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F O R M 1 0-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 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 ta