--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
FORM 10-K/A
(AMENDMENT NO. 1)
---------------------
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 0-22664
---------------------
PATTERSON-UTI ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 75-2504748
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4510 LAMESA HIGHWAY, SNYDER, TEXAS 79549
(Address of principal executive offices) (Zip Code)
---------------------
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(325) 574-6300
---------------------
SECURITIES REGISTERED PURSUANT TO 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO 12(g) OF THE ACT:
(TITLE OF CLASS)
----------------
Common Stock, $.01 Par Value
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 the Regulation S-K is not contained herein, and will not be contained, to
the best of the 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. [ ]
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant as of January 31, 2003 was $2,267,237,824,
calculated by reference to the closing price of $30.51 for the common stock on
the Nasdaq National Market on that date.
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant as of June 28, 2002, the last business day
of the registrant's most recently completed second fiscal quarter was
$2,065,033,816, calculated by reference to the closing price of $28.23 for the
common stock on the Nasdaq National Market on that date.
As of January 31, 2003, the registrant had outstanding 80,086,023 shares of
common stock, $.01 par value, its only class of voting stock.
Documents incorporated by reference:
Portions of the Definitive Proxy Statement for the 2003 Annual Meeting of
Stockholders filed by the registrant with the Securities and Exchange Commission
on March 24, 2003 (Part III)
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
EXPLANATORY NOTE
We are filing this Amendment No. 1 to our Annual Report on Form 10-K in
response to comments received by us from the Staff of the Securities and
Exchange Commission. Unless otherwise stated, all information contained in this
amendment is as of February 7, 2003, the filing date of our original Annual
Report on Form 10-K for the fiscal year ended December 31, 2002.
---------------------
This Report on Form 10-K/A (including documents incorporated by reference
herein) contains statements with respect to our expectations and beliefs as to
future events. These types of statements are "forward-looking" and subject to
uncertainties. Readers are cautioned that such forward-looking statements should
be read in conjunction with our disclosures under the heading: "Forward Looking
Statements and Cautionary Statements for Purposes of the 'Safe Harbor'
Provisions of the Private Securities Litigation Reform Act of 1995" beginning on
page 15.
This report on Form 10-K/A, along with our quarterly reports on Form 10-Q,
current reports on Form 8-K, and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are
available through our Internet website (www.patenergy.com) as soon as reasonably
practicable after we electronically file such material with, or furnish it to,
the SEC.
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
OVERVIEW
Based on publicly available information, we believe we are the second
largest owner of land-based drilling rigs in North America. Formed in 1978 and
reincorporated in 1993 as a Delaware corporation, we conduct our contract
drilling operations in:
- Texas,
- New Mexico,
- Oklahoma,
- Louisiana,
- Mississippi,
- Utah, and
- Western Canada (Alberta, British Columbia, and Saskatchewan).
As of December 31, 2002, we had a drilling fleet of 324 drilling rigs. A
drilling rig includes the structure, power source, and machinery necessary to
cause a drill bit to penetrate earth to a depth desired by the customer.
We provide drilling fluids, completion fluids, and related services to oil
and natural gas operators in West Texas, Southeast New Mexico, South Texas, East
Texas, Oklahoma, the Gulf Coast regions of Texas and Louisiana, and the Gulf of
Mexico. Drilling and completion fluids are used by oil and natural gas operators
during the drilling process to control pressure when drilling oil and natural
gas wells. We provide pressure pumping services to oil and natural gas operators
in the Appalachian Basin. These services consist primarily of well stimulation
and cementing for completion of new wells and remedial work on existing wells.
We are also engaged in the development, exploration, acquisition and production
of oil and natural gas. Our oil and natural gas operations are focused in
producing regions in West Texas, Southeast New Mexico and South Texas.
1
PATTERSON/UTI MERGER
Patterson Energy, Inc. ("Patterson") and UTI Energy Corp. ("UTI")
consummated a merger on May 8, 2001. The transaction was treated as a
reorganization within the meaning of Section 368 (a) of the Internal Revenue
Code of 1986, as amended, and accounted for as a pooling of interests for
financial accounting purposes. Historical financial statements and related
financial and statistical data contained in this Report have been restated to
provide for the retroactive effect of the merger.
INDUSTRY SEGMENTS
Our revenues, operating profits and identifiable operating assets are
attributable to four industry segments:
- contract drilling,
- drilling and completion fluids services,
- pressure pumping services, and
- oil and natural gas development, exploration, acquisition and production.
With respect to these four segments:
- the contract drilling segment had operating profits in 2000, 2001 and
2002,
- the drilling and completion fluids segment had operating losses in 2000
and 2002 and an operating profit in 2001,
- the pressure pumping segment had operating profits in 2000, 2001 and
2002, and
- the oil and natural gas segment had operating profits in 2000, 2001 and
2002.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and Note 15 of Notes to Consolidated Financial Statements
included as a part of Items 7 and 8, respectively, of this Report for financial
information pertaining to these industry segments.
CONTRACT DRILLING OPERATIONS
GENERAL -- We market our contract drilling services to major and
independent oil and natural gas operators. As of December 31, 2002, we owned 324
drilling rigs which are located in the following regions:
- 262 in Texas and New Mexico (1),
- 41 in Oklahoma,
- 5 in Utah, and
- 16 in Western Canada.
--------------------
(1) 144 in West Texas and New Mexico, 56 in South Texas, 42 in East Texas,
and 20 in North Central Texas.
Of our drilling rigs, 38 are SCR electric rigs and 286 are mechanical rigs.
An electric rig differs from a mechanical rig in that the electric rig converts
the diesel power (the sole energy source for a mechanical rig) into electricity
to power the rig. Our drilling rigs have rated maximum depth capabilities
ranging from 4,000 feet to 30,000 feet.
Drilling rigs are typically equipped with:
- engines,
- drawworks or hoists,
- derricks or masts,
2
- pumps to circulate the drilling fluid,
- blowout preventers,
- drill string (pipe), and
- other related equipment.
Over time, many of the components on a drilling rig are replaced or
rebuilt. We spend significant funds each year on an ongoing program of modifying
and upgrading our drilling rigs to ensure that our drilling equipment is well
maintained and competitive. During fiscal years 2002, 2001, and 2000, we
capitalized approximately $65 million, $151 million, and $117 million,
respectively, to modify and upgrade our drilling rigs.
Depth of the well and drill site conditions are the principal factors in
determining the size of drilling rig used for a particular job. Our drilling
rigs are utilized for both developmental and exploratory drilling and can be
used for either vertical or horizontal drilling.
Our contract drilling operations depend on the availability of:
- drill pipe,
- bits,
- replacement parts and other related rig equipment,
- fuel, and
- qualified personnel,
some of which have been in short supply from time to time.
DRILLING CONTRACTS -- Most of our drilling contracts are with established
customers and are obtained on a competitive bid or negotiated basis. Typically,
the contracts are entered into for short-term periods and cover the drilling of
a single well or a series of wells.
The drilling contracts obligate us to provide and operate a drilling rig
and to pay certain operating expenses, including wages of drilling personnel and
necessary maintenance expenses. The contracts are subject to termination by the
customer on short notice, usually upon payment of a fee. We generally indemnify
our customers against claims by our employees and claims arising from surface
pollution caused by spills of fuel, lubricants, and other solvents within our
control. The customers generally indemnify us against claims arising from other
surface and subsurface pollution, except claims arising from our own gross
negligence.
The contracts provide for payment on a daywork, footage, or turnkey basis,
or a combination thereof. In each case we provide the rig and crews. Our bids
for each contract depend upon:
- the location, depth, and anticipated complexity of the well,
- the on-site drilling conditions,
- the equipment to be used,
- our estimate of the risks involved,
- the estimated duration of the work to be performed,
- the availability of drilling rigs, and
- other factors particular to each proposed well.
DAYWORK CONTRACTS
Under daywork contracts, we provide the drilling rig and crew to the
customer, also known as the operator. The operator supervises the drilling of
the well. Our compensation is based on a negotiated rate per
3
day during the period the drilling rig is utilized. We generally receive a lower
rate when the drilling rig is moving, or when drilling operations are
interrupted or restricted by adverse weather conditions or other conditions
beyond our control. In addition, daywork contracts typically provide for a lump
sum fee for the mobilization and demobilization of the drilling rig.
FOOTAGE CONTRACTS
Under footage contracts, we contract to drill a well to a certain depth
under specified conditions for a fixed price per foot. The customer provides
drilling fluids, casing, cementing, and well design expertise. These contracts
require us to bear the cost of services and supplies that we provide until the
well has been drilled to the agreed depth. If we drill the well in less time
than estimated, we have the opportunity to improve our margins over those that
would be attainable under a daywork contract. Margins are reduced and losses may
be incurred if the well requires more days to drill to the contracted depth than
estimated. Footage contracts generally contain greater risks for a drilling
contractor than daywork contracts. Under footage contracts, the drilling
contractor assumes certain risks associated with loss of the well from fire,
blowouts, and other risks.
TURNKEY CONTRACTS
Under turnkey contracts, we contract to drill a well to a certain depth
under specified conditions for a fixed fee. In a turnkey arrangement, we are
required to bear the costs of services, supplies, and equipment beyond those
typically provided under a footage contract. In addition to the drilling rig and
crew, we are required to provide the drilling and completion fluids, casing,
cementing, and the technical well design and engineering services during the
drilling process. We would also assume certain risks associated with drilling
the well such as fires, blowouts, cratering of the well bore, and other such
risks. Compensation occurs only when the agreed scope of the work has been
completed which requires us to make significant up-front working capital
commitments prior to receiving payments under a turnkey drilling contract. Under
a turnkey contract we have the opportunity to improve our margins if the
drilling process goes as expected and there are no complications or time delays.
However, given the increased exposure we have under a turnkey contract, margins
can be significantly reduced and losses incurred if complications or delays
occur during the drilling process. Turnkey contracts generally involve the
highest degree of risk among the three different types of drilling contracts:
daywork, footage, and turnkey.
The following table sets forth the approximate percentage of our drilling
revenues attributable to daywork, footage, and turnkey contracts for each of the
last three years:
YEAR ENDED DECEMBER 31,
------------------------
TYPE OF REVENUES 2002 2001 2000
---------------- ------ ------ ------
Daywork..................................................... 82% 93% 65%
Footage..................................................... 11 3 24
Turnkey..................................................... 7 4 11
CONTRACT DRILLING ACTIVITY -- The following table sets forth certain
information regarding our contract drilling activity for each of the last three
years:
YEAR ENDED DECEMBER 31,
------------------------
2002 2001 2000
------ ------ ------
Average rigs owned.......................................... 323 302 263
Average rigs operating...................................... 126 211 173
Average rig utilization rate (1)............................ 39% 70% 66%
Number of rigs operated..................................... 230 287 229
Number of wells drilled..................................... 2,012 2,869 2,649
---------------
(1) Rig utilization is based on a 365-day year for rigs owned during 2001 and
2002, and a 366-day year for rigs owned in 2000. A rig is utilized when it
is operating or being moved, assembled, or dismantled under contract.
4
DRILLING RIGS AND RELATED EQUIPMENT -- The following table provides certain
information about our drilling rigs as of December 31, 2002:
DEPTH RATING (FT.) MECHANICAL ELECTRIC
------------------ ---------- --------
4,000 to 9,999.............................................. 52 --
10,000 to 11,999............................................ 67 2
12,000 to 14,999............................................ 114 6
15,000 to 30,000............................................ 53 30
--- ---
Totals................................................. 286 38
=== ===
At December 31, 2002, we owned 244 trucks and 285 trailers used to rig
down, transport, and rig up our drilling rigs. This reduces Patterson-UTI's
dependency upon third parties for these services and enhances the efficiency of
our contract drilling operations particularly in periods of high drilling rig
utilization.
Most repair work and overhauls of our drilling rig equipment are performed
at our yard facilities located in Texas, New Mexico, Oklahoma, and Western
Canada.
DRILLING AND COMPLETION FLUIDS OPERATIONS
GENERAL -- We provide drilling fluids, completion fluids, and related
services to oil and natural gas operators in West Texas, Southeast New Mexico,
South Texas, East Texas, Oklahoma, the Gulf Coast regions of Texas and
Louisiana, and the Gulf of Mexico. We serve our offshore customers through seven
stockpoints located along the Gulf of Mexico in Texas and Louisiana and our
land-based customers through seven stockpoints in Texas, Louisiana, Oklahoma,
and New Mexico.
DRILLING FLUIDS -- Drilling fluid products and systems are used to cool and
lubricate the bit during drilling operations, contain formation pressures
(thereby minimizing blowout risk), suspend and remove rock cuttings from the
hole, and maintain the stability of the wellbore. Technical services are
provided to ensure that the products and systems are applied effectively to
optimize drilling operations.
COMPLETION FLUIDS -- After a well is drilled it undergoes the completion
process wherein the well casing is set and cemented into place. At that point,
the drilling fluid services are complete, and the drilling fluids are circulated
out of the well and replaced with completion fluids. Completion fluids, also
known as clear brine fluids, are solids-free, clear salt solutions that have
high specific gravities. Combined with a range of specialty chemicals, these
fluids are used by operators to control bottom-hole pressures and to meet a
well's specific corrosion, inhibition, viscosity, and fluid loss requirements
during the completion and workover phases.
RAW MATERIALS -- Our drilling and completion fluids operations depend on
the availability of the following raw materials:
DRILLING COMPLETION
-------- -----------------
barite calcium chloride
bentonite calcium bromide
zinc bromide
We obtain these raw materials through purchases made on the spot market and
supply contracts with producers of these raw materials.
BARITE GRINDING FACILITY -- We own and operate a barite grinding facility
equipped with two barite grinding mills located in Houma, Louisiana. We believe
the ability to process our own barite is critical to being competitive on the
Gulf Coast and in the Gulf of Mexico since barite accounts for a substantial
portion of the dollar volume for drilling fluids jobs in both of these areas.
Our grinding facility allows us to grind raw barite into the powder additive
used in drilling fluids. Owning this facility reduces our dependence upon third
parties in our supply of barite. Without the grinding mills we would be required
to purchase processed barite from
5
third parties, including some of our competitors, which could result in higher
production costs and less efficient operations.
OTHER EQUIPMENT -- We own 27 trucks and 102 trailers and lease another 25
trucks used to transport drilling and completion fluids and related equipment.
PRESSURE PUMPING OPERATIONS
GENERAL -- We provide pressure pumping services to oil and natural gas
operators in the Appalachian Basin. Pressure pumping services consist primarily
of well stimulation and cementing for the completion of new wells and remedial
work on existing wells. Most wells drilled in the Appalachian Basin require some
form of fracturing or other stimulation to enhance the flow of oil and natural
gas which is accomplished by pumping fluids under pressure into the well bore.
Generally, Appalachian Basin wells require cementing services before production
commences. Cementing is the process of inserting material between the wall of
the well bore and the casing to center and stabilize the casing.
EQUIPMENT -- Continuous maintenance of our pressure pumping equipment is
necessary as significantly all of the pressure pumping equipment is in use on a
regular basis. As of December 31, 2002, we operated the following pressure
pumping equipment:
- 16 cement pumper trucks,
- 22 fracturing pumper trucks,
- 19 nitrogen pumper trucks,
- 12 blender trucks,
- 10 bulk acid trucks,
- 24 bulk cement trucks,
- 6 bulk nitrogen trucks,
- 22 bulk sand trucks, and
- 8 connection trucks.
OIL AND NATURAL GAS OPERATIONS
GENERAL -- We are engaged in the development, exploration, acquisition, and
production of oil and natural gas. Our oil and natural gas operations are
focused in producing regions in West Texas, Southeast New Mexico, and South
Texas. Our strategy for our oil and natural gas operations is to increase our
reserve base primarily through developmental drilling, as well as selected
acquisitions of leasehold acreage and producing properties.
OIL AND NATURAL GAS RESERVES -- The following table sets forth estimates,
derived from reserve reports provided by M. Brian Wallace, an independent
petroleum engineer, of our proved developed reserves and estimated future net
revenues from our proved developed reserves as of December 31, 2002, 2001, and
2000. The estimates were based upon production histories, current market prices
for oil and natural gas, and other geologic, ownership, and engineering data
provided by us. The present values (discounted at 10% before income taxes) of
estimated future net revenues shown in the table are not intended to represent
the current market value of the estimated oil and natural gas reserves. For
further information concerning the present value of estimated future net
revenues from these proved developed reserves, see also Note 20 of Notes to
Consolidated Financial Statements included as a part of Item 8 of this Report.
Proved oil and natural gas reserves are the estimated quantities of oil and
natural gas which geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Reserves are considered proved if
economical productibility is supported by either actual production or conclusive
formation tests. Proved developed oil and natural gas reserves can be expected
to be recovered through existing wells with existing equipment and operating
methods.
6
AS OF DECEMBER 31,
---------------------------
2002 2001 2000
------- ------- -------
(IN THOUSANDS)
Proved Developed Reserves:
Oil (Bbls)............................................ 1,227 1,047 1,129
Gas (Mcf)............................................. 6,240 4,634 3,880
Total (BOE)........................................... 2,267 1,819 1,776
Estimated future net revenues before income taxes....... $46,016 $19,597 $31,891
Present value of estimated future net revenues before
income taxes, discounted at 10%....................... $32,308 $14,492 $22,801
Standardized measure of discounted future net cash
flows(1).............................................. $21,100 $10,714 $16,640
---------------
(1) For the calculation of standardized measure of discounted future net cash
flows, see Note 20 of Notes to Consolidated Financial Statements included as
a part of Item 8 of this Report.
A barrel (Bbl) of oil is 42 U.S. gallons and represents the basic unit for
measuring production of crude oil and condensate.
An Mcf of natural gas refers to a volume of 1,000 cubic feet under
prescribed conditions of pressure and temperature and represents the basic unit
for measuring volumes of produced natural gas. A barrel of equivalent (BOE) in
reference to natural gas equivalents is determined using the rate of six Mcf of
natural gas (including natural gas liquids) to one Bbl of crude oil or
condensate.
PRODUCTION -- At December 31, 2002, we held a working interest in 305
productive wells, of which 147 were considered oil and 158 were considered
natural gas. A productive well is a well producing oil or natural gas in
commercial quantities. A working interest is the operating interest under an oil
or natural gas lease. It gives the owner the right to explore for and produce
oil or natural gas from the lease. We were the operator of 256 of these wells at
December 31, 2002. The following table sets forth our net oil and natural gas
production, average sales price, and average production costs. Production costs
are costs incurred to operate and maintain our wells and related equipment and
include costs of labor, well service and repair, utilities, field supervision,
property taxes, production and severance taxes and related charges.
YEAR ENDED DECEMBER 31,
------------------------
2002 2001 2000
------ ------ ------
Average net daily production:
Oil (Bbls)............................................... 794 739 752
Gas (Mcf)................................................ 5,109 4,654 3,784
Total (BOE).............................................. 1,646 1,515 1,383
Average sales prices:
Oil (per Bbl)............................................ $25.02 $24.88 $29.99
Gas (per Mcf)............................................ 2.91 4.12 3.87
Average production costs (per BOE)......................... $ 5.11 $ 5.32 $ 6.41
PRODUCTIVE WELLS -- The following table sets forth information regarding
the number of productive wells in which we held a working interest as of the end
of 2002. One or more completions in the same well bore are reflected as one
well.
PRODUCTIVE
WELLS
-------------
GROSS NET
----- -----
Oil......................................................... 147 32.88
Gas......................................................... 158 19.99
--- -----
Total............................................. 305 52.87
=== =====
7
A productive well is a well producing oil or natural gas in commercial
quantities. A working interest is the operating interest under an oil and
natural gas lease. It gives the owner the right to explore for and produce oil
and natural gas from the lease.
DEVELOPED AND UNDEVELOPED ACREAGE -- The following table sets forth the
developed and undeveloped acreage in which we owned a working interest at the
end of 2002:
DEVELOPED ACREAGE UNDEVELOPED ACREAGE
------------------ --------------------
LOCATION GROSS NET GROSS NET
-------- ------- ------- -------- --------
Texas........................................... 57,590 10,219 48,017 9,840
Kansas.......................................... 320 45 -- --
New York........................................ 160 131 -- --
New Mexico...................................... 3,639 443 601 96
Mississippi..................................... 2,000 306 20,000 4,400
Ohio............................................ 880 86 -- --
Pennsylvania.................................... 880 129 -- --
------ ------ ------ ------
Total................................. 65,469 11,359 68,618 14,336
====== ====== ====== ======
Undeveloped acreage is leased acres on which wells have not been drilled to
a point that would permit production of commercial quantities of oil and natural
gas. Developed acreage is leased acres that have been assigned to productive
wells. Our gross acreage is the total number of acres, developed or undeveloped,
in which we own a working interest, regardless of the size of our working
interest in the acreage. Our net acreage is the gross acreage proportionally
reduced by our working interest in the acreage.
Many of our leases summarized in the table above as undeveloped acreage
will expire at the end of their respective primary terms unless production has
been obtained from the acreage prior to that date. If production is obtained,
the lease will remain in effect until the cessation of production. The following
table sets forth the gross and net acreage subject to leases summarized in the
table of undeveloped acreage that will expire:
LEASE ACRES EXPIRING
--------------------
GROSS NET
-------- --------
Years ending:
December 31, 2003........................................... 5,367 1,262
December 31, 2004........................................... 4,871 1,123
December 31, 2005 and later................................. 58,380 11,951
------ ------
Total............................................. 68,618 14,336
====== ======
DRILLING ACTIVITIES -- The following table sets forth the results of our
participation in the drilling of developmental and exploratory wells during
2000, 2001 and 2002:
DEVELOPMENTAL WELLS EXPLORATORY WELLS
---------------------------- ---------------------------
PRODUCTIVE DRY HOLES PRODUCTIVE DRY HOLES
------------- ------------ ------------ ------------
YEAR ENDED DECEMBER 31, GROSS NET GROSS NET GROSS NET GROSS NET
----------------------- ----- ----- ----- ---- ----- ---- ----- ----
2000.................................. 16 3.63 14 3.33 4 0.50 3 0.57
2001.................................. 20 3.82 5 1.06 5 0.87 2 0.56
2002.................................. 24 4.17 11 2.67 6 0.56 1 0.25
-- ----- -- ---- -- ---- -- ----
Total....................... 60 11.62 30 7.06 15 1.93 6 1.38
== ===== == ==== == ==== == ====
Generally, a developmental well is a well that is drilled into an oil and
gas reservoir that is known to be productive. An exploratory well is a well that
is drilled to find oil and gas in an unproved area.
8
CUSTOMERS
The customers of each of our four business segments are operators or
purchasers of oil and natural gas. Our customer base includes both major and
independent oil and natural gas companies. During 2002, no single customer
accounted for 10% or more of our consolidated operating revenues.
COMPETITION
CONTRACT DRILLING AND PRESSURE PUMPING BUSINESSES -- Our land drilling and
pressure pumping businesses are intensely competitive due to the fact that the
supply of available land drilling rigs and pressure pumping equipment exceeds
the demand for those rigs and equipment. This excess capacity has resulted in
substantial competition for drilling and pressure pumping contracts. The fact
that drilling rigs and pressure pumping equipment are mobile and can be moved
from one market to another in response to market conditions heightens the
competition in the industry.
We believe that price competition for drilling and pressure pumping
contracts will continue for the foreseeable future due to the existence of
available rigs and pressure pumping equipment. In addition, some of our
competitors have greater financial resources than we do which may enable them
to:
- better withstand industry downturns,
- compete more effectively on the basis of price, and
- acquire existing rigs or equipment or build new rigs or equipment.
In recent years, many drilling and pressure pumping companies have
consolidated or merged with other companies. Although this consolidation has
decreased the total number of competitors, we believe the competition for
drilling and pressure pumping services will continue to be intense.
DRILLING AND COMPLETION FLUIDS BUSINESS -- The drilling and completion
fluids services industry is highly competitive. Price is generally the most
important competitive factor in the industry. Other competitive factors include
the availability of chemicals and experienced personnel, the reputation of the
fluids services provider in the drilling industry, and our relationship with
existing customers. Some of our competitors have substantially greater resources
and longer operating histories than we have. We believe that competition for
drilling and completion fluids service contracts will continue to be intense.
OIL AND NATURAL GAS BUSINESS -- There is substantial competition for the
acquisition of oil and natural gas leases suitable for development and
exploration and for the hiring of experienced personnel. Our competitors in this
business include:
- major integrated oil and natural gas companies,
- independent oil and natural gas companies,
- drilling and production purchase programs, and
- individual operators.
Our ability to increase our oil and natural gas reserves in the future is
directly dependent upon our ability to select, acquire, and develop suitable
prospects. Many of our competitors have financial resources, staffs, and
facilities greater than ours.
GOVERNMENT AND ENVIRONMENTAL REGULATION
All of our operations and facilities are subject to numerous federal,
state, foreign, and local laws, rules, and regulations related to various
aspects of our business, including:
- drilling of oil and natural gas wells,
- containment and disposal of hazardous materials, oilfield waste, other
waste materials, and acids,
9
- use of underground storage tanks, and
- use of underground injection wells.
To date, we have not been required to expend significant resources in order
to satisfy applicable environmental laws and regulations. We do not anticipate
any material capital expenditures for environmental control facilities or
extraordinary expenditures to comply with environmental rules and regulations in
the foreseeable future. However, compliance costs under existing laws or under
any new requirements could become material and we could incur liability for
noncompliance.
Our business is generally affected by political developments and by
federal, state, foreign, and local laws and regulations, which relate to the oil
and natural gas industry. The adoption of laws and regulations affecting the oil
and natural gas industry for economic, environmental, and other policy reasons
could increase costs relating to drilling and production. They could have an
adverse effect on our operations. Several state and federal environmental laws
and regulations currently apply to our operations and may become more stringent
in the future.
We have utilized operating and disposal practices that were or are
currently standard in the industry. However, hydrocarbons and other materials
may have been disposed of or released in or under properties currently or
formerly owned or operated by us or our predecessors. In addition, some of these
properties have been operated by third parties over whom we have no control
either as to such entities' treatment of hydrocarbon and other materials or the
manner in which such materials may have been disposed of or released.
The federal Comprehensive Environmental Response Compensation and Liability
Act of 1980, commonly known as CERCLA, and comparable state statutes impose
strict liability on:
- owners and operators of sites, and
- persons who disposed of or arranged for the disposal of "hazardous
substances" found at sites.
The federal Resource Conservation and Recovery Act and comparable state
statutes govern the disposal of "hazardous wastes." Although CERCLA currently
excludes petroleum from the definition of "hazardous substances," and the
Resource Conservation and Recovery Act also excludes certain classes of
exploration and production wastes from regulation, such exemptions by Congress
under both CERCLA and the Resource Conservation and Recovery Act may be deleted,
limited, or modified in the future. If such changes are made to CERCLA and/or
the Resource Conservation and Recovery Act, we could be required to remove and
remediate previously disposed of materials (including materials disposed of or
released by prior owners or operators) from properties (including ground water
contaminated with hydrocarbons) and to perform removal or remedial actions to
prevent future contamination.
The Federal Water Pollution Control Act and the Oil Pollution Act of 1990
and implementing regulations govern:
- the prevention of discharges, including oil and produced water spills,
and
- liability for drainage into waters.
The Oil Pollution Act is more comprehensive and stringent than previous oil
pollution liability and prevention laws. It imposes strict liability for a
comprehensive and expansive list of damages from an oil spill into waters from
facilities. Liability may be imposed for oil removal costs and a variety of
public and private damages. Penalties may also be imposed for violation of
federal safety, construction, and operating regulations, and for failure to
report a spill or to cooperate fully in a clean-up.
The Oil Pollution Act also expands the authority and capability of the
federal government to direct and manage oil spill clean-up and operations, and
requires operators to prepare oil spill response plans in cases where it can
reasonably be expected that substantial harm will be done to the environment by
discharges on or into navigable waters. We have spill prevention control and
countermeasure plans in place for our oil and natural gas properties in each of
the areas in which we operate and for each of the stockpoints operated by our
10
drilling and completion fluids business. Failure to comply with ongoing
requirements or inadequate cooperation during a spill event may subject a
responsible party, such as Patterson-UTI, to civil or criminal actions. Although
the liability for owners and operators is the same under the Federal Water
Pollution Act, the damages recoverable under the Oil Pollution Act are
potentially much greater and can include natural resource damages.
Our operations are also subject to federal, state, and local regulations
for the control of air emissions. The federal Clean Air Act and various state
and local laws impose certain air quality requirements on Patterson-UTI.
Amendments to the Clean Air Act revised the definition of "major source" such
that emissions from both wellhead and associated equipment involved in oil and
natural gas production may be added to determine if a source is a "major
source." As a consequence, more facilities may become major sources and thus
would be required to obtain operating permits. This permitting process may
require capital expenditures in order to comply with permit limits.
RISKS AND INSURANCE
Our operations are subject to the many hazards inherent in the drilling
business, including:
- accidents at the work location,
- blow-outs,
- cratering,
- fires, and
- explosions.
These hazards could cause:
- personal injury or death,
- suspension of drilling operations, or
- serious damage or destruction of the equipment involved and, in addition
to environmental damage, could cause substantial damage to producing
formations and surrounding areas.
Damage to the environment, including property contamination in the form of
either soil or ground water contamination, could also result from our
operations, particularly through:
- oil or produced water spillage,
- natural gas leaks, and
- fires.
In addition, we could become subject to liability for reservoir damages.
The occurrence of a significant event, including pollution or environmental
damages, could materially affect our operations and financial condition.
As a protection against operating hazards, we maintain insurance coverage
we believe to be adequate, including:
- all-risk physical damages,
- employer's liability,
- commercial general liability, and
- workers compensation insurance.
We believe that we are adequately insured for public liability and property
damage to others with respect to our operations. However, such insurance may not
be sufficient to protect us against liability for all consequences of:
- personal injury,
- well disasters,
- extensive fire damage,
11
- damage to the environment, or
- other hazards.
We also carry insurance coverage for major physical damage to our drilling
rigs. However, we do not carry insurance against loss of earnings resulting from
such damage. In view of the difficulties that may be encountered in renewing
such insurance at reasonable rates, no assurance can be given that:
- we will be able to maintain the type and amount of coverage that we
believe to be adequate at reasonable rates, or
- any particular types of coverage will be available.
In addition to insurance coverage, we also attempt to obtain
indemnification from our customers for certain of the risks. These indemnity
agreements typically require our customers to hold us harmless in the event of
loss of production or reservoir damage. These contractual indemnifications may
not be supported by adequate insurance maintained by the customer.
EMPLOYEES
We employed approximately 4,607 full-time persons (268 office personnel and
4,339 field personnel) at December 31, 2002. The number of field employees
fluctuates depending on the current and expected demand for our services. We
consider our employee relations to be satisfactory. None of our employees are
represented by a union.
SEASONALITY
Seasonality does not significantly affect our overall operations. However,
our pressure pumping division in Appalachia and our drilling operations in
Canada are subject to slow periods of activity during the spring thaw. In
addition, our drilling operations in Canada are subject to slow periods of
activity during the fall.
RAW MATERIALS AND SUBCONTRACTORS
Patterson-UTI uses many suppliers of raw materials and services. These
materials and services have been and continue to be available. We also utilize
numerous independent subcontractors from various trades.
INCORPORATION BY REFERENCE
The various factors disclosed under the caption "Forward Looking Statements
and Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the
Private Securities Litigation Reform Act of 1995," beginning on page 15 of this
Report, are incorporated by this reference into Items 1 and 2 of this Report.
Readers of this Report should review those factors in conjunction with their
review of Items 1 and 2.
CORPORATE HEADQUARTERS, FIELD OFFICES, AND OTHER FACILITIES
Our corporate headquarters are located in Snyder, Texas. We also have a
number of offices, yard, and stockpoint facilities located in our various
operating areas.
Our corporate headquarters are located at 4510 Lamesa Highway, Snyder,
Texas, and our telephone number at that address is (325) 574-6300. There are a
number of improvements at our headquarters, including:
- an office building with approximately 34,000 square feet of office space
and storage,
- a shop facility with approximately 7,000 square feet used for drilling
equipment repairs and metal fabrication,
- a truck shop facility with approximately 10,000 square feet used to
maintain, overhaul and repair our truck fleet,
12
- an engine shop facility with approximately 20,000 square feet used to
overhaul and repair the engines used to power our drilling rigs, and
- an open-ended metal storage facility with approximately 10,200 square
feet.
We have regional administrative offices, yard, and stockpoint facilities in
many of the areas in which we operate. The facilities are primarily used to
support the day-to-day operations, including the repair and maintenance of
equipment as well as the storage of equipment, inventory, and supplies and to
facilitate administrative responsibilities and sales.
CONTRACT DRILLING OPERATIONS -- Our drilling services are supported by
several administrative offices and yard facilities located throughout our areas
of operations including:
- Texas,
- New Mexico,
- Oklahoma,
- Utah, and
- Western Canada.
DRILLING AND COMPLETION FLUIDS -- Our drilling and completion fluids
services are supported by several administrative offices and stockpoint
facilities located throughout our areas of operations including:
- Texas,
- Louisiana,
- New Mexico, and
- Oklahoma.
PRESSURE PUMPING -- Our pressure pumping services are supported by several
offices and yard facilities located throughout our areas of operations
including:
- Pennsylvania,
- Ohio,
- West Virginia,
- Kentucky, and
- New York.
OIL AND NATURAL GAS -- Our oil and natural gas services are supported by
administrative and field offices in Texas.
We own our headquarters in Snyder and lease the majority of our other
facilities. We do not believe that any of these other facilities are
individually material to our operations. We believe that our existing facilities
are suitable and adequate to meet our needs.
ITEM 3. LEGAL PROCEEDINGS.
Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta, Inc.
("Westfort"), filed a lawsuit against two Patterson-UTI subsidiaries, Patterson
Petroleum LP, and Patterson-UTI Drilling Company LP, in the Circuit Court,
Rankin County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter
agreement entered into in July 2000 between Patterson Petroleum LP and Westfort
concerning the drilling of a daywork well in Mississippi. This lawsuit was filed
by Westfort after Patterson Petroleum LP made demand on Westfort for payment of
the contract drilling services.
In this lawsuit, Westfort alleges breach of contract, fraud, and negligence
causes of action. Westfort seeks alleged monetary damages, the return of shares
of Westfort stock, unspecified damages from alleged lost profits, lost use of
income stream, and additional operating expenses, along with alleged punitive
damages to be determined by the jury, but not less than 25% of Patterson's net
worth. The Company intends to vigorously contest the allegations made by
Westfort and asserts claims against Westfort, including the monies owed
13
Patterson Petroleum LP under the letter agreement in the amount of approximately
$5,075,000. The Company believes that it is remote that the outcome of this
matter will have a material adverse effect on the Company's financial condition
or results of operations.
In addition to the Westfort lawsuit, we are party to various legal
proceedings arising in the normal course of our business. We do not believe that
the outcome of these proceedings, either individually or in the aggregate, will
have a material adverse effect on our financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
14
FORWARD LOOKING STATEMENTS AND CAUTIONARY
STATEMENTS FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Patterson-UTI from time to time makes written or oral forward-looking
statements, including statements contained in this Annual Report on Form 10-K/A,
our other filings with the SEC, press releases, and reports to stockholders.
These forward-looking statements are made pursuant to the "safe harbor"
provisions of the Private Securities Litigation Reform Act of 1995. These
statements include, without limitation, statements relating to liquidity,
financing of operations, sources and sufficiency of funds, and impact of
inflation. The words "believes," "budgeted," "expects," "project," "will,"
"could," "may," "plans," "intends," "strategy," or "anticipates," and similar
expressions are used to identify our forward-looking statements. We do not
undertake to update, revise, or correct any of our forward-looking information.
We include the following cautionary statement in accordance with the "safe
harbor" provisions of the Private Securities Litigation Reform Act of 1995 for
any forward-looking statement made by us, or on our behalf. The factors
identified in this cautionary statement are important factors (but not
necessarily all of the important factors) that could cause actual results to
differ materially from those expressed in any forward-looking statement made by
us, or on our behalf. Where any such forward-looking statement includes a
statement of the assumptions or bases underlying such forward-looking statement,
we caution that, while we believe such assumptions or bases to be reasonable and
make them in good faith, assumed facts or bases almost always vary from actual
results. The differences between assumed facts or bases and actual results can
be material, depending upon the circumstances.
Where, in any forward-looking statement, Patterson-UTI, or our management,
expresses an expectation or belief as to the future results, such expectation or
belief is expressed in good faith and believed to have a reasonable basis.
However, there can be no assurance that the statement of expectation or belief
will result, or be achieved or accomplished. Taking this into account, the
following are identified as important risk factors currently applicable to, or
which could readily be applicable to, Patterson-UTI:
PATTERSON-UTI IS DEPENDENT ON THE OIL AND NATURAL GAS INDUSTRY AND MARKET
PRICES FOR OIL AND NATURAL GAS. DECLINES IN OIL AND NATURAL GAS PRICES HAVE
ADVERSELY AFFECTED OUR OPERATIONS.
Our revenue, profitability, and rate of growth are substantially dependent
upon prevailing prices for oil and natural gas. In recent years, oil and natural
gas prices and, therefore, the level of drilling, exploration, development, and
production, have been extremely volatile. Prices are affected by:
- market supply and demand,
- international military, political, and economic conditions, and
- the ability of the Organization of Petroleum Exporting Countries,
commonly known as OPEC, to set and maintain production and price targets.
All of these factors are beyond our control. Natural gas prices fell from
an average of $4.41 per Mcf in the second quarter of 2001 to an average of $3.41
per Mcf for the same period in 2002. During this same period, the average number
of the Company's rigs operating dropped by approximately 50%. The average market
price of natural gas improved to $4.31 in the fourth quarter of 2002 resulting
in marginal improvement in the average number of rigs operating. We expect oil
and natural gas prices to continue to be volatile and to affect our financial
condition and operations and ability to access sources of capital.
A GENERAL EXCESS OF OPERABLE LAND DRILLING RIGS ADVERSELY AFFECTS OUR PROFIT
MARGINS PARTICULARLY IN TIMES OF WEAKER DEMAND.
The contract drilling business experienced increased demand for drilling
services from 1995 through most of 1997 and from mid-1999 through the second
quarter of 2001. However, except for those periods and other occasional upturns,
generally, there have been substantially more drilling rigs available than
necessary to meet
15
demand in most operational and geographic segments of the North American land
drilling industry. As a result, drilling contractors have had difficulty
sustaining profit margins.
In addition to adverse effects that future declines in demand could have on
Patterson-UTI, ongoing factors which could adversely affect utilization rates
and pricing, even in an environment of stronger oil and natural gas prices and
increased drilling activity, include:
- movement of drilling rigs from region to region,
- reactivation of land-based drilling rigs, or
- new construction of drilling rigs.
We cannot predict either the future level of demand for our contract
drilling services or future conditions in the oil and natural gas contract
drilling business.
SHORTAGES OF DRILL PIPE, REPLACEMENT PARTS, AND OTHER RELATED RIG EQUIPMENT
ADVERSELY AFFECTS PATTERSON-UTI'S OPERATING RESULTS.
During periods of increased demand for drilling services, the industry has
experienced shortages of drill pipe, replacement parts, and other related rig
equipment. These shortages can cause the price of these items to increase
significantly and require that orders for the items be placed well in advance of
expected use. These price increases and delays in delivery may require us to
substantially increase capital expenditures in our contract drilling segment.
Severe shortages could impair our ability to operate our drilling rigs.
THE VARIOUS BUSINESS SEGMENTS IN WHICH WE OPERATE ARE HIGHLY COMPETITIVE WITH
EXCESS CAPACITY WHICH MAY ADVERSELY AFFECT OUR OPERATING RESULTS.
Our land drilling and pressure pumping businesses are intensely competitive
due to the fact that the supply of available land drilling rigs and pressure
pumping equipment exceeds the demand for those rigs and equipment. This excess
capacity has resulted in substantial competition for drilling and pressure
pumping contracts. The fact that drilling rigs and pressure pumping equipment
are mobile and can be moved from one market to another in response to market
conditions heightens the competition in the industry.
Patterson-UTI believes that price competition for drilling and pressure
pumping contracts will continue for the foreseeable future due to the existence
of available rigs and pressure pumping equipment. In addition, some of our
competitors have greater financial resources than we do which may enable them
to:
- better withstand industry downturns,
- compete more effectively on the basis of price, and
- acquire existing rigs or equipment or build new rigs or equipment.
In recent years, many drilling and pressure pumping companies have
consolidated or merged with other companies. Although this consolidation has
decreased the total number of competitors, we believe the competition for
drilling and pressure pumping services will continue to be intense.
The drilling and completion fluids services industry is highly competitive.
Price is generally the most important competitive factor in the industry. Other
competitive factors include the availability of chemicals and experienced
personnel, the reputation of the fluids services provider in the drilling
industry, and our relationship with existing customers. Some of our competitors
have substantially greater resources and longer operating histories than we
have. We believe that competition for our drilling and completion fluids service
contracts will continue to be intense.
LABOR SHORTAGES ADVERSELY AFFECT OUR OPERATING RESULTS.
During periods of increased demand for contract drilling services, the
industry experiences shortages of qualified drilling rig personnel. During these
periods, our ability to attract and retain sufficient qualified personnel to
market and operate our drilling rigs is adversely affected which in turn has a
negative impact on
16
both our operations and profitability. Operationally, it is more difficult to
hire qualified personnel which adversely affects our ability to mobilize
inactive rigs in response to the increased demand for our contract drilling
services. Additionally, wage rates for drilling personnel are likely to
increase, resulting in greater operating costs and reduced operating margins.
During the last upturn in our industry, we experienced an approximate 30% to 40%
increase in wage rates to our drilling personnel which reduced operating
margins.
CONTINUED GROWTH OF PATTERSON-UTI THROUGH RIG ACQUISITION IS NOT ASSURED.
We have increased our drilling rig fleet over the past several years
through mergers and acquisitions. The land drilling industry has experienced
significant consolidation over the past several years, and there can be no
assurance that acquisition opportunities will continue to be available.
Additionally, we are likely to continue to face intense competition from other
companies for available acquisition opportunities.
There can be no assurance that we would:
- have sufficient capital resources to complete additional acquisitions,
- successfully integrate acquired operations and assets,
- be able to manage effectively the growth and increased size,
- be successful in deploying idle or stacked rigs,
- be able to maintain the crews and market share attributable to operating
drilling rigs acquired, or
- be successful in improving our financial condition, results of operation,
business, or prospects in any material manner as a result of any
completed acquisition.
We may incur substantial indebtedness to finance future acquisitions and
also may issue equity securities or convertible securities in connection with
any such acquisitions. Debt service requirements could represent a significant
burden on our results of operations and financial condition and the issuance of
additional equity could be dilutive to our existing stockholders. Also,
continued growth could strain our management, operations, employees, and
resources.
THE NATURE OF OUR BUSINESS OPERATIONS PRESENTS INHERENT RISKS OF LOSS THAT, IF
NOT INSURED OR INDEMNIFIED AGAINST, COULD ADVERSELY AFFECT PATTERSON-UTI'S
OPERATING RESULTS.
Our operations are subject to many hazards inherent in the contract
drilling, pressure pumping, and drilling and completion fluids businesses, which
in turn could cause personal injury or death, work stoppage, or serious damage
to our equipment. Our operations could also cause environmental and reservoir
damages. We maintain insurance coverage and have indemnification agreements with
many of our customers. However, there is no assurance that such insurance or
indemnification agreements would adequately protect Patterson-UTI against
liability or losses from all consequences of the hazards. Additionally, there
can be no assurance that insurance would be available to cover any or all of
these risks, or, even if available, that insurance premiums or other costs would
not rise significantly in the future, so as to make such insurance prohibitive.
We have elected in some cases to accept a greater amount of risk through
increased deductibles on certain insurance policies. For example, we maintain a
$750,000 per occurrence deductible on our workers' compensation insurance
coverage and a $1 million per occurrence deductible on our general liability
insurance coverage. These levels of self-insurance expose us to increased
operating costs and risks.
VIOLATIONS OF ENVIRONMENTAL LAWS AND REGULATIONS COULD MATERIALLY ADVERSELY
AFFECT PATTERSON-UTI OPERATING RESULTS.
The drilling of oil and natural gas wells is subject to various federal,
state, foreign, and local laws, rules, and regulations. The cost to
Patterson-UTI of compliance with these laws and regulations could be
substantial. Failure to comply with these requirements could subject
Patterson-UTI to substantial civil and criminal penalties. In addition, federal
law imposes a variety of regulations on "responsible parties" related to
17
the prevention of oil spills and liability for damages from such spills.
Patterson-UTI, as an owner and operator of land-based drilling rigs may be
deemed to be a responsible party under federal law. Our operations and
facilities are subject to numerous state and federal environmental laws, rules,
and regulations, including, without limitation, laws concerning the containment,
and disposal of hazardous substances, oil field waste and other waste materials,
the use of underground storage tanks and the use of underground injection wells.
SOME OF OUR CONTRACT DRILLING SERVICES ARE DONE UNDER TURNKEY AND FOOTAGE
CONTRACTS, WHICH ARE FINANCIALLY RISKY.
A portion of our contract drilling is done under turnkey and footage
contracts, which involve significant risks. Under turnkey drilling contracts, we
contract to drill a well to a certain depth under specified conditions for a
fixed price. Under footage contracts, we contract to drill a well to a certain
depth under specified conditions at a fixed price per foot. The risk to us under
these types of drilling contracts are greater than on a well drilled on a
daywork basis. Unlike daywork contracts, we must bear the cost of performing
drilling services until the target depth is reached. We must also make
significant up-front working capital commitments prior to receiving payment. In
addition, we must assume most of the risk associated with the drilling
operations, generally assumed by the operator of the well on a daywork contract,
including blowouts, loss of hole from fire, machinery breakdowns, and abnormal
drilling conditions. Accordingly, if severe drilling problems are encountered in
drilling wells under such contracts, we could suffer substantial losses.
ANTI-TAKEOVER MEASURES IN OUR CHARTER DOCUMENTS AND UNDER STATE LAW COULD
DISCOURAGE AN ACQUISITION OF PATTERSON-UTI AND THEREBY AFFECT THE RELATED
PURCHASE PRICE.
Patterson-UTI, as a Delaware corporation, is subject to the Delaware
General Corporation Law, including Section 203, an anti-takeover law enacted in
1988. We have also enacted certain anti-takeover measures, including a
stockholders' rights plan. In addition, our board of directors has the authority
to issue up to one million shares of preferred stock and to determine the price,
rights (including voting rights), conversion ratios, preferences, and privileges
of that stock without further vote or action by the holders of the common stock.
As a result of these measures and others, potential acquirers of Patterson-UTI
may find it more difficult or be discouraged from attempting to effect an
acquisition transaction with us. This may deprive holders of our securities of
certain opportunities to sell or otherwise dispose of the securities at
above-market prices pursuant to any such transactions.
WE HAVE PAID NO DIVIDENDS ON OUR COMMON STOCK AND HAVE NO PLANS TO PAY
DIVIDENDS.
We have not declared or paid cash dividends on our common shares in the
past. We do not expect to declare or pay any cash dividends on our common stock
in the foreseeable future. The terms of our existing credit facility limit
payment of dividends without the prior written consent of the lenders.
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Our common stock, par value $0.01 per share, is publicly traded on the
Nasdaq National Market and is quoted under the symbol "PTEN." In December 2002,
our common stock was added to the Nasdaq-100 Index and in November 2001, our
common stock was added to the S&P MidCap 400 Index. Our common stock is also
included in several other market indexes.
The following table sets forth the high and low sales prices of our common
shares for the periods indicated:
HIGH LOW
------ ------
2002:
First quarter............................................... $29.85 $18.87
Second quarter.............................................. 34.60 26.83
Third quarter............................................... 29.78 20.63
Fourth quarter.............................................. 33.97 23.96
2001:
First quarter............................................... $41.38 $28.62
Second quarter.............................................. 36.83 16.01
Third quarter............................................... 19.49 11.06
Fourth quarter.............................................. 25.73 11.80
As of December 31, 2002, there were approximately 300 holders of record and
approximately 17,000 beneficial holders of our common shares.
We have not declared or paid cash dividends on our common shares in the
past and do not expect to declare or pay any cash dividends on our common stock
in the foreseeable future. Instead, we intend to retain our earnings to support
the operations and growth of our business. Any future cash dividends would
depend on future earnings, capital requirements, financial condition, and other
factors deemed relevant by the board of directors. In addition, the terms of our
existing credit facility limit payment of dividends without the prior written
consent of the lenders.
The following table summarizes as of December 31, 2002, certain information
regarding equity compensation to our employees, officers, directors, and other
persons under our equity compensation plans:
EQUITY COMPENSATION PLAN INFORMATION
--------------------------------------------------------
NUMBER OF
NUMBER OF SECURITIES
SECURITIES TO WEIGHTED- REMAINING AVAILABLE
BE ISSUED UPON AVERAGE EXERCISE FOR FUTURE ISSUANCE
EXERCISE OF PRICE OF UNDER EQUITY
OUTSTANDING OUTSTANDING COMPENSATION PLANS
OPTIONS, OPTIONS, (EXCLUDING
WARRANTS AND WARRANTS AND SECURITIES REFLECTED
PLAN CATEGORY RIGHTS RIGHTS IN COLUMN (A))
------------- -------------- ---------------- --------------------
(A) (B) (C)
Equity compensation plans approved by
security holders....................... 5,157,364 $17.31 877,536
Equity compensation plans not approved by
security holders(1).................... 981,524 $19.15 8,733
--------- ------ -------
Total............................... 6,138,888 $17.61 886,269
========= ====== =======
---------------
(1) The Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan was approved by
the Company's Board of Directors in July 2001. The terms of the Plan provide
for grants of stock options to eligible employees
19
other than officers and directors of the Company. The total number of stock
options that could be granted under the Plan was 1,000,000. No Incentive
Stock Options may be awarded under the Plan. All options are granted with an
exercise price equal to or greater than the fair market value of the
Company's common stock at the time of grant. The vesting schedule and term
are set by the Compensation Committee of the Board of Directors.
Also in July 2001, the Company's Board of Directors approved option grants,
not included in any of the Company's stock option plans, for two
non-employee directors, each covering options to purchase 12,000 shares of
the Company's common stock at an exercise price greater than the fair
market value of the Company's common stock on the grant date. The options
vested in November 2001 and expire in November 2005.
ITEM 6. SELECTED FINANCIAL DATA.
The selected consolidated financial data of Patterson-UTI as of December
31, 2002, 2001, 2000, 1999, and 1998, and for each of the five years then ended
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements and related Notes thereto, included as Items 7 and 8, respectively,
of this document. Historical financial statements as presented herein, have been
restated to provide for the retroactive effect of the merger with UTI Energy
Corp., on May 8, 2001.
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
INCOME STATEMENT DATA:
Operating revenues:
Drilling.............................. $410,295 $839,931 $512,998 $266,212 $329,003
Drilling and completion fluids........ 69,943 94,456 32,053 11,686 13,397
Pressure pumping...................... 32,996 39,600 21,465 20,721 23,365
Oil and natural gas................... 14,723 15,988 15,806 8,563 7,170
Other................................. -- -- -- 184 192
-------- -------- -------- -------- --------
Total.............................. 527,957 989,975 582,322 307,366 373,127
-------- -------- -------- -------- --------
Operating costs and expenses:
Drilling.............................. 318,201 487,343 384,840 224,590 253,768
Drilling and completion fluids........ 60,762 80,034 26,545 9,864 10,205
Pressure pumping...................... 19,802 21,146 13,403 12,219 14,041
Oil and natural gas................... 3,956 5,190 4,872 2,500 3,696
Depreciation, depletion, and
amortization....................... 91,216 86,159 61,464 52,553 51,436
General and administrative............ 26,140 28,561 22,190 17,735 20,004
Bad debt expense...................... 320 2,045 570 282 1,233
Merger costs.......................... -- 5,943 -- -- --
Restructuring and other charges....... 4,700 7,202 -- -- --
Other................................. (538) (820) (147) (2,927) (335)
-------- -------- -------- -------- --------
Total.............................. 524,559 722,803 513,737 316,816 354,048
-------- -------- -------- -------- --------
Operating income (loss)................. 3,398 267,172 68,585 (9,450) 19,079
-------- -------- -------- -------- --------
Other income (expense).................. 441 (677) (8,481) (7,053) (5,953)
-------- -------- -------- -------- --------
Income (loss) before income taxes....... 3,839 266,495 60,104 (16,503) 13,126
20
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Income tax expense (benefit)............ 1,670 102,333 22,878 (4,766) 5,328
-------- -------- -------- -------- --------
Net income (loss)....................... $ 2,169 $164,162 $ 37,226 $(11,737) $ 7,798
======== ======== ======== ======== ========
Net income (loss) per common share:
Basic................................. $ 0.03 $ 2.15 $ 0.52 $ (0.18) $ 0.12
======== ======== ======== ======== ========
Diluted............................... $ 0.03 $ 2.07 $ 0.50 $ (0.18) $ 0.12
======== ======== ======== ======== ========
Weighted average number of common shares
outstanding:
Basic................................. 78,705 76,407 71,207 66,483 63,785
======== ======== ======== ======== ========
Diluted............................... 81,252 79,197 74,841 66,483 65,757
======== ======== ======== ======== ========
BALANCE SHEET DATA:
Current assets.......................... $243,015 $199,458 $237,742 $106,091 $ 94,708
Total assets............................ 942,509 869,642 739,898 496,715 468,554
Current liabilities..................... 75,152 89,286 110,443 60,930 46,871
Long-term debt.......................... -- -- 79,416 82,196 87,435
Stockholders' equity.................... 737,556 687,142 481,299 309,695 300,881
Working capital......................... 167,863 110,172 127,299 45,161 47,837
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
This Item 7 contains forward-looking statements, which are made pursuant to
the "safe harbor" provisions of the Private Securities Litigation Reform Act of
1995.
Commitments and Contingencies -- We have no commitments or contingencies
which would require further disclosure in our financial statements other than
letters of credit totaling $25.5 million at December 31, 2002, maintained for
the benefit of various insurance companies as collateral for retrospective
premiums and retained losses which would become payable under the terms of the
underlying insurance contracts. No amounts have been drawn under the letters of
credit.
Net income for the year ended December 31, 2002 includes a charge of $4.7
million related to the financial failure in 2002 of a workers' compensation
insurance carrier that had provided coverage for the Company in prior years.
Trading and investing -- We have not engaged in trading activities that
include high-risk securities, such as derivatives and non-exchange traded
contracts. We invest cash primarily in highly liquid, short-term investments
such as overnight deposits, money markets, and highly rated municipal and
commercial bonds. However in June 2002 and October 2002, we acquired a total of
1,058,673 shares of common stock of TMBR/Sharp Drilling, Inc., a company whose
stock is traded on the NASDAQ National Market System, for a total of $17.7
million.
Description of business -- We are a leading provider of land-based contract
drilling services to major and independent oil and natural gas operators in
Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Utah, and Western Canada.
As of December 31, 2002, we owned 324 drilling rigs. We provide drilling fluids,
completion fluids, and related services to oil and natural gas operators in West
Texas, Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast
regions of Texas and Louisiana, and the Gulf of Mexico. Drilling and completion
fluids are used by oil and natural gas operators during the drilling process to
control pressure when drilling oil and natural gas wells. We provide pressure
pumping services to oil and natural gas operators in the Appalachian Basin.
These services consist primarily of well stimulation and cementing for
completion of new wells and remedial work on existing wells. We are also engaged
in the development,
21
exploration, acquisition, and production of oil and natural gas. Our oil and
natural gas operations are focused in producing regions in West Texas, Southeast
New Mexico, and South Texas.
The contract drilling business experienced increased demand for drilling
services from 1995 through most of 1997 and from mid-1999 through the second
quarter of 2001. However, except for those periods and other occasional upturns,
generally, there have been substantially more drilling rigs available than
necessary to meet demand in most operational and geographic segments of the
North American land drilling industry. As a result, drilling contractors have
had difficulty sustaining profit margins.
In addition to adverse effects that future declines in demand could have on
Patterson-UTI, ongoing factors which could adversely affect utilization rates
and pricing, even in an environment of stronger oil and natural gas prices and
increased drilling activity, include:
- movement of drilling rigs from region to region,
- reactivation of land-based drilling rigs, or
- new construction of drilling rigs.
We cannot predict either the future level of demand for our contract
drilling services or future conditions in the oil and natural gas contract
drilling business.
CRITICAL ACCOUNTING POLICIES
In addition to established accounting policies, our consolidated financial
statements are impacted by certain estimates and assumptions made by management.
The following is a discussion of our critical accounting policies pertaining to
property and equipment, oil and natural gas properties, impairment, revenue
recognition, and the use of estimates.
Property and equipment -- Property and equipment, including betterments
which extend the useful life of the asset, are stated at cost. Maintenance and
repairs are charged to expense when incurred. We provide for the depreciation of
our property and equipment using the straight-line method over the estimated
useful lives. Our method of depreciation does not change when equipment becomes
idle; we continue to depreciate idled equipment on a straight-line basis. No
provision for salvage value is considered in determining depreciation of our
property and equipment. We review our assets, including intangible assets, for
impairment when events or changes in circumstances indicate that the carrying
values of certain assets either exceed their respective fair values or may not
be recovered over their estimated remaining useful lives. The cyclical nature of
our industry has resulted in fluctuations in rig utilization over periods of
time. Management believes that the contract drilling industry will continue to
be cyclical and rig utilization will fluctuate. Based on management's
expectations of future trends we estimate future cash flows in our assessment of
impairment assuming the following four-year industry cycle: one year projected
with low utilization, one year projected as a recovery period with improving
utilization and the remaining two years projecting higher utilization.
Provisions for asset impairment are charged to income when estimated future cash
flows, on an undiscounted basis, are less than the asset's net book value.
Impairment charges are recorded based on discounted cash flows. There were no
impairment charges during the years 2002, 2001 or 2000.
Oil and natural gas properties -- Oil and natural gas properties are
accounted for using the successful efforts method of accounting. Exploration and
development costs which result directly in the discovery of oil and natural gas
reserves are capitalized to the appropriate well. Exploration costs which do not
result directly in the discovery of oil and natural gas reserves are charged to
expense when such determinations are made. In accordance with paragraph 31(b) of
SFAS 19, costs of exploratory wells are initially capitalized to wells in
progress until the outcome of the drilling is known. We review wells in progress
quarterly to determine the related reserve classification. If the reserve
classification is uncertain after one year following the completion of drilling,
we consider the costs of the well to be impaired and recognize the costs as
expense. Geological and geophysical costs, including seismic costs, and costs to
carry and retain undeveloped properties are charged to expense when incurred.
Capitalized costs of both developmental and successful exploratory type wells,
consisting of lease and well equipment, lease acquisition costs, and intangible
development costs, are
22
depreciated, depleted, and amortized on the units-of-production method, based on
petroleum engineer estimates of proved oil and natural gas reserves of each
respective field. The Company reviews its proved oil and natural gas properties
for impairment when an event occurs such as downward revisions in reserve
estimates or decreases in oil and natural gas prices. Proved properties are
grouped by field and undiscounted cash flow estimates are provided by our
reserve engineer. If the net book value of a field exceeds its undiscounted cash
flow estimate, impairment expense is measured and recognized as the difference
between its net book value and discounted cash flow. Unproved oil and natural
gas properties are reviewed quarterly to determine impairment. The Company's
intent to drill, lease expiration, and abandonment of area are considered.
Assessment of impairment is made on a lease-by-lease basis. If an unproved
property is determined to be impaired, then costs related to that property are
expensed. Impairment expense is included in depreciation, depletion, and
amortization in the accompanying financial statements.
Revenue recognition -- Revenues are recognized when services are performed,
except for revenues earned under turnkey contract drilling arrangements which
are recognized using the completed contract method of accounting, as described
below. The Company follows the percentage-of-completion method of accounting for
footage contract drilling arrangements. Under this method, drilling revenues and
costs related to a well in progress are recognized proportionately over the time
it takes to drill the well. Percentage-of-completion is determined based upon
the amount of expenses incurred through the measurement date as compared to
total estimated expenses to be incurred drilling the well. Under the
percentage-of-completion method, management estimates are relied upon in the
determination of the total estimated expenses to be incurred drilling the well.
Due to the nature of turnkey contract drilling arrangements and risks therein,
the Company follows the completed contract method of accounting for such
arrangements. Under this method, all drilling advances and costs (including
maintenance and repairs) related to a well in progress are deferred and
recognized as revenues and expenses in the period the well is completed.
Provisions for losses on incomplete or in-process wells are made when estimated
total costs are expected to exceed estimated total revenues.
Use of estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
certain estimates and assumptions. These estimates and assumptions affect the
reported amounts of assets and liabilities, the disclosures of contingent assets
and liabilities at the balance sheet date and the amounts of revenues and
expenses recognized during the reporting period. Actual results could differ
from such estimates.
Key estimates used by management include:
- allowance for doubtful accounts,
- depreciation, depletion, and amortization,
- asset impairment,
- reserves for self-insured levels of insurance coverages, and
- fair values of assets and liabilities assumed.
For additional information on our accounting policies, see Note 1 of Notes
to Consolidated Financial Statements included as a part of Item 8 of this
Report.
Related party transactions -- In 2001 and 2000, we leased a 1981 Beech
King-Air 90 airplane owned by SSI Oil and Gas, Inc., an entity beneficially
owned 50% by Cloyce A. Talbott, Patterson-UTI's Chief Executive Officer, and
directly owned 50% by A. Glenn Patterson, Patterson-UTI's President/Chief
Operating Officer. Under the terms of the lease, we paid a monthly rental of
$9,200, the costs of fuel, insurance, taxes, and maintenance of the aircraft.
Such amounts totaled approximately $212,000 and $194,000 for 2001 and 2000,
respectively.
The Company operates certain oil and natural gas properties in which
certain of our affiliated persons have participated, either individually or
through entities they control, in the prospects or properties in which we have
an interest. These participations, which have been on a working interest basis,
have been in prospects or properties originated or acquired by Patterson-UTI. At
December 31, 2002, affiliated persons were working
23
interest owners in 215 of the 256 wells then being operated by Patterson-UTI.
Sales of working interests are made by Patterson-UTI to reduce its economic risk
in the properties. Generally, it is more efficient for Patterson-UTI to sell the
working interests to these affiliated persons than to market them to unrelated
third parties. Sales were made by Patterson-UTI at its cost, comprised of
Patterson-UTI's costs of acquiring and preparing the working interests for sale.
These costs were paid by the working interest owners on a pro rata basis based
upon their working interest ownership percentage. The price at which working
interests were sold to affiliated persons was the same price at which working
interests were sold to unaffiliated persons.
The following table sets forth production revenues received and joint
interest billings paid by each of the affiliated persons during 2002 for all
wells operated by Patterson-UTI in which they have working interests. These
numbers do not necessarily represent their profits or losses from these
interests because the joint interest billings do not include the parties'
related drilling and leasehold acquisition costs incurred prior to January 1,
2002.
YEAR ENDED
DECEMBER 31, 2002
---------------------------
PRODUCTION JOINT
REVENUES INTEREST
NAME RECEIVED (1) BILLINGS (2)
---- ------------ ------------
Cloyce A. Talbott........................................... $ 178,277 $ 81,371
Anita Talbott (3)........................................... 91,268 52,359
Jana Talbott, Executrix to the Estate of Steve Talbott
(3)....................................................... 11,471 6,097
Stan Talbott (3)............................................ 25,922 14,084
John Evan Talbott Trust (3)................................. 2,298 1,024
Lisa Beck and Stacy Talbott (3)............................. 542,625 185,207
SSI Oil & Gas, Inc. (4)..................................... 271,808 182,538
IDC Enterprises, Ltd. (5)................................... 5,559,548 4,751,785
SSSL, Ltd. (6) (8).......................................... -- 13,380
---------- ----------
Subtotal.................................................. 6,683,217 5,287,845
---------- ----------
A. Glenn Patterson.......................................... 127,160 47,246
Glenn Patterson Family Limited Partnership (7) (8).......... -- 13,365
Robert Patterson (7)........................................ 8,893 2,684
Thomas M. Patterson (7)..................................... 8,893 2,684
---------- ----------
Subtotal.................................................. 144,946 65,979
---------- ----------
Jonathan D. Nelson.......................................... 60,571 151,649
Steve DeGroat............................................... 16,390 5,440
---------- ----------
Subtotal.................................................. 76,961 157,089
---------- ----------
Total.................................................. $6,905,124 $5,510,913
========== ==========
---------------
(1) Revenues received for production of oil and natural gas, net of state
severance taxes.
(2) Includes leasehold costs, tangible equipment costs, intangible drilling
costs, and lease operating expense billed during that period. All joint
interest billings have been paid on a timely basis.
(3) Anita Talbott is the wife of Cloyce A. Talbott. Stan Talbott, Lisa Beck, and
Stacy Talbott are Mr. Talbott's adult children. Steve Talbott is the
deceased son of Mr. Talbott. John Evan Talbott is Mr. Talbott's grandson.
(4) SSI Oil & Gas, Inc. is beneficially owned 50% by Cloyce A. Talbott and
directly owned 50% by A. Glenn Patterson.
(5) IDC Enterprises, Ltd. is 50% owned by Cloyce A. Talbott and 50% owned by A.
Glenn Patterson.
(6) SSSL, Ltd. is a limited partnership in which children and grandchildren of
Mr. Talbott are beneficiaries and Mr. Talbott is the general partner.
24
(7) Robert and Thomas M. Patterson are A. Glenn Patterson's adult children. The
Glenn Patterson Family Limited Partnership is a partnership in which each of
Mr. Patterson's children shares equally and Mr. Patterson is the manager.
(8) Revenues included in IDC Enterprises, Ltd. revenues.
In 2002 and 2001, we paid approximately $279,000 and $387,000,
respectively, to TMP Truck and Trailer LP ("TMP"), an entity owned by Thomas M.
Patterson (son of A. Glenn Patterson), for certain equipment and metal
fabrication services. Purchases from TMP were at then current market prices.
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2002, we had working capital of approximately $167.9
million including cash and cash equivalents of approximately $82.2 million. For
2002, our significant sources of cash flow were:
- $131.4 million derived from operations,
- $15.7 million from the exercise of stock options and warrants, and
- $1.8 million from the sale of certain property and equipment.
Correspondingly, we used approximately $17.7 million to acquire 1,058,673
common shares of TMBR/Sharp Drilling, Inc. (see Note 6 of Notes to Consolidated
Financial Statements included as part of Item 8 to this Report), and
approximately $83.8 million:
- to make capital expenditures for the betterment and refurbishment of our
drilling rigs,
- for the acquisition and procurement of drilling equipment,
- to fund capital expenditures for our drilling and completion fluids and
pressure pumping divisions, and
- to fund leasehold acquisition and development and exploration of oil and
natural gas properties.
On March 21, 2002, we acquired five SCR electric land-based drilling rigs
from Odin Drilling, Inc., increasing our land-based drilling fleet to 324. The
purchase price of $16.9 million consisted of 650,000 shares of our common stock
valued at $26.06 per share. A deferred tax liability of $4.1 million was
recorded as a result of the transaction. The transaction was accounted for as a
purchase and the related purchase price was allocated among the rigs based on
their estimated fair values.
Subsequent to December 31, 2002, the Company purchased seven drilling rigs,
in two separate transactions, for an aggregate purchase price of $16.5 million
in cash. The acquisitions were funded out of the Company's existing cash.
We believe that the current level of cash and short-term investments,
together with cash generated from operations, should be sufficient to meet our
capital needs. From time to time, acquisition opportunities are reviewed
relating to our business. The timing, size or success of any acquisition and the
associated capital commitments are unpredictable. Over the longer term, should
further opportunities for growth requiring capital arise, we believe we would be
able to satisfy these needs through a combination of working capital, cash
generated from operations, and either debt or equity financing. However, there
can be no assurance that such capital would be available.
25
RESULTS OF OPERATIONS
COMPARISON OF THE YEARS ENDED DECEMBER 31, 2002 AND 2001
The following tables summarize operations by business segment for the
twelve months ended December 31, 2002 and 2001:
YEAR ENDED DECEMBER 31,
------------------------------
CONTRACT DRILLING 2002 2001 % CHANGE
----------------- -------- -------- --------
(DOLLARS IN 000'S)
Revenues.............................................. $410,295 $839,931 (51.2)%
Direct operating costs................................ $318,201 $487,343 (34.7)%
Selling, general, and administrative.................. $ 3,987 $ 5,277 (24.4)%
Depreciation and amortization......................... $ 80,500 $ 72,797 10.6%
Operating income...................................... $ 7,607 $274,514 (97.2)%
Operating days........................................ 45,919 76,871 (40.3)%
Average revenue per operating day..................... $ 8.94 $ 10.93 (18.2)%
Average direct operating cost per operating day....... $ 6.93 $ 6.34 9.3%
Average margin per operating day...................... $ 2.01 $ 4.59 (56.2)%
Number of owned rigs at end of period................. 324 319 1.6%
Average number of rigs owned during period............ 323 302 7.0%
Average rigs operating................................ 126 211 (40.3)%
Rig utilization percentage............................ 39% 70% (44.3)%
Capital expenditures.................................. $ 64,821 $150,788 (57.0)%
The following table illustrates the average market price of natural gas and
our average rigs operating for each of the fiscal quarters in 2002 and 2001:
1ST 2ND 3RD 4TH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
2002:
Average natural gas price........................... $2.51 $3.41 $3.20 $4.31
Average rigs operating.............................. 117 119 127 140
2001:
Average natural gas price........................... $6.23 $4.41 $2.78 $2.70
Average rigs operating.............................. 231 248 225 140
Our rig count began to decline in the third quarter of 2001 and continued
until March 2002 when our rig count bottomed at 103 rigs (90 rigs in the U.S.
and 13 rigs in Canada). The deterioration in our rig count was primarily the
result of weakening natural gas prices through mid-February 2002. Natural gas
prices then rebounded somewhat and our rig count improved marginally during the
period from March through September 2002. In the fourth quarter of 2002,
consistent with improved natural gas prices, our rig count continued to improve
and averaged 140 rigs (132 rigs in the U.S. and 8 rigs in Canada).
The decreased operating results in 2002 were reflective of a significant
decline in demand for our contract drilling services as evidenced by decreases
in the number of operating days and average rig utilization. Increased
competition during 2002 for available jobs resulted in downward pricing pressure
and decreased operating revenues. Increased operating costs were primarily
attributable to increased labor costs, including payroll expenses and workers'
compensation insurance costs. Payroll expenses increased as experienced field
personnel were retained despite the significant decline in our average rig
utilization. Management believes this strategy is beneficial as it (1) retains
experienced personnel and (2) facilitates the Company's response to increased
demand levels as industry conditions improve. General and administrative
expenses decreased primarily as a result of reduced incentive compensation in
2002. Depreciation and amortization increased in
26
2002 primarily as a result of (1) significant capital expenditures in 2001 and
2002 to maintain, modify, and refurbish our drilling fleet and (2) our
acquisition of drilling rigs and related equipment from Cleere Drilling Company
in December 2001.
YEAR ENDED DECEMBER 31,
----------------------------
DRILLING AND COMPLETION FLUIDS 2002 2001 % CHANGE
------------------------------ ------- ------- --------
(DOLLARS IN 000'S)
Revenues................................................ $69,943 $94,456 (26.0)%
Direct operating costs.................................. $60,762 $80,034 (24.1)%
Selling, general, and administrative.................... $ 7,243 $ 7,936 (8.7)%
Depreciation and amortization........................... $ 2,216 $ 2,644 (16.2)%
Operating income (loss)................................. $ (278) $ 3,842 (107.2)%
Total jobs.............................................. 1,457 1,920 (24.1)%
Average revenue per job................................. $ 48.00 $ 49.20 (2.4)%
Average costs per job................................... $ 41.70 $ 41.68 (1.1)%
Average margin per job.................................. $ 6.30 $ 7.52 (9.8)%
Capital expenditures.................................... $ 1,571 $ 4,937 (68.2)%
The decrease in revenues for our drilling and completion fluids operations
were primarily attributable to industry conditions, as discussed in Contract
Drilling above, and the resulting 24.1% decline in the number of jobs completed.
Operating expenses per job increased despite reduced activity levels due to a
portion of the segment's operating expenses being fixed in nature. The 8.7%
decrease in selling, general, and administrative expense is primarily the result
of reduced employee incentive compensation in 2002.
YEAR ENDED DECEMBER 31,
----------------------------
PRESSURE PUMPING 2002 2001 % CHANGE
---------------- ------- ------- --------
(DOLLARS IN 000'S)
Revenues................................................ $32,996 $39,600 (16.7)%
Direct operating costs.................................. $19,802 $21,146 (6.4)%
Selling, general, and administrative.................... $ 4,301 $ 3,910 10.0%
Depreciation............................................ $ 2,803 $ 1,895 47.9%
Operating income........................................ $ 6,090 $12,649 (51.9)%
Total jobs.............................................. 3,796 4,609 (17.6)%
Average revenue per job................................. $ 8.69 $ 8.59 1.2%
Average costs per job................................... $ 5.22 $ 4.59 13.7%
Average margin per job.................................. $ 3.47 $ 4.00 (13.3)%
Capital expenditures.................................... $ 7,399 $ 7,756 (4.6)%
The decreases in revenues and expenses for our pressure pumping operations
were primarily attributable to industry conditions, as discussed in Contract
Drilling above. Expansion of our pressure pumping services in 2001 and 2002 into
the Appalachian regions of Kentucky and West Virginia resulted in increased
depreciation and selling, general, and administrative expenses in 2002. The
increase in average revenue per job was attributable to the change in the
composition of operating revenues. Cementing revenue as a percent of total
operating revenue increased from 34.2% in 2001 to 55.6% in 2002 and fracturing
revenue as a percent of total operating revenue decreased from 46.7% in 2001 to
39.6% in 2002. Cementing jobs, as compared to fracturing jobs, typically
generate greater revenues as the services being provided are much more
extensive, requiring us to incur increased operating and material costs.
Additionally, operating costs per job increased in 2002 since a portion of
direct operating costs remain constant despite fluctuating activity levels.
27
YEAR ENDED DECEMBER 31,
OIL AND NATURAL GAS PRODUCTION AND ----------------------------
EXPLORATION 2002 2001 % CHANGE
---------------------------------- ------- ------- --------
(DOLLARS IN 000'S)
Revenues................................................ $14,723 $15,988 (7.9)%
Direct operating costs.................................. $ 3,956 $ 5,190 (23.8)%
Selling, general, and administrative.................... $ 1,571 $ 1,537 2.2%
Depreciation and depletion.............................. $ 5,251 $ 8,505 (38.3)%
Operating income........................................ $ 3,945 $ 756 421.8%
Capital expenditures.................................... $ 6,357 $ 7,956 (28.3)%
Average net daily oil production (Bbls)................. 794 739 7.4%
Average net daily gas production (Mcf).................. 5,109 4,654 9.8%
Average oil sales price (per Bbl)....................... $ 25.02 $ 24.88 0.6%
Average gas sales price (per Mcf)....................... $ 2.91 $ 4.12 (29.4)%
Decreased revenues are attributable to lower average prices received from
sales of natural gas. Direct operating costs declined in 2002 primarily due to
the divestiture of marginally productive wells in 2002, thus reducing lease
operating costs. Depreciation and depletion declined in 2002 primarily due to
significant decreased depletion expense in 2002 as a result of increased
commodity prices at December 31, 2002.
YEAR ENDED DECEMBER 31,
--------------------------
CORPORATE AND OTHER 2002 2001 % CHANGE
------------------- ------ ------ --------
(DOLLARS IN 000'S)
Selling, general, and administrative...................... $9,038 $9,901 (8.7)%
Bad debt expense.......................................... $ 320 $2,045 (84.4)%
Depreciation and amortization............................. $ 446 $ 318 40.3%
Other income.............................................. $ (538) $ (820) 34.4%
Merger costs.............................................. $ -- $5,943 (100.0)%
Restructuring and other charges........................... $4,700 $7,202 (34.7)%
Capital expenditures...................................... $3,695 $5,320 (30.5)%
The decrease in selling, general, and administrative expense of 8.7%
primarily relates to reduced employee incentive compensation in 2002.
Restructuring and other charges reflect a $4.7 million charge taken in the
second quarter of 2002 due to the financial failure of a workers' compensation
insurance carrier we used from 1992 until March 2001. Merger costs and
restructuring and other charges in 2001 include an aggregate of $13.1 million
for professional fees, severance and related expenses, closing of duplicate
operational facilities and costs to amend our credit facilities associated with
the merger with UTI.
28
COMPARISON OF THE YEARS ENDED DECEMBER 31, 2001 AND 2000
The following tables summarize operations by business segment for the
twelve months ended December 31, 2001 and 2000:
YEAR ENDED DECEMBER 31,
------------------------------
CONTRACT DRILLING 2001 2000 % CHANGE
----------------- -------- -------- --------
(DOLLARS IN 000'S)
Revenues.............................................. $839,931 $512,998 63.7%
Direct operating costs................................ $487,343 $384,840 26.6%
Selling, general, and administrative.................. $ 5,277 $ 5,457 (3.3)%
Depreciation and amortization......................... $ 72,797 $ 54,274 34.1%
Operating income...................................... $274,514 $ 68,427 301.2%
Operating days........................................ 76,871 63,303 21.4%
Average revenue per operating day..................... $ 10.93 $ 8.10 34.9%
Average direct operating cost per operating day....... $ 6.34 $ 6.08 4.3%
Average margin per operating day...................... $ 4.59 $ 2.02 127.2%
Number of owned rigs at end of period................. 319 275 16.0%
Average number of rigs owned during period............ 302 263 14.8%
Average rigs operating................................ 211 173 22.0%
Rig utilization percentage............................ 70% 66% 6.1%
Capital expenditures.................................. $150,788 $116,836 29.1%
The significant increases shown were reflective of increased activity in
the contract drilling industry and specifically:
- increases in average rig utilization and in the number of operating days,
- increases in dayrates as evidenced by average revenue per operating day,
and
- the addition of an average 39 drilling rigs from 2000 to 2001.
Largely due to favorable commodity prices during the first half of 2001,
the demand for our contract drilling services was strong as we reached our peak
rig utilization of 81% in July. However, beginning in the third quarter of 2001
the industry conditions began to deteriorate as the commodity prices of oil and
natural gas significantly weakened. Market prices for oil fell from
approximately $27 per barrel at the end of 2000 to approximately $17 per barrel
in late 2001 and natural gas prices declined from approximately $10 per Mcf to
under $3 per Mcf for the same time period. Accordingly, the demand for our
contract drilling services was negatively impacted.
YEAR ENDED DECEMBER 31,
----------------------------
DRILLING AND COMPLETION FLUIDS 2001 2000 % CHANGE
------------------------------ ------- ------- --------
(DOLLARS IN 000'S)
Revenues................................................ $94,456 $32,053 194.7%
Direct operating costs.................................. $80,034 $26,545 201.5%
Selling, general, and administrative.................... $ 7,936 $ 4,294 84.8%
Depreciation and amortization........................... $ 2,644 $ 1,464 80.6%
Operating income (loss)................................. $ 3,842 $ (250) N/A%
Total jobs.............................................. 1,920 601 219.5%
Average revenue per job................................. $ 49.20 $ 53.33 (7.7)%
Average costs per job................................... $ 41.68 $ 44.17 (5.6)%
Average margin per job.................................. $ 7.52 $ 9.16 (17.9)%
Capital expenditures.................................... $ 4,937 $10,166 (51.4)%
29
The increases above were primarily attributable to the purchase of the
fluids division of Ambar, Inc., during October 2000 providing for twelve months
of activity in 2001 versus three months in 2000. Deteriorating industry
conditions as noted above also had an adverse impact on our drilling and
completion fluids division beginning in the third quarter of 2001.
YEAR ENDED DECEMBER 31,
----------------------------
PRESSURE PUMPING 2001 2000 % CHANGE
---------------- ------- ------- --------
(DOLLARS IN 000'S)
Revenues................................................ $39,600 $21,465 84.5%
Direct operating costs.................................. $21,146 $13,403 57.8%
Selling, general, and administrative.................... $ 3,910 $ 3,196 22.3%
Depreciation............................................ $ 1,895 $ 1,564 21.2%
Operating income........................................ $12,649 $ 3,302 283.1%
Total jobs.............................................. 4,609 3,329 38.5%
Average revenue per job................................. $ 8.59 $ 6.45 33.2%
Average costs per job................................... $ 4.59 $ 4.03 13.9%
Average margin per job.................................. $ 4.00 $ 2.42 65.3%
Capital expenditures.................................... $ 7,756 $ 4,426 75.2%
The improvement in the pressure pumping segment's operating results were
primarily attributable to improved market conditions throughout 2001 as
evidenced by the increase in number of jobs and revenue per job.
YEAR ENDED DECEMBER 31,
----------------------------
OIL AND NATURAL GAS PRODUCTION AND EXPLORATION 2001 2000 % CHANGE
---------------------------------------------- ------- ------- --------
(DOLLARS IN 000'S)
Revenues................................................ $15,988 $15,806 1.2%
Direct operating costs.................................. $ 5,190 $ 4,872 6.5%
Selling, general, and administrative.................... $ 1,537 $ 1,453 5.8%
Depreciation and depletion.............................. $ 8,505 $ 3,674 131.5%
Operating income........................................ $ 756 $ 5,807 (87.0)%
Capital expenditures.................................... $ 7,956 $ 5,341 49.0%
Average net daily oil production (Bbls)................. 739 752 (1.7)%
Average net daily gas production (Mcf).................. 4,654 3,784 23.0%
Average oil sales price (per Bbl)....................... $ 24.88 $ 29.99 (17.0)%
Average gas sales price (per Mcf)....................... $ 4.12 $ 3.87 6.5%
Increased revenues are attributable to increased production and sales of
natural gas. Direct operating costs increased in 2001 primarily due to the
increased levels of production of natural gas. Depreciation and depletion
increased in 2001 due to increased depletion expense in 2001 as a result of
significantly decreased commodity prices at December 31, 2001 and impairment
expense in 2001 of $1.1 million compared to no impairment expense in 2000. This
impairment in 2001 was attributable to declining commodity prices and
unfavorable results from certain oil and natural gas prospects.
30
YEAR ENDED DECEMBER 31,
--------------------------
CORPORATE AND OTHER 2001 2000 % CHANGE
------------------- ------ ------ --------
(DOLLARS IN 000'S)
Selling, general, and administrative...................... $9,901 $7,790 27.1%
Bad debt expense.......................................... $2,045 $ 570 258.8%
Depreciation and amortization............................. $ 318 $ 488 (35.0)%
Other income.............................................. $ (820) $ (147) (457.8)%
Merger costs.............................................. $5,943 $ -- 100.0%
Restructuring and other charges........................... $7,202 $ -- 100.0%
Capital expenditures...................................... $5,320 $ -- 100.0%
The merger costs and restructuring charges incurred in 2001 are associated
with our merger with UTI that occurred in 2001. Selling, general, and
administrative expenses increased primarily as a result of the increased
activity as evidenced by the operating segments' individual results of
operations and the growth of our Company in 2001 through acquisitions. Included
in this increase are management and operational bonuses resulting from improved
operations.
INCOME TAXES
YEAR ENDED DECEMBER 31,
---------------------------
2002 2001 2000
------ -------- -------
(DOLLARS IN 000'S)
Income before income tax................................ $3,839 $266,495 $60,104
Income tax expense...................................... 1,670 102,333 22,878
Effective tax rate...................................... 43.5% 38.4% 38.1%
Patterson-UTI's remaining unutilized investment tax credit carryforward
expired in 2000. Net operating losses were fully utilized in 2001 and our
remaining alternative minimum tax credit of $602,000 may be carried forward
indefinitely. Other deferred tax assets consist primarily of various allowance
accounts and tax deferred expenses expected to generate a future tax benefit of
approximately $12.9 million.
Our effective income tax rate for 2002 includes 38% applicable to our
statutory Federal and state income tax rates and approximately 6% attributable
to permanent differences. The significance of the impact of the permanent
differences to our effective income tax rate in 2002 was largely attributable to
our reduced 2002 pretax earnings.
We record non-cash deferred Federal income taxes based primarily on the
relationship between the amount of our unused Federal NOL carryforwards and the
temporary differences between the book basis and tax basis in our assets.
Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the year in which those temporary
differences are expected to be settled. As a result of fully recognizing the
benefit of our deferred income taxes, we incur deferred income tax expense as
these benefits are utilized. We incurred deferred income tax expense of
approximately $23.5 million, $14.6 million, and $15.9 million for 2002, 2001,
and 2000, respectively.
VOLATILITY OF OIL AND NATURAL GAS PRICES
Our revenue, profitability, and future rate of growth are substantially
dependent upon prevailing prices for oil and natural gas, with respect to all of
our operating segments. Historically, oil and natural gas prices and markets
have been volatile. Prices are affected by market supply and demand factors as
well as actions of state and local agencies, the United States and foreign
governments, and international cartels. All of these are beyond our control. Any
significant or extended decline in oil and/or natural gas prices would have a
material adverse effect on our financial condition and results of operations.
The contract drilling business experienced increased demand for drilling
services from 1995 through most of 1997 and from mid-1999 and continued through
the second quarter of 2001. However, except for those
31
periods and other occasional upturns, generally, there have been substantially
more drilling rigs available than necessary to meet demand in most operational
and geographic segments of the North American land drilling industry. As a
result, drilling contractors have had difficulty sustaining profit margins.
IMPACT OF INFLATION
We believe that inflation will not have a significant near-term impact on
our financial position.
RECENTLY-ISSUED ACCOUNTING STANDARDS
The Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets,"
("SFAS No. 142") in June 2001. SFAS No. 142 supersedes APB Opinion No. 17,
"Intangible Assets." Under the provisions of SFAS No. 142, which the Company
adopted on January 1, 2002, goodwill is no longer amortized but is subject to an
annual impairment test. During the years ended December 31, 2001 and 2000,
goodwill amortization totaled approximately $4.7 million each year.
The FASB issued Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations," ("SFAS No. 143") in July 2001.
SFAS No. 143 addresses financial accounting requirements for retirement
obligations associated with tangible long-lived assets. The provisions of SFAS
No. 143, which the Company adopted on January 1, 2003, will result in the
Company recording a liability of approximately $1.1 million for estimated costs
to be incurred in connection with the abandonment of oil and natural gas
properties in the future. In addition, the cumulative effect of this change in
accounting policy, which will be recorded in the consolidated statement of
income in the first quarter of 2003, will total approximately $500,000, net of
tax.
The FASB issued Statement of Financial Accounting Standards No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS No.
144") in August 2001. SFAS No. 144 supersedes SFAS No. 121 and APB Opinion No.
30. The provisions of SFAS No. 144, which the Company adopted on January 1,
2002, did not have a material impact on the Company's consolidated financial
statements.
The FASB issued Statement of Financial Accounting Standards No. 145,
"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement
No. 13, and Technical Corrections," ("SFAS No. 145") in April 2002. SFAS No. 145
amends existing authoritative pronouncements to make various technical
corrections, clarify meanings, or describe their applicability under changed
conditions. The provisions of SFAS No. 145, which the Company adopted in 2002,
did not have a material impact on the Company's consolidated financial
statements.
The FASB issued Statement of Financial Accounting Standards No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities," ("SFAS No.
146") in June 2002. SFAS No. 146 is effective for exit or disposal activities
that are initiated after December 31, 2002. The provisions of SFAS No. 146 are
not expected to have a material impact on the Company's consolidated financial
statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We currently have no exposure to interest rate market risk as we have no
outstanding balance under our credit facility. Should we incur a balance in the
future, we would have exposure associated with the floating rate of the interest
charged on that balance. The revolving credit facility calls for periodic
interest payments at a floating rate ranging from LIBOR plus 1.75% to 2.75%. The
applicable rate above LIBOR (1.75% at December 31, 2002) is based upon our
trailing twelve-month EBITDA (earnings before interest expense, income taxes,
and depreciation, depletion and amortization expense). Our exposure to interest
rate risk due to changes in LIBOR is not expected to be material.
We conduct some business in Canadian dollars through our Canadian
land-based drilling operations. The exchange rate between Canadian dollars and
U.S. dollars has fluctuated over the last ten years. If the value of the
Canadian dollar against the U.S. dollar weakens, revenues and earnings of our
Canadian operations will be
32
reduced when they are translated to U.S. dollars. Also, the value of our
Canadian net assets in U.S. dollars may decline.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Financial Statements are filed as a part of this Report at the end of Part
IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and
are incorporated herein by this reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
As of the end of the period covered by this Annual Report on Form 10-K/A,
the effectiveness of our disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934)
was evaluated by our management, with the participation of our Chief Executive
Officer, Cloyce A. Talbott (principal executive officer), and our Vice
President, Chief Financial Officer, Secretary and Treasurer, Jonathan D. Nelson
(principal financial officer). Messrs. Talbott and Nelson have concluded that
our disclosure controls and procedures are effective, as of the end of the
period covered by this Annual Report on Form 10-K/A, to help ensure that
information we are required to disclose in reports that we file with the SEC is
accumulated and communicated to management and recorded, processed, summarized
and reported within the time periods prescribed by the SEC.
There were no changes in our internal control over financial reporting that
occurred during our last fiscal quarter (the quarter ended December 31, 2002)
that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
33
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this Item is incorporated herein by reference
to the information appearing under the captions "Proposal No. 1 -- Election of
Directors", "Executive Officers" and "Other Matters -- Section 16(a) Beneficial
Ownership Reporting Compliance" in the Definitive Proxy Statement filed by the
Company with the Securities and Exchange Commission on March 24, 2003 (the
"Proxy Statement").
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item is incorporated herein by reference
to the information appearing under the captions "Proposal No. 1 -- Election of
Directors -- Compensation of Directors", "Summary Compensation Table", "Options
Granted During Fiscal Year 2002", "Aggregated Option Exercises in 2002 and Value
Table at December 31, 2002", "Employment Contracts and Change-in-Control
Arrangements" and "Compensation Committee Interlocks and Insider Participation"
in the Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item is incorporated herein by reference
to the information appearing under the captions "Proposal No. 2 -- Amendment to
1997 Long-Term Incentive Plan -- Summary Information Pertaining to All Stock
Option and Related Plans of Patterson-UTI" and "Security Ownership of Principal
Stockholders and Management" in the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this Item is incorporated herein by reference
to the information appearing under the caption "Certain Transactions" in the
Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
This information is not required to be disclosed in this Annual Report on
Form 10-K/A pursuant to the SEC's Final Rule Release No. 33-8183, dated January
28, 2003.
34
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) Financial Statements
See Index to Consolidated Financial Statements on page F-1 of this Report.
(a)(2) Financial Statement Schedule
Schedule II -- Valuation and qualifying accounts is filed herewith on page
S-1.
All other financial statement schedules have been omitted because they are
not applicable or the information required therein is included elsewhere in the
financial statements or notes thereto.
(a)(3) Exhibits
The following exhibits are filed herewith or incorporated by reference
herein.
2.1 Agreement and Plan of Merger dated March 10, 2002 among
Patterson-UTI Energy, Inc., Patterson-UTI Drilling Company
LP, LLLP and Odin Drilling, Inc.(1)
2.2 Stock Purchase Agreement dated as of June 11, 2002 by and
among Patterson-UTI Energy, Inc. and Roper Family
Properties, Ltd., Estate of Joe G. Roper, Patricia R.
Elledge, Judy Kathleen Roper Davis, Jeanie Elisabeth
Cornelius and J. Mark Roper.(2)
2.3 Stock Purchase Agreement dated as of October 28, 2002 by and
between Patterson-UTI Energy, Inc. and J. Mark Roper.(3)
3.1 Restated Certificate of Incorporation, as amended.(4)
3.2 Amended and Restated Bylaws.(5)
4.1 Rights Agreement dated January 2, 1997, between Patterson
Energy, Inc. and Continental Stock Transfer & Trust
Company.(6)
4.2 Amendment to Rights Agreement dated as of October 23,
2001.(7)
4.3 Restated Certificate of Incorporation, as amended (See
Exhibit 3.1)
4.4 Registration Rights Agreement with Bear, Stearns and Co.
Inc., dated March 25, 1994, as assigned by REMY Capital
Partners III, L.P.(5)
4.5 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as
amended.(8)*
4.6 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock
Option Plan, as amended.(9)*
4.7 Patterson-UTI Energy, Inc. Amended and Restated 1997
Long-Term Incentive Plan.(4)*
4.8 Amended and Restated Patterson-UTI Energy, Inc. Non-Employee
Director Stock Option Plan(4)*
4.9 Amended and Restated Patterson-UTI Energy, Inc. 1996
Employee Stock Option Plan.(10)*
4.10 1997 Stock Option Plan of DSI Industries, Inc.(11)*
4.11 Stock Option Agreement dated July 20, 2001 between
Patterson-UTI Energy, Inc. and Kenneth R. Peak (a
non-employee director of Patterson-UTI Energy, Inc.).(5)*
10.1 For additional material contracts, see Exhibits 4.1, 4.2 and
4.4 through 4.11.
10.2 Amended and Restated Loan and Security Agreement, dated July
26, 2002.(12)
10.3 Revolving Loan Promissory Note, dated July 26, 2002.(12)
10.4 Amended and Restated Guaranty Agreement, dated July 26,
2002.(12)
10.5 Amended and Restated Pledge Agreement, dated July 26,
2002.(12)
10.6 Model Form Operating Agreement.(13)
10.7 Form of Drilling Bid Proposal and Footage Drilling
Contract.(13)
10.8 Form of Turnkey Drilling Agreement.(13)
21.1 Subsidiaries of the Registrant.(14)
23.1 Consent of Independent Auditors -- PricewaterhouseCoopers
LLP.
23.2 Consent of Independent Auditors -- Ernst & Young LLP.
23.3 Consent of Independent Petroleum Engineer -- M. Brian
Wallace, P.E.
31.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934,
as amended.
35
31.2 Certification of Chief Financial Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934,
as amended.
32.1 Certification of Chief Executive Officer and Chief Financial
Officer pursuant to 18 USC Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
---------------
(1) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended March 31, 2002.
(2) Incorporated herein by reference to Item 7, "Material to be Filed as
Exhibits" to Amendment No. 1 to Schedule 13D filed on October 31, 2002.
(3) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended June 30, 2002.
(4) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended June 30, 2003.
(5) Incorporated herein by reference to Item 14, "Exhibits, Financial Statement
Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the
fiscal year ended December 31, 2001.
(6) Incorporated by reference to Item 2, "Exhibits" to Registration Statement
on Form 8-A filed on January 14, 1997.
(7) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended September 30, 2001, filed
on October 31, 2001.
(8) Incorporated herein by reference to Item 8, "Exhibits" to Registration
Statement on Form S-8 (File No. 333-39471) filed on March 13, 1998.
(9) Incorporated herein by reference to Item 8, "Exhibits" to Registration
Statement on Form S-8 (File No. 333-39471) filed on November 4, 1997.
(10) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective
Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60466)
filed on July 25, 2001.
(11) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective
Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60470)
filed on July 25, 2001.
(12) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended June 30, 2001, filed on
August 1, 2001.
(13) Incorporated herein by reference to Item 27, "Exhibits" to Registration
Statement on Form SB-2 (File No. 33-68058-FW) filed on August 30, 1993.
(14) Incorporated herein by reference to Item 15, "Exhibits, Financial Statement
Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the
fiscal year ended December 31, 2002.
* Management Contract or Compensatory Plan identified as required by Item
15(a)(3) of Form 10-K.
(b) Reports on Form 8-K.
There were no reports on Form 8-K filed during the three months ended
December 31, 2002.
36
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
PAGE
-------
Report of Independent Auditors; PricewaterhouseCoopers
LLP....................................................... F-2
Report of Independent Auditors; Ernst & Young LLP........... F-3
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and
2001................................................... F-4
Consolidated Statements of Income for the years ended
December 31, 2002, 2001, and 2000...................... F-5
Consolidated Statements of Changes In Stockholders' Equity
for the years ended
December 31, 2002, 2001, and 2000...................... F-6
Consolidated Statements of Changes In Cash Flows for the
years ended
December 31, 2002, 2001, and 2000...................... F-7
Notes to Consolidated Financial Statements................ F-9
F-1
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders of
Patterson-UTI Energy, Inc.
In our opinion, based on our audits and the report of other auditors, the
consolidated financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Patterson-UTI
Energy, Inc. and its subsidiaries at December 31, 2002 and 2001, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
based on our audits and the report of other auditors, the financial schedule
listed in Item 14(a) (2) presents fairly, in all material respects, the
information set forth therein, when read in conjunction with the related
consolidated financial statements. These financial statements and financial
schedule are the responsibility of the Company's management; our responsibility
is to express an opinion on these financial statements and financial schedule
based on our audits. The consolidated financial statements give retroactive
effect to the merger of UTI Energy Corp. ("UTI") on May 8, 2001 in a transaction
accounted for as a pooling of interests, as described in Note 2 to the
consolidated financial statements. We did not audit the financial statements of
UTI, which statements reflect total assets of $330 million as of December 31,
2000 and total revenues of $275 million for the year ended December 31, 2000.
Those statements were audited by other auditors whose report thereon has been
furnished to us, and our opinion expressed herein, insofar as it relates to the
amounts included for UTI, is based solely on the report of the other auditors.
We conducted our audits of these statements in accordance with auditing
standards generally accepted in the United States of America, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits and the report of other
auditors provide a reasonable basis for our opinion.
As discussed in Notes 1 and 5 to the consolidated financial statements, in
accordance with Statement of Financial Accounting Standards No. 142, "Goodwill
and Other Intangible Assets," beginning in 2002 the Company no longer amortizes
goodwill.
PricewaterhouseCoopers LLP
Houston, Texas
February 3, 2003
F-2
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors
Patterson-UTI Energy, Inc.
We have audited the consolidated balance sheet of UTI Energy Corp. as of
December 31, 2000 and the related consolidated statements of operations, changes
in shareholders' equity and cash flows for the year then ended (not presented
separately herein). Our audit also included the financial statement schedule
listed in the Index at Item 14(a) of UTI Energy Corp.'s Annual Report (Form
10-K) for the year ended December 31, 2000 (also not presented separately
herein). These financial statements and schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
UTI Energy Corp. at December 31, 2000, and the consolidated results of its
operations and its cash flows for the year then ended, in conformity with
accounting principles generally accepted in the United States. Also, in our
opinion, the related financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
Ernst & Young LLP
Houston, Texas
February 16, 2001
F-3
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
-------------------
2002 2001
-------- --------
ASSETS
Current assets:
Cash and cash equivalents................................. $ 82,154 $ 33,584
Accounts receivable, net of allowance for doubtful
accounts of $3,144 and $4,021 at December 31, 2002 and
2001, respectively..................................... 99,014 133,837
Federal and state income taxes receivable, net............ 24,719 1,673
Inventory................................................. 15,323 16,272
Deferred tax assets....................................... 15,290 8,747
Other..................................................... 6,515 5,345
-------- --------
Total current assets.............................. 243,015 199,458
Property and equipment, at cost, net........................ 627,734 614,420
Goodwill and other intangible assets, net................... 51,313 51,634
Investment in equity securities............................. 17,707 --
Other....................................................... 2,740 4,130
-------- --------
Total assets...................................... $942,509 $869,642
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade.................................................. $ 30,618 $ 43,873
Accrued revenue distributions.......................... 6,266 4,072
Other.................................................. 2,755 4,833
Accrued expenses.......................................... 35,513 36,508
-------- --------
Total current liabilities......................... 75,152 89,286
Deferred tax liabilities.................................... 127,006 92,859
Other....................................................... 2,795 355
-------- --------
Total liabilities................................. 204,953 182,500
-------- --------
Commitments and contingencies............................... -- --
Stockholders' equity:
Preferred stock, par value $.01; authorized 1,000,000
shares, no shares issued............................... -- --
Common stock, par value $.01; authorized 200,000,000
shares with 81,576,674 and 78,462,543 issued and
80,070,126 and 76,955,995 outstanding at December 31,
2002 and 2001, respectively............................ 816 784
Additional paid-in capital................................ 489,201 441,475
Retained earnings......................................... 261,003 258,834
Accumulated other comprehensive loss...................... (1,809) (2,296)
Treasury stock, at cost, 1,506,548 shares................. (11,655) (11,655)
-------- --------
Total stockholders' equity........................ 737,556 687,142
-------- --------
Total liabilities and stockholders' equity...... $942,509 $869,642
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEARS ENDED DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
Operating revenues:
Drilling.................................................. $410,295 $839,931 $512,998
Drilling and completion fluids............................ 69,943 94,456 32,053
Pressure pumping.......................................... 32,996 39,600 21,465
Oil and natural gas....................................... 14,723 15,988 15,806
-------- -------- --------
527,957 989,975 582,322
-------- -------- --------
Operating costs and expenses:
Drilling.................................................. 318,201 487,343 384,840
Drilling and completion fluids............................ 60,762 80,034 26,545
Pressure pumping.......................................... 19,802 21,146 13,403
Oil and natural gas....................................... 3,956 5,190 4,872
Depreciation, depletion, and amortization................. 91,216 86,159 61,464
General and administrative................................ 26,140 28,561 22,190
Bad debt expense.......................................... 320 2,045 570
Merger costs.............................................. -- 5,943 --
Restructuring and other charges........................... 4,700 7,202 --
Other..................................................... (538) (820) (147)
-------- -------- --------
524,559 722,803 513,737
-------- -------- --------
Operating income............................................ 3,398 267,172 68,585
-------- -------- --------
Other income (expense):
Interest income........................................... 1,110 2,080 1,377
Interest expense.......................................... (532) (3,142) (10,108)
Other..................................................... (137) 385 250
-------- -------- --------
441 (677) (8,481)
-------- -------- --------
Income before income taxes.................................. 3,839 266,495 60,104
-------- -------- --------
Income tax expense (benefit):
Current................................................... (21,878) 87,773 6,931
Deferred.................................................. 23,548 14,560 15,947
-------- -------- --------
1,670 102,333 22,878
-------- -------- --------
Net income.................................................. $ 2,169 $164,162 $ 37,226
======== ======== ========
Net income per common share:
Basic..................................................... $ 0.03 $ 2.15 $ 0.52
======== ======== ========
Diluted................................................... $ 0.03 $ 2.07 $ 0.50
======== ======== ========
Weighted average number of common shares outstanding:
Basic..................................................... 78,705 76,407 71,207
======== ======== ========
Diluted................................................... 81,252 79,197 74,841
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(IN THOUSANDS)
COMMON STOCK ACCUMULATED
------------------ ADDITIONAL OTHER
NUMBER PAID-IN RETAINED COMPREHENSIVE TREASURY
OF SHARES AMOUNT CAPITAL EARNINGS INCOME (LOSS) STOCK TOTAL
--------- ------ ---------- -------- ------------- -------- --------
December 31, 1999.................. 69,542 $695 $261,559 $57,446 $ -- $(10,005) $309,695
Issuance of common stock......... 4,203 42 120,964 -- -- -- 121,006
Issuance of stock purchase
warrant........................ -- -- 900 -- -- -- 900
Treasury stock acquired.......... -- -- -- -- -- (1,650) (1,650)
Exercise of stock purchase
warrants....................... 1,054 11 683 -- -- -- 694
Exercise of stock options........ 1,451 15 6,254 -- -- -- 6,269
Tax benefit related to exercise
of stock options............... -- -- 7,129 -- -- -- 7,129
Foreign currency translation..... -- -- -- -- 30 -- 30
Net income....................... -- -- -- 37,226 -- -- 37,226
------ ---- -------- -------- ------- -------- --------
December 31, 2000.................. 76,250 763 397,489 94,672 30 (11,655) 481,299
Issuance of common stock......... 1,260 12 31,405 -- -- -- 31,417
Issuance of stock purchase
warrant........................ -- -- 2,600 -- -- -- 2,600
Exercise of stock purchase
warrants....................... 121 1 1,819 -- -- -- 1,820
Exercise of stock options........ 832 8 4,237 -- -- -- 4,245
Tax benefit related to exercise
of stock options............... -- -- 3,925 -- -- -- 3,925
Foreign currency translation..... -- -- -- -- (2,326) -- (2,326)
Net income....................... -- -- -- 164,162 -- -- 164,162
------ ---- -------- -------- ------- -------- --------
December 31, 2001.................. 78,463 784 441,475 258,834 (2,296) (11,655) 687,142
Issuance of common stock......... 650 7 16,933 -- -- -- 16,940
Exercise of stock options and
warrants....................... 2,464 25 15,714 -- -- -- 15,739
Tax benefit related to exercise
of stock options............... -- -- 15,079 -- -- -- 15,079
Foreign currency translation..... -- -- -- -- 457 -- 457
Change in unrealized gain on
securities, net of tax......... -- -- -- -- 30 -- 30
Net income....................... -- -- -- 2,169 -- -- 2,169
------ ---- -------- -------- ------- -------- --------
December 31, 2002.................. 81,577 $816 $489,201 $261,003 $(1,809) $(11,655) $737,556
====== ==== ======== ======== ======= ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
-------- --------- ---------
Cash flows from operating activities:
Net income............................................... $ 2,169 $ 164,162 $ 37,226
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion, and amortization................ 91,216 86,159 61,464
Provision for bad debts.................................. 320 2,045 570
Deferred income tax expense.............................. 23,548 14,560 15,947
Tax benefit related to exercise of stock options......... 15,079 3,925 7,129
Other.................................................... (538) (648) 881
Changes in operating assets and liabilities:
Accounts receivable................................. 34,565 6,648 (63,323)
Inventory and other current assets.................. (222) (355) 7,105
Accrued federal income taxes receivable............. (23,216) 796 2,596
Accounts payable.................................... (11,079) (33,174) 24,077
Other liabilities................................... (409) 9,888 4,525
-------- --------- ---------
Net cash provided by operating activities........ 131,433 254,006 98,197
-------- --------- ---------
Cash flows from investing activities:
Acquisitions............................................. -- (40,546) (56,627)
Purchases of property and equipment...................... (83,843) (172,850) (95,822)
Proceeds from sales of property and equipment............ 1,813 742 3,528
Purchase of investment equity securities................. (17,659) -- --
Change in other assets................................... 1,097 (1,101) 630
-------- --------- ---------
Net cash used in investing activities............ (98,592) (213,755) (148,291)
-------- --------- ---------
Cash flows from financing activities:
Proceeds from issuance of common stock................... -- -- 98,766
Purchase of treasury stock............................... -- -- (1,650)
Proceeds from issuance of notes payable.................. -- 9,760 76,392
Payments of notes payable................................ -- (89,176) (79,766)
Proceeds from exercise of stock options and warrants..... 15,739 6,065 6,963
-------- --------- ---------
Net cash provided by (used in) financing
activities..................................... 15,739 (73,351) 100,705
-------- --------- ---------
Net increase (decrease) in cash and cash
equivalents.................................... 48,580 (33,100) 50,611
Foreign currency translation adjustment.......... (10) (232) (34)
Cash and cash equivalents at beginning of year............. 33,584 66,916 16,339
-------- --------- ---------
Cash and cash equivalents at end of year................... $ 82,154 $ 33,584 $ 66,916
======== ========= =========
Supplemental disclosure of cash flow information:
Net cash received (paid) during the year for:
Interest......................................... $ (532) $ (3,142) $ (10,097)
Income taxes..................................... 13,492 (81,802) (3,319)
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
Non-cash investing and financing activities:
During March 2002, the Company acquired five SCR electric land-based
drilling rigs through the acquisition of Odin Drilling, Inc., for a purchase
price of $16.9 million. The purchase price consisted of 650,000 shares of common
stock valued at $26.06 per share. A deferred tax liability of $4.1 million was
recorded as a result of the transaction. The transaction was accounted for as a
purchase and the related purchase price was allocated among the rigs based on
their fair values.
During 2001 the Company acquired Jones Drilling Corporation and certain
assets of three other entities affiliated with Jones Drilling Corporation for
$33.0 million, drilling rigs and related equipment from Cleere Drilling Company
for an aggregate purchase price of $25.8 million and six drilling rigs through
three separate transactions for $15.7 million. Of the $74.6 million,
approximately $40.5 million was paid in cash as follows:
(IN THOUSANDS)
--------------
Purchase price.............................................. $ 74,563
Less non-cash items:
Common stock issued....................................... (31,417)
Warrants issued........................................... (2,600)
--------
Total cash paid...................................... $ 40,546
========
During May, 2000 the Company acquired a drilling rig in exchange for
certain drilling rig components and drill pipe with a net book value of
approximately $970,000. No gain or loss was recognized on this transaction.
During 2000, the Company acquired WEK Drilling Co., Inc., High Valley
Drilling, Inc., the land drilling operations of Phelps Drilling International,
Ltd., four drilling rigs through two separate transactions, and the drilling and
completion fluids operations of Ambar, Inc., for an aggregate purchase price of
approximately $79.8 million, of which approximately $56.6 million was paid in
cash as follows:
(IN THOUSANDS)
--------------
Purchase price.............................................. $ 79,767
Less non-cash items:
Common stock issued....................................... (22,240)
Warrants issued........................................... (900)
--------
Total cash paid........................................ $ 56,627
========
The accompanying notes are an integral part of these consolidated financial
statements.
F-8
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A DESCRIPTION AND BASIS OF PRESENTATION FOLLOWS:
DESCRIPTION OF BUSINESS -- Patterson-UTI Energy, Inc. and its wholly-owned
subsidiaries, (collectively referred to herein as "Patterson-UTI" or the
"Company") is a leading provider of onshore contract drilling services to major
and independent oil and natural gas operators in Texas, New Mexico, Oklahoma,
Louisiana, Mississippi, Utah, and Western Canada. The Company owns 324 drilling
rigs. The Company provides drilling fluids, completion fluids, and related
services to oil and natural gas operators in West Texas, Southeast New Mexico,
South Texas, East Texas, Oklahoma, the Gulf Coast regions of Texas and
Louisiana, and the Gulf of Mexico. The Company provides pressure pumping
services to oil and natural gas operators in the Appalachian Basin. The Company
is also engaged in the development, exploration, acquisition, and production of
oil and natural gas. The Company's oil and natural gas operations are focused in
producing regions in West Texas, Southeast New Mexico, and South Texas.
BASIS OF PRESENTATION -- The consolidated financial statements of
Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries have been prepared
to give retroactive effect to the merger between Patterson Energy, Inc.
("Patterson") and UTI Energy Corp. ("UTI") on May 8, 2001. The transaction was
treated as a reorganization within the meaning of Section 368(a) of the Internal
Revenue Code of 1986, as amended, and accounted for as a pooling of interests
for financial accounting purposes. These financial statements also give
retroactive effect to the two for one stock split in October 2000 by UTI.
A SUMMARY OF THE SIGNIFICANT ACCOUNTING POLICIES FOLLOWS:
PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements
include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All
significant intercompany accounts and transactions have been eliminated.
MANAGEMENT ESTIMATES -- The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
REVENUE RECOGNITION -- Revenues are recognized when services are performed,
except for revenues earned under turnkey contract drilling arrangements which
are recognized using the completed contract method of accounting, as described
below. The Company follows the percentage-of-completion method of accounting for
footage contract drilling arrangements. Under this method, drilling revenues and
costs related to a well in progress are recognized proportionately over the time
it takes to drill the well. Percentage-of-completion is determined based upon
the amount of expenses incurred through the measurement date as compared to
total estimated expenses to be incurred drilling the well. Under the
percentage-of-completion method, management estimates are relied upon in the
determination of the total estimated expenses to be incurred drilling the well.
Due to the nature of turnkey contract drilling arrangements and risks therein,
the Company follows the completed contract method of accounting for such
arrangements. Under this method, all drilling advances and costs (including
maintenance and repairs) related to a well in progress are deferred and
recognized as revenues and expenses in the period the well is completed.
Provisions for losses on incomplete or in-process wells are made when estimated
total costs are expected to exceed estimated total revenues.
INVENTORIES -- Inventories consist primarily of chemical products to be
used in conjunction with the Company's drilling and completion fluids
activities. The inventories are stated at the lower of cost or market,
determined by the first-in, first-out method.
F-9
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
PROPERTY AND EQUIPMENT -- Property and equipment is carried at cost less
accumulated depreciation. Depreciation is provided on the straight-line method
over the estimated useful lives. The method of depreciation does not change when
equipment becomes idle. The estimated useful lives are defined below.
USEFUL LIVES
(YEARS)
-------------
Drilling rigs and related equipment......................... 2-15
Office furniture............................................ 3-10
Buildings................................................... 5-20
Automotive equipment........................................ 2-7
Other....................................................... 3-7
OIL AND NATURAL GAS PROPERTIES -- Oil and natural gas properties are
accounted for using the successful efforts method of accounting. Under the
successful efforts method of accounting, exploration costs which result directly
in the discovery of oil and natural gas reserves and all development costs are
capitalized to the appropriate well. Exploration costs which do not result
directly in discovering oil and natural gas reserves are charged to expense when
such determinations are made. In accordance with paragraph 31(b) of SFAS 19,
costs of exploratory wells are initially capitalized to wells in progress until
the outcome of the drilling is known. We review wells in progress quarterly to
determine the related reserve classification. If the reserve classification is
uncertain after one year following the completion of drilling, we consider the
costs of the well to be impaired and recognize the costs as expense. Geological
and geophysical costs, including seismic costs, and costs to carry and retain
undeveloped properties are charged to expense when incurred. The capitalized
costs of both developmental and successful exploratory type wells, consisting of
lease and well equipment, lease acquisition costs, and intangible development
costs, are depreciated, depleted, and amortized on the units-of-production
method, based on petroleum engineer estimates of proved oil and natural gas
reserves of each respective field. The Company reviews its proved oil and
natural gas properties for impairment when an event occurs such as downward
revisions in reserve estimates or decreases in oil and natural gas prices.
Proved properties are grouped by field and undiscounted cash flow estimates are
provided by our reserve engineer. If the net book value of a field exceeds its
undiscounted cash flow estimate, impairment expense is measured and recognized
as the difference between its net book value and discounted cash flow. Unproved
oil and natural gas properties are reviewed quarterly to determine impairment.
The Company's intent to drill, lease expiration, and abandonment of area are
considered. Assessment of impairment is made on a lease-by-lease basis. If an
unproved property is determined to be impaired, then costs related to that
property are expensed. Impairment expense is included in depreciation,
depletion, and amortization in the accompanying financial statements.
INTANGIBLE ASSETS -- Intangible assets consist primarily of goodwill and
covenants not to compete arising from business combinations (see Notes 2 and 5).
Intangible assets other than goodwill are amortized on a straight line basis
over their estimated useful lives. Covenants not to compete are amortized over
their underlying contractual lives. Prior to 2002, goodwill, representing the
excess of the purchase price over the estimated fair value of the net assets of
the acquired business, was amortized over the period of expected benefit of 15
years. However, effective January 1, 2002, the Company adopted Statement of
Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets,"
("SFAS No. 142") which requires that the Company cease amortization of all
intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined to
be finite, however, a recognized intangible asset with an indefinite useful life
should be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. At December 31, 2002, the Company evaluated its goodwill and
determined that fair value had
F-10
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
not decreased below carrying value and no adjustment to impair goodwill was
necessary in accordance with SFAS No. 142.
The following table summarizes depreciation, depletion, amortization, and
impairment expense for 2002, 2001 and 2000 (in millions):
2002 2001 2000
----- ----- -----
Depreciation expense........................................ $85.8 $72.6 $52.0
Depletion expense........................................... 4.4 7.3 3.5
Amortization expense........................................ 0.3 5.2 6.0
Impairment of oil and gas properties........................ 0.7 1.1 --
----- ----- -----
Total..................................................... $91.2 $86.2 $61.5
===== ===== =====
MAINTENANCE AND REPAIRS -- Maintenance and repairs are charged to expense
when incurred. Renewals and betterments which extend the life or improve
existing properties are capitalized.
RETIREMENTS -- Upon disposition or retirement of property and equipment,
the cost and related accumulated depreciation are removed and any resulting gain
or loss is credited or charged to operations.
INVESTMENTS IN EQUITY SECURITIES -- In accordance with Statement of
Financial Accounting Standards No. 115, "Accounting for Certain Investments in
Debt and Equity Securities," ("SFAS No. 115"), investments in Available-for-Sale
equity securities are recorded at fair value. Unrealized gains and losses on
such investments, net of tax, are included in accumulated other comprehensive
loss in our consolidated balance sheet as of December 31, 2002 and are shown as
a separate component of stockholders' equity (see Notes 3 and 6).
EARNINGS PER SHARE -- The Company provides a dual presentation of its
earnings per share; Basic Earnings per Share ("Basic EPS") and Diluted Earnings
per Share ("Diluted EPS") in its Consolidated Statements of Operations. Basic
EPS is computed using the weighted average number of shares outstanding during
the year. Diluted EPS includes common stock equivalents which are dilutive to
earnings per share. For the years ended December 31, 2002, 2001, and 2000,
dilutive securities, consisting of certain stock options and warrants as
described in Note 11, included in the calculation of Diluted EPS were 2.5
million shares, 2.8 million shares, and 3.6 million shares, respectively. At
December 31, 2002, 2001, and 2000, there were potentially dilutive securities of
328,500, 490,000, and 46,000, respectively, excluded from the calculation of
Diluted EPS as their exercise prices were greater than the average market price
for the respective year.
INCOME TAXES -- The asset and liability method is used in accounting for
income taxes. Under this method, deferred tax assets and liabilities are
recognized for operating loss and tax credit carryforwards and for the future
tax consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in the results of
operations in the period that includes the enactment date. A valuation allowance
is recorded to reduce the carrying amounts of deferred tax assets unless it is
more likely than not that such assets will be realized.
STOCK BASED COMPENSATION -- The Company grants stock options to employees
and non-employee directors under stock-based incentive compensation plans, (the
"Plans"). The Company accounts for all stock-based employee compensation plans
under the recognition and measurement provisions of APB Opinion No. 25,
"Accounting for Stock Issued to Employees," ("APB No. 25") and related
interpretations. Under APB No. 25, no stock-based employee compensation cost is
reflected in net income, as all options granted
F-11
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
under those plans had an exercise price equal to or in excess of the market
value of the underlying common stock on the date of grant. The following table
illustrates the effect on net income and earnings per share as if the company
had applied the fair value recognition provisions of FASB Statement No. 123,
"Accounting for Stock-Based Compensation," to stock-based employee compensation:
YEARS ENDED DECEMBER 31,
-----------------------------------------
2002 2001 2000
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Net income, as reported............................ $ 2,169 $164,162 $ 37,226
Deduct: Total stock-based employee compensation
expense determined under fair value based method
for all awards, net of related tax effects(1).... (5,296) (7,053) (6,016)
-------- -------- --------
Pro forma net income (loss)........................ $ (3,127) $157,109 $ 31,210
======== ======== ========
Earnings (loss) per share:
Basic, as reported............................... $ 0.03 $ 2.15 $ 0.52
======== ======== ========
Basic, pro forma................................. $ (0.04) $ 2.06 $ 0.44
======== ======== ========
Diluted, as reported............................. $ 0.03 $ 2.07 $ 0.50
======== ======== ========
Diluted, pro forma............................... $ (0.04) $ 1.98 $ 0.42
======== ======== ========
Weighted-average fair value per share of options
granted(1)....................................... $ 15.19 $ 9.97 $ 15.73
---------------
(1) See Note 11 for additional information regarding the computations presented
here.
STATEMENT OF CASH FLOWS -- For purposes of reporting cash flows, cash and
cash equivalents include cash on deposit and unrestricted certificates of
deposit with original maturities of 90 days or less.
RECENTLY ISSUED ACCOUNTING STANDARDS -- The Financial Accounting Standards
Board ("FASB") issued Statement of Financial Accounting Standards No. 142,
"Goodwill and Other Intangible Assets," ("SFAS No. 142") in June 2001. SFAS No.
142 supersedes APB Opinion No. 17, "Intangible Assets." Under the provisions of
SFAS No. 142, which the Company adopted on January 1, 2002, goodwill is no
longer amortized but is subject to an annual impairment test. During the years
ended December 31, 2001 and 2000, goodwill amortization totaled approximately
$4.7 million each year.
The FASB issued Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations," ("SFAS No. 143") in July 2001.
SFAS No. 143 addresses financial accounting requirements for retirement
obligations associated with tangible long-lived assets. The provisions of SFAS
No. 143, which the Company adopted on January 1, 2003, will result in the
Company recording a liability of approximately $1.1 million for estimated costs
to be incurred in connection with the abandonment of oil and natural gas
properties in the future. In addition, the cumulative effect of this change in
accounting policy, which will be recorded in the consolidated statement of
income in the first quarter of 2003, will total approximately $500,000, net of
tax.
The FASB issued Statement of Financial Accounting Standards No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS No.
144") in August 2001. SFAS No. 144 supersedes SFAS No. 121 and APB Opinion No.
30. The provisions of SFAS No. 144, which the Company adopted on January 1,
2002, did not have a material impact on the Company's consolidated financial
statements.
F-12
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The FASB issued Statement of Financial Accounting Standards No. 145,
"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement
No. 13, and Technical Corrections," ("SFAS No. 145") in April 2002. SFAS No. 145
amends existing authoritative pronouncements to make various technical
corrections, clarify meanings, or describe their applicability under changed
conditions. The provisions of SFAS No. 145, which the Company adopted in 2002,
did not have a material impact on the Company's consolidated financial
statements.
The FASB issued Statement of Financial Accounting Standards No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities," ("SFAS No.
146") in June 2002. SFAS No. 146 is effective for exit or disposal activities
that are initiated after December 31, 2002. The provisions of SFAS No. 146 are
not expected to have a material impact on the Company's consolidated financial
statements.
RECLASSIFICATIONS -- Certain reclassifications have been made to the 2001
and 2000 consolidated financial statements in order for them to conform with the
2002 presentation.
2. MERGERS AND ACQUISITIONS
2002 ACQUISITION
ODIN DRILLING, INC. -- On March 21, 2002, the Company acquired five SCR
electric land-based drilling rigs through the acquisition of Odin Drilling,
Inc., for a purchase price of $16.9 million. The purchase price consisted of
650,000 shares of common stock valued at $26.06 per share. A deferred tax
liability of $4.1 million was recorded as a result of the transaction. The
transaction was accounted for as an acquisition of assets and the purchase price
was allocated among the rigs based on their fair values.
2001 MERGER AND ACQUISITIONS
CLEERE DRILLING COMPANY -- On December 21, 2001, the Company acquired 17
drilling rigs and related equipment from Cleere Drilling Company for an
aggregate purchase price of $25.8 million. The purchase price consisted of $13.5
million cash plus 450,000 shares of its common stock and warrants to acquire an
additional 325,000 shares of common stock at an exercise price of $26.75 per
share. The common stock was recorded at $21.55 per share and the warrants were
valued at $8.00 per underlying share of the Company's Common Stock using the
Black-Scholes option valuation model. The transaction was accounted for as an
acquisition of assets and the purchase price was allocated to the rigs and
related equipment acquired.
UTI ENERGY, CORP. -- On February 4, 2001, Patterson entered into an
Agreement and Plan of Merger with UTI providing for the merger of the two
entities. On May 8, 2001, the stockholders of each company approved the merger
and the merger was consummated. Each outstanding share of UTI common stock was
converted into one share of Patterson common stock and each option or warrant
then outstanding representing the right to receive UTI common stock was
converted into the right to purchase Patterson-UTI common stock on an equivalent
basis. A total of 37,782,135 shares of common stock was issued pursuant to the
merger and an additional 3,621,079 shares were reserved for issuance under the
then outstanding UTI stock option plans. Additionally, the stockholders of
Patterson approved an increase in the authorized shares of common stock from 50
million to 200 million and a name change to "Patterson-UTI Energy, Inc."
The Company incurred $13.1 million in expenses related to the merger. The
expenses consisted of $5.9 million in merger costs which were primarily related
to professional fees paid to investment banking firms, attorneys, accountants
and commercial printers for their professional services rendered and $7.2
million in restructuring costs and related charges incurred as a result of the
following:
- severance costs and related expenses of $2.8 million,
- closing of duplicate operational facilities of $1.6 million,
F-13
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- costs of $1.4 million incurred in connection with changes to the
Company's credit facilities (see Note 8), and
- fees and expenses related to the transfer of licenses and leaseholds, and
in some instances the impairment of such leaseholds, the combination or
cancellation of various service contracts and the renegotiation of
certain insurance policies of $1.4 million.
The merger was treated as a reorganization within the meaning of Section
368(a) of the Internal Revenue Code of 1986, as amended, and was accounted for
as a pooling of interests for financial accounting purposes. The consolidated
financial statements give retroactive effect to the merger. Certain adjustments
were made in those periods to conform the previous accounting policies of UTI
with those of Patterson.
JONES DRILLING CORPORATION -- On January 5, 2001, the Company consummated
the transactions contemplated by certain agreements among the Company and Jones
Drilling Corporation and three of its affiliated entities. The acquired assets
consisted of 21 drilling rigs and related equipment and approximately $2.3
million of net working capital. The purchase price of $33.2 million consisted of
810,070 shares of the Company's common stock valued at $26.8125 per share and
$11.3 million cash plus approximately $240,000 in transaction costs. The
transaction was accounted for as a business combination and the purchase price,
net of working capital acquired, was allocated among the assets acquired based
on their estimated fair market values as of the date of the transaction.
OTHER -- In January 2001, the Company acquired six drilling rigs, through
three separate transactions, for approximately $15.7 million cash in aggregate.
The transactions were accounted for as acquisitions of assets and the purchase
price was allocated to the rigs acquired.
2000 MERGER AND ACQUISITIONS
AMBAR, INC. -- In October 2000, the Company completed, through a wholly
owned subsidiary, the acquisition of the drilling and completion fluid
operations of Ambar, Inc., a non-affiliated entity with its principal operations
in Louisiana, the Gulf Coast region of South Texas and the Gulf of Mexico. The
purchase price of $12.4 million consisted of cash of $11.7 million and $680,000
of direct costs incurred related to the acquisition. The assets acquired
included net working capital of approximately $7.8 million (current assets of
$18.2 million and current liabilities assumed of $10.4 million). The transaction
was accounted for as a business combination and the purchase price, net of
working capital acquired, was allocated to the fixed assets based on their
estimated fair market values as of the date of the transaction.
OTHER -- In September, 2000, the Company acquired four drilling rigs in two
separate transactions for a total of $7.7 million in cash. The transactions were
accounted for as acquisitions of assets and the purchase price was allocated to
the rigs acquired.
HIGH VALLEY DRILLING, INC. -- On June 2, 2000, the Company completed the
merger of High Valley Drilling, Inc., a privately held, non-affiliated company,
with and into Patterson-UTI Drilling Company LP, LLLP, a wholly owned subsidiary
of Patterson-UTI. The purchase price of $21.8 million was funded using 1,150,000
shares of common stock valued at $18 per share, three-year warrants to acquire
127,000 shares at $22 per share and approximately $208,000 of direct costs
incurred related to the transaction. Using a Black-Scholes model, the warrants
were valued at $900,000. The assets acquired consisted of eight drilling rigs
and other related equipment. The transaction was accounted for as an acquisition
of assets and the purchase price was allocated among such assets based upon the
estimated fair market value of the drilling rigs and related equipment.
ASSET SWAP. -- On May 15, 2000, the Company, in a non-monetary exchange,
acquired a drilling rig in exchange for certain drilling rig components and
drill pipe with a net book value of approximately $970,000.
F-14
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The transaction was accounted for as an acquisition of assets and no gain or
loss was recognized on this transaction.
PHELPS DRILLING INTERNATIONAL LTD. -- On May 5, 2000, the Company acquired
the land drilling operations of Phelps Drilling International Ltd. for $29.6
million in cash. Phelps' assets and operations are located in the Canadian
provinces of Alberta, Saskatchewan and British Columbia. The acquired assets
consisted of fourteen land drilling rigs and related equipment. The acquisition
was accounted for as a business combination and the purchase price was allocated
among such assets based upon the fair market value of the drilling rigs and
related equipment.
WEK DRILLING CO., INC. -- On March 31, 2000, the Company acquired the
outstanding stock of WEK Drilling Co., Inc., a privately held, non-affiliated
drilling company with its principal operations in Southeast New Mexico. The
purchase price of $6.8 million, which is net of cash acquired, was funded using
$5.66 million of proceeds from the Company's existing credit facility and 53,000
shares of the Company's common stock valued at $29.0625 per share and
approximately $77,000 of direct costs incurred related to the transaction. The
assets acquired consisted of four operable drilling rigs, other related
equipment, and working capital of $1.2 million. Immediately following the
transaction, certain assets unrelated to the oil and natural gas industry were
sold back to one of the previous owners for a cash payment of $1.0 million. The
transaction was accounted for as an acquisition of assets and the purchase price
of $6.8 million, less the $1.0 million of unrelated assets that were
subsequently sold and the net working capital acquired, was allocated among the
acquired assets based upon the estimated fair market value of the drilling rigs
and related equipment.
3. COMPREHENSIVE INCOME
The following table illustrates the Company's comprehensive income
including the effects of foreign currency translation adjustments for the years
ended December 31, 2002, 2001, and 2000 (in thousands):
2002 2001 2000
------ -------- -------
Net income.............................................. $2,169 $164,162 $37,226
Other comprehensive income:
Foreign currency translation adjustment related to our
Canadian operations................................... 457 (2,326) 30
Unrealized gain on equity securities, net of tax........ 30 -- --
------ -------- -------
Comprehensive income.................................... $2,656 $161,836 $37,256
====== ======== =======
4. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following at December 31, 2002 and
2001 (in thousands):
2002 2001
---------- --------
Drilling rigs and related equipment......................... $ 895,125 $810,910
Other equipment............................................. 54,788 46,201
Oil and natural gas properties.............................. 49,736 45,839
Buildings................................................... 11,073 10,357
Land........................................................ 3,779 3,703
---------- --------
1,014,501 917,010
Less accumulated depreciation and depletion................. (386,767) (302,590)
---------- --------
$ 627,734 $614,420
========== ========
F-15
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. GOODWILL AND OTHER INTANGIBLE ASSETS
Intangible assets consist primarily of goodwill and covenants not to
compete arising from business combinations (see Note 2). In accordance with SFAS
No. 142, all of our intangible assets that have definite lives are being
amortized on a straight-line basis over their estimated useful lives and
goodwill is evaluated to determine if fair value of the asset has decreased
below its carrying value. At December 31, 2002, we evaluated goodwill and
determined no adjustment to impair goodwill was necessary. Amortization expense
of approximately $4.7 million recognized during 2001 and during 2000, would not
have been recognized under SFAS No. 142. Goodwill and other intangible assets as
of December 31, 2002 and 2001 are as follows (in thousands):
2002 2001
------- -------
Goodwill.................................................... $69,860 $69,860
Accumulated amortization.................................... (19,661) (19,661)
------- -------
Goodwill, net............................................... 50,199 50,199
------- -------
Covenants-not-to-compete and other.......................... $ 1,956 $ 3,635
Accumulated amortization.................................... (842) (2,200)
------- -------
Other intangible assets, net................................ 1,114 1,435
------- -------
Intangible assets, net...................................... $51,313 $51,634
======= =======
The amount of goodwill and other intangible assets as of December 31, 2002
and 2001 assigned to the contract drilling and drilling and completion fluids
operating segments, the only operating segments that had intangible assets for
such periods, is as follows (in thousands):
2002
Contract Drilling:
Goodwill...................... $56,543.. Accumulated Amortization........ $16,278
Non-Competes & Other.......... $ 1,909 Accumulated Amortization........ $ 828
Drilling and Completion Fluids:
Goodwill...................... $13,317 Accumulated Amortization........ $ 3,383
Non-Competes & Other.......... $ 47 Accumulated Amortization........ $ 14
2001
Contract Drilling:
Goodwill...................... $56,543 Accumulated Amortization........ $16,278
Non-Competes & Other.......... $ 3,588 Accumulated Amortization........ $ 2,189
Drilling and Completion Fluids:
Goodwill...................... $13,317 Accumulated Amortization........ $ 3,383
Non-Competes & Other.......... $ 47 Accumulated Amortization........ $ 11
F-16
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Change in the net carrying amount of goodwill for the year ended December
31, 2002 is as follows (in thousands):
DRILLING &
COMPLETION
DRILLING FLUIDS TOTAL
-------- ---------- -------
Balance at December 31, 2001........................... $40,265 $9,934 $50,199
Changes to goodwill.................................... -- -- --
------- ------ -------
Balance at December 31, 2002........................... $40,265 $9,934 $50,199
======= ====== =======
Amortization expense consists of the following (in thousands):
TWELVE MONTHS ENDED DECEMBER 31,
----------------------------------
2002 2001 2000
-------- -------- --------
Goodwill............................................... $ -- $4,665 $4,665
Covenants-not-to-compete and other..................... 315 507 712
------ ------ ------
Goodwill, net.......................................... $ 315 $5,172 $5,953
====== ====== ======
Our weighted average amortization period for other intangible assets is
approximately 10 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
2003........................................................ $134
2004........................................................ $ 97
2005........................................................ $ 97
2006........................................................ $ 97
2007........................................................ $ 97
Had SFAS No. 142 been in effect prior to January 1, 2002, our reported net
income and net income per share would have been as follows (in thousands, except
per share amounts):
TWELVE MONTHS ENDED DECEMBER 31,
---------------------------------
2002 2001 2000
-------- ---------- ---------
Net income:
Reported.............................................. $2,169 $164,162 $37,226
Goodwill amortization................................. -- 4,665 4,665
------ -------- -------
Adjusted.............................................. $2,169 $168,827 $41,891
====== ======== =======
Basic net income per common share:
Reported.............................................. $ 0.03 $ 2.15 $ 0.52
Effect of goodwill amortization....................... -- 0.06 0.07
------ -------- -------
Adjusted.............................................. $ 0.03 $ 2.21 $ 0.59
====== ======== =======
Diluted net income per common share:
Reported.............................................. $ 0.03 $ 2.07 $ 0.50
Effect of goodwill amortization....................... -- 0.06 0.06
------ -------- -------
Adjusted.............................................. $ 0.03 $ 2.13 $ 0.56
====== ======== =======
F-17
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. INVESTMENT IN EQUITY SECURITIES
On June 14, 2002, the Company purchased 762,597 shares of the common stock
of TMBR/Sharp Drilling, Inc. ("TMBR"), $.10 par value per share, for an
aggregate cash purchase price of $12.7 million, or $16.60 per share plus
approximately $39,000 of additional costs incurred to acquire the shares. The
purchase agreement also included (i) an option for the Company to purchase, and
(ii) an option for the sellers to require the Company to purchase, up to an
additional 195,000 shares of common stock at $16.60 per share. This option was
exercised in October 2002. The company also purchased an additional 101,076
shares on that date at the same price and incurred an additional $45,000 in
costs to acquire the shares. As of December 31, 2002, the Company owned
approximately 19.9% of the outstanding shares of TMBR.
The accounting treatment of shares representing the Company's investment in
the common stock of TMBR is affected by the Company's ability to sell shares
within one year. As of December 31, 2002, the Company has restrictions on its
ability to sell 892,742 of the TMBR shares within one year. These shares are
reflected in the balance sheet at cost under the cost method of accounting in
accordance with Accounting Principles Board Opinion No. 18, "The Equity Method
of Accounting for Investment in Common Stock," ("APB 18"). The remaining 165,931
TMBR shares are not restricted from sale within one year. These shares are
classified as Available-for-Sale and are reflected in the balance sheet at fair
value in accordance with SFAS No. 115. Fair value is determined from publicly
quoted market prices as of the balance sheet date. In accordance with SFAS No.
115, unrealized gains and losses recorded as a result of the adjustment to fair
value are reflected directly in stockholders' equity.
The following table summarizes the Company's unrealized gain on its
investment in equity securities as of December 31, 2002 (in thousands, except
share amounts):
COMMON UNREALIZED
SHARES COST GAIN TOTAL
--------- ------- ---------- -------
TMBR/Sharp Drilling, Inc.
Cost method................................. 892,742 $14,833 $ -- $14,833
Available-for-Sale.......................... 165,931 2,826 48 2,874
--------- ------- ---- -------
1,058,673 $17,659 $ 48 $17,707
========= ======= ==== =======
7. ACCRUED EXPENSES
Accrued expenses consisted of the following at December 31, 2002 and 2001
(in thousands):
2002 2001
------- -------
Salaries, wages, payroll taxes and benefits................. $10,573 $13,833
Workers' compensation liability............................. 15,516 10,683
Sales, use and other taxes.................................. 2,712 4,758
Insurance, other than workers' compensation................. 2,605 1,777
Restructuring and merger related costs...................... 1,029 2,200
Other....................................................... 3,078 3,257
------- -------
$35,513 $36,508
======= =======
F-18
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes activity in restructuring and merger related
accrual accounts for the year ended December 31, 2002 (in thousands):
Balance at December 31, 2001................................ $2,200
Severance costs and related expenses........................ (324)
Closing of duplicate operational facilities................. (392)
Professional fees........................................... (455)
------
Balance at December 31, 2002................................ $1,029
======
8. NOTES PAYABLE
There were no amounts outstanding under the Company's revolving credit
facility at December 31, 2002 or December 31, 2001. The maximum borrowings under
this revolving credit facility were increased from $90.0 million to $100.0
million in June 2001 and the term of the facility was also extended to June
2005. A fee of .375% per annum is assessed on the unused facility amount. The
amount used for letters of credit decreases the borrowing base of the facility
on a dollar-for-dollar basis. The revolving credit facility calls for periodic
interest payments at a floating rate ranging from LIBOR plus 1.75% to 2.75%. The
applicable rate above LIBOR (1.75% at December 31, 2002) is based upon our
trailing twelve-month EBITDA (earnings before interest expense, income taxes and
depreciation, depletion and amortization expense). Assets of the Company secure
the facility. The facility has restrictions customary in financial instruments
of this type including restrictions on certain investments, acquisitions and
loans. The facility has no financial covenants unless availability under the
facility is less than $20.0 million. The terms of the facility limit the payment
of dividends without the prior written consent of the lenders.
During 2001, the Company repaid $89.2 million under its existing credit
facilities and other term obligations. The Company incurred expenses of $448,000
as a result of prepayment penalties and $942,000 related to deferred financing
costs which were unamortized at the time the debt was extinguished. The
penalties and deferred financing costs were included in restructuring and
related charges in 2001.
9. COMMITMENTS, CONTINGENCIES, AND OTHER MATTERS
The Company maintains letters of credit in the aggregate amount of $25.5
million for the benefit of various insurance companies as collateral for
retrospective premiums and retained losses which could become payable under the
terms of the underlying insurance contracts. These letters of credit expire
variously during each calendar year. No amounts have been drawn under the
letters of credit.
Contingencies -- The Company's contract services and oil and natural gas
exploration and production operations are subject to inherent risks, including
blowouts, cratering, fire, and explosions which could result in personal injury
or death, suspended drilling operations, damage to, or destruction of equipment,
damage to producing formations, and pollution or other environmental hazards.
As a protection against these hazards, the Company maintains general
liability insurance coverage of $2.0 million per occurrence with $4.0 million of
aggregate coverage and excess liability and umbrella coverages up to $50.0
million per occurrence and in the aggregate. We maintain a $1 million per
occurrence deductible on our general liability insurance coverage and a $750,000
per occurrence deductible on our workers' compensation insurance coverage. These
levels of self-insurance expose us to increased operating costs and risks.
Net income for the year ended December 31, 2002 includes a charge of $4.7
million related to the financial failure in 2002 of a workers' compensation
insurance carrier that had provided coverage for the Company in prior years.
F-19
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company believes it is adequately insured for public liability and
property damage to others with respect to its operations. However, such
insurance may not be sufficient to protect the Company against liability for all
consequences of well disasters, extensive fire damage, or damage to the
environment. The Company also carries insurance to cover physical damage to, or
loss of, its rigs; however, it does not carry insurance against loss of earnings
resulting from such damage or loss. The Company's lender who has a security
interest in the drilling rigs is named as loss payee on the physical damage
insurance on such rigs.
Westfort Energy LTD and Westfort Energy (US) LTD f/k/a Canadian Delta, Inc.
("Westfort"), filed a lawsuit against two Patterson-UTI subsidiaries, Patterson
Petroleum LP, and Patterson-UTI Drilling Company LP, in the Circuit Court,
Rankin County, Mississippi, Case No. 2002-18. The lawsuit relates to a letter
agreement entered into in July 2000 between Patterson Petroleum LP and Westfort
concerning the drilling of a daywork well in Mississippi. This lawsuit was filed
by Westfort after Patterson Petroleum LP made demand on Westfort for payment of
the contract drilling services.
In this lawsuit, Westfort alleges breach of contract, fraud, and negligence
causes of action. Westfort seeks alleged monetary damages, the return of shares
of Westfort stock, unspecified damages from alleged lost profits, lost use of
income stream, and additional operating expenses, along with alleged punitive
damages to be determined by the jury, but not less than 25% of Patterson's net
worth. The Company intends to vigorously contest the allegations made by
Westfort and asserts claims against Westfort, including for the monies owed
Patterson Petroleum LP under the letter agreement in the amount of approximately
$5,075,000. The Company believes that it is remote that the outcome of this
matter will have a material adverse effect on the Company's financial condition
or results of operations.
In addition to the Westfort lawsuit, the Company is party to various legal
proceedings arising in the normal course of its business. The Company does not
believe that the outcome of these proceedings, either individually or in the
aggregate, will have a material adverse effect on its financial condition.
10. STOCKHOLDERS' EQUITY
During March 2002, the Company issued 650,000 shares of its common stock as
consideration for the acquisition of Odin Drilling, Inc. (see Note 2). The
common stock was valued at $26.06 per share, its fair market value on the date
the terms of the transaction were agreed upon.
During December 2001, the Company issued 450,000 shares of its common stock
and warrants to acquire an additional 325,000 shares at an exercise price of
$26.75 per share, as partial consideration for the acquisition of 17 drilling
rigs and related equipment from Cleere Drilling Company. The common stock was
recorded at $21.55 per share and the warrants were valued at $8.00 per
underlying share of common stock using the Black-Scholes option valuation model
(see Note 2).
On May 8, 2001, pursuant to the merger between Patterson and UTI, the
Company's stockholders approved an amendment to the Company's charter increasing
the number of authorized shares of the Company's common stock to 200 million.
During January 2001, the Company issued 810,070 shares of its common stock
as partial consideration for the acquisition of Jones Drilling Corporation and
certain assets owned by its related entities (see Note 2). The common stock was
valued at $26.8125 per share, its fair market value on the date of the
transaction.
During September 2000, the Company issued 3,000,000 shares of its common
stock at a public price of $34.50 per share. An underwriting discount of $1.50
was paid for a net price of $33.00 per share. Net proceeds from the offering
totaled approximately $98.8 million.
During June 2000, the Company issued 1,150,000 shares of its common stock
and three-year warrants to acquire an additional 127,000 shares at an exercise
price of $22.00 per share, as consideration for certain drilling equipment
acquired from High Valley Drilling, Inc. (see Note 2). The common stock was
recorded at
F-20
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$18 per share, its fair market value on the date of purchase and the warrants
were valued at $900,000 using the Black-Scholes option valuation model.
During March 2000, the Company issued 53,000 shares of its common stock as
consideration for certain drilling equipment acquired from WEK Drilling Company,
Inc. The common stock was recorded at $29.0625 per share, its fair market value
on the date of purchase (see Note 2).
11. STOCK OPTIONS AND WARRANTS
EMPLOYEE AND NON-EMPLOYEE DIRECTOR STOCK OPTION PLANS -- The Company has
seven stock option plans of which three are active. The remaining four plans are
dormant and the Company does not intend to grant any further options under such
plans. At December 31, 2002, the Company's stock option plans were as follows:
OPTIONS OPTIONS
AUTHORIZED OPTIONS AVAILABLE
PLAN NAME FOR GRANT OUTSTANDING FOR GRANT
--------- ---------- ----------- ---------
Patterson-UTI Energy, Inc. Amended and Restated 1997
Long-Term Incentive Plan ("1997 Plan")(1)(3).............. 6,000,000 3,881,988 532,536
Patterson-UTI Energy, Inc. 2001 Long-Term Incentive Plan
("2001 Plan")(2).......................................... 1,000,000 957,524 8,733
Amended and Restated Non-Employee Director Stock Option Plan
of Patterson-UTI Energy, Inc. ("Non-Employee Director
Plan")(1)................................................. 600,000 112,500 345,000
Patterson-UTI Energy, Inc. Non-Employee Directors' Stock
Option Plan, as amended ("1995 Non-Employee Director
Plan").................................................... 120,000 28,000 --
1997 Stock Option Plan of DSI Industries, Inc. ("DSI
Plan")(1)................................................. -- 5,388 --
Amended and Restated Patterson-UTI Energy, Inc. 1996
Employee Stock Option Plan ("1996 Plan")(1)............... -- 253,300 --
Patterson-UTI Energy, Inc., 1993 Incentive Stock Plan, as
amended ("1993 Plan")..................................... 2,800,000 876,188 --
---------------
(1) Plan was assumed by the Company as a part of the merger between Patterson
and UTI.
(2) Plan is for the benefit of employees of the Company, other than officers and
directors of the Company.
(3) Plan is for the benefit of employees of the Company, including officers and
directors of the Company.
The Company's active plans are the 1997 Plan, the 2001 Plan and the
Non-Employee Director Plan. A summary of each of these plans is set forth below.
1997 PLAN
- Administered by the Compensation Committee of the Board of Directors.
- All employees including officers and employee directors are eligible for
awards.
- Vesting schedule is set by the Compensation Committee, however, typically
options vest over 3 or 5 years.
- The Compensation Committee sets the term of the option except that no
Incentive Stock Option ("ISO") can have a term of longer than 10 years.
Typically options granted under the plan have a term of 10 years.
- The options granted under the plan, unless otherwise stated in the grant
thereof, vest upon a change of control as defined in the plan. Options
granted to non-executive employees typically do not vest upon a change of
control.
F-21
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- All options granted under the plan are granted with an exercise price
equal to or greater than the fair market value of the Company's common
stock at the time the option is granted.
- Although the plan allows for awards of tandem and independent stock
appreciation rights, restricted stock and performance awards, no such
awards have been granted.
- During 2002, the Company increased the options authorized for grant from
3,800,000 to 6,000,000.
2001 PLAN
The terms and conditions of the 2001 Plan are identical to the 1997 Plan
except as follows:
- Officers and directors of the Company are not eligible for grants of
options under the 2001 Plan.
- No ISO's may be awarded under the 2001 Plan.
- Unless the grant states otherwise, options granted under the 2001 Plan do
not vest upon a change of control of the Company.
NON-EMPLOYEE DIRECTOR PLAN
- Administered by the Compensation Committee of the Board of Directors.
- All options vest upon the first anniversary of the option grant.
- Each director receives options to purchase 15,000 shares upon becoming a
director of the Company and options to purchase 7,500 shares on December
31 of each subsequent year in which the director serves as a director of
the Company.
- The exercise price of the options is the fair market value of the
Company's common stock on the date of grant.
Of the four dormant plans administered by the Company, two of the plans
(the 1993 Plan and the 1995 Non-Employee Director Plan) were plans of the
Company prior to the merger of Patterson and UTI and two of the plans (the DSI
Plan and the 1996 Plan) were plans of UTI.
1995 NON-EMPLOYEE DIRECTOR PLAN -- Options granted under the 1995
Non-Employee Director Plan vest on the first anniversary of the option grant.
1995 Non-Employee Director Plan options have five year terms. All options were
granted with an exercise price equal to the fair market value of the Company's
common stock at the time of grant.
DSI PLAN -- The options granted under the DSI plan typically vested at a
rate of 33% per year with ten year terms. All options were granted with an
exercise price equal to the fair market value of the Company's common stock at
the time of grant.
1996 PLAN -- The options granted under the 1996 plan vested over one, four
and five years as dictated by the Compensation Committee. These options had
terms of five and ten years as dictated by the Compensation Committee. All
options were granted with a strike price equal to the fair market value of the
Company's common stock at the time of grant.
1993 PLAN -- Options granted under the 1993 Plan, typically had terms of 10
years and vested over five years in 20% increments beginning at the end of the
first year. These options vest in the event of a change of control as defined in
the plan. All options were granted with an exercise price equal to the fair
market value of the Company's common stock at the time of grant.
ADDITIONAL OPTIONS -- In July 2001, the Compensation Committee granted to
each of two non-employee directors of the Company an option to purchase 12,000
shares of the Company's common stock. These options vested on November 6, 2001
and terminate four years later on November 5, 2005. The exercise price of each
of the options was $28.625, which was in excess of the fair market value of the
Company's common stock on the date of grant.
F-22
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A summary of the status of the Company's stock options issued as of
December 31, 2002, 2001, and 2000 and the changes during each of the years then
ended are presented below (in thousands, except weighted average exercise
price):
2002 2001 2000
--------------------- --------------------- ---------------------
NO. OF WEIGHTED NO. OF WEIGHTED NO. OF WEIGHTED
SHARES OF AVERAGE SHARES OF AVERAGE SHARES OF AVERAGE
UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
---------- -------- ---------- -------- ---------- --------
Outstanding at beginning
of the year............ 6,596 $10.40 5,488 $ 7.57 6,497 $5.72
Granted................ 2,149 26.77 2,103 16.19 586 18.58
----- ------ ----- ------ ----- -----
Total granted....... 8,745 14.42 7,591 9.96 7,083 6.78
Exercised.............. 2,457 6.41 805 5.26 1,563 3.93
Surrendered............ 149 15.32 190 14.39 32 11.42
----- ------ ----- ------ ----- -----
Outstanding at end of
year................... 6,139 $17.61 6,596 $10.40 5,488 $7.57
===== ====== ===== ====== ===== =====
Exercisable at end of
year................... 2,395 $10.88 4,110 $ 7.52 2,672 $6.89
===== ====== ===== ====== ===== =====
The following table summarizes information about stock options outstanding
at December 31, 2002:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------- ----------------------
WEIGHTED
AVERAGE WEIGHTED
REMAINING WEIGHTED AVERAGE
NUMBER CONTRACTED AVERAGE NUMBER EXERCISE
RANGE OF EXERCISE PRICES OUTSTANDING LIFE EXERCISE PRICE EXERCISABLE PRICES
------------------------ ----------- ---------- -------------- ----------- --------
$3.125 to $5.00.............. 1,057,579 6.14 $ 4.55 963,712 $ 4.52
$5.01 to $20.00.............. 2,819,809 7.53 $15.18 1,318,800 $14.22
$20.01 to $32.875............ 2,261,500 9.20 $26.74 113,000 $26.25
--------- ---- ------ --------- ------
6,138,888 7.90 $17.61 2,395,512 $10.88
========= ==== ====== ========= ======
PUBLIC RELATIONS SERVICES STOCK OPTIONS -- In June 1999, the Company issued
options covering a total of 50,000 shares of common stock at an exercise price
of $8.0625 per share to a consultant as partial compensation for public
relations services rendered to the Company. The options granted to the
consultant have an exercise price equal to the fair market value of the stock at
date of grant. The options were fully exercisable upon grant date. All such
options were exercised in 2000.
PRO FORMA STOCK-BASED COMPENSATION DISCLOSURE -- Pro forma information
regarding net income and earnings per share, as described in Note 1, has been
determined as if the Company had accounted for its employee stock options under
the fair value method as defined in that statement. The fair value of each stock
option granted is estimated on the date of grant using the Black-Scholes option
valuation model with the following weighted-average assumptions for grants in
1995 through 2002 respectively; dividend yield of 0.00%; risk-free interest
rates are different for each grant and range from 3.77% to 7.02%; the expected
term is 5 years; and a volatility of 38.68% for all 1995 and 1996 grants, 35.97%
for all 1997 grants, 51.08% for all 1998 grants, 61.97% for all 1999 grants,
67.71% for all 2000 grants, 68.33% for all 2001 grants and 63.02% for all 2002
grants. The effects of applying SFAS No. 123 in this pro forma disclosure are
not indicative of future amounts. SFAS No. 123 does not apply to awards prior to
1995.
STOCK PURCHASE WARRANTS -- In December 2001, the Company issued 325,000
warrants exercisable at $26.75 per share as partial consideration for the
purchase of 17 drilling rigs and related equipment from Cleere
F-23
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Drilling Company (see Note 2). The warrants were fully exercisable upon the date
of issuance. If not exercised, the warrants will expire on December 21, 2004.
In June 2000, the Company issued 127,000 warrants exercisable at $22 per
share as partial consideration for the purchase of eight drilling rigs and
related equipment from High Valley Drilling, Inc. (see Note 2). The warrants
were fully exercisable upon date of issuance. If not exercised, the warrants
will expire on June 2, 2003.
TABULAR SUMMARY -- The following table summarizes information regarding the
Company's stock options and warrants granted under the provisions of the
aforementioned plans: as well as stock options and warrants issued pursuant to
certain transactions described in Notes 2 and 10:
WEIGHTED AVERAGE
SHARES EXERCISE PRICE
--------- ----------------
GRANTED
2002..................................................... 2,148,500 $26.77
2001..................................................... 2,428,500 17.60
2000..................................................... 713,000 19.19
EXERCISED
2002..................................................... 2,481,486 $ 6.56
2001..................................................... 804,581 5.26
2000..................................................... 1,563,345 3.93
SURRENDERED
2002..................................................... 149,205 $15.32
2001..................................................... 190,473 14.39
2000..................................................... 31,879 11.42
OUTSTANDING AT YEAR END
2002..................................................... 6,566,101 $18.13
2001..................................................... 7,048,292 11.36
2000..................................................... 5,614,846 7.89
EXERCISABLE AT YEAR END
2002..................................................... 2,822,726 $13.11
2001..................................................... 4,562,259 9.29
2000..................................................... 2,799,482 7.58
12. LEASES
The Company incurred rent expense, consisting primarily of daily rental
charges for the use of drilling equipment, of $5.7 million, $5.9 million, and
$8.6 million, for the years 2002, 2001, and 2000, respectively. The Company's
obligations under non-cancelable operating lease agreements are not material to
the Company's operations.
F-24
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. INCOME TAXES
Components of the income tax provision applicable for federal, state and
foreign income taxes are as follows (in thousands):
2002 2001 2000
-------- -------- -------
Federal income tax expense (benefit):
Current............................................. $(18,064) $ 82,417 $ 6,932
Deferred............................................ 21,687 10,887 14,705
-------- -------- -------
3,623 93,304 21,637
State income tax expense (benefit):
Current............................................. (1,811) 4,294 (1)
Deferred............................................ 1,117 661 772
-------- -------- -------
(694) 4,955 771
Foreign income tax expense (benefit):
Current............................................. (2,003) 1,062 --
Deferred............................................ 744 3,012 470
-------- -------- -------
(1,259) 4,074 470
Total:
Current............................................. $(21,878) $ 87,773 $ 6,931
Deferred............................................ 23,548 14,560 15,947
-------- -------- -------
Total income tax expense.............................. $ 1,670 $102,333 $22,878
======== ======== =======
The difference between the statutory federal income tax rate and the
effective income tax rate is summarized as follows:
2002 2001 2000
---- ---- ----
Statutory tax rate.......................................... 35.0% 35.0% 35.0%
State income taxes.......................................... 2.8 1.9 1.0
Foreign taxes............................................... -- -- 0.2
Permanent differences....................................... 5.7 1.3 1.4
Other, net.................................................. -- 0.2 .5
---- ---- ----
Effective tax rate.......................................... 43.5% 38.4% 38.1%
==== ==== ====
In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. The ultimate realization of deferred tax assets is
dependent upon the generation of future taxable income during the periods in
which those temporary differences become deductible. Management considers the
scheduled reversal of deferred tax liabilities, projected future taxable income,
and tax planning strategies in making this assessment. The Company expects the
deferred tax assets at December 31, 2002 to be realized as a result of the
reversal during the carryforward period of existing taxable temporary
differences giving rise to deferred tax liabilities and the generation of
taxable income in the carryforward period; therefore, no valuation allowance is
necessary.
F-25
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The tax effect of significant temporary differences representing deferred
tax assets and liabilities and changes therein were as follows (in thousands):
DECEMBER 31, NET DECEMBER 31, NET DECEMBER 31, NET JANUARY 1,
2002 CHANGE 2001 CHANGE 2000 CHANGE 2000
------------ -------- ------------ -------- ------------ -------- ----------
Deferred tax assets:
Net operating loss
carryforwards.............. $ -- $ -- $ -- $ (5,850) $ 5,850 $ (5,878) $ 11,728
Investment tax credit
carryforwards.............. -- -- -- (469) 469 73 396
AMT credit carryforwards....... 602 -- 602 (3,770) 4,372 543 3,829
Other.......................... 14,688 6,543 8,145 2,791 5,354 2,215 3,139
--------- -------- -------- -------- -------- -------- --------
15,290 6,543 8,747 (7,298) 16,045 (3,047) 19,092
Valuation allowance............ -- -- -- -- -- -- --
--------- -------- -------- -------- -------- -------- --------
Deferred tax assets.......... 15,290 6,543 8,747 (7,298) 16,045 (3,047) 19,092
Deferred tax liabilities:
Property and equipment basis
difference................. (127,006) (34,147) (92,859) (16,005) (76,854) (17,132) (59,722)
--------- -------- -------- -------- -------- -------- --------
Net deferred tax
liability................ $(111,716) $(27,604) $(84,112) $(23,303) $(60,809) $(20,179) $(40,630)
========= ======== ======== ======== ======== ======== ========
Patterson-UTI's investment tax credit carryforward expired in 2000. Net
operating losses were fully utilized in 2001 and the remaining alternative
minimum tax credit may be carried forward indefinitely. Significant other
deferred tax assets consist primarily of workers' compensation allowance of $7.2
million and bad debt allowance of $3.1 million at December 31, 2002.
14. EMPLOYEE BENEFITS
The Company maintains a 401(k) plan for all eligible employees. The
Company's operating results include expenses of $2.1 million in 2002 and 2001
and $783,000 in 2000 for the Company's discretionary contributions to the plan.
15. BUSINESS SEGMENTS
The Company conducts its business through four distinct operating segments:
contract drilling of oil and natural gas wells, drilling and completion fluids
services and pressure pumping services to operators in the oil and natural gas
industry, and the exploration, development, acquisition and production of oil
and natural gas. Each of these segments represents a distinct type of business
based upon the type and nature of services and products offered. These segments
have separate management teams which report to the Company's chief executive
officer and have distinct and identifiable revenues and expenses.
CONTRACT DRILLING -- The Company markets its contract drilling services to
major and independent oil and natural gas operators. The Company owns 324
drilling rigs, of which 230 operated in 2002. Currently, 262 of the drilling
rigs are based in Texas and New Mexico (144 in West Texas and New Mexico, 56 in
South Texas, 42 in East Texas, and 20 in North-Central Texas), 41 are based in
Oklahoma, five in Utah, and 16 in Western Canada. Our contract drilling
operations contributed operating income of $7.6 million in 2002.
DRILLING AND COMPLETION FLUIDS -- The Company provides contract drilling
and completion fluids services to oil and natural gas operators in West Texas,
Southeast New Mexico, South Texas, East Texas, Oklahoma, the Gulf Coast regions
of Texas and Louisiana, and the Gulf of Mexico. Drilling and completion fluids
are used by oil and natural gas operators during the drilling process to control
pressure when drilling oil and natural gas wells. The drilling fluids operations
were added by the Company during 1998 with its acquisition of two companies with
operations in Texas, New Mexico, Oklahoma, and Colorado. Our services
F-26
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
were expanded to include completion fluids in October 2000 with the acquisition
of the drilling and completion fluids division of Ambar, Inc., which had
operations in the coastal areas of Texas, Louisiana, and in the Gulf of Mexico.
Our drilling and completion fluids services operations had an operating loss of
$278,000 in 2002.
PRESSURE PUMPING -- The Company provides pressure pumping services in the
Appalachian Basin. Pressure pumping services consist primarily of well
stimulation and cementing for the completion of new wells and remedial work on
existing wells. Well stimulation involves processes inside a well designed to
enhance the flow of oil, natural gas, or other desired substances from the well.
Cementing is the process of inserting material between the hole and the pipe to
center and stabilize the pipe in the hole. Our pressure pumping operations
contributed operating income of $6.1 million in 2002.
OIL AND NATURAL GAS -- The Company is engaged in the development,
exploration, acquisition, and production of oil and natural gas. Our oil and
natural gas operations contributed operating income of $3.9 million in 2002.
The following tables summarize selected financial information relating to
our business segments (in thousands):
DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
Revenues:
Contract drilling.................................. $410,295 $839,931 $512,998
Drilling and completion fluids..................... 69,943 94,456 32,053
Pressure pumping................................... 32,996 39,600 21,465
Oil and natural gas................................ 14,723 15,988 15,806
-------- -------- --------
Total revenues....................................... $527,957 $989,975 $582,322
======== ======== ========
Income before income taxes:
Contract drilling.................................. $ 7,607 $274,514 $ 68,427
Drilling and completion fluids..................... (278) 3,842 (250)
Pressure pumping................................... 6,090 12,649 3,302
Oil and natural gas................................ 3,945 756 5,807
-------- -------- --------
17,364 291,761 77,286
Corporate and other................................ (9,266) (11,444) (8,701)
Merger costs....................................... -- (5,943) --
Restructuring and other charges(a)................. (4,700) (7,202) --
Interest income.................................... 1,110 2,080 1,377
Interest expense................................... (532) (3,142) (10,108)
Other.............................................. (137) 385 250
-------- -------- --------
Income before income taxes........................... $ 3,839 $266,495 $ 60,104
======== ======== ========
---------------
(a) Restructuring and other charges relate to decisions of the executive
management group regarding corporate strategy, credit risk, loss
contingencies and restructuring activities. Due to the non-operating nature
of these decisions, the related charges have been separately presented and
excluded from the results of specific segments. These charges primarily
related to the contract drilling segment.
F-27
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
Identifiable assets:
Contract drilling.................................. $694,020 $681,700 $571,498
Drilling and completion fluids..................... 34,687 41,724 52,414
Pressure pumping................................... 35,084 29,473 16,114
Oil and natural gas................................ 20,854 15,398 21,232
Corporate and other (a)............................ 157,864 101,347 78,640
-------- -------- --------
Total assets......................................... $942,509 $869,642 $739,898
======== ======== ========
Depreciation, depletion and amortization:
Contract drilling.................................. $ 80,500 $ 72,797 $ 54,274
Drilling and completion fluids..................... 2,216 2,644 1,464
Pressure pumping................................... 2,803 1,895 1,564
Oil and natural gas................................ 5,251 8,505 3,673
Corporate and other................................ 446 318 489
-------- -------- --------
Total depreciation, depletion and amortization....... $ 91,216 $ 86,159 $ 61,464
======== ======== ========
Capital expenditures:
Contract drilling.................................. $ 64,821 $150,788 $116,836
Drilling and completion fluids..................... 1,571 4,937 10,166
Pressure pumping................................... 7,399 7,756 4,426
Oil and natural gas................................ 6,357 7,956 5,341
Corporate and other................................ 3,695 5,320 --
-------- -------- --------
Total capital expenditures........................... $ 83,843 $176,757 $136,769
======== ======== ========
---------------
(a) Corporate assets primarily include cash on hand managed by the parent
corporation and certain deferred federal income tax assets.
F-28
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Quarterly financial information for the years ended December 31, 2002 and
2001 is as follows (in thousands):
1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL
----------- ----------- ----------- ----------- --------
2002
Operating revenues............ $128,223 $125,363 $133,495 $140,876 $527,957
Operating income (loss)..... 6,428 (6,591) 683 2,878 3,398
Net income (loss)........... 3,935 (3,845) 249 1,830 2,169
Earnings (loss) per share:
Basic.................... $ 0.05 $ (0.05) $ 0.00 $ 0.02 $ 0.03
Diluted.................. $ 0.05 $ (0.05) $ 0.00 $ 0.02 $ 0.03
2001
Operating revenues.......... $238,586 $287,564 $289,104 $174,721 $989,975
Operating income............ 59,160 79,249 98,872 29,891 267,172
Net income.................. 36,611 48,466 60,382 18,703 164,162
Earnings per share:
Basic.................... $ 0.48 $ 0.63 $ 0.79 $ 0.24 $ 2.15
Diluted.................. $ 0.46 $ 0.61 $ 0.77 $ 0.24 $ 2.07
17. CONCENTRATIONS OF CREDIT RISK
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist primarily of demand deposits, temporary
cash investments, and trade receivables.
The Company believes that it places its demand deposits and temporary cash
investments with high credit quality financial institutions. At December 31,
2002 and 2001, the Company's demand deposits and temporary cash investments
consisted of the following (in thousands):
2002 2001
-------- --------
Deposit in FDIC and SIPC-insured institutions under
$100,000.................................................. $ 1,711 $ 5,416
Deposit in FDIC and SIPC-insured institutions over
$100,000.................................................. 90,464 39,057
-------- --------
92,175 44,473
Less outstanding checks and other reconciling items......... (10,021) (10,889)
-------- --------
Cash and cash equivalents................................... $ 82,154 $ 33,584
======== ========
Concentrations of credit risk with respect to trade receivables are
primarily focused on companies involved in the exploration and development of
oil and natural gas properties. The concentration is somewhat mitigated by the
diversification of customers for which the Company provides drilling services.
As is general industry practice, the Company generally does not require
customers to provide collateral. No significant losses from individual contracts
were experienced during the years ended December 31, 2002, 2001, or 2000. We
recognized bad debt expense for 2002, 2001, and 2000 of $320,000, $2.0 million,
and $570,000, respectively.
The carrying values of cash and cash equivalents, marketable securities,
and trade receivables approximate fair value due to the short-term maturity of
these assets.
F-29
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
18. RELATED PARTY TRANSACTIONS
USE OF ASSETS -- In 2001 and 2000, we leased a 1981 Beech King-Air 90
airplane owned by SSI Oil and Gas, Inc., an entity beneficially owned 50% by
Cloyce A. Talbott, Patterson-UTI's Chief Executive Officer, and directly owned
50% by A. Glenn Patterson, Patterson-UTI's President/Chief Operating Officer.
Under the terms of the lease, we paid a monthly rental of $9,200, the costs of
fuel, insurance, taxes and maintenance of the aircraft. Such amounts totaled
approximately $212,000 and $194,000 for 2001 and 2000, respectively.
JOINT OPERATION OF OIL AND NATURAL GAS PROPERTIES -- The Company operates
certain oil and natural gas properties in which certain of our affiliated
persons have participated, either individually or through entities they control,
in the prospects or properties in which we have an interest. These
participations, which have been on a working interest basis, have been in
prospects or properties originated or acquired by Patterson-UTI. At December 31,
2002, affiliated persons were working interest owners in 215 of the 256 wells
then being operated by Patterson-UTI. Sales of working interests are made by
Patterson-UTI to reduce its economic risk in the properties. Generally, it is
more efficient for Patterson-UTI to sell the working interests to these
affiliated persons than to market them to unrelated third parties. Sales were
made by Patterson-UTI at its cost, comprised of Patterson-UTI's costs of
acquiring and preparing the working interests for sale. These costs were paid by
the working interest owners on a pro rata basis based upon their working
interest ownership percentage. The price at which working interests were sold to
affiliated persons was the same price at which working interests were sold to
unaffiliated persons. The Company made oil and natural gas production payments
(net of royalty) of $6.9 million, $8.3 million, and $13.4 million from these
properties in 2002, 2001, and 2000, respectively, to the aforementioned persons
or entities. These persons or entities reimbursed the Company for joint
operating costs of $5.5 million, $5.9 million, and $8.0 million in 2002, 2001,
and 2000, respectively.
OTHER -- In 2002 and 2001, we paid approximately $279,000 and $387,000,
respectively, to TMP Truck and Trailer LP ("TMP"), and entity owned by Thomas M.
Patterson (son of A. Glenn Patterson), for certain equipment and metal
fabrication services. Purchases from TMP were at then current market prices.
19. SUBSEQUENT EVENT
Subsequent to December 31, 2002, the Company purchased seven drilling rigs
in two separate transactions, for an aggregate purchase price of $16.5 million
in cash. The acquisitions were funded out of the Company's existing cash.
20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA
(UNAUDITED)
OIL AND GAS EXPENDITURES AND CAPITALIZED COSTS
Gross oil and natural gas expenditures by the Company for the years ended
December 31, 2002, 2001 and 2000 are summarized below (in thousands):
2002 2001 2000
------ ------- ------
Property acquisition costs............................... $ 905 $ 3,813 $ 798
Exploration costs........................................ 6,267 6,788 5,401
Development costs........................................ 845 1,354 1,012
------ ------- ------
$8,017 $11,955 $7,211
====== ======= ======
F-30
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA
(UNAUDITED) -- (CONTINUED)
The aggregate amount of capitalized costs of oil and natural gas properties
as of December 31, 2002, 2001 and 2000 are comprised of the following (in
thousands):
2002 2001 2000
-------- -------- --------
Proved properties................................... $ 44,849 $ 43,500 $ 37,709
Accumulated depreciation and depletion.............. (35,684) (35,828) (28,338)
-------- -------- --------
$ 9,165 $ 7,672 $ 9,371
======== ======== ========
RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES:
Oil and natural gas sales........................... $ 12,738 $ 13,842 $ 13,619
Gain on sale of oil and natural gas properties...... 303 213 4
-------- -------- --------
13,041 14,055 13,623
-------- -------- --------
Costs and expenses:
Lease operating and production costs................ 3,068 3,978 3,245
Exploration costs including dry holes and
abandonments...................................... 785 1,038 1,627
Depreciation and depletion.......................... 4,633 6,317 3,601
Impairment of oil and natural gas properties........ 727 1,100 --
-------- -------- --------
9,213 12,433 8,473
-------- -------- --------
Results of operations for oil and natural gas
producing activities, before taxes................ $ 3,828 $ 1,622 $ 5,150
======== ======== ========
OIL AND NATURAL GAS RESERVE QUANTITIES:
The following table sets forth information with respect to quantities of
net proved developed oil and natural gas reserves and changes in those reserves
for the years ended December 31, 2002, 2001, and 2000 (in
F-31
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA
(UNAUDITED) -- (CONTINUED)
thousands). The quantities were estimated by an independent petroleum engineer.
The Company's proved developed oil and natural gas reserves are located entirely
within the United States.
OIL (BBLS) GAS (MCF)
---------- ---------
Estimated quantity, January 1, 2000......................... 1,209 4,118
Revision in previous estimates.............................. 61 (157)
Extensions, discoveries and other additions................. 134 1,303
Production.................................................. (275) (1,384)
------ -------
Estimated quantity, January 1, 2001......................... 1,129 3,880
Revision in previous estimates.............................. 16 609
Extensions, discoveries and other additions................. 175 1,862
Sales of reserves........................................... (1) --
Production.................................................. (272) (1,717)
------ -------
Estimated quantity, January 1, 2002......................... 1,047 4,634
Revision in previous estimates.............................. 145 2,103
Extensions, discoveries and other additions................. 331 1,420
Sales of reserves........................................... (12) (110)
Production.................................................. (284) (1,807)
------ -------
Estimated quantity, January 1, 2003......................... 1,227 6,240
====== =======
Estimates of our proved reserves and future net revenues are determined
based on various assumptions such as oil and natural gas prices, operating
costs, reservoir performance, and economic conditions. The oil and natural gas
prices and operating cost assumptions were based on the actual prices and costs
in effect as of the date of such estimates. These assumptions are held constant
throughout the life of the properties, except operating costs are adjusted for
contractual escalations. Our reserve engineer estimates the assumptions relating
to reservoir performance and economic conditions using information available and
industry experience. The oil and natural gas prices used to value our reserves
as of December 31, 2002 were $31.20 per Bbl of oil and $4.789 per Mcf of natural
gas. Estimates of reserves and production performance are subjective and may
change materially as actual production information becomes available.
F-32
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
20. SUPPLEMENTARY OIL AND NATURAL GAS RESERVE INFORMATION AND RELATED DATA
(UNAUDITED) -- (CONTINUED)
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS OF PROVED DEVELOPED OIL AND
NATURAL GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (IN THOUSANDS):
YEAR ENDED DECEMBER 31,
---------------------------
2002 2001 2000
------- ------- -------
Future gross revenues................................... $68,165 $32,674 $48,161
Future development and production costs................. (22,149) (13,077) (16,270)
Future income tax expense (a)........................... (15,964) (5,110) (8,617)
------- ------- -------
Future net cash flows................................... 30,052 14,487 23,274
Discount at 10% per annum............................... (8,952) (3,773) (6,634)
------- ------- -------
Standardized measure of discounted future net cash
flows................................................. $21,100 $10,714 $16,640
======= ======= =======
---------------
(a) Future income taxes are computed by applying the statutory tax rate to
future net cash flows less the tax basis of the properties and net operating
loss attributable to oil and gas operations and investment tax credit
carryforwards as of year-end; statutory depletion and tax credits applicable
to future oil and gas-producing activities are also considered in the income
tax computation.
CHANGES IN THE STANDARDIZED MEASURE OF NET CASH FLOWS OF PROVED DEVELOPED OIL
AND GAS RESERVES DISCOUNTED AT 10% PER ANNUM (IN THOUSANDS):
YEAR ENDED DECEMBER 31,
---------------------------
2002 2001 2000
------- ------- -------
Standardized measure at beginning of year............... $10,714 $16,640 $12,082
Sales and transfers of oil and gas produced, net of
production costs...................................... (8,342) (8,684) (7,982)
Net changes in sales price and future production and
development costs..................................... 4,888 (10,670) 5,819
Extensions, discoveries and improved recovery, less
related costs......................................... 6,017 2,870 4,064
Sales of minerals-in-place.............................. (30) (1) --
Revision of previous quantity estimates................. 4,315 (2,824) 1,255
Accretion of discount................................... 1,531 2,440 1,873
Other................................................... (9,358) 13,588 (2,435)
Net change in income taxes.............................. 11,365 (2,645) 1,964
------- ------- -------
Standardized measure at end of year..................... $21,100 $10,714 $16,640
======= ======= =======
F-33
PATTERSON-UTI ENERGY, INC.
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
ADDITIONS(1)
------------------------
CHARGED TO ACQUIRED
BEGINNING COSTS AND THROUGH ENDING
DESCRIPTION BALANCE EXPENSES ACQUISITION DEDUCTIONS(2) BALANCE
----------- --------- ---------- ----------- ------------- -------
YEAR ENDED DECEMBER 31, 2002
Deducted from asset accounts:
Allowance for doubtful accounts....... $4,021 $ 320 $ -- $1,197 $3,144
YEAR ENDED DECEMBER 31, 2001
Deducted from asset accounts:
Allowance for doubtful accounts....... $3,462 $2,045 $ -- $1,486 $4,021
YEAR ENDED DECEMBER 31, 2000
Deducted from asset accounts:
Allowance for doubtful accounts....... $3,508 $ 570 $800 $1,416 $3,462
---------------
(1) Net of recoveries.
(2) Uncollectible accounts written off.
S-1
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
PATTERSON-UTI ENERGY, INC.
Date: December 30, 2003 By: /s/ CLOYCE A. TALBOTT
---------------------------------------------
Cloyce A. Talbott
Chief Executive Officer
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 Agreement and Plan of Merger dated March 10, 2002 among
Patterson-UTI Energy, Inc., Patterson-UTI Drilling Company
LP, LLLP and Odin Drilling, Inc.(1)
2.2 Stock Purchase Agreement dated as of June 11, 2002 by and
among Patterson-UTI Energy, Inc. and Roper Family
Properties, Ltd., Estate of Joe G. Roper, Patricia R.
Elledge, Judy Kathleen Roper Davis, Jeanie Elisabeth
Cornelius and J. Mark Roper.(2)
2.3 Stock Purchase Agreement dated as of October 28, 2002 by and
between Patterson-UTI Energy, Inc. and J. Mark Roper.(3)
3.1 Restated Certificate of Incorporation, as amended.(4)
3.2 Amended and Restated Bylaws.(5)
4.1 Rights Agreement dated January 2, 1997, between Patterson
Energy, Inc. and Continental Stock Transfer & Trust
Company.(6)
4.2 Amendment to Rights Agreement dated as of October 23,
2001.(7)
4.3 Restated Certificate of Incorporation, as amended (See
Exhibit 3.1)
4.4 Registration Rights Agreement with Bear, Stearns and Co.
Inc., dated March 25, 1994, as assigned by REMY Capital
Partners III, L.P.(5)
4.5 Patterson-UTI Energy, Inc. 1993 Stock Incentive Plan, as
amended.(8)*
4.6 Patterson-UTI Energy, Inc. Non-Employee Directors' Stock
Option Plan, as amended.(9)*
4.7 Patterson-UTI Energy, Inc. Amended and Restated 1997
Long-Term Incentive Plan.(4)*
4.8 Amended and Restated Patterson-UTI Energy, Inc. Non-Employee
Director Stock Option Plan(4)*
4.9 Amended and Restated Patterson-UTI Energy, Inc. 1996
Employee Stock Option Plan.(10)*
4.10 1997 Stock Option Plan of DSI Industries, Inc.(11)*
4.11 Stock Option Agreement dated July 20, 2001 between
Patterson-UTI Energy, Inc. and Kenneth R. Peak (a
non-employee director of Patterson-UTI Energy, Inc.).(5)*
10.1 For additional material contracts, see Exhibits 4.1, 4.2 and
4.4 through 4.11.
10.2 Amended and Restated Loan and Security Agreement, dated July
26, 2002.(12)
10.3 Revolving Loan Promissory Note, dated July 26, 2002.(12)
10.4 Amended and Restated Guaranty Agreement, dated July 26,
2002.(12)
10.5 Amended and Restated Pledge Agreement, dated July 26,
2002.(12)
10.6 Model Form Operating Agreement.(13)
10.7 Form of Drilling Bid Proposal and Footage Drilling
Contract.(13)
10.8 Form of Turnkey Drilling Agreement.(13)
21.1 Subsidiaries of the Registrant.(14)
23.1 Consent of Independent Auditors -- PricewaterhouseCoopers
LLP.
23.2 Consent of Independent Auditors -- Ernst & Young LLP.
23.3 Consent of Independent Petroleum Engineer -- M. Brian
Wallace, P.E.
31.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934,
as amended.
31.2 Certification of Chief Financial Officer pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934,
as amended.
32.1 Certification of Chief Executive Officer and Chief Financial
Officer pursuant to 18 USC Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
---------------
(1) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended March 31, 2002.
(2) Incorporated herein by reference to Item 7, "Material to be Filed as
Exhibits" to Amendment No. 1 to Schedule 13D filed on October 31, 2002.
(3) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended June 30, 2002.
(4) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended June 30, 2003.
(5) Incorporated herein by reference to Item 14, "Exhibits, Financial Statement
Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the
fiscal year ended December 31, 2001.
(6) Incorporated by reference to Item 2, "Exhibits" to Registration Statement
on Form 8-A filed on January 14, 1997.
(7) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended September 30, 2001, filed
on October 31, 2001.
(8) Incorporated herein by reference to Item 8, "Exhibits" to Registration
Statement on Form S-8 (File No. 333-39471) filed on March 13, 1998.
(9) Incorporated herein by reference to Item 8, "Exhibits" to Registration
Statement on Form S-8 (File No. 333-39471) filed on November 4, 1997.
(10) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective
Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60466)
filed on July 25, 2001.
(11) Incorporated herein by reference to Item 8, "Exhibits" to Post-Effective
Amendment No. 1 to Registration Statement on Form S-8 (file No. 333-60470)
filed on July 25, 2001.
(12) Incorporated herein by reference to Item 6, "Exhibits and Reports on Form
8-K" to Form 10-Q for the quarterly period ended June 30, 2001, filed on
August 1, 2001.
(13) Incorporated herein by reference to Item 27, "Exhibits" to Registration
Statement on Form SB-2 (File No. 33-68058-FW) filed on August 30, 1993.
(14) Incorporated herein by reference to Item 15, "Exhibits, Financial Statement
Schedules and Reports on Form 8-K" to Annual Report on Form 10-K for the
fiscal year ended December 31, 2002.
* Management Contract or Compensatory Plan identified as required by Item
15(a)(3) of Form 10-K.