
consideration paid and goodwill recognized for the acquisition is as follows (in
thousands):
Allocation of Total Consideration Paid and
Goodwill Recognized:
Drilling rigs including tubulars $ 31,012
Spare drilling equipment 904
Office, yard & yard equipment 1,200
Trucking fleet 1,486
Other vehicles 398
----------
Total cash consideration 35,000
Goodwill recognized 10,928
----------
Total consideration paid and recognized $ 45,928
==========
68
On August 15, 2002, Unit completed the acquisition of CREC Rig Equipment
Company and CDC Drilling Company ("Cactus Acquisition"). Both of these
acquisitions were stock purchase transactions. Unit issued 6,819,748 shares of
common stock and paid $3,813,053 for all the outstanding shares of CREC Rig
Equipment Company and issued 400,252 shares of common stock and paid $686,947
for all the outstanding shares of CDC Drilling Company. The assets of the
acquired companies included 20 drilling rigs, spare drilling equipment and
vehicles. What we paid in both transactions was determined through arms-length
negotiations between the parties and only the cash portion of the transaction
appears in the investing and financing activities of Unit's Consolidated
Statement of Cash Flows. The results of operations for the acquired entities are
included in the statement of operations for the period beginning August 15, 2002
and continuing through December 31, 2003.
Total consideration given in both the acquisitions was determined based on
the equipment purchased, depth capacity of the rigs, the working condition of
the rigs and the ability of the rigs to enhance Unit's ability to provide
services and equipment required by our customers on a timely basis within the
Anadarko and Gulf Coast areas where the rigs are located. The calculation and
allocation of the total consideration paid for the acquisition are as follows
(in thousands):
Calculation of Consideration Paid:
Unit Corporation common stock
(7,220,000 shares at $16.96556 per share) $ 122,491
Cash 4,500
----------
Total consideration $ 126,991
==========
Allocation of Total Consideration Paid:
Drilling rigs $ 112,994
Spare drilling equipment 3,500
Vehicles 636
Deferred tax asset 2,155
Goodwill 7,706
----------
Total consideration $ 126,991
==========
69
Unaudited summary pro forma results of operations for Unit, reflecting the
Cactus Acquisition as if it had occurred at the beginning of the year ended
December 31, 2001 are as follow:
Year Ended Year Ended
December 31, December 31,
2001 2002
-------------- --------------
(In thousands except per
Per share amounts)
Revenues $ 311,104 $ 215,805
============== ==============
Net Income $ 70,457 $ 15,320
============== ==============
Net Income per
Common Share
(Diluted) $ 1.62 $ 0.34
============== ==============
The pro forma results of operations are not necessarily indicative of the
actual results of operations that would have occurred had the purchase actually
been made at the beginning of the respective periods nor of the results which
may occur in the future.
70
NOTE 3 - EARNINGS PER SHARE
- ---------------------------
The following data shows the amounts used in computing earnings per share.
Weighted
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except per share amounts)
For the Year Ended
December 31, 2001:
Basic earnings per
common share $ 62,766 35,967 $ 1.75
==========
Effect of dilutive
stock options 291
------------- -------------
Diluted earnings per
common share $ 62,766 36,258 $ 1.73
============= ============= ==========
For the Year Ended
December 31, 2002:
Basic earnings per
common share $ 18,244 38,844 $ 0.47
==========
Effect of dilutive
stock options 268
------------- -------------
Diluted earnings per
common share $ 18,244 39,112 $ 0.47
============= ============= ==========
71
Weighted
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- ------------- ----------
(In thousands except)
per share amounts)
For the Year Ended
December 31, 2003:
Basic earnings per
common share:
Income before
change in
accounting
principle $ 48,864 43,616 $ 1.12
Cumulative effect
of change in
accounting
principle net
of income tax 1,325 43,616 0.03
----------- ----------
Net Income $ 50,189 43,616 $ 1.15
=========== ==========
Diluted earnings per
common share:
Weighted average
number of common
shares used in
basic earnings
per common share 43,616
Effect of dilutive
stock options 157
-------------
Weighted average
number of common
shares and
dilutive potential
common shares used
in diluted earnings
per share 43,773
=============
Income before change
in accounting
principle $ 48,864 43,773 $ 1.12
Cumulative effect of
change in
accounting
principle net
of income tax 1,325 43,773 0.03
----------- ----------
Net Income $ 50,189 43,773 $ 1.15
=========== ==========
72
The following options and their average exercise prices were not included
in the computation of diluted earnings per share because the option exercise
prices were greater than the average market price of common shares for the years
ended December 31,:
2001 2002 2003
---------- ---------- ----------
Options 153,000 198,500 137,850
========== ========== ==========
Average Exercise Price $ 16.79 $ 19.01 $ 22.52
========== ========== ==========
NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
- -------------------------------------------------------
Long-term debt consisted of the following as of December 31, 2002 and 2003:
2002 2003
---------- ----------
(In thousands)
Revolving Credit and Term Loan,
with Interest at December 31,
2002 and 2003 of 2.5% and 4.0%,
Respectively $ 30,500 $ 400
Notes Payable for Hickman
Drilling Company Acquisition
with Interest at December 31,
2002 of 4.25% 1,000 --
---------- ----------
31,500 400
Less Current Portion 1,000 --
---------- ----------
Total Long-Term Debt $ 30,500 $ 400
========== ==========
At December 31, 2003, Unit had a $100 million bank loan agreement
consisting of a revolving credit facility through May 1, 2005 and a term loan
thereafter, maturing on May 1, 2008. On January 30, 2004, in conjunction with
Unit's acquisition of PetroCorp Incorporated, Unit replaced its loan agreement
with a revolving credit facility totaling $150 million having a four year term
ending January 30, 2008. Borrowings under the new credit facility are limited to
a commitment amount. Although, the current value of Unit's assets under the
latest loan value computation supported a full $150 million, Unit elected to set
the loan commitment at
73
$120 million in order to reduce financing costs. Unit pays a commitment fee of
..375 of 1% for any unused portion of the commitment amount. Unit paid
origination, agency and syndication fees of $515,000 at the inception of the new
agreement $40,000 of which will be paid annually and the remainder of the fees
will be amortized over the 4 year life of the loan.
The borrowing base under the current credit facility is subject to a
semi-annual re-determination on May 10 and November 10 of each year, beginning
May 10, 2004. The calculation is based primarily on the sum of a percentage of
the discounted future value of Unit's oil and natural gas reserves, as
determined by the banks. In addition, an amount representing a part of the value
of Unit's drilling rig fleet, limited to $20 million, is added to the borrowing
base. Provisions are also in the agreement which allow for one requested special
re-determination of the borrowing base by either the lender or Unit between each
scheduled re-determination date if conditions warrant such a request.
At Unit's election, any portion of the debt outstanding may be fixed at a
Eurodollar Rate for 30, 60, 90 or 180 day terms. During any Eurodollar Rate
funding period the outstanding principal balance of the note to which such
Eurodollar Rate option applies may be repaid upon three days prior notice to the
Administrative Agent. Interest on the Eurodollar Rate is computed at the
Eurodollar Base Rate applicable for the interest period plus 1.00% tp 1.50%
depending on the level of debt as a percentage of the total loan value and
payable at the end of each term or every 90 days whichever is less. Borrowings
not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate
payable at the end of each month and the principal borrowed may be paid anytime
in part or in whole without premium or penalty.
The loan agreement includes prohibitions against:
. the payment of dividends (other than stock dividends) during any fiscal
year in excess of 25% of our consolidated net income for the preceding
fiscal year,
. the incurrence of additional debt with certain very limited exceptions
and
. the creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any of our property, except in favor of
Unit's banks.
The loan agreement also requires that at the end of each quarter:
. consolidated net worth of at least $350 million,
. a current ratio (as defined in the loan agreement) of not less than 1 to
1 and
. a leverage ratio of long-term debt to consolidated EBITDA (as defined in
the loan agreement) for the most recently ended rolling four fiscal
quarters of no greater than 3.25 to 1.0.
74
Other long-term liabilities consisted of the following as of December 31,
2002 and 2003:
2002 2003
---------- ----------
(In thousands)
Separation Benefit Plan $ 2,081 $ 2,545
Deferred Compensation Plan 1,391 1,829
Retirement Agreement 1,412 1,349
Gas Balancing Liability 1,020 1,191
Plugging Liability -- 11,994
---------- ----------
5,904 18,908
Less Current Portion 465 1,015
---------- ----------
Total Other Long-Term Liabilities $ 5,439 $ 17,893
========== ==========
Estimated annual principal payments under the terms of long-term debt and
other long-term liabilities from 2004 through 2008 are $1,015,000, $606,000,
$686,000, $841,000 and $679,000. Based on the borrowing rates currently
available to Unit for debt with similar terms and maturities, long-term debt at
December 31, 2003 approximates its fair value.
75
NOTE 5 - INCOME TAXES
- ---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income to Unit's effective income tax expense
is as follows:
2001 2002 2003
---------- ---------- ----------
(In thousands)
Income Tax Expense Computed by
Applying the Statutory Rate $ 34,538 $ 9,739 $ 27,213
State Income Tax, Net of
Federal Benefit 2,859 834 2,333
Statutory Depletion and Other (1,484) (1,021) (659)
---------- ---------- ----------
Income tax expense $ 35,913 $ 9,552 $ 28,887
========== ========== ==========
Deferred tax assets and liabilities are comprised of the following at
December 31, 2002 and 2003:
2002 2003
----------- -----------
(In thousands)
Deferred Tax Assets:
Allowance for losses
and nondeductible accruals $ 3,942 $ 9,972
Net operating loss carryforward 17,752 20,745
Statutory depletion carryforward 4,231 4,476
Alternative minimum tax credit
carryforward 395 395
----------- -----------
Gross deferred tax assets 26,320 35,588
Deferred Tax Liability:
Depreciation, depletion and
amortization (110,598) (159,990)
----------- -----------
Net deferred tax liability (84,278) (124,402)
Current Deferred Tax Asset 2,042 2,651
----------- -----------
Non-Current - Deferred Tax Liability $ (86,320) $ (127,053)
=========== ===========
76
Realization of the deferred tax asset is dependent on generating sufficient
future taxable income. Although realization is not assured, management believes
it is more likely than not that the deferred tax asset will be realized. The
amount of the deferred tax asset considered realizable, however, could be
reduced in the near-term if estimates of future taxable income are reduced.
At December 31, 2003, Unit has an excess statutory depletion carryforward
of approximately $11,778,000, which may be carried forward indefinitely and is
available to reduce future taxable income, subject to statutory limitations. At
December 31, 2003, Unit has net operating loss carryforwards of approximately
$54,591,000 which expire from 2019 to 2022.
NOTE 6 - EMPLOYEE BENEFIT AND COMPENSATION PLANS
- ------------------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common stock
were authorized for issuance under the Plan. On May 3, 1995, Unit's shareholders
approved and amended the Plan to increase by 250,000 shares the aggregate number
of shares of common stock that could be issued under the Plan. Under the terms
of the Plan, bonuses may be granted to employees in either cash or stock or a
combination thereof, and are payable in a lump sum or in annual installments
subject to certain restrictions. No shares were issued under the Plan in 2001,
2002 and 2003.
Unit also has a Stock Option Plan (the "Option Plan"), which provides for
the granting of options for up to 2,700,000 shares of common stock to officers
and employees. The Option Plan permits the issuance of qualified or nonqualified
stock options. Options granted typically become exercisable at the rate of 20%
per year one year after being granted and expire after 10 years from the
original grant date. The exercise price for options granted under this plan is
the fair market value of the common stock on the date of the grant.
77
Activity pertaining to the Stock Option Plan is as follows:
Weighted
Number Average
of Exercise
Shares Price
----------- ----------
Outstanding at January 1, 2001 719,700 $ 6.87
Exercised (177,200) 3.13
Cancelled (10,400) 10.26
----------- ----------
Outstanding at December 31, 2001 532,100 8.09
Granted 160,000 19.03
Exercised (59,400) 5.67
----------- ----------
Outstanding at December 31, 2002 632,700 11.08
Granted 116,850 22.89
Exercised (202,900) 5.94
Cancelled (9,900) 15.41
----------- ----------
Outstanding at December 31, 2003 536,750 $ 15.52
=========== ==========
Outstanding Options
at December 31, 2003
---------------------------------------
Weighted
Average Weighted
Number Remaining Average
Exercise of Contractual Exercise
Prices Shares Life Price
----------------------- ----------- ----------- -----------
$ 3.00 - $ 4.00 99,600 3.8 years $ 3.52
$ 7.25 - $10.00 45,700 3.2 years $ 8.52
$11.31 - $14.06 3,500 5.8 years $ 13.28
$16.69 - $22.95 387,950 8.6 years $ 19.44
78
Exercisable Options
At December 31, 2003
------------------------
Weighted
Number Average
Exercise of Exercise
Prices Shares Price
------------------------------------ ----------- -----------
$ 2.75 - $ 4.00 99,600 $ 3.52
$ 7.25 - $10.00 45,700 $ 8.52
$11.31 - $14.06 2,500 $ 12.96
$16.69 - $19.04 108,500 $ 17.49
Options for 329,300, 355,100 and 256,300 shares were exercisable with
weighted average exercise prices of $6.25, $7.28 and $5.32 at December 31, 2001,
2002 and 2003, respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock Option
Plan (the "Old Plan") and in February and May 2000, the Board of Directors and
shareholders, respectively, approved the Unit Corporation 2000 Non-Employee
Directors' Stock Option Plan (the "Directors' Plan"). Under the Directors' Plan,
which replaced the Old Plan, an aggregate of 300,000 shares of Unit's common
stock may be issued upon exercise of the stock options. Under the Old Plan, on
the first business day following each annual meeting of stockholders of Unit,
each person who was then a member of the Board of Directors of Unit and who was
not then an employee of Unit or any of its subsidiaries was granted an option to
purchase 2,500 shares of common stock. Under the Directors' Plan, commencing
with the year 2000 annual meeting, the amount granted has been increased to
3,500 shares of common stock. The option price for each stock option is the fair
market value of the common stock on the date the stock options are granted. No
stock options may be exercised during the first six months of its term except in
case of death and no stock options are exercisable after 10 years from the date
of grant.
79
Activity pertaining to the Directors' Plan is as follows:
Weighted
Number Average
of Exercise
Shares Price
----------- ----------
Outstanding at January 1, 2001 95,000 $ 7.03
Granted 17,500 17.54
Exercised (37,000) 6.80
----------- ----------
Outstanding at December 31, 2001 75,500 9.58
Granted 21,000 20.10
Exercised (2,500) 1.75
----------- ----------
Outstanding at December 31, 2002 94,000 12.14
Granted 21,000 20.46
Exercised (34,500) 7.73
----------- ----------
Outstanding at December 31, 2003 80,500 $ 8.94
=========== ==========
Outstanding and
Exercisable Options
at December 31, 2003
---------------------------------------
Weighted
Average Weighted
Number Remaining Average
Exercise of Contractual Exercise
Prices Shares Life Price
----------------------- ----------- ----------- -----------
$ 2.88 - $ 3.75 2,500 0.4 years $ 2.88
$ 6.87 - $ 9.00 15,000 3.8 years $ 7.58
$12.19 - $17.54 21,000 7.0 years $ 15.76
$20.10 - $20.46 42,000 8.8 years $ 20.28
80
Under Unit's 401(k) Employee Thrift Plan, employees who meet specified
service requirements may contribute a percentage of their total compensation, up
to a specified maximum, to the plan. Unit may match each employee's
contribution, up to a specified maximum, in full or on a partial basis. Unit
made discretionary contributions under the plan of 35,016, 87,452 and 61,175
shares of common stock and recognized expense of $1,082,000, $1,079,000 and
$1,365,000 in 2001, 2002 and 2003, respectively.
Unit provides a salary deferral plan ("Deferral Plan") which allows
participants to defer the recognition of salary for income tax purposes until
actual distribution of benefits which occurs at either termination of
employment, death or certain defined unforeseeable emergency hardships. Funds
set aside in a trust to satisfy Unit's obligation under the Deferral Plan at
December 31, 2001, 2002 and 2003 totaled $1,277,000, $1,391,000 and $1,829,000,
respectively. Unit recognizes payroll expense and records a liability at the
time of deferral.
Effective January 1, 1997, Unit adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees whose
employment with Unit is involuntarily terminated or, in the case of an employee
who has completed 20 years of service, voluntarily or involuntarily terminated,
to receive benefits equivalent to 4 weeks salary for every whole year of service
completed with Unit up to a maximum of 104 weeks. To receive payments the
recipient must waive any claims against Unit in exchange for receiving the
separation benefits. On October 28, 1997, Unit adopted a Separation Benefit Plan
for Senior Management ("Senior Plan"). The Senior Plan provides certain officers
and key executives of Unit with benefits generally equivalent to the Separation
Plan. The Compensation Committee of the Board of Directors has absolute
discretion in the selection of the individuals covered in this plan. Unit
recognized expense of $589,000, $619,000 and $707,000 in 2001, 2002 and 2003,
respectively, for benefits associated with anticipated payments from both
separation plans.
Unit has entered into key employee change of control contracts with six of
its current executive officers. These severance contracts have an initial
three-year term that is automatically extended for one year upon each
anniversary, unless a notice not to extend is given by Unit. If a change of
control of the company, as defined in the contracts, occurs during the term of
the severance contract, then the contract becomes operative for a fixed
three-year period. The severance contracts generally provide that the
executive's terms and conditions for employment (including position, work
location, compensation and benefits) will not be adversely changed during the
three-year period after a change of control. If the executive's employment is
terminated (other than for cause, death or disability), the executive terminates
for good reason during such three-year period, or the executive terminates
employment for any reason during the 30-day period following the first
anniversary of the change of control, and upon certain terminations prior to a
change of control or in connection with or in anticipation of a change of
control, the executive is generally entitled to receive, in addition to certain
other benefits, any earned but unpaid compensation; up to 2.9 times the
executive's base salary
81
plus annual bonus (based on historic annual bonus); and the company matching
contributions that would have been made had the executive continued to
participate in the company's 401(k) plan for up to an additional three years.
The severance contract provides that the executive is entitled to receive a
payment in an amount sufficient to make the executive whole for any excise tax
on excess parachute payments imposed under Section 4999 of the Code. As a
condition to receipt of these severance benefits, the executive must remain in
the employ of the company prior to change of control and render services
commensurate with his position.
NOTE 7 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
Unit Petroleum Company serves as the general partner of 10 oil and gas
limited partnerships. Four were formed for investment by third parties and six
(the employee partnerships) were formed to allow employees of Unit and its
subsidiaries and directors of Unit to participate in Unit Petroleum's oil and
gas exploration and production operations. The partnerships for the third party
investments were formed in 1984, 1985 and 1986. An additional third party
partnership, the 1979 Oil and Gas Limited Partnership was dissolved on July 1,
2003. Employee partnerships have been formed for each year beginning with 1984.
Interests in the employee partnerships were offered to the employees of Unit and
its subsidiaries whose annual base compensation was at least a specified amount
($22,680 for 2002 and 2003 and $36,000 for 2004) and to the directors of Unit.
The employee partnerships formed in 1984 through 1990 were consolidated
into a single consolidating partnership in 1993 and the employee partnerships
formed in 1991 through 1999 were also consolidated into the consolidating
partnership in 2002. The consolidation of the 1991 through the 1999 employee
partnerships at the end of last year was done by the general partners under the
authority contained in the respective partnership agreements and did not involve
any vote, consent or approval by the limited partners. The employee partnerships
have each had a set percentage (ranging from 1% to 15%) of our interest in most
of the oil and natural gas wells we drill or acquire for our own account during
the particular year for which the partnership was formed. The total interest the
employees have in our oil and natural gas wells by participating in these
partnerships does not exceed one percent.
82
Amounts received in the years ended December 31 from both public and
private Partnerships for which Unit is a general partner are as follows:
2001 2002 2003
--------- --------- ---------
(In thousands)
Contract Drilling $ 416 $ 209 $ 428
Well Supervision and Other Fees $ 498 $ 510 $ 236
General and Administrative
Expense Reimbursement $ 193 $ 210 $ 209
Related party transactions for contract drilling and well supervision fees
are the related party's share of such costs. These costs are billed to related
parties on the same basis as billings to unrelated parties for such services.
General and administrative reimbursements are both direct general and
administrative expense incurred on the related party's behalf and indirect
expenses allocated to the related parties. Such allocations are based on the
related party's level of activity and are considered by management to be
reasonable.
A subsidiary of Unit paid the Partnerships, for which Unit or a subsidiary
is the general partner, $3,000, $1,000 and $2,000 during the years ended
December 31, 2001, 2002 and 2003, respectively, for purchases of natural gas
production.
Unit owns a 40% equity interest in Superior Pipeline Company LLC, an
Oklahoma Limited Liability Company. Superior is a natural gas gathering and
processing company. The investment, including Unit's share of the equity in the
earnings of this company, totaled $3.0 million at December 31, 2003 and is
reported in other assets in Unit's consolidated balance sheet. During 2003,
Superior Pipeline Company LLC purchased $3.3 million of our natural gas
production and paid $64,000 for our natural gas liquids. We paid this company
$39,000 for gathering and compression services.
Unit also owns a 16.7% limited partnership interest in Eagle Energy
Partnership I, L.P. ("Eagle"), carried at cost, for $2.5 million. Eagle is
engaged in the purchase and sale of natural gas, electricity (or similar
electricity based products), future commodities, and the performance of
scheduling and nomination services for both energy related commodities and
similar energy management functions. Total purchases by Eagle Energy Partnership
I, L.P., which are competitively marketed, accounted for 6% of Unit's oil and
natural gas revenues in 2003. Unit increased its sales to Eagle Energy Partners
I LP since it first starting selling natural gas to them in August, 2003. For
the period August through December 2003 Eagle has purchased 16% of Unit's oil
and natural gas revenues.
83
NOTE 8 - SHAREHOLDER RIGHTS PLAN
- --------------------------------
Unit maintains a Shareholder Rights Plan (the "Plan") designed to deter
coercive or unfair takeover tactics, to prevent a person or group from gaining
control of Unit without offering fair value to all shareholders and to deter
other abusive takeover tactics, which are not in the best interest of
shareholders.
Under the terms of the Plan, each share of common stock is accompanied by
one right, which given certain acquisition and business combination criteria,
entitles the shareholder to purchase from Unit one one-hundredth of a newly
issued share of Series A Participating Cumulative Preferred Stock at a price
subject to adjustment by Unit or to purchase from an acquiring company certain
shares of its common stock or the surviving company's common stock at 50% of its
value.
The rights become exercisable 10 days after Unit learns that an acquiring
person (as defined in the Plan) has acquired 15% or more of the outstanding
common stock of Unit or 10 business days after the commencement of a tender
offer, which would result in a person owning 15% or more of such shares. Unit
can redeem the rights for $0.01 per right at any date prior to the earlier of
(i) the close of business on the 10th day following the time Unit learns that a
person has become an acquiring person or (ii) May 19, 2005 (the "Expiration
Date"). The rights will expire on the Expiration Date, unless redeemed earlier
by Unit.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
- --------------------------------------
Unit leases office space in Tulsa and Woodward Oklahoma and Houston Texas
under the terms of operating leases expiring through January 31, 2010. Future
minimum rental payments under the terms of the leases are approximately
$719,000, $710,000, $714,000, $531,000 and $423,000 in 2004, 2005, 2006, 2007
and 2008, respectively. Total rent expense incurred by the Company was $582,000,
$678,000 and $752,000 in 2001, 2002 and 2003, respectively.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income
Limited Partnership agreements along with the employee oil and gas limited
partnerships require, upon the election of a limited partner, that Unit
repurchase the limited partner's interest at amounts to be determined by
appraisal in the future. Such repurchases in any one year are limited to 20% of
the units outstanding. Unit made repurchases of $1,000 and $106,000 in 2002 and
2003, respectively, for such limited partners' interests. No repurchases were
made in 2001. In 2001, Unit paid $15,000 for interests in two of the Questa
limited partnerships and subsequently dissolved one of the Questa partnerships.
Unit manages its exposure to environmental liabilities on properties to be
acquired by identifying existing problems and assessing the potential liability.
The Company also conducts periodic reviews, on a company-wide basis, to identify
changes in its environmental risk profile. These reviews
84
evaluate whether there is a probable liability, its amount, and the
likelihood that the liability will be incurred. The amount of any potential
liability is determined by considering, among other matters, incremental direct
costs of any likely remediation and the proportionate cost of employees who are
expected to devote a significant amount of time directly to any possible
remediation effort. As it relates to evaluations of purchased properties,
depending on the extent of an identified environmental problem, the Company may
exclude a property from the acquisition, require the seller to remediate the
property to Unit's satisfaction, or agree to assume liability for the
remediation of the property.
We have not historically experienced any environmental liability while
being a contract driller since the greatest portion of risk is borne by the
operator. Any liabilities we have incurred have been small and have been
resolved while the rig is on the location and the cost has been included in the
direct cost of drilling the well.
Unit is a party to various legal proceedings arising in the ordinary course
of its business none of which, in management's opinion, will result in judgments
which would have a material adverse effect on Unit's financial position,
operating results or cash flows.
85
NOTE 10 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
Unit has two business segments: Contract Drilling and Oil and Natural Gas,
representing its two main business units offering different products and
services. The Contract Drilling segment provides land contract drilling of oil
and natural gas wells and the Oil and Natural Gas segment is engaged in the
development, acquisition and production of oil and natural gas properties.
The accounting policies of the segments are the same as those described in
the Summary of Significant Accounting Policies (Note 1). Management evaluates
the performance of Unit's operating segments based on operating income, which is
defined as operating revenues less operating expenses and depreciation,
depletion and amortization. Unit has natural gas production in Canada, which is
not significant.
86
2001 2002 2003
---------- ---------- ----------
(In thousands)
Revenues:
Contract drilling $ 169,301 $ 119,014 $ 188,832
Elimination of intersegment
revenue 2,259 841 5,686
---------- ---------- ----------
Contract drilling net of
intersegment revenue 167,042 118,173 183,146
Oil and natural gas 90,237 67,959 116,609
Other 1,900 1,504 2,829
---------- ---------- ----------
Total revenues $ 259,179 $ 187,636 $ 302,584
========== ========== ==========
Operating Income (1):
Contract drilling $ 62,148 $ 12,151 $ 20,740
Oil and natural gas 45,925 23,826 64,097
---------- ---------- ----------
Total operating income 108,073 35,977 84,837
General and administrative
expense (8,476) (8,712) (9,222)
Interest expense (2,818) (973) (693)
Other income (expense)- net 1,900 1,504 2,829
---------- ---------- ----------
Income before income taxes $ 98,679 $ 27,796 $ 77,751
========== ========== ==========
Identifiable Assets (2):
Contract drilling $ 183,471 $ 299,655 $ 364,855
Oil and natural gas 220,476 261,440 327,172
---------- ---------- ----------
Total identifiable assets 403,947 561,095 692,027
Corporate assets 13,306 17,068 20,898
---------- ---------- ----------
Total assets $ 417,253 $ 578,163 $ 712,925
========== ========== ==========
87
2001 2002 2003
---------- ---------- ----------
(In thousands)
Capital Expenditures:
Contract drilling $ 51,280 $ 139,298 (3) $ 71,899 (4)
Oil and natural gas 56,933 58,778 80,883 (5)
Other 539 516 3,940
---------- ---------- ----------
Total capital
expenditures $ 108,752 $ 198,592 $ 156,722
========== ========== ==========
Depreciation, Depletion,
Amortization and
Impairment:
Contract drilling $ 13,888 $ 14,684 $ 23,644
Oil and natural gas 22,116 23,338 27,343
Other 638 635 796
---------- ---------- ----------
Total depreciation,
depletion,
amortization
and impairment $ 36,642 $ 38,657 $ 51,783
========== ========== ==========
- ----------------------
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not include
non-operating revenues, general corporate expenses, interest expense or
income taxes.
(2) Identifiable assets are those used in Unit's operations in each industry
segment. Corporate assets are principally cash and cash equivalents,
short-term investments, corporate leasehold improvements, furniture and
equipment.
(3) Includes $7.7 million for goodwill and $2.2 million for deferred tax
assets.
(4) Includes $10.9 million for goodwill.
(5) Includes $7.6 million for capitalized cost relating to plugging liability
recorded in 2003.
88
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 2002 and 2003 is as follows:
Three Months Ended
---------------------------------------------------
March 31 June 30 September 30 December 31
----------- ----------- ------------ -----------
(In thousands except per share amounts)
Year Ended
December 31, 2002:
Revenues $ 38,730 $ 44,753 $ 48,272 $ 55,881
=========== =========== ============ ===========
Gross profit(1) $ 6,515 $ 10,295 $ 8,107 $ 11,060
=========== =========== ============ ===========
Income before
income taxes $ 4,254 $ 8,297 $ 6,022 $ 9,223
=========== =========== ============ ===========
Net income(2) $ 2,642 $ 5,108 $ 3,708 $ 6,786
=========== =========== ============ ===========
Earnings per
common share:
Basic (3) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== ============ ===========
Diluted (4) $ 0.07 $ 0.14 $ 0.09 $ 0.16
=========== =========== ============ ===========
Year Ended
December 31, 2003:
Revenues $ 68,446 $ 72,980 $ 78,201 $ 82,957
=========== =========== ============ ===========
Gross profit(1) $ 22,447 $ 20,214 $ 22,251 $ 19,925
=========== =========== ============ ===========
Income before
income taxes
and change in
accounting
principle $ 20,418 $ 18,857 $ 20,598 $ 17,878
=========== =========== ============ ===========
Income before
change in
accounting
principle $ 12,659 $ 11,691 $ 12,763 $ 11,751
=========== =========== ============ ===========
Net Income(2) $ 13,984 $ 11,691 $ 12,763 $ 11,751
=========== =========== ============ ===========
89
Three Months Ended
---------------------------------------------------
March 31 June 30 September 30 December 31
----------- ----------- ------------ -----------
(In thousands except per share amounts)
Earnings Before
Change in
Accounting
Principle per
Common Share:
Basic $ 0.29 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
Diluted $ 0.29 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
Net Income per
Common Share:
Basic $ 0.32 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
Diluted $ 0.32 $ 0.27 $ 0.29 $ 0.27
=========== =========== ============ ===========
- ------------------
(1) Gross profit excludes other revenues, general and administrative expense
and interest expense.
(2) The net income for the three months ended December 31, 2002 and 2003
includes a tax benefit of $1.1 million and $0.8 million, respectively,
relating primarily to an increase in the estimated amount of statutory
depletion carryforward.
(3) Due to the effect of rounding basic earnings per share for the year's four
quarters does not equal the annual earnings per share.
(4) Due to the effect of price changes of Unit's stock, diluted earnings per
share for the year's four quarters, which includes the effect of potential
dilutive common shares calculated during each quarter, does not equal the
annual diluted earnings per share, which includes the effect of such
potential dilutive common shares calculated for the entire year.
90
NOTE 12 - SUBSEQUENT EVENT
- --------------------------
On January 30, 2004 Unit acquired the outstanding common stock of PetroCorp
Incorporated for $182.1 million in cash. PetroCorp Incorporated explored and
developed oil and natural gas properties primarily in Texas and Oklahoma.
Approximately 84% of the oil and natural gas properties acquired in the
acquisition are located in the Mid-Continent and Permian basins, while 6% are
located in the Rocky Mountains and 10% are located in the Gulf Coast basin. The
acquired properties increased Unit's reserve base by approximately 56.7 billion
equivalent cubic feet of natural gas and provide additional locations for
development drilling in the future. With the acquisition of PetroCorp
Incorporated, Unit also entered into a new $150 million credit facility to
replace its existing loan agreement as more fully discussed in Note 4.
The preliminary allocation of the total consideration paid for the
acquisition is as follows (in thousands):
Working Capital $ 93,668
Undeveloped Oil and Natural Gas Properties 6,557
Proved Oil and Natural Gas Properties 114,518
Property and Equipment - Other 401
Other Assets 1,499
Other Long-Term Liabilities (5,557)
Deferred Income Taxes (net) (28,966)
----------
Total consideration $ 182,120
==========
Unaudited summary pro forma results of operations for Unit, reflecting the
above described acquisition as if it had occurred at the beginning of the year
ended December 31, 2002 and December 31, 2003, are as follows, respectively;
revenues, $217.0 million and $339.6 million; income from continuing operations
of $19.5 million and $55.2 million; net income of $19.5 million and $53.5
million; income from continuing operations per common share (diluted) of $0.50
and $1.26 and net income per common shares (diluted) of $0.50 and $1.22. The pro
forma results of operations are not necessarily indicative of the actual results
of operations that would have occurred had the purchase actually been made at
the beginning of the respective period nor of the results which may occur in the
future.
91
NOTE 13 - OIL AND NATURAL GAS INFORMATION
- -----------------------------------------
The capitalized costs at year end and costs incurred during the year were
as follows:
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Capitalized costs:
Proved properties $ 391,216 $ 888 $ 392,104
Unproved properties 14,207 180 14,387
----------- --------- -----------
405,423 1,068 406,491
Accumulated depreciation,
depletion, amortization
and impairment (196,270) (475) (196,745)
----------- --------- -----------
Net capitalized costs $ 209,153 $ 593 $ 209,746
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 7,503 $ 21 $ 7,524
Proved properties acquired 1,419 -- 1,419
Exploration 9,336 -- 9,336
Development 38,359 295 38,654
----------- --------- -----------
Total costs incurred $ 56,617 $ 316 $ 56,933
=========== ========= ===========
2002:
Capitalized costs:
Proved properties $ 448,331 $ 895 $ 449,226
Unproved properties 15,692 332 16,024
----------- --------- -----------
464,023 1,227 465,250
Accumulated depreciation,
depletion, amortization
and impairment (218,956) (520) (219,476)
----------- --------- -----------
Net capitalized costs $ 245,067 $ 707 $ 245,774
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 5,330 $ 152 $ 5,482
Proved properties acquired 13,379 -- 13,379
Exploration 6,591 -- 6,591
Development 33,319 7 33,326
----------- --------- -----------
Total costs incurred $ 58,619 $ 159 $ 58,778
=========== ========= ===========
92
USA Canada Total
----------- --------- -----------
(In thousands)
2003:
Capitalized costs:
Proved properties $ 527,196 $ 914 $ 528,110
Unproved properties 17,149 337 17,486
----------- --------- -----------
544,345 1,251 545,596
Accumulated depreciation,
depletion, amortization
and impairment (240,047) (540) (240,587)
----------- --------- -----------
Net capitalized costs $ 304,298 $ 711 $ 305,009
=========== ========= ===========
Cost incurred:
Unproved properties acquired $ 8,611 $ 19 $ 8,630
Proved properties acquired 2,557 -- 2,557
Exploration 7,071 -- 7,071
Development(1) 62,620 5 62,625
----------- --------- -----------
Total costs incurred $ 80,859 $ 24 $ 80,883
=========== ========= ===========
- ----------------
(1) Includes $7.0 million of capitalized cost for plugging liability recorded
in the first quarter of 2003 for wells drilled in prior years.
The following table shows a summary of the oil and natural gas property
costs not being amortized at December 31, 2003, by the year in which such costs
were incurred.
2000
and
Prior 2001 2002 2003 Total
--------- --------- --------- --------- ---------
(In thousands)
Undeveloped
Leasehold
Acquired $ 3,341 $ 3,272 $ 3,187 $ 7,686 $ 17,486
========= ========= ========= ========= =========
93
The results of operations for producing activities are provided below.
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Revenues $ 86,810 $ 190 $ 87,000
Production costs (18,636) (23) (18,659)
Depreciation, depletion
and amortization (19,756) (40) (19,796)
----------- --------- -----------
48,418 127 48,545
Income tax expense (17,621) (40) (17,661)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 30,797 $ 87 $ 30,884
=========== ========= ===========
2002:
Revenues $ 64,534 $ 87 $ 64,621
Production costs (17,300) (25) (17,325)
Depreciation, depletion
and amortization (22,685) (45) (22,730)
----------- --------- -----------
24,549 17 24,566
Income tax expense (8,436) (5) (8,441)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 16,113 $ 12 $ 16,125
=========== ========= ===========
2003:
Revenues $ 114,398 $ 171 $ 114,569
Production costs (21,366) (21) (21,387)
Depreciation, depletion
and amortization (27,059) (20) (27,079)
----------- --------- -----------
65,973 130 66,103
Income tax expense (24,508) (41) (24,549)
----------- --------- -----------
Results of operations for
producing activities
(excluding corporate
overhead and financing costs) $ 41,465 $ 89 $ 41,554
=========== ========= ===========
94
Estimated quantities of proved developed oil and natural gas reserves and
changes in net quantities of proved developed and undeveloped oil and natural
gas reserves were as follows (unaudited):
USA Canada Total
---------------- ---------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------- -------- ------- --------
(In thousands)
2001:
Proved developed and
undeveloped reserves:
Beginning of year 4,183 215,196 -- 441 4,183 215,637
Revision of previous
estimates (214) (24,253) -- (7) (214) (24,260)
Extensions, discoveries
and other additions 861 54,521 -- -- 861 54,521
Purchases of minerals
in place 8 1,246 -- -- 8 1,246
Sales of minerals in
place (3) (26) -- -- (3) (26)
Production (492) (18,819) -- (45) (492) (18,864)
------- -------- ------- -------- ------- --------
End of Year 4,343 227,865 -- 389 4,343 228,254
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 3,222 162,718 -- 389 3,222 163,107
End of year 2,753 150,419 -- 338 2,753 150,757
2002:
Proved developed and
undeveloped reserves:
Beginning of year 4,343 227,865 -- 389 4,343 228,254
Revision of previous
estimates (166) (10,543) -- (31) (166) (10,574)
Extensions, discoveries
and other additions 230 29,541 -- -- 230 29,541
Purchases of minerals
in place 192 16,558 -- -- 192 16,558
Sales of minerals in
place (30) -- -- -- (30) --
Production (473) (18,927) -- (41) (473) (18,968)
------- -------- ------- -------- ------- --------
End of Year 4,096 244,494 -- 317 4,096 244,811
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 2,753 150,419 -- 338 2,753 150,757
End of year 2,951 168,049 -- 317 2,951 168,366
95
USA Canada Total
---------------- ---------------- ----------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls(1) Mcf Bbls Mcf Bbls Mcf
------- -------- ------- -------- ------- --------
(In thousands)
2003:
Proved developed and
undeveloped reserves:
Beginning of year 4,096 244,494 -- 317 4,096 244,811
Revision of previous
estimates 629 (10,510) -- 371 629 (10,139)
Extensions, discoveries
and other additions 1,000 39,762 -- -- 1,000 39,762
Purchases of minerals
in place 8 437 -- -- 8 437
Sales of minerals
in place (76) (31) -- -- (76) (31)
Production (516) (20,610) -- (38) (516) (20,648)
------- -------- ------- -------- ------- --------
End of Year 5,141 253,542 -- 650 5,141 254,192
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 2,951 168,049 -- 317 2,951 168,366
End of year 3,984 182,203 -- 650 3,984 128,853
- ----------------------
(1) Oil includes natural gas liquids in barrels.
96
Oil and natural gas reserves cannot be measured exactly. Estimates of oil
and natural gas reserves require extensive judgments of reservoir engineering
data and are generally less precise than other estimates made in connection with
financial disclosures. Unit utilizes Ryder Scott Company, independent petroleum
consultants, to review its reserves as prepared by its reservoir engineers.
Proved oil and gas reserves, as defined in SEC Rule 4-10(a), are the
estimated quantities of crude oil, natural gas, and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided only
by contractual arrangements, but not on escalations based upon future
conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes:
. that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
. the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following:
. oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";
. crude oil, natural gas, and natural gas liquids, the recovery of which
is subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors;
. crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
. crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite and other such sources.
97
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
Estimates of oil and natural gas reserves require extensive judgments of
reservoir engineering data as previously explained. Assigning monetary values to
such estimates does not reduce the subjectivity and changing nature of such
reserve estimates. Indeed the uncertainties inherent in the disclosure are
compounded by applying additional estimates of the rates and timing of
production and the costs that will be incurred in developing and producing the
reserves. The information set forth herein is, therefore, subjective and, since
judgments are involved, may not be comparable to estimates submitted by other
oil and natural gas producers. In addition, since prices and costs do not remain
static and no price or cost escalations or de-escalations have been considered,
the results are not necessarily indicative of the estimated fair market value of
estimated proved reserves nor of estimated future cash flows.
98
The standardized measure of discounted future net cash flows ("SMOG") was
calculated using year-end prices and costs, and year-end statutory tax rates,
adjusted for permanent differences, that relate to existing proved oil and
natural gas reserves. SMOG as of December 31 is as follows (unaudited):
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Future cash flows $ 676,051 $ 975 $ 677,026
Future production costs (220,590) (311) (220,901)
Future development costs (58,909) (30) (58,939)
Future income tax expenses (94,037) (134) (94,171)
----------- --------- -----------
Future net cash flows 302,515 500 303,015
10% annual discount for
estimated timing of cash flows (125,238) (194) (125,432)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 177,277 $ 306 $ 177,583
=========== ========= ===========
2002:
Future cash flows $1,256,434 $ 1,400 $1,257,834
Future production costs (320,940) (309) (321,249)
Future development costs (65,266) -- (65,266)
Future income tax expenses (250,413) (233) (250,646)
----------- --------- -----------
Future net cash flows 619,815 858 620,673
10% annual discount for
estimated timing of cash flows (275,015) (344) (275,359)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 344,800 $ 514 $ 345,314
=========== ========= ===========
2003:
Future cash flows $1,548,785 $ 3,500 $1,552,285
Future production costs (418,007) (581) (418,588)
Future development costs (72,891) -- (72,891)
Future income tax expenses (313,827) (805) (314,632)
----------- --------- -----------
Future net cash flows 744,060 2,114 746,174
10% annual discount for
estimated timing of cash flows (325,182) (738) (325,920)
----------- --------- -----------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 418,878 $ 1,376 $ 420,254
=========== ========= ===========
99
The principal sources of changes in the standardized measure of discounted
future net cash flows were as follows (unaudited):
USA Canada Total
----------- --------- -----------
(In thousands)
2001:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (68,174) $ (167) $ (68,341)
Net changes in prices and
production costs (768,295) (1,600) (769,895)
Revisions in quantity
estimates and changes in
production timing (32,705) 13 (32,692)
Extensions, discoveries and
improved recovery, less
related costs 54,127 -- 54,127
Changes in estimated future
development cost 2,673 -- 2,673
Previously estimated cost
incurred during the period 7,361 -- 7,361
Purchases of minerals in place 1,217 -- 1,217
Sales of minerals in place (220) -- (220)
Accretion of discount 99,953 205 100,158
Net change in income taxes 271,421 524 271,945
Other - net (64,668) (108) (64,776)
----------- --------- -----------
Net change (497,310) (1,133) (498,443)
Beginning of year 674,587 1,439 676,026
----------- --------- -----------
End of year $ 177,277 $ 306 $ 177,583
=========== ========= ===========
2002:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (47,230) $ (62) $ (47,292)
Net changes in prices and
production costs 230,934 363 231,297
Revisions in quantity
estimates and changes in
production timing (49,000) (110) (49,110)
Extensions, discoveries and
improved recovery, less
related costs 60,957 -- 60,957
Changes in estimated future
development cost 1,743 -- 1,743
Previously estimated cost
incurred during the period 9,911 30 9,941
Purchases of minerals in place 23,334 -- 23,334
Sales of minerals in place (150) -- (150)
Accretion of discount 23,080 39 23,119
Net change in income taxes (84,843) (59) (84,902)
Other - net (1,213) 7 (1,206)
----------- --------- -----------
Net change 167,523 208 167,731
Beginning of year 177,277 306 177,583
----------- --------- -----------
End of year $ 344,800 $ 514 $ 345,314
=========== ========= ===========
100
USA Canada Total
----------- --------- -----------
(In thousands)
2003:
Sales and transfers of oil and
natural gas produced,
net of production costs $ (93,948) $ (150) $ (94,098)
Net changes in prices and
production costs 65,611 195 65,806
Revisions in quantity
estimates and changes in
production timing (14,637) 1,007 (13,630)
Extensions, discoveries and
improved recovery, less
related costs 113,421 -- 113,421
Changes in estimated future
development cost (5,356) -- (5,356)
Previously estimated cost
incurred during the period 15,664 -- 15,664
Purchases of minerals in place 881 -- 881
Sales of minerals in place (837) -- (837)
Accretion of discount 48,317 66 48,383
Net change in income taxes (38,950) (386) (39,336)
Other - net (16,088) 130 (15,958)
----------- --------- -----------
Net change 74,078 862 74,940
Beginning of year 344,800 514 345,314
----------- --------- -----------
End of year $ 418,878 $ 1,376 $ 420,254
=========== ========= ===========
Unit's SMOG and changes therein were determined in accordance with
Statement of Financial Accounting Standards No. 69. Certain information
concerning the assumptions used in computing SMOG and their inherent limitations
are discussed below. Management believes such information is essential for a
proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those reserves
nor their present worth. Assigning monetary values to the reserve quantity
estimation process does not reduce the subjective and ever-changing nature of
such reserve estimates. Additional subjectivity occurs when determining present
values because the rate of producing the reserves must be estimated. In addition
to difficulty inherent in predicting the future, variations from the expected
production rate could result from factors outside of management's control, such
as unintentional delays in development, environmental concerns or changes in
prices or regulatory controls. Also, the reserve valuation assumes that all
reserves will be disposed of by production. However, other factors such as the
sale of reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end spot prices of oil
$32.52 and natural gas $5.67 relating to proved reserves to the year-end
quantities of those reserves. Future price changes are considered only to the
extent provided by contractual arrangements in existence at year-end.
101
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of existing
economic conditions.
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates to the future pretax net cash flows relating to
proved oil and natural gas reserves less the tax basis of Unit's properties. The
future income tax expenses also give effect to permanent differences and tax
credits and allowances relating to Unit's proved oil and natural gas reserves.
Care should be exercised in the use and interpretation of the above data.
As production occurs over the next several years, the results shown may be
significantly different as changes in production performance, petroleum prices
and costs are likely to occur.
102
REPORT OF INDEPENDENT AUDITORS
The Shareholders and Board of Directors
Unit Corporation
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income, changes in shareholders' equity and
cash flows present fairly in all material respects, the financial position of
Unit Corporation and its subsidiaries at December 31, 2002 and 2003, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003, in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the index appearing under item
15(a)(2), presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these financial statements in accordance
with auditing standards generally accepted in the United States of America which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, effective
January 1, 2003, the Company adopted the requirements of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations."
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 18, 2004
103
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------- ---------------------------------------------------------------
Financial Disclosure.
---------------------
None.
Item 9a. Controls and Procedures.
- -------- -------------------------
(a) Evaluation of Disclosure Controls and Procedures
The company maintains "disclosure controls and procedures," as such
term is defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities
Exchange Act of 1934 (the "Exchange Act"), that are designed to ensure that
information required to be disclosed in reports the company files or
submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in Securities and Exchange
Commission rules and forms, and that such information is collected and
communicated to management, including the company's Chief Executive Officer
and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure. In designing and evaluating its disclosure
controls and procedures, management recognized that no matter how well
conceived and operated, disclosure controls and procedures can provide only
reasonable, not absolute, assurance that the objectives of the disclosure
controls and procedures are met. The company's disclosure controls and
procedures have been designed to meet, and management believes that they
meet, reasonable assurance standards. Based on their evaluation as of the
end of the period covered by this Annual Report on Form 10-K, the Chief
Executive Officer and Chief Financial Officer have concluded that, subject
to the limitations noted above, the company's disclosure controls and
procedures were effective to ensure that material information relating to
the company, including its consolidated subsidiaries, is made known to them
by others within those entities.
(b) Changes in Internal Control Over Financial Reporting
As of the last quarter, there were no changes in the company's
internal control over financial reporting that have materially affected, or
are reasonably likely to materially affect, the company's internal control
over financial reporting.
104
PART III
Item 10. Directors and Executive Officers of the Registrant
- -------- --------------------------------------------------
The information regarding Directors and Executive Officers appearing under
the headings "Item 1: Election of Directors", and "Other Matters" of our 2004
Proxy Statement is incorporated by reference in this section. The information
under the heading "Executive Officers" in Items 1 and 2 of this Form 10-K is
also incorporated by reference in this section.
Item 11. Executive Compensation
- -------- ----------------------
The information appearing under the headings "Directors' Compensation and
Benefits", "Executive Compensation", "Termination of Employment & Change in
Control Arrangements", "Compensation Committee Interlocks and Insider
Participation" and "Report of the Compensation Committee" of our 2004 Proxy
Statement is incorporated by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- -------- --------------------------------------------------------------
and Related Stockholder Matters
-------------------------------
The information appearing under the heasding "Ownership of Our Common Stock
by Beneficial Owners and Management" of our 2004 Proxy Statement is incorporated
by reference.
Item 13. Certain Relationships and Related Transactions
- -------- ----------------------------------------------
The information appearing under the heading "Other Matters" of our 2004
Proxy Statement is incorporated by reference.
ITEM 14. Principal Accounting Fees and Services.
- -------- ---------------------------------------
The information appearing under the headings "Report of Audit Committee",
"Principal Accounting Fees and Services" and "Ratification of Appointment of
Auditors" of our 2004 Proxy Statement is incorporated by reference.
105
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on
- -------- ------------------------------------------------------
Form 8-K
--------
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements:
---------------------
Included in Part II of this report:
Consolidated Balance Sheets as of December 31, 2002 and 2003
Consolidated Statements of Income for the years ended December
31, 2001, 2002 and 2003
Consolidated Statements of Changes in Shareholders' Equity
for the years ended December 31, 2001, 2002 and 2003
Consolidated Statements of Cash Flows for the
years ended December 31, 2001, 2002 and 2003
Notes to Consolidated Financial Statements
Report of Independent Auditors
2. Financial Statement Schedules:
------------------------------
Included in Part IV of this report for the years ended December 31,
2001, 2002 and 2003:
Schedule II - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under
which they are required or because the required information is included
in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers
assigned such exhibits in the Exhibit Table of Item 601 of Regulation
S-K.
3. Exhibits:
--------
2.6.1 Amended and Restated Stock Purchase Agreement dated as of June 24,
2002 by and among Unit Corporation, George B. Kaiser and Kaiser
Francis Oil Company (incorporated herein by reference to Exhibit
99.1 to Form 8-K dated August 27,2002).
2.6.2 Amended and Restated Share Purchase Agreement dated as of June 24,
2002, by and among Unit Corporation, Kaiser Francis Charitable
Income Trust B and Kaiser Francis Oil Company (incorporated herein
by reference to Exhibit 99.2 to Form 8-K dated August 27, 2002).
106
3.1 Restated Certificate of Incorporation of Unit Corporation (filed
as Exhibit 3.1 to Form S-3 (file No. 333-83551), which is
incorporated herein by reference).
3.2 By-Laws of Unit Corporation (filed as Exhibit 3.2 to Unit's Form
8-K to Form S-3 (file No. 333-83551), which is incorporated herein
by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.1 on Form S-3
as S.E.C. File No. 333-83551, which is incorporated herein by
reference).
4.2.6 Rights Agreement between Unit Corporation and Chemical Bank, as
Rights Agent (filed as Exhibit 1 to Unit's Form 8-A filed with the
S.E.C. on May 23, 1995, File No. 1-92601 and incorporated herein
by reference).
4.2.7 First Amendment of Rights Agreement dated May 19, 1995, between
the Company and Mellon Shareholder Services LLC, as Rights Agent
(filed as Exhibit 4 to Unit's Form 8-K dated August 23, 2001,
which is incorporated herein by reference).
4.2.8 Second Amendment of the Rights Agreement, dated August 14, 2002,
between the Company and Mellon Shareholder Services LLC, as Rights
Agent (filed as an Exhibit to Unit's Annual Report under cover of
Form 10-K for the year ended December 31, 2002, which is
incorporated herein by reference).
4.3 Indenture (filed as Exhibit 4.3 to Unit's Form S-3 filed with the
S.E.C. File No. 333-104165, which is incorporated herein by
reference).
10.1.26 Loan Agreement dated January 30, 2004 (filed herein).
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership
(filed as Exhibit I to Unit Drilling and Exploration Company's
Registration Statement on Form S-1 as S.E.C. File No. 2-66347,
which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership
(filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's
Registration Statement Form S-1 as S.E.C. File No. 2-92582, which
is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as
Exhibit 10.16 to Unit's Registration Statement on Form S-4 as
S.E.C. File No. 33-7848, which is incorporated herein by
reference).
10.2.22* The Company's Amended and Restated Stock Option Plan (filed as an
Exhibit to Unit's Registration Statement on Form S-8 as S.E.C.
File No's. 33-19652, 33-44103 and 33-64323 which is incorporated
herein by reference).
107
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan (filed
as an Exhibit to Form S-8 as S.E.C. File No. 33-49724, which is
incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed as an Exhibit to
Form S-8 as S.E.C. File No. 33-53542, which is incorporated herein
by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to Unit's Annual Report under
cover of Form 10-K for the year ended December 31, 1993, which is
incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to
Unit's Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
10.2.30* Separation Benefit Plan of Unit Corporation and Participating
Subsidiaries (filed as an Exhibit to Unit's Annual Report under
the cover of Form 10-K for the year ended December 31, 1996, which
is incorporated herein by reference).
10.2.32* Unit Corporation Separation Benefit Plan for Senior Management
(filed as an Exhibit to Unit's Quarterly Report under cover of
Form 10-Q for the quarter ended September 30, 1997, which is
incorporated herein by reference).
10.2.35 Unit 2000 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to Unit's Annual Report
under the cover of Form 10-K for the year ended December 31,
1999).
10.2.36* Unit Corporation 2000 Non-Employee Directors' Stock Option Plan
(filed as an Exhibit to Form S-8 as S.E.C. File No. 333-38166,
which is incorporated herein by reference).
10.2.37* Unit Corporation's Amended and Restated Stock Option Plan (filed
as an Exhibit to Unit's Registration Statement on Form S-8 as
S.E.C. File No. 333-39584 which is incorporated herein by
reference).
10.2.38 Unit 2001 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to Unit's Annual Report
under the cover of Form 10-K for the year ended December 31,
2000).
10.2.39* Form of Unit Corporation Key Employee Change of Control Contract
entered into with certain of Unit's officers (filed as an Exhibit
to Unit's Annual Report under the cover of Form 10-K for the year
ended December 31, 2000).
10.2.40 Form of Indemnification Agreement entered into between the Company
and its executive officers and directors (filed as Exhibit 10 to
Unit's Form 8-K dated August 23, 2001, which is incorporated
herein by reference).
108
10.2.41 Unit 2002 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to Unit's Annual Report
under cover of Form 10-K for the year ended December 31, 2001).
10.2.42 Unit 2003 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed as an Exhibit to Unit's Annual Report
under cover of Form 10-K for the year ended December 31, 2002).
10.2.43 Unit 2004 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership (filed herein).
21 Subsidiaries of the Registrant (filed herein).
23.1 Consent of Independent Accountants (filed herein).
23.2 Consent of Independent Petroleum Engineers (filed herein).
31.1 Certification of Chief Executive Officer under Rule 13a - 14(a) of
the Exchange Act (filed herein).
31.2 Certification of Chief Financial Officer under Rule 13a -14(a) of
the Exchange Act (filed herein).
32.1 Certification of Chief Executive Officer and Chief Financial
Officer under Rule 13a-14(a) of the Exchange Act and 18 U.S.C.
Section 1350, as adopted under Section 906 of the Sarbanes-Oxley
Act of 2002 (filed herein).
99.2 Separation Agreement, dated May 11, 2001, between the Registrant
and Mr. Kirchner (filed as Exhibit 99.A4 to Unit's Form 8-K dated
May 18, 2001, which is incorporated herein by reference).
* Indicates a management contract or compensatory plan identified pursuant to
the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
On October 22, 2003, we filed a report on Form 8-K under items 7 and
12. This report announced our results of operations and financial
condition for the quarter ended September 30, 2003. The press
release regarding this announcement was furnished as an exhibit.
On October 27, 2003, we filed a report on Form 8-K under items 5 and
7. This report announced that our Board of Directors has elected Mr.
Mark E. Monroe to the Company's Board of Directors. The press
release regarding this announcement was furnished as an exhibit.
109
On November 21, 2003, we filed a report on Form 8-K under items 5
and 7. This report announced that we signed an agreement to acquire
Serdrilco Incorporated and its subsidiary, Service Drilling
Southwest LLC, a U.S. land drilling company located in Borger,
Texas, for $35.0 million in cash and an earn-out provision allowing
the sellers to obtain one-half of the cash flow in excess of $10
million for each of the next three years. The press release
regarding this announcement was furnished as an exhibit.
On December 8, 2003, we filed a report on Form 8-K under items 7 and
9. This report announced the completion of the acquisition of
SerDrilco Incorporated and its subsidiary, Service Drilling
Southwest LLC. We also announced we intend to offer 2 million shares
of our common stock pursuant to an effective shelf registration
statement filed with the Securities and Exchange Commission. The
press releases regarding both of the announcements were furnished as
exhibits.
On December 9, 2003, we filed a report on Form 8-K/A under item 7.
This report updated the proforma financial statements related to the
acquisition of CREC Rig Acquisition Company LLC and CDC Drilling
Company.
On December 10, 2003, we filed a report on Form 8-K under items 7
and 9. This report announced that the previously announced public
offering of 2 million shares of our common stock was priced at
$22.00 per share and we anticipate the transaction will close on
December 15, 2003. The press release regarding this announcement was
furnished as an exhibit.
On December 11, 2003, we filed a report on Form 8-K under items 5
and 7. This report filed exhibits in connection with a prospectus
supplement relating to the issuance and sale in an underwritten
public offering of 2,000,000 shares of the Company's common stock.
110
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance
Balance at Charged to Deductions at
Beginning Costs & & Net End of
Description of Period Expenses Write-Offs Period
----------- ---------- ---------- ---------- ----------
(In thousands)
Year ended
December 31, 2001 $ 919 $ -- $ 315 $ 604
========== ========== ========== ==========
Year ended
December 31, 2002 $ 604 $ 603 $ 4 $ 1,203
========== ========== ========== ==========
Year ended
December 31, 2003 $ 1,203 $ 645 $ 625 $ 1,223
========== ========== ========== ==========
111
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 10, 2004 By: /s/ John G. Nikkel
----------------- ---------------------------
JOHN G. NIKKEL
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities indicated on the 10th day of March, 2004.
Name Title
- ------------------------------- -----------------------------------
/s/ John G. Nikkel
- ------------------------------- Chairman of the Board and Chief
JOHN G. NIKKEL Executive Officer
(Principal Executive Officer)
/s/ Larry D. Pinkston
- ------------------------------- Director, President, Chief
LARRY D. PINKSTON Operating Officer
/s/ David T. Merrill
- ------------------------------- Chief Financial Officer and
DAVID T. MERRILL Treasurer (Principal Financial
Officer)
/s/ Stanley W. Belitz
- ------------------------------- Controller (Principal Accounting
STANLEY W. BELITZ Officer)
/s/ J. Michael Adcock
- ------------------------------- Director
J. MICHAEL ADCOCK
/s/ Don Cook
- ------------------------------- Director
DON COOK
/s/ King P. Kirchner
- ------------------------------- Director
KING P. KIRCHNER
/s/ Mark E. Monroe
- ------------------------------- Director
MARK E. MONROE
/s/ William B. Morgan
- ------------------------------- Director
WILLIAM B. MORGAN
/s/ John H. Williams
- ------------------------------- Director
JOHN H. WILLIAMS
/s/ John S. Zink
- ------------------------------- Director
JOHN S. ZINK
112
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
---------- ------------------------------------------- ----
10.1.26 Loan Agreement dated January 30, 2004.
10.2.43 Unit 2004 Employee Oil and Gas Limited Partnership Agreement of
Limited Partnership.
21 Subsidiaries of the Registrant.
23.1 Consent of Independent Accountants.
23.2 Consent of Independent Petroleum Engineers.
31.1 Certification of Chief Executive Officer under Rule 13a - 14(a) of
the Exchange Act.
31.2 Certification of Chief Financial Officer under Rule 13a -14(a) of
the Exchange Act.
32.1 Certification of Chief Executive Officer and Chief Financial
Officer under Rule 13a-14(a) of the Exchange Act and 18 U.S.C.
Section 1350, as adopted under Section 906 of the Sarbanes-Oxley
Act of 2002.
113