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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[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
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission file number 1-8226
[GREY WOLF LOGO]
GREY WOLF, INC.
(Exact name of registrant as specified in its charter)
TEXAS 74-2144774
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
10370 RICHMOND AVENUE, SUITE 600
HOUSTON, TEXAS 77042
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 713-435-6100
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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COMMON STOCK, PAR VALUE $0.10 AMERICAN STOCK EXCHANGE
RIGHTS TO PURCHASE JUNIOR PARTICIPATING AMERICAN STOCK EXCHANGE
PREFERRED STOCK, PAR VALUE $1.00
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (229.405 under the Securities Exchange Act of 1934)
is not contained herein, and will not be contained, to the best of Registrant's
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
At February 28, 2003, 181,147,811 shares of the Registrant's common
stock were outstanding. The aggregate market value of the Registrant's voting
stock held by non-affiliates (based upon the closing price on the American Stock
Exchange on February 28, 2003 of $4.17) was approximately $702.9 million.
The following documents have been incorporated by reference into the
Parts of this Report indicated: Certain sections of the Registrant's definitive
proxy statement for the Registrant's 2002 Annual Meeting of shareholders which
is to be filed pursuant to Regulation 14A under the Securities Exchange Act of
1934 within 120 days of the Registrant's fiscal year ended December 31, 2002,
are incorporated by reference into Part III hereof.
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-1-
PART I
ITEM 1. BUSINESS
GENERAL
Grey Wolf, Inc., a Texas corporation formed in 1980, is a leading
provider of contract land drilling services in the United States with a fleet of
116 rigs at February 28, 2003, of which 73 rigs are marketed. Included in the
marketed fleet is one non-owned rig that we operate for a third party. Our
customers include independent producers and major oil and gas companies. We
conduct all of our operations through our subsidiaries. Our principal office is
located at 10370 Richmond Avenue, Suite 600, Houston, TX 77042, and our
telephone number is (713) 435-6100. Our website address is www.gwdrilling.com.
We make available free of charge through our website our annual report
on Form 10-K, quarterly reports on Form 10-Q, current reports of Form 8-K, and
all amendments to those reports as soon as reasonably practicable after such
material is electronically filed with the Securities and Exchange Commission.
Information on our website is not a part of this report.
BUSINESS STRATEGY
Within the framework of a very cyclical industry, our strategy is to
maximize shareholder value during periods of increasing demand and mitigate risk
during periods of reduced demand. Our goal is to enter each phase of our
industry's cycles in a stronger position. We attempt to achieve this by:
- delivering quality, value-added service to our customers;
- maintaining a leading position in our core markets;
- responding to market conditions by balancing dayrates with
utilization;
- maintaining a high level of utilization for our marketed rigs;
- enhancing cash-flow through our turnkey and trucking
operations and use of our top drives;
- controlling costs and maintaining capital spending discipline;
- maintaining a premium fleet of equipment with bias toward deep
drilling for natural gas;
- using term contracts to provide sufficient cash flow to cover
incremental capital expenditures for refurbishments on rigs
under term contracts;
- using term contracts to mitigate the cyclical nature of
dayrates;
- searching for new market opportunities where we believe our
quality fleet of rigs would be able to generate attractive
returns; and
- searching for potential acquisition candidates that we believe
would be accretive.
INDUSTRY OVERVIEW
Our business is highly cyclical. It depends on the level of drilling
activity by oil and gas exploration and production companies. The number of
wells they choose to drill is strongly influenced by past trends in oil and
natural gas prices, current prices, and their outlook for future oil and gas
prices.
After approximately two years of increasing dayrates and rig activity,
demand for drilling rigs began to decline late in the third quarter of 2001. We
believe this decline was due to lower commodity prices. This was reflected in
the domestic land rig count, as reported in the Baker Hughes rotary rig count,
which declined from a high of 1,114 rigs during July 2001 to a low of 613 rigs
in early April 2002. Natural gas and West Texas Intermediate Crude prices based
upon the New York Mercantile Exchange ("NYMEX") near month contract were $2.67
per mmbtu and $22.80 per barrel, respectively, during this time period. During
the second quarter of 2002 and until the end of 2002, natural gas and oil prices
generally improved and we saw a stabilization of the domestic land rig count at
an average of 710 rigs. Natural gas prices, based upon the NYMEX near month
contract, from April 1, 2002 through December 31, 2002 averaged $3.64 per mmbtu
while the average NYMEX near month contract price of West Texas Intermediate
Crude was $27.57 per barrel.
There was an increase in natural gas and oil prices beginning in
December 2002 that has continued into 2003. Natural gas and oil prices averaged
$5.99 per mmbtu and $34.17 per barrel, respectively, from January 1, 2003 to
February 28, 2003. The domestic land rig count at February 28, 2003 was 788
rigs.
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CURRENT CONDITIONS AND OUTLOOK
We are in a solid position to benefit from an increase in drilling activity
which we believe could develop in 2003. During the latest downturn, we
maintained our premium fleet of equipment and retained our experienced personnel
which are essential to providing quality service to our customers and returning
our rigs to work when market conditions improve. Improving commodity prices have
and should continue to improve our customers' cash flows, which we believe could
result in additional drilling. The NYMEX twelve-month strip price for natural
gas and West Texas Intermediate Crude was $5.90 per mmbtu and $30.67 per barrel,
respectively at February 28, 2003. In addition, natural gas storage levels have
recently been falling with current levels approximately 34% lower than the
five-year average as of February 27, 2003. We averaged between 54 to 56 rigs
working each quarter in 2002 and have averaged 57 rigs working thus far in the
first quarter of 2003. However, we have seen an increase in the amount of future
work for our rigs currently operating. This future work is in the form of signed
contracts and oral commitments from our customers. At February 28, 2003, we had
63 rigs working.
OPERATIONS
At February 28, 2003, we had a rig fleet of 116 rigs, 73 of which were
marketed, 27 cold-stacked and 16 held for future refurbishment. Cold-stacked
rigs are rigs that are stacked without crews and are not currently being
marketed. Included in the rig fleet is one rig that we do not own but operate
for a third party. We currently conduct our operations in the following domestic
drilling markets:
- Ark-La-Tex;
- Gulf Coast;
- Mississippi/Alabama;
- South Texas;
- Rocky Mountain; and
- West Texas.
We refer to the Ark-La-Tex, Gulf Coast, Mississippi/Alabama and South
Texas markets as our "core markets," because the majority of our rigs are
located in those markets. We conduct our operations primarily in domestic
markets which we believe have historically had greater utilization rates and
dayrates than the combined total of all other domestic markets. This is in part
due to the heavy concentration of natural gas reserves in these markets. During
2002, approximately 98% of the wells we drilled for our customers were drilled
in search of natural gas. Larger natural gas reserves are typically found in
deeper geological formations and generally require premium equipment and quality
crews to drill the wells.
Ark-La-Tex Division. Our Ark-La-Tex division provides drilling services
primarily in the Ark-La-Tex market which consists of Northeast Texas, Northern
Louisiana and Southern Arkansas, and the Mississippi/Alabama market. We
currently have 17 marketed rigs in this division which consist of 10 diesel
electric rigs and seven mechanical rigs. Our Ark-La-Tex division also operates a
fleet of 22 trucks which are used exclusively to move our rigs. The Ark-La-Tex
division also manages the operations of our Rocky Mountain and West Texas
districts.
We had an average of 12 rigs working in our Ark-La-Tex division during
2002. Daywork contracts generated approximately 92% of our revenues in this
division, while turnkey and footage contracts generated the remaining 8%. The
average revenue per rig day worked by the division during 2002 was $11,250.
Gulf Coast Division. Our Gulf Coast division provides drilling services
in Southern Louisiana and along the upper Texas Gulf Coast. We currently have 19
marketed rigs in this division which consist of 17 diesel electric rigs and two
mechanical rigs.
We had an average of 16 rigs working in our Gulf Coast division during
2002. Daywork contracts generated approximately 77% of our revenues in this
division, while turnkey and footage contracts generated the remaining 23%. The
average revenue per rig day worked by the division during 2002 was $15,560.
South Texas Division. We believe that trailer-mounted rigs and 1,500 to
2,000 horsepower diesel electric rigs are in highest demand in this market.
Trailer-mounted rigs are more mobile than conventional rigs, thus decreasing the
time and expense to the customer of moving the rig to and from the drill site.
Under ordinary conditions, trailer-mounted rigs are capable of drilling an
average of two 10,000 foot wells per month. We currently
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have 29 marketed rigs in this division, including one non-owned rig that we
operate for a third party. The marketed rigs consist of 14 diesel electric rigs,
ten trailer-mounted rigs, one of which is diesel electric, and five mechanical
rigs. The South Texas division also operates a fleet of 35 trucks which are used
exclusively to move our rigs.
We had an average of 22 rigs working in our South Texas division during
2002. Daywork contracts generated approximately 98% of our revenues in this
division, while turnkey and footage contracts generated the remaining 2%. The
average revenue per rig day worked by the division during 2002 was $10,185.
Rocky Mountain District. Our Rocky Mountain district provides drilling
services in the market area which consists of Wyoming, Colorado, northwest Utah
and northern New Mexico. We began operations in the Rocky Mountain market in
June 2001 and currently have two marketed rigs in this district. Both rigs are
high horsepower diesel electric rigs. Both rigs worked all year under daywork
term contracts which generated 100% of our revenues in this district. The
average revenue per rig day worked by the district during 2002 was $17,411.
Currently, we have one rig working in this district. We continue to look for
opportunities to expand our market presence in this area.
West Texas District. Our West Texas district provides drilling services
in West Texas and Southeast New Mexico. We began operations in West Texas in
October 2001. Since that time we have increased the number of marketed rigs in
this district to six and all six are diesel electric rigs. During 2002, we
averaged three rigs working under daywork contracts, with the average revenue
per rig day worked during 2002 of $11,394.
COLD STACKED RIGS AND RIGS HELD FOR REFURBISHMENT
We have the ability to return all 27 cold-stacked rigs to work at an
estimated aggregate cost of $1.5 million, which would bring our marketed fleet
to 100 rigs. In addition, we have 16 rigs held for future refurbishment that
could be returned to service for an average of approximately $5.0 million per
rig, excluding drill pipe and drill collars. The actual number of rigs
reactivated in 2003, if any, and in the future will depend upon many factors,
including our estimation of existing and anticipated demand and dayrates, our
success in bidding for domestic contracts, including term contracts, and the
timing of the reactivations. The actual cost of reactivating these rigs would
also depend upon the specific customer requirements and to the extent that we
choose to upgrade these rigs.
CONTRACTS
Our contracts for drilling oil and natural gas wells are obtained
either through competitive bidding or as a result of negotiations with
customers. Contract terms offered by us are generally dependent on the
complexity and risk of operations, on-site drilling conditions, type of
equipment used and the anticipated duration of the work to be performed.
Generally, drilling contracts are for a single well. The majority of our
drilling contracts are typically subject to termination by the customer on short
notice with no penalty. Our drilling contracts generally provide for
compensation on either a daywork, turnkey or footage basis.
Daywork Contracts. Under daywork drilling contracts, we provide a
drilling rig with required personnel to our customer who supervises the drilling
of the well. We are paid based on a fixed rate per day while the rig is
utilized. Daywork drilling contracts specify the equipment to be used, the size
of the hole and the depth of the well. Under a daywork drilling contract, the
customer bears a large portion of out-of-pocket costs of drilling. The dayrate
we receive is not dependent on the usual risks associated with drilling, such as
time delays for various reasons, including stuck drill pipe or blowout.
We strive, whenever market conditions allow, to utilize term contracts
to provide drilling services on a daywork basis. These term contracts typically
have terms ranging in length from six months to two years and include a per rig
day termination rate approximately equal to our daily margin on each contract.
During late 2001 and 2002, the use of term contracts enabled us to maintain
higher margins than would otherwise be attainable during the latest downturn.
Turnkey Contracts. Under a turnkey contract, we contract to drill a
well to an agreed-upon depth under specified conditions for a fixed price,
regardless of the time required or the problems encountered in drilling the
well. We provide technical expertise and engineering services, as well as most
of the materials required for the well, and are compensated when the contract
terms have been satisfied. Turnkey contracts afford an opportunity to earn a
higher margin than would normally be available on daywork or footage contracts
if the contract can be completed successfully without complications.
-4-
The risks to us under a turnkey contract are substantially greater than
on a daywork basis because we assume most of the risks associated with drilling
operations generally assumed by the operator in a daywork contract, including
the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns,
abnormal drilling conditions and risks associated with subcontractors' services,
supplies, cost escalation and personnel. We employ or contract for engineering
expertise to analyze seismic, geologic and drilling data to identify and reduce
many of the drilling risks assumed by us. We use the results of this analysis to
evaluate the risks of a proposed contract and seek to account for such risks in
our bid preparation. We believe that our operating experience, qualified
drilling personnel, risk management program, internal engineering expertise and
access to proficient third party engineering contractors have allowed us to
reduce the risks inherent in turnkey drilling operations. We also maintain
insurance coverage against some but not all drilling hazards.
Footage Contracts. Under footage contracts, we are paid a fixed amount
for each foot drilled, regardless of the time required or certain problems
encountered in drilling the well. We typically pay more of the out-of-pocket
costs associated with footage contracts than under daywork contracts. Similar to
a turnkey contract, the risks to us on a footage contract are greater because we
assume most of the risks associated with drilling operations generally assumed
by the operator in a daywork contract, including the risk of blowout, loss of
hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and
risks associated with subcontractors' services, supplies, cost escalation and
personnel. As with turnkey contracts, we manage this additional risk through the
use of engineering expertise and bid the footage contracts accordingly. We also
maintain insurance coverage against certain drilling hazards.
CUSTOMERS AND MARKETING
Our contract drilling customers include independent producers and major
oil and gas companies. In 2002, 45% of our revenue came from major oil and gas
companies and large independent producers, while the remaining 55% came from
other independents. Also during 2002, 11% of our revenue was derived from
daywork contracts with EOG Resources, Inc. We primarily market our drilling rigs
on a regional basis through employee sales representatives. These sales
representatives utilize personal contacts and industry periodicals and
publications to determine which operators are planning to drill oil and natural
gas wells in the immediate future. Once we have been placed on the "bid list"
for an operator, we will typically be given the opportunity to bid on all future
wells for that operator in the area.
From time to time we also enter into informal, nonbinding commitments
with our customers to provide drilling rigs for future periods at agreed upon
rates plus fuel and mobilization charges, if applicable, and escalation
provisions. This practice is customary in the land drilling business during
times of increasing rig demand. Although neither we nor the customer are legally
required to honor these commitments, we generally satisfy such commitments in
order to maintain good customer relations.
INSURANCE
Our operations are subject to the many hazards inherent in the drilling
business, including, for example, blowouts, cratering, fires, explosions and
adverse weather. These hazards could cause personal injury, death, suspend
drilling operations or seriously damage or destroy the equipment involved and
could cause substantial damage to producing formations and surrounding areas.
Damage to the environment could also result from our operations, particularly
through oil spillage and extensive, uncontrolled fires. As a protection against
operating hazards, we maintain insurance coverage, including comprehensive
general liability and commercial contract indemnity, commercial umbrella and
workers' compensation insurance, property casualty insurance on our rigs and
drilling equipment, and "control of well" insurance.
Our third party liability insurance coverage under our general policies
is $1.0 million per occurrence, with a deductible of $250,000 per occurrence. We
believe that we are adequately insured for public liability and property damage
to others with respect to our operations. However, our insurance may not be
sufficient to protect us against liability for all consequences of well
disasters, extensive fire damage, damage to the environment, damage to
producing formations, or other hazards.
Our workers' compensation insurance coverage is $1.0 million per
occurrence with a deductible of $250,000 per occurrence. With respect to
workers' compensation insurance, we issue letters of credit for the benefit of
various insurance companies as collateral for retrospective premiums and
retained losses within the deductible amounts. We believe that we are adequately
insured for workers' compensation. We have commercial umbrella, or
-5-
excess liability insurance, to cover general liability and workers' compensation
claims which are higher than the maximum coverage provided under those policies.
Our excess liability insurance covers up to a maximum of $75.0 million in the
aggregate and has deductibles per occurrence of $25,000 on the first $10.0
million of coverage and $50,000 on the remaining $65.0 million of coverage.
Our insurance coverage for property damage to our rigs and drilling
equipment is based on our estimate of the cost of comparable used equipment to
replace the insured property. There is a deductible on rigs of $850,000 in the
aggregate over an eighteen month policy period (with a sublimit of up to
$575,000 per claim in respect of such aggregate limit) to be comprised of losses
otherwise recoverable thereafter in excess of a $50,000 maintenance deductible.
There is a $10,000 deductible per occurrence on other equipment. We do not have
insurance coverage against loss of earnings resulting from damage to our rigs.
We also maintain insurance coverage to protect against certain hazards
inherent in our turnkey and footage contract drilling operations. This insurance
covers "control of well" (including blowouts above and below the surface),
cratering, seepage and pollution and care, custody and control. Our current
insurance provides $500,000 coverage per occurrence for care, custody and
control, and coverage per occurrence for control of well, cratering, seepage and
pollution associated with drilling operations of either $10.0 million or $20.0
million, depending upon the area in which the well is drilled and its target
depth. Each form of coverage provides for a deductible that we must meet, as
well as a maximum limit of liability. Each casualty is an occurrence, and there
may be more than one such occurrence on a well, each of which would be subject
to a separate deductible.
We are self-insured for our employee health plan but purchase stop-loss
coverage in order to limit our exposure to a maximum of $175,000 per occurrence
under the plan. There is no aggregate limit under the stop-loss policy.
No assurances can be given that we will be able to maintain the
above-mentioned insurance types and/or the amounts of coverage that we believe
to be adequate. Also, there are no assurances that these types of coverages
will be available in the future. The rising cost and/or availability of
certain types of insurance could have an adverse effect on our financial
condition and results of operations.
CERTAIN RISKS
Our business is subject to a number of risks and uncertainties, the
most important of which are listed below:
Our business can be adversely affected by low oil and natural gas prices and
expectations of low prices.
As a supplier of land drilling services, our business depends on the
level of drilling activity by oil and natural gas exploration and production
companies operating in the geographic markets where we operate. The number of
wells they choose to drill is strongly influenced by past trends in oil and
natural gas prices, current prices, and their outlook for future oil and natural
gas prices. Low oil and natural gas prices, or the perception among oil and gas
companies that future prices are likely to decline, can materially and adversely
affect us in many ways, including:
- our revenues, cash flows and earnings;
- our customers may seek to terminate, renegotiate or fail to
honor our term drilling contracts;
- the fair market value of our rig fleet which in turn could
trigger a writedown for accounting purposes;
- our ability to maintain or increase our borrowing capacity;
- our ability to obtain additional capital to finance our
business and make acquisitions, and the cost of that capital;
and
- our ability to retain skilled rig personnel who we would need
in the event of an increase in the demand for our services.
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Oil and natural gas prices have been volatile historically and, we
believe, will continue to be so in the future. Many factors beyond our control
affect oil and natural gas prices, including:
- weather conditions in the United States and elsewhere;
- economic conditions in the United States and elsewhere;
- actions by OPEC, the Organization of Petroleum Exporting
Countries;
- political stability in the Middle East, Venezuela and other
major producing regions;
- governmental regulations, both domestic and foreign;
- the pace adopted by foreign governments for exploration of
their national reserves; and
- the overall supply and demand for oil and natural gas.
We operate in a highly competitive, fragmented industry in which price
competition is intense.
The drilling contracts we compete for are usually awarded on the basis
of competitive bids. We believe pricing and rig availability are the primary
factors considered by our potential customers in determining which drilling
contractor to select. We believe other factors are also important. Among those
factors are:
- the type and condition of drilling rigs;
- the quality of service and experience of rig crews;
- the safety record of the Company and the particular drilling
rig;
- the offering of ancillary services; and
- the ability to provide drilling equipment adaptable to, and
personnel familiar with, new technologies and drilling
techniques.
While we must generally be competitive in our pricing, our competitive
strategy generally emphasizes the quality of our equipment, the safety record of
our rigs and the experience of our rig crews to differentiate us from our
competitors. This strategy is less effective as lower demand for drilling
services intensifies price competition and makes it more difficult for us to
compete on the basis of factors other than price. In all of the markets in which
we compete, an over supply of rigs can cause greater price competition.
Contract drilling companies compete primarily on a regional basis, and
the intensity of competition may vary significantly from region to region at any
particular time. If demand for drilling services improves in a region where we
operate, our competitors might respond by moving in suitable rigs from other
regions. An influx of rigs from other regions could rapidly intensify
competition and make any improvement in demand for drilling rigs short-lived.
We face competition from competitors with greater resources.
Certain of our competitors have greater financial and human resources
than do we. Their greater capabilities in these areas may enable them to:
- better withstand periods of low rig utilization;
- compete more effectively on the basis of price and technology;
- retain skilled rig personnel; and
- build new rigs or acquire and refurbish existing rigs so as to
be able to place rigs into service more quickly than us in
periods of high drilling demand.
Our drilling operations involve inherent risks of loss which if not insured or
indemnified against could adversely affect our results of operations and
financial condition.
Our business is subject to the many hazards inherent in the land
drilling business including the risks of:
- blowouts;
- fires and explosions;
- collapse of the borehole;
- lost or stuck drill strings; and
- damage or loss from natural disasters.
-7-
We attempt to obtain indemnification from our customers by contract for
certain of these risks under daywork contracts but are not always able to do so.
We also seek to protect ourselves from some but not all operating hazards
through insurance coverage.
If these drilling hazards occur they can produce substantial
liabilities to us from, among other things:
- suspension of drilling operations;
- damage to the environment;
- damage to, or destruction of our property and equipment and
that of others;
- personal injury and loss of life; and
- damage to producing or potentially productive oil and natural
gas formations through which we drill.
The indemnification we receive from our customers and our own insurance
coverage may not, however, be sufficient to protect us against liability for all
consequences of disasters, personal injury and property damage. Additionally,
our insurance coverage generally provides that we bear a portion of the claim
through substantial insurance coverage deductibles. The premiums we pay for
insurance policies are also subject to substantial increase based upon our
claims history and outside economic events that affect the insurance industry in
general, which may increase our operating costs. We can offer no assurance that
our insurance or indemnification arrangements will adequately protect us against
liability from all of the hazards of our business. We are also subject to the
risk that we may be unable to obtain or renew insurance coverage of the type and
amount we desire at reasonable rates. If we were to incur a significant
liability for which we were not fully insured or indemnified it could have a
material adverse effect on our financial position and results of operations.
Our operations are subject to environmental laws that may expose us to
liabilities for noncompliance which may adversely affect us.
Many aspects of our operations are subject to domestic laws and
regulations. For example, our drilling operations are typically subject to
extensive and evolving laws and regulations governing:
- environmental quality;
- pollution control; and
- remediation of environmental contamination.
Our operations are often conducted in or near ecologically sensitive
areas, such as wetlands which are subject to special protective measures and
which may expose us to additional operating costs and liabilities for
noncompliance with applicable laws. The handling of waste materials, some of
which are classified as hazardous substances, is a necessary part of our
operations. Consequently, our operations are subject to stringent regulations
relating to protection of the environment and waste handling which may impose
liability on us for our own noncompliance and, in addition, that of other
parties without regard to whether we were negligent or otherwise at fault.
Compliance with applicable laws and regulations may require us to incur
significant expenses and capital expenditures which could have a material and
adverse effect on our operations by increasing our expenses and limiting our
future contract drilling opportunities.
In addition to trade liabilities, we have $250.0 million of principal amount
indebtedness under our senior notes with semi-annual interest payments of
approximately $11.1 million.
We are indebted for a total of $250.0 million in principal amount under
our 8 7/8% Senior Notes due 2007. Semi-annual interest payments on the senior
notes of approximately $11.1 million are due on January 1 and July 1 of each
year. Our operating activities provided net cash sufficient to pay our debt
service obligations for the year ended December 31, 2002; however, there can be
no assurances that we will be able to generate sufficient cash flow in the
future.
Our ability in the future to meet our debt service obligations and
reduce our total indebtedness will depend on a number of factors including:
- oil and natural gas prices;
- demand for our drilling services;
-8-
- continuation of a successful business strategy ; and
- other financial and business factors that affect us.
Many of these factors are beyond our control.
If we do not generate sufficient cash flow to pay debt service and
repay principal in the future, we will likely be required to use one or more of
the following measures:
- use our cash balances;
- use our existing credit facility;
- obtain additional external financing;
- refinance our indebtedness; and
- sell our assets.
We have had only two profitable years since 1991.
We have a history of losses with our only profitable years since 1991
being 1997 and 2001 in which we had net income of $10.2 million and $68.5
million, respectively. Whether we are able to be profitable in the future will
depend on many factors, but primarily on the utilization rates for our rigs and
the rates we charge for them.
Unexpected cost overruns on our turnkey and footage drilling jobs could
adversely affect us.
We have historically derived a significant portion of our revenues from
turnkey and footage drilling contracts and we expect that they will continue to
represent a significant component of our revenues. The occurrence of uninsured
or under-insured losses or operating cost overruns on our turnkey and footage
jobs could have a material adverse effect on our financial position and results
of operations. Under a typical turnkey or footage drilling contract, we agree to
drill a well for our customer to a specified depth and under specified
conditions for a fixed price. We typically provide technical expertise and
engineering service, as well as most of the equipment required for the drilling
of turnkey and footage wells. We often subcontract for related services. Under
typical turnkey drilling arrangements, we do not receive progress payments and
are entitled to be paid by our customer only after we have performed the terms
of the drilling contract in full. For these reasons, the risk to us under
turnkey and footage drilling contracts is substantially greater than for wells
drilled on a daywork basis because we must assume most of the risks associated
with drilling operations that are generally assumed by our customer under a
daywork contract. Although we attempt to obtain insurance coverage to reduce
certain of the risks inherent in our turnkey and footage drilling operations, we
can offer no assurance that adequate coverage will be obtained or will be
available in the future.
Our indentures and credit agreements may prohibit us from participation in
certain transactions that we may consider advantageous.
The indentures under which we issued our senior notes contain
restrictions on our ability and the ability of certain of our subsidiaries to
engage in certain types of transactions. These restrictive covenants may
adversely affect our ability to pursue business acquisitions. These include
covenants which may prohibit or limit our ability to:
- incur additional indebtedness;
- pay dividends or make other restricted payments;
- repurchase our equity securities;
- sell material assets;
- grant or permit liens to exist on our assets;
- enter into sale and lease-back transactions;
- make certain investments;
- enter into transactions with related persons; and
- engage in lines of business unrelated to our core land
drilling business.
Our senior secured credit facility also contains covenants restricting
our ability and our subsidiaries' ability to undertake many of the same types of
transactions, and when certain conditions are met, contains financial ratio
covenants. They may also limit our ability to respond to changes in market
conditions. Our ability to meet the
-9-
financial ratio covenants of our credit agreement and indentures can be affected
by events and conditions beyond our control and we may be unable to meet those
tests.
Our senior secured credit facility contains default terms that
effectively cross default with the indentures covering our senior notes. If we
breach the covenants in the indentures it could cause our default under our
senior notes, and also under our senior secured credit agreement, and possibly
under other then outstanding debt obligations owed by us or our subsidiaries. If
the indebtedness under our senior secured credit agreement or other indebtedness
owed by us or our subsidiaries is more that $10.0 million and is not paid when
due, or is accelerated by the holders of the debt, then an event of default
under the indenture covering our senior notes would occur. If circumstances
arise in which we are in default under our various credit agreements, our cash
and other assets may be insufficient to repay our indebtedness and that of our
subsidiaries.
We could be adversely affected if shortages of equipment, supplies or personnel
occur.
While we are not currently experiencing any shortages, from time to
time there have been shortages of drilling equipment and supplies which we
believe could reoccur. During periods of shortages, the cost and delivery times
of equipment and supplies are substantially greater. In the past, in response to
such shortages, we have entered in agreements with various suppliers and
manufacturers that enabled us to reduce our exposure to price increases and
supply shortages. Although we have formed many informal supply arrangements with
equipment manufacturers and suppliers, there can be no assurance that we will be
able to maintain existing arrangements. Shortages of drilling equipment or
supplies could delay and adversely affect our ability to return to service our
rigs held for future refurbishment and obtain contracts for our marketed rigs,
which could have a material adverse effect on our financial condition and
results of operations.
Although we have not encountered material difficulty in hiring and
retaining qualified rig crews, such shortages have occurred in the past in our
industry. We may experience shortages of qualified personnel to operate our
rigs, which could have a material adverse effect on our financial condition and
results of operations.
Our indentures and credit agreement restrict our ability to pay dividends.
We have never declared a cash dividend on our common stock and do not
expect to pay cash dividends on our common stock for the foreseeable future. We
expect that all cash flow generated from our operations in the foreseeable
future will be retained and used to develop or expand our business, pay debt
service and reduce outstanding indebtedness. Furthermore, the terms of our
senior secured credit facility prohibit the payment of dividends without the
prior written consent of the lenders and the terms of the indentures under which
our senior notes are issued also restrict our ability to pay dividends under
certain conditions.
Certain provisions of our organizational documents, securities, and credit
agreement have anti-takeover effects which may prevent our shareholders from
receiving the maximum value for their shares.
Our articles of incorporation, bylaws, securities, and credit
agreements contain certain provisions that may delay or prevent entirely a
change of control transaction not supported by our board of directors, or which
may have that general effect. These measures include:
- classification of our board of directors into three classes,
with each class serving a staggered three year term;
- giving our board of directors the exclusive authority to
adopt, amend or repeal our bylaws and thus prohibiting
shareholders from doing so;
- requiring our shareholders to give advance notice of their
intent to submit a proposal at the annual meeting; and
- limiting the ability of our shareholders to call a special
meeting and act by written consent.
Additionally, the indentures under which our senior notes are issued,
require us to offer to repurchase all senior notes then outstanding at a
purchase price equal to 101% of the principal amount of the senior notes plus
accrued and unpaid interest to the date of purchase in the event that we become
subject to a change of control, as defined in the indentures. This feature of
the indentures could also have the effect of discouraging potentially attractive
change of control offers.
-10-
Furthermore, we have adopted a shareholder rights plan which may have
the effect of impeding a hostile attempt to acquire control of us.
Large amounts of our common stock may be resold into the market in the future
which could cause the market price of our common stock to drop significantly,
even if our business is doing well.
As of February 28, 2003, 181.1 million shares of our common stock were
issued and outstanding. In addition, as of February 28, 2003, we had issued
options to purchase 8.7 million shares of common stock and these options are
currently exercisable for 4.0 million shares of common stock. The market price
of our common stock could drop significantly if future sales of substantial
amounts of our common stock occur, or if the perception exists that substantial
sales may occur.
EMPLOYEES
At February 28, 2003, we had approximately 1,750 employees. None of our
employees are subject to collective bargaining agreements, and we believe our
employee relations are satisfactory.
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. All statements
other than statements of historical facts included in this report are
forward-looking statements, including statements regarding the following:
- business strategy;
- demand for our services;
- 2003 rig activity and financial results;
- reactivation and cost of reactivation of non-marketed rigs;
- projected dayrates and daily margins;
- wage rates and retention of employees;
- sufficiency of our capital resources and liquidity;
- depreciation and capital expenditures in 2003; and
- anticipated operating and financial results with respect to
our term drilling contracts.
Although we believe the expectations and beliefs reflected in such
forward-looking statements are reasonable, we can give no assurance that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from our expectations include:
- fluctuations in prices and demand for oil and natural gas;
- fluctuations in levels of oil and natural gas exploration and
development activities;
- fluctuations in the demand for contract land drilling
services;
- the existence and competitive responses of our competitors;
- attempts by our customers to terminate, renegotiate, or fail
to honor term drilling contracts;
- technological changes and developments in the industry;
- the existence of operating risks inherent in the contract land
drilling industry;
- U.S. and global economic conditions;
- the availability and terms of insurance coverage;
- the ability to attract and retain qualified personnel;
- unforeseen operating costs such as cost for environmental
remediation and turnkey cost overruns; and
- weather conditions.
Our forward-looking statements speak only as of the date specified in
such statements or, if no date is stated, as of the date of this report. Grey
Wolf expressly disclaims any obligation or undertaking to release publicly any
updates or revisions to any forward-looking statement contained in this report
to reflect any change in our expectations or with regard to any change in
events, conditions or circumstances on which our forward-looking statements are
based. Please refer to "Certain Risks" above for additional information
concerning risk factors that could also cause actual results to differ from the
forward-looking statements.
-11-
ITEM 2. PROPERTIES
DRILLING EQUIPMENT
An operating land drilling rig consists of engines, drawworks, mast,
substructure, pumps to circulate drilling fluid, blowout preventers, drill pipe
and related equipment. The actual drilling capacity of a rig may be less than
its rated drilling capacity due to numerous factors. The intended well depth and
the drill site conditions determine the amount of drill pipe and other equipment
needed to drill a well. Generally, land rigs operate domestically with crews of
four to six people.
Our rig fleet consists of several rig types to meet the demands of our
customers in each of the markets we serve. Our rig fleet consists of two basic
types of drilling rigs, mechanical and diesel electric. Mechanical rigs transmit
power generated by a diesel engine directly to an operation (for example the
drawworks or mud pumps on a rig) through a compound consisting of chains, gears
and hydraulic clutches. Diesel electric rigs are further broken down into two
subcategories, direct current rigs and Silicon Controlled Rectifier ("SCR")
rigs. Direct current rigs transmit the power generated by a diesel engine to a
direct current generator. This direct current electrical system then distributes
the electricity generated to direct current motors on the drawworks and mud
pumps. An SCR rig's diesel engines drive alternating current generators and this
alternating current can be transmitted to use for rig lighting and rig quarters
or converted to direct current to drive the direct current motors on the rig. We
own nine direct current diesel electric rigs and 50 SCR diesel electric rigs. We
also own 18 mechanical rigs and one diesel electric rig that are trailer-mounted
for greater mobility.
We also utilize top drives in our drilling operations. A top drive
allows drilling with 90-foot lengths of drill pipe rather than 30-foot lengths,
thus reducing the number of required connections. A top drive also permits
rotation of the drill string while tripping in or out of the hole. These
characteristics increase drilling speed, personnel safety and drilling
efficiency, and reduce the risk of the drill string sticking during operations.
At February 28, 2003, we owned 14 top drives.
We generally deploy our rig fleet among our divisions and districts
based on the types of rigs preferred by our customers for drilling in the
geographic markets served by our divisions and districts. The following table
summarizes the rigs we own as of February 28, 2003:
Maximum Rated Depth Capacity
-----------------------------------------------------------------------------
Under 10,000' 15,000' 20,000'
10,000' to 14,999' to 19,999' and Deeper Total
------------ ---------- ---------- ---------- -----
MARKETED
Ark-La-Tex
Diesel Electric - 1 4 5 10
Trailer-Mounted - 1 - - 1
Mechanical - 2 2 2 6
Gulf Coast
Diesel Electric - - 1 16 17
Mechanical - 1 1 - 2
South Texas
Diesel Electric - 1 4 8 13(1)
Trailer-Mounted - 9 - 1 10(2)
Mechanical - 4 - 1 5
Rocky Mountain
Diesel Electric - - - 2 2
West Texas
Diesel Electric - - 2 4 6
------------ ---------- ---------- ---------- -----
Total Marketed - 19 14 39 72
NON-MARKETED
Diesel Electric - - 1 9 10
Trailer-Mounted 2 6 - - 8
Mechanical - 11 10 4 25
------------ ---------- ---------- ---------- -----
Total Non-Marketed 2 17 11 13 43
------------ ---------- ---------- ---------- -----
Total Rig Fleet 2 36 25 52 115
============ ========== ========== ========== =====
- ---------------------------
(1) Excludes one rig which we operate for a third party.
(2) Includes one diesel electric rig.
-12-
FACILITIES
The following table summarizes our significant real estate:
Location Interest Uses
- -------- -------- ----
Houston, Texas................... Leased Executive Offices
Alice, Texas..................... Owned Field Office, Rig Yard, Truck Yard
Eunice, Louisiana................ Owned Field Office, Rig Yard
Haughton, Louisiana.............. Owned Rig Yard
Oklahoma City, Oklahoma.......... Owned Rig Yard
Shreveport, Louisiana............ Leased Field Office
Shreveport, Louisiana............ Owned Rig Yard
Casper, Wyoming.................. Leased Field Office
Midland, Texas................... Leased Field Office
We lease approximately 22,700 square feet of office space in Houston,
Texas for our principal executive offices at a cost of approximately $39,600 per
month. We believe that all our facilities are in good operating condition and
that they are adequate for their present uses.
ITEM 3. LEGAL PROCEEDINGS
We are involved in litigation incidental to the conduct of our
business, none of which we believe is, individually or in the aggregate,
material to our consolidated financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
-13-
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
MARKET DATA
Our common stock is listed and traded on the American Stock Exchange
("AMEX") under the symbol "GW." The following table sets forth the high and low
closing prices of our common stock on the AMEX for the periods indicated:
High Low
-------- ---------
Period from January 1, 2003 to February 28, 2003 $ 4.50 $ 3.50
Year Ended December 31, 2002
Quarter ended March 31, 2002 4.07 2.69
Quarter ended June 30, 2002 5.01 3.72
Quarter ended September 30, 2002 4.08 2.78
Quarter ended December 31, 2002 4.42 3.15
Year Ended December 31, 2001:
Quarter ended March 31, 2001 6.96 5.06
Quarter ended June 30, 2001 6.87 3.77
Quarter ended September 30, 2001 3.73 1.75
Quarter ended December 31, 2001 3.31 1.76
We have never declared or paid cash dividends on our common stock and
do not expect to pay cash dividends in 2003 or for the foreseeable future. We
anticipate that all cash flow generated from operations in the foreseeable
future will be retained and used to develop or expand our business, pay debt
service and reduce outstanding indebtedness. Any future payment of cash
dividends will depend upon our results of operations, financial condition, cash
requirements and other factors deemed relevant by our board of directors.
The terms of our credit facility prohibit the payment of dividends
without the prior written consent of the lender and the terms of the Indentures
under which our senior notes are issued also restrict our ability to pay
dividends under certain conditions.
On February 28, 2003, the last reported sales price of our common stock
on the AMEX was $4.17 per share.
-14-
ITEM 6. SELECTED FINANCIAL DATA
Years Ended December 31,
-------------------------------------------------------------------------
2002 2001 2000 1999 1998
----------- ----------- ----------- ----------- -----------
(Amounts in thousands, except per share amounts)
Revenues (1) $ 250,260 $ 433,739 $ 276,758 $ 148,465 $ 244,120
Net income (loss) (21,476) 68,453 (8,523) (41,262) (83,213)
Net income (loss) per common share
- basic and diluted (.12) .38 (.05) (.25) (.50)
Total assets (1) 590,623 625,471 512,370 453,852 501,303
Senior notes & other long-term debt 249,613 250,695 249,851 249,962 250,527
Series A Preferred Stock - Manditorily
Redeemable - - - - 305
- ---------------------------
(1) Presentation revised to give effect to reclassification of certain
items to conform to the presentation in 2002. (see Note 1 to
consolidated financial statements)
-15-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read in conjunction with our
consolidated financial statements included elsewhere herein. All significant
intercompany transactions have been eliminated.
GENERAL
We are a leading provider of contract land drilling services in the
United States with a fleet of 116 rigs, of which 73 rigs are currently marketed.
Included in the marketed fleet is one non-owned rig that we operate for a third
party.
Rig Activity
After approximately two years of increasing rig utilization and
dayrates, demand for land drilling rigs began to decline late in the third
quarter of 2001. From the second quarter of 2002 until the end of January 2003,
rig counts stabilized and our rig count averaged between 50 to 59 rigs working
each week. Beginning in February 2003, however, we have seen an increase in the
amount of future work for our rigs currently operating in the form of signed
contracts and oral commitments from our customers. At February 28, 2003, we had
63 rigs working. The table below shows the average number of our rigs working in
our operating markets during the periods indicated.
2000 2001 2002 2003
- ---- --------------------------------------- --------------------------------------- ----
Full Full Full Q-1 to
Year Q-1 Q-2 Q-3 Q-4 Year Q-1 Q-2 Q-3 Q-4 Year Date
- ---- --- --- --- --- ---- --- --- --- --- ---- ----
71 88 92 91 68 85 56 54 55 54 55 57
Drilling Contract Bid Rates
Dayrates are generally driven by utilization and, with the decline in
the number of rigs running beginning in late 2001, we also experienced a drop in
dayrates. From the high leading edge bid rates of $13,500 to $17,000 per rig day
without fuel or top drives in April 2001, our daywork bid rates declined to the
current daywork bid rates between $7,000 and $8,500 per rig day without fuel or
top drives. Based upon the recent increase in rig activity, we believe that
these rates mark the low point of the down cycle and should rise as utilization
increases. The timing or occurrence of such an event cannot be assured.
We currently own 14 top drives for which our current bid rates are
approximately $1,500 per rig day. Bid rates for our top drives are in addition
to the above-stated bid rates for our rigs.
Term Contracts
Whenever market conditions allow, we strive to utilize term contracts
to provide drilling services on a daywork basis. During late 2001 and 2002, the
use of term contracts enabled us to maintain higher margins than would otherwise
be attainable during the latest downturn. If current market conditions do not
improve as our remaining term contracts expire, there will be a further decline
in our operating margin as rigs go to work under lower spot market rate
contracts.
Our term contracts contain termination provisions which require our
customers, upon cancellation of a contract, to pay an amount that approximates
our operating margin for the remaining days of the contract. We have
approximately 930 rig days contracted under term contracts in 2003, of which 420
days are in the first quarter, 250 days in the second quarter, 170 days in the
third quarter, and 90 days in the fourth quarter.
-16-
Turnkey and Footage Contract Activity
During all phases of the industry cycle, turnkey work continues to be
an important part of our business strategy. Our engineering and operating
experience allows us to provide this service to our customers and has
historically provided higher margins than would otherwise have been obtainable
under daywork contracts. During the fourth quarter of 2002, our turnkey
operating margin was $6,123 per rig day compared to a daywork operating margin
of $1,667 per rig day. For the year ended December 31, 2002, our turnkey
operating margin per rig day was $5,760 compared to a daywork operating margin
per day of $2,364.
The operating margins generated on turnkey and footage contracts varies
widely based upon a number of factors, including the location of the contracted
work as well as the depth and level of complexity of the wells drilled. The
demand for drilling services under turnkey and footage contracts has
historically been greater during periods of overall lower demand. There can be
no assurance that we will be able to maintain the current level of revenue or
operating margins derived from turnkey and footage contracts.
Critical Accounting Policies
Our consolidated financial statements and accompanying notes have been
prepared in accordance with accounting principles generally accepted in the
United States of America. The preparation of these financial statements require
our management to make subjective estimates, judgments and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses.
However, these estimates, judgments and assumptions concern matters that are
inherently uncertain. Accordingly, actual amounts and results could differ from
these estimates made by management. The accounting policies that we believe are
critical are property and equipment, impairment of long-lived assets, revenue
recognition, insurance accruals, and income taxes.
Property and Equipment. Property and equipment are stated at cost with
depreciation calculated using the straight-line method over the estimated useful
lives of the assets. We expense our maintenance and repairs costs as incurred.
We estimate the useful lives of our assets are between three and fifteen years.
Impairment of Long-Lived Assets. We assess the impairment of our
long-lived assets whenever events or changes in circumstances indicate that the
carrying value may not be recoverable. Such indicators include changes in our
business plans, a change in the physical condition of a long-lived asset or the
extent or manner in which it is being used, or a severe or sustained downturn in
the oil and gas industry. If a review of our long-lived assets indicates that
the carrying value of certain of these assets is more than the estimated
undiscounted cash flows, a write-down of the assets to their estimated fair
market value must be made. The estimated fair market value is the amount at
which an asset could be bought or sold in a current transaction between willing
parties. Quoted market prices in active markets are the best estimate of fair
market value, however, quoted market prices will generally not be available. As
a result, fair value must be determined based upon other valuation techniques.
This could include appraisals or present value calculations. The calculation of
undiscounted future net cash flows and fair market value is based on estimates
and projections.
During the fourth quarter of 2002, we recorded a pre-tax non-cash asset
impairment charge of $3.5 million in accordance with SFAS 144. After review of
our rigs held for future refurbishment, we no longer intend to return five of
those rigs to service, but will instead use their component parts as spare
equipment inventory. This decision was made based upon the physical condition of
the five rigs and the estimated cost of refurbishment. As such, we recorded the
charge to write the rigs down to their fair market value and revised the number
of drilling rigs in our fleet from 121 to 116, including one non-owned rig that
we operate for a third party. The fair market value was based on an appraisal
obtained from a third party appraiser. The after tax effect of this impairment
charge was $.01 per diluted share.
Revenue Recognition. Revenue from daywork and footage contracts is
recognized when earned as services are performed under the provisions of the
contract. Revenue from turnkey drilling contracts is recognized using the
percentage-of-completion method based upon costs incurred to date and estimated
total contract costs. Provision for anticipated losses, if any, on uncompleted
contracts is made at the time our estimated costs exceed the contract revenue.
Insurance Accruals. We maintain insurance coverage related to workers'
compensation and general liability claims up to $1.0 million per occurrence with
an aggregate of $2.0 million under general liability. These policies include
deductibles of $250,000 per occurrence. In addition, we are self-insured for our
employee health
-17-
plan but purchase stop-loss coverage in order to limit our exposure to a maximum
of $175,000 per occurrence under the plan. If losses should exceed the workers'
compensation and general liability policy amounts, we have excess liability
coverage up to a maximum of $75.0 million with deductibles per occurrence of
either $10,000 or $50,000. The provision for losses incurred within the
deductible and stop-loss amounts involves estimates by management and we base
these estimates on our historical claims experience.
Income Taxes. Our deferred tax assets consist primarily of net
operating loss carryforwards ("NOL's") which expire from 2010 to 2022. Deferred
tax assets must be assessed based upon the likelihood of recoverability from
future taxable income and to the extent that recovery is not likely, a valuation
allowance is established. At December 31, 2002, we do not have a valuation
allowance as we believe that it is more likely than not that we will be able to
generate future taxable income sufficient to recover our deferred tax assets.
Our business, however, is extremely cyclical and is highly sensitive to changes
in oil and natural gas prices and demand for our services and there can be no
assurances that future economic or financial developments will not impact our
ability to recover our deferred tax assets.
In addition, we have $26.5 million in permanent differences which
relate to differences between the financial accounting and tax basis of acquired
assets. The permanent difference will be reduced as the assets are depreciated
for financial accounting purposes on a straight-line basis over the next 10
years. As the amortization of these permanent differences is a fixed amount, our
effective tax rate varies widely based upon the current level of income or loss.
See Footnote 3 in the notes to the consolidated financial statements for a
reconciliation of our statutory to effective tax rate.
Financial Results
Our net loss for 2002 was $21.5 million compared with net income of
$68.5 million for 2001. Revenue for 2002 was $250.3 million compared with $433.7
million for the year 2001. For the fourth quarter of 2002 our net loss was $9.1
million and revenues were $61.4 million. This compares to net income of $9.0
million and revenues of $89.6 million in the fourth quarter of 2001.
Our operating margin for the fourth quarter of 2002 was $2,194 per rig
day, compared to the third quarter 2002 operating margin of $2,225 per rig day
and fourth quarter 2001 operating margin of $5,337 per rig day. Our operating
margins for the years ended December 31, 2002 and 2001 were $2,674 per rig day
and $5,963 per rig day, respectively.
Financial Outlook
Based on currently anticipated levels of activity and dayrates, we
expect to generate an operating margin of approximately $1,300 per rig day for
the first quarter of 2003. This operating margin level should generate earnings
before interest, income taxes, depreciation and amortization ("EBITDA") of
approximately $4.1 million. Net loss per share is expected to be approximately
$.05 on a diluted basis, assuming an annual tax benefit rate of between 30% and
34%. We expect depreciation expense of approximately $11.9 million for the first
quarter of 2003. We project capital expenditures for 2003 to be between $23.0
million and $26.0 million subject to the actual level of rig activity. These
projections are forward-looking statements and while we believe our estimates
are reasonable, we can give no assurance that such expectations will prove to be
correct. See Item 1. Business-Forward-Looking Statements for important factors
that could cause actual results to be differ materially from our expectations.
-18-
FINANCIAL CONDITION AND LIQUIDITY
The following table summarizes our financial position as of December
31, 2002 and December 31, 2001.
December 31, 2002 December 31, 2001
---------------------- ----------------------
(In thousands)
Amount % Amount %
----------- ----- ----------- -----
Working capital $ 114,353 21 $ 113,163 20
Property and equipment, net 420,791 78 448,660 79
Other noncurrent assets 4,668 1 5,744 1
----------- ----- ----------- -----
Total $ 539,812 100 $ 567,567 100
=========== ===== ========== =====
Long-term debt $ 249,613 46 $ 250,695 44
Other long-term liabilities 64,941 12 71,575 13
Shareholders' equity 225,258 42 245,297 43
----------- ----- ----------- -----
Total $ 539,812 100 $ 567,567 100
=========== ===== =========== =====
The significant changes in our financial position from December 31,
2001 to December 31, 2002 are the decreases in net property and equipment of
$27.9 million, other long-term liabilities of $6.6 million, and shareholders'
equity of $20.0 million.
The decrease in net property and equipment is due primarily to $46.6
million of depreciation expense and the $3.5 million pre-tax non-cash asset
impairment charge partially offset by capital expenditures of $22.5 million.
Other long-term liabilities decreased due to lower deferred tax liabilities of
$6.6 million as a result of a net loss of $21.5 million in 2002. Shareholders'
equity also decreased due to the net loss in 2002 slightly offset by stock
option exercises.
Senior Notes
In June 1997 and May 1998, we concluded public offerings of $175.0
million and $75.0 million, respectively, in principal amount of senior notes.
The senior notes ("Notes") bear interest at 8 7/8% per annum and mature July 1,
2007. The Notes are general unsecured senior obligations and are fully and
unconditionally guaranteed, on a joint and several basis, by all of our domestic
wholly-owned subsidiaries. Non-guarantor subsidiaries are immaterial.
We have the option to redeem the Notes in whole or in part during the
twelve months beginning July 1, 2002 at 104.4375%, beginning July 1, 2003 at
102.9580%, beginning July 1, 2004 at 101.4792% and beginning July 1, 2005 and
thereafter at 100.0000% together with any interest accrued and unpaid to the
redemption date. Upon a change of control as defined in the indentures, each
holder of the Notes will have the right to require us to repurchase all or any
part of such holder's Notes at a purchase price equal to 101% of the aggregate
principal amount thereof, plus accrued and unpaid interest to the date of
purchase. We may also, from time-to-time, seek to retire the Notes through open
market purchases and privately-negotiated transactions.
The indentures for the Notes permit us and our subsidiaries to incur
additional indebtedness, including senior indebtedness of up to $100.0 million
aggregate principal amount which may be secured by liens on all of our assets
and the assets of our subsidiaries, subject to certain limitations. The
indentures contain other covenants limiting our ability and our subsidiaries
ability to, among other things, pay dividends or make certain other restricted
payments, make certain investments, incur additional indebtedness, permit liens,
incur dividend and other payment restrictions affecting subsidiaries, enter into
consolidation, merger, conveyance, lease or transfer transactions, make asset
sales, enter into transactions with affiliates or engage in unrelated lines of
business. These covenants are subject to certain exceptions and qualifications.
The indentures consider non-compliance with the limitations events of default.
In addition to non-payment of interest and principal amounts, the indentures
also consider default with respect to other indebtedness in excess of $10.0
million an event of default. In the event of a default, the principal and
interest could be accelerated upon written notice by 25% or more of the holders
of our senior notes. We are in compliance with these covenants.
-19-
We owe a total of $250.0 million in principal amount under our senior
notes. While the principal is not due until 2007, semi-annual interest payments
of approximately $11.1 million are due on January 1 and July 1 of each year. For
the year ended December 31, 2002, our operating activities provided cash, while
our investing and financing activities consumed cash. To the extent we are
unable to generate cash flow sufficient to pay debt service and meet our other
cash needs, including capital expenditures, we would be required to use our cash
on hand. At February 28, 2003, our cash balance was $100.9 million.
CIT Facility
We have a $75.0 million credit facility with the CIT Group/Business
Credit, Inc. ("CIT Facility") which expires during January 2006. The CIT
Facility provides us with the ability to borrow up to the lesser of $75.0
million or 50% of the orderly liquidation value (as defined in the agreement) of
certain drilling rig equipment located in the 48 contiguous states of United
States of America. At December 31, 2002, the orderly liquidation value was
greater than $75.0 million. The CIT Facility is a revolving facility with
automatic renewals after expiration unless terminated by the lender on any
subsequent anniversary date and then only upon 60 days prior notice. Periodic
interest payments are due at a floating rate based upon our debt service
coverage ratio within a range of either LIBOR plus 1.75% to 3.50% or prime plus
0.25% to 1.50%. We recently amended the CIT Facility to increase the
availability of letters of credit from $10.0 million to $20.0 million. This was
done to enable us to issue additional letters of credit for the benefit of
various insurance companies as collateral for retrospective premiums and
retained losses which may become payable under the terms of the underlying
insurance contracts. See Item 1 - "Business Insurance." We are required to pay a
commitment fee of 0.375% per annum on the unused portion of the CIT Facility and
letters of credit accrue a fee of 1.25% per annum. Outstanding letters of credit
reduce the amount available for borrowing under the CIT Facility.
The CIT Facility contains certain affirmative and negative covenants
and we are in compliance with these covenants. Substantially all of our assets,
including our drilling equipment, are pledged as collateral under the CIT
Facility and it is also secured by our guarantees and certain of our
wholly-owned subsidiaries guarantees. We, however, retain the option, subject to
a minimum appraisal value, under the CIT Facility to extract $75.0 million of
the equipment out of the collateral pool in connection with the sale or exchange
of such collateral or relocation of equipment outside the contiguous 48 states
of the United States of America. We currently have no outstanding balance under
the CIT facility and had $7.4 million of undrawn letters of credit outstanding
at December 31, 2002.
Under the CIT Facility the lender's commitments of $75.0 million will
be reduced by the amount of net cash proceeds received by us or our subsidiaries
from sales or other dispositions of collateral in excess of $1.0 million
individually or $2.0 million in the aggregate in any 12 month period (other than
sales or other dispositions of certain types of inventory, rigs identified in
the CIT Facility as equipment held for sale and up to $75.0 million of rigs and
accessories). In addition, mandatory prepayments would be required upon:
- the receipt of net proceeds received by us or our subsidiaries
from the incurrence of certain other debt or sales of debt or
equity securities in a public offering or private placement,
or;
- the receipt of net cash proceeds by us or our subsidiaries
from asset sales (including proceeds from sale of rigs
identified in the credit agreement as equipment held for sale,
but excluding proceeds from dispositions of inventory in the
ordinary course of business, and sales of up to $75.0 million
of rigs and rig accessories) or;
- the receipt of insurance proceeds on our assets in each case
to the extent that such proceeds are in excess of $500,000
individually or $1.0 million in the aggregate in any twelve
month period.
Among the various covenants that we must satisfy under the CIT Facility
are the following two covenants which apply whenever our liquidity, defined as
the sum of cash, cash equivalents and availability under the CIT facility, falls
below $25.0 million.
- 1 to 1 EBITDA coverage of debt service, tested monthly on a
trailing 12 month basis; and
- minimum tangible net worth (all as defined in the CIT
Facility) at the end of each quarter will be at least the
prior year tangible net worth less $30.0 million adjusted for
quarterly tests.
-20-
Additionally, if the total amount outstanding under the CIT Facility
(including outstanding letters of credit) exceeds 50% of the orderly liquidation
value of our domestic rigs, we are required to make a prepayment in the amount
of the excess. Also, if the average rig utilization rate falls below 45% for two
consecutive months, the lender will have the option to request one additional
appraisal per year to aid in determining the current orderly liquidation value
of the drilling equipment. Average rig utilization is defined as the total
number of rigs owned which are operating under drilling contracts in the 48
contiguous states of the United States of America divided by the total number of
rigs owned, excluding rigs not capable of working without substantial capital
investment.
The CIT Facility also contains provisions restricting our ability to,
among other things:
- engage in new lines of business unrelated to our current
activities;
- enter into mergers or consolidations or asset sales or
purchases (with specified exceptions);
- incur liens or debts or make advances, investments or loans
(in each case, with specified exceptions);
- pay dividends or redeem stock (except for certain
inter-company transfers);
- prepay or materially amend any other indebtedness; and
- issue any stock (other than common stock).
Events of default under the CIT Facility include, in addition to
non-payment of amounts due, misrepresentations and breach of loan covenants and
certain other events of default:
- default with respect to other indebtedness in excess of
$350,000;
- judgments in excess of $350,000; or
- a change in control which means that we cease to own 100% of
our two principal subsidiaries, some person or group has
either acquired beneficial ownership of 30% or more of the
Company or obtained the power to elect a majority of our board
of directors, or our board of directors ceases to consist of a
majority of "continuing directors" (all defined by the CIT
facility).
Certain Contractual Commitments
The following table summarizes our contractual cash obligations and
related payments due by period at December 31, 2002 (amounts in thousands):
Payments Due by Period (1)
-----------------------------------------------------------------------------
Less than 1-3 4-5 After 5
Contractual Obligation Total 1 year years years years
- ---------------------- ----------- ----------- ----------- ---------- -----------
Senior notes(2)
Principal $ 250,000 $ - $ - $ 250,000 $ -
Interest 110,937 22,187 44,375 44,375 -
Operating leases 1,270 627 643 - -
----------- ----------- ----------- ---------- -----------
Total contractual cash obligations $ 362,207 $ 22,814 $ 45,018 $ 294,375 $ -
=========== =========== =========== ========== ===========
- ---------------------------
(1) Assumes no acceleration of maturity dates due to redemption or to
breach of, or default under, the terms of the applicable contractual
obligation.
(2) See "Senior Notes" above, for information relating to certain financial
ratio covenants and certain other covenants the breach of which could
cause a default under, and acceleration of the maturity date of, the
senior notes.
-21-
Our CIT Facility provides up to $20.0 million for the issuance of
letters of credit. If letters of credit which we cause to be issued are drawn
upon by the holders of those letters of credit, then we will become obligated
to repay those amounts along with any accrued interest and fees. Letters of
credit issued reduce the amount available for borrowing under the CIT Facility
and, as a result, we had $67.6 million available at December 31, 2002. The
following table illustrates the undrawn outstanding letters of credit at
December 31, 2002 and the potential maturities if drawn upon by the holders
(amounts in thousands):
Payments Due by Period (1)
-----------------------------------------------------------------------------
Potential Total Less than 1-3 4-5 Over 5
Contractual Obligation Committed 1 year years years years
- ---------------------- ----------- ----------- ----------- ----------- -----------
Standby letters of credit $ 7,407 $ 7,407 $ - $ - $ -
----------- ----------- ----------- ---------- -----------
Total contractual obligation $ 7,407 $ 7,407 $ - $ - $ -
=========== =========== =========== ========== ===========
- ---------------------------
(1) Assumes no acceleration of maturity dates due to breach of, or default
under, the potential contractual obligation.
Cash Flow
The net cash provided by or used in our operating, investing and
financing activities is summarized below (amounts in thousands):
Years Ended December 31,
------------------------------------------------------
2002 2001 2000
----------- ----------- ----------
Net cash provided by (used in):
Operating activities $ 36,317 $ 148,226 $ 16,310
Investing activities (21,947) (101,123) (38,536)
Financing activities (1,138) 491 53,793
------------ ----------- ----------
Net increase (decrease) in cash: $ 13,232 $ 47,594 $ 31,567
=========== =========== ==========
Our cash flows from operating activities are affected by a number of
factors including the number of rigs under contract, whether the contracts are
daywork, footage, or turnkey, and the rate received for these services. Our cash
flow generated from operating activities during the year ended December 31, 2002
was $23.3 million (before changes in operating assets and liabilities) compared
to cash generated from operating activities during the year ended December 31,
2001 of $150.5 million (before changes in operating assets and liabilities).
This change is principally due to a 35% decrease in operating days and a 55%
decrease in our per rig day operating margins between the two periods. Our cash
flows from operating activities were also impacted by changes in operating
assets and liabilities which provided $13.0 million and used $2.3 million in
cash flow for the years ended December 31, 2002 and 2001, respectively.
Generally, during times of increasing demand our changes in working capital will
result in the use of cash flows due primarily to the build-up of accounts
receivable.
Our cash flow generated from operating activities during the year ended
December 31, 2001 was $150.5 million (before changes in operating assets and
liabilities) compared to cash generated in operating activities during the year
ended December 31, 2000 of $27.2 million (before changes in operating assets and
liabilities). This change is principally due to an 18% increase in operating
days and a 177% increase in our per rig day operating margins between the two
periods. Our cash flows from operating activities were also impacted by changes
in operating assets and liabilities which used $2.3 million and $10.9 million in
cash flow for the years ended December 31, 2001 and 2000, respectively.
-22-
Cash flow used in investing activities for the year ended December 31,
2002 primarily consisted of $22.3 million of capital expenditures for sustaining
our rigs, the acquisition of one additional top drive, and other capital items.
Our cash flow used in investing activities for the year ended December 31, 2001
primarily consisted of $103.0 million of capital expenditures for reactivating
rigs, acquisition of drill pipe, drill collars and top drives, and other capital
items. Cash flow used in investing activities for the year ended December 31,
2000, primarily consisted of $38.6 million of capital expenditures for
reactivating rigs, acquisition of top drives, and other capital items.
Cash flow used by financing activities for the year ended December 31,
2002 consisted principally of $1.8 million for repayment of long-term lease
obligations, partially offset by $686,000 from stock option exercises. Cash flow
provided by financing activities for the year ended December 31, 2001 consisted
principally of $1.7 million from stock option exercises, partially offset by
$911,000 for repayment of long-term lease obligations. Cash flow provided by
financing activities for the year ended December 31, 2000 primarily consisted of
net proceeds of $51.6 million and $3.2 million from the sale of common stock and
from stock option exercises, respectively, partially offset by $1.1 million
repayment of long-term lease obligations.
RESULTS OF OPERATIONS
Our drilling contracts generally provide compensation on either a
daywork, turnkey or footage basis. However, successfully completed turnkey and
footage contracts generally result in higher effective revenues per rig day
worked than under daywork contracts. Operating margins per rig day worked on
successful turnkey and footage jobs are also generally greater than under
daywork contracts, although we are typically required to bear additional
operating costs (such as drill bits) that would typically be paid by the
customer under daywork contracts. Contract drilling revenues, drilling operating
expenses and operating margins or losses on turnkey and footage contacts are
affected by a number of variables, which include the depth of the well,
geological complexities and the actual difficulties encountered in drilling the
well.
In accordance with Emerging Issues Task Force Issue No. 01-14 "Income
Statement Characterization of Reimbursements Received for Out-of-Pocket Expenses
Incurred," we have revised the presentation of reimbursements received for
certain expenses in the periods presented. These reimbursements are now included
in contract drilling revenues on the consolidated statement of operations versus
previously being recorded net of the incurred expenses in drilling operations
expenses. This reclassification had no effect on net income or cash flows.
-23-
The following tables highlight rig days worked, contract drilling
revenues and drilling operating expenses for our daywork and turnkey operations
for the years ended December 31, 2002, 2001 and 2000.
For the Year Ended December 31, 2002
---------------------------------------------------------
Daywork Turnkey
Operations Operations(2) Total
------------- ---------- -------------
(Dollars in thousands, except averages per rig day worked)
Rig days worked 18,248 1,832 20,080
Contract drilling revenue $ 197,594 $ 52,666 $ 250,260
Drilling operating expenses(1) 154,458 42,112 196,570
------------- ------------- -------------
Operating margin (loss) $ 43,136 $ 10,554 $ 53,690
============= ============= =============
Averages per rig day worked:
Contract drilling revenue $ 10,828 $ 28,748 $ 12,463
Drilling operating expenses 8,464 22,988 9,789
------------- ------------- -------------
Operating margin (loss) $ 2,364 $ 5,760 $ 2,674
============= ============= =============
For the Year Ended December 31, 2001
---------------------------------------------------------
Daywork Turnkey
Operations Operations(2) Total
------------- ---------- -------------
(Dollars in thousands, except averages per rig day worked)
Rig days worked 28,766 2,158 30,924
Contract drilling revenue $ 376,222 $ 57,517 $ 433,739
Drilling operating expenses(1) 208,966 40,362 249,328
------------- ------------- -------------
Operating margin (loss) $ 167,256 $ 17,155 $ 184,411
============= ============= =============
Averages per rig day worked:
Contract drilling revenue $ 13,079 $ 26,657 $ 14,026
Drilling operating expenses 7,265 18,707 8,063
------------- ------------- -------------
Operating margin (loss) $ 5,814 $ 7,950 $ 5,963
============= ============= =============
For the Year Ended December 31, 2000
---------------------------------------------------------
Daywork Turnkey
Operations Operations(2) Total
------------- ---------- -------------
(Dollars in thousands, except averages per rig day worked)
Rig days worked 21,533 4,574 26,107
Contract drilling revenue $ 194,832 $ 81,926 $ 276,758
Drilling operating expenses(1) 149,315 71,398 220,713
------------- ------------- -------------
Operating margin (loss) $ 45,517 $ 10,528 $ 56,045
============= ============= =============
Averages per rig day worked:
Contract drilling revenue $ 9,048 $ 17,911 $ 10,601
Drilling operating expenses 6,930 15,610 8,451
------------- ------------- -------------
Operating margin (loss) $ 2,118 $ 2,301 $ 2,150
============= ============= =============
- ---------------------------
(1) Drilling operating expenses exclude depreciation, and general and
administrative expenses.
(2) Turnkey operations include the results from turnkey and footage
contracts.
-24-
COMPARISON OF FISCAL YEARS ENDED DECEMBER 31, 2002 AND 2001
Contract drilling revenue decreased approximately $183.5 million, or
42%, to $250.3 million for the year ended December 31, 2002, from $433.7 million
for the year ended December 31, 2001. The decrease is due to a decrease in total
rig days worked of 10,844 days, or 35%, and a decrease in the total average
revenue per rig day of $1,563, or 11% due to the downturn in drilling activity.
The decrease in the total rig days worked consists of 10,518 fewer rig days
under daywork contracts and 326 fewer rig days under turnkey contracts. The
decline in the total average revenue per day was due to the decrease in the
daywork average revenue per rig day. This was the result of lower dayrates and
rigs rolling off higher rate term contracts onto lower rate spot market
contracts. Turnkey average revenue per rig day was higher due to the location
and complexity of the wells drilled during 2002 when compared to the same period
in 2001.
Total drilling operating expenses decreased by approximately $52.8
million, or 21% to $196.6 million for the year ended December 31, 2002, as
compared to $249.3 million for the year ended December 31, 2001. The decrease is
a result of the decreased level of activity from daywork operations.
Drilling operating expenses on a per rig day basis increased overall
principally due to a wage increase of 12% effective June 1, 2001, the retention
of our experienced toolpushers and drillers during the downturn, the cost of
cold-stacking rigs, and overhead and other fixed costs being spread over less
days. Turnkey expenses were also higher due to the greater overall depth and
complexity of turnkey wells drilled.
Depreciation expense increased by $5.2 million, or 12%, to $46.6
million for the year ended December 31, 2002 compared to $41.4 million for the
year ended December 31, 2001. The increase is primarily due to additional
depreciation attributable to equipment purchased and placed into service during
2001 and 2002.
General and administrative expenses increased by $1.4 million, or 14%,
to $11.3 million for the year ended December 31, 2002 compared to $9.9 million
for the year ended December 31, 2001. This increase is due primarily to $330,000
for severance costs and $515,000 of non-cash compensation expense related to
stock options as a result of the termination of employment of an officer in the
first quarter of 2002. Also contributing to the increase are higher insurance
costs and higher professional fees.
The difference in interest expense for the years ended December 31,
2002 and 2001 is negligible as the average outstanding debt balance was
virtually the same and the largest component of our debt structure is our Senior
Notes which carry interest at a fixed rate.
Interest income decreased by $709,000, or 29%, to $1.7 million for the
year ended December 31, 2002, from $2.4 million for the year ended December 31,
2001 due to lower interest rates in 2002 partially offset by higher cash
balances. Cash balances were higher in 2002 as a result of an overall build in
cash due to higher drilling activity and dayrates throughout 2001.
Net other income (expense) increased by $574,000 to income of $128,000
for the year ended December 31, 2002 from expense of $446,000 for the same
period of 2001. The expense in 2001 related to the realization of $454,000 in
previously unrealized foreign currency translation losses as a result of moving
our Venezuela rigs to the United States.
COMPARISON OF FISCAL YEARS ENDED DECEMBER 31, 2001 AND 2000
Contract drilling revenue increased approximately $156.9 million, or
57%, to $433.7 million for the year ended December 31, 2001, from $276.8 million
for the year ended December 31, 2000. The increase is due to an increase in
total rig days worked of 4,817 days, or 18%, and an increase in the total
average revenue per rig day of $3,425, or 32%. The increase in the total days
worked is the result of a 34% increase in daywork drilling activity partially
offset by a 53% decrease in turnkey drilling activity. The increase in the total
average revenue per rig day is due to higher dayrates received from both daywork
and turnkey operations.
Drilling operating expenses increased by approximately $28.6 million,
or 13%, to $249.3 million for the year ended December 31, 2001, as compared to
$220.7 million for the year ended December 31, 2000. The increase is the direct
result of the overall increased level of activity from daywork operations and
increases in wages partially offset by a decreased level of activity from
turnkey operations discussed above. Operating expenses on a per rig day basis,
however, decreased due to overhead items being spread over more days worked and
a decrease in the
-25-
percentage of turnkey days worked to total days worked from 18% in 2000 to 7% in
2001. The decrease in operating expenses on a per rig day basis was partially
offset by wage increases of 5% on July 1, 2000, 14% on August 31, 2000, and 12%
on June 1, 2001.
Depreciation expense increased by $4.7 million, or 13%, to $41.4
million for the year ended December 31, 2001 compared to $36.8 million for the
year ended December 31, 2000. The increase is primarily due to additional
depreciation attributable to equipment purchased and placed in service during
the year ended December 31, 2001.
General and administrative expenses increased by $1.8 million, or 22%,
to $9.9 million for the year ended December 31, 2001 compared to $8.1 million
for the year ended December 31, 2000, due primarily to the increased level of
our operating activity and accrual of performance based compensation.
The difference in interest expense for the years ended December 31,
2001 and 2000 is negligible as the average outstanding debt balance was
virtually the same and the largest component of our debt structure is our Senior
Notes which carry interest at a fixed rate.
Interest income decreased by $649,000, or 21%, to $2.4 million for the
year ended December 31, 2001, from $3.1 million for the year ended December 31,
2000 due to lower interest rates in 2001 partially offset by higher cash
balances. Cash balances were higher as a result of the issuance of 13.0 million
shares of common stock on April 4, 2000 and due to higher drilling activity and
dayrates in 2001.
Net other income (expense) decreased by $416,000 to expense of $446,000
for the year ended December 31, 2001 from expense of $30,000 for the same period
of 2000 due primarily to the realization of $454,000 in previously unrealized
foreign currency translation losses as a result of moving our Venezuela rigs to
the United States.
INFLATION AND CHANGING PRICES
Contract drilling revenues do not necessarily track the changes in
general inflation as they tend to respond to the level of activity of the oil
and gas industry in combination with the supply of equipment and the number of
competing companies. Capital and operating costs are influenced to a larger
extent by specific price changes in the oil and gas industry and to a lesser
extent by changes in general inflation.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Interest Rate Risk. We are subject to market risk exposure related to
changes in interest rates on our CIT Facility. Interest on borrowings under the
CIT facility accrues at a variable rate, using (at our election) either the
prime rate plus 0.25% to 1.50% or LIBOR plus 1.75% to 3.5%, depending upon our
debt service coverage ratio for the trailing 12 month period. We currently have
no outstanding balance under the CIT facility and as such have no exposure at
this time to a change in interest rates.
-26-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULE
Independent Auditors' Report.................................................................................. 28
Consolidated Balance Sheets as of December 31, 2002 and 2001.................................................. 29
Consolidated Statements of Operations for the Years
Ended December 31, 2002, 2001, and 2000.............................................................. 30
Consolidated Statements of Shareholders' Equity and Comprehensive Income
for the Years Ended December 31, 2002, 2001, and 2000................................................ 31
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2002, 2001, and 2000.............................................................. 32
Notes to Consolidated Financial Statements.................................................................... 33
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts..................................................... 43
Schedules other than those listed above are omitted because they are either not
applicable or not required or the information required is included in the
consolidated financial statements or notes thereto.
-27-
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors
of Grey Wolf, Inc.:
We have audited the accompanying consolidated balance sheets of Grey
Wolf, Inc. and Subsidiaries as of December 31, 2002 and 2001, and the related
consolidated statements of operations, shareholders' equity and comprehensive
income, and cash flows for each of the years in the three-year period ended
December 31, 2002. In connection with our audits of the consolidated financial
statements, we have also audited the financial statement schedule for the years
ended December 31, 2002, 2001 and 2000. These consolidated financial statements
and financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. 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 audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Grey Wolf,
Inc. and Subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2002, in conformity with accounting principles generally
accepted in the United States of America. Also in our opinion, the related
financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects the information set forth therein.
KPMG LLP
Houston, Texas
February 3, 2003
-28-
GREY WOLF, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
December 31,
------------------------------
2002 2001
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents $ 113,899 $ 100,667
Restricted cash - insurance deposits 784 884
Accounts receivable, net of allowance
of $2,500 and $1,800, respectively 47,034 67,574
Prepaids and other current assets 3,447 1,942
----------- -----------
Total current assets 165,164 171,067
----------- -----------
Property and equipment:
Land, buildings and improvements 5,424 5,137
Drilling equipment 704,734 703,076
Furniture and fixtures 3,185 2,978
----------- -----------
Total property and equipment 713,343 711,191
Less: accumulated depreciation (292,552) (262,531)
----------- -----------
Net property and equipment 420,791 448,660
Other noncurrent assets 4,668 5,744
----------- -----------
$ 590,623 $ 625,471
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ - $ 543
Accounts payable - trade 19,460 21,365
Accrued workers' compensation 4,947 4,595
Payroll and related employee costs 6,685 7,654
Accrued interest payable 11,160 11,228
Other accrued liabilities 8,559 12,519
----------- -----------
Total current liabilities 50,811 57,904
----------- -----------
Senior notes 249,613 249,526
Long-term debt, net of current maturities - 1,169
Other long-term liabilities 4,789 4,868
Deferred income taxes 60,152 66,707
Commitments and contingent liabilities - -
Shareholders' equity:
Series B Junior Participating Preferred stock,
$1 par value; 250,000 shares authorized, none outstanding - -
Common stock, $.10 par value; 300,000,000 shares
authorized; 181,037,811 and 180,726,061 issued and
outstanding, respectively 18,104 18,073
Additional paid-in capital 329,712 328,306
Accumulated deficit (122,558) (101,082)
----------- -----------
Total shareholders' equity 225,258 245,297
----------- -----------
$ 590,623 $ 625,471
=========== ===========
See accompanying notes to consolidated financial statements
-29-
GREY WOLF, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands, except per share data)
Years Ended December 31,
-------------------------------------------------
2002 2001 2000
------------ ------------ --------------
Revenues:
Contract drilling $ 250,260 $ 433,739 $ 276,758
Costs and expenses:
Drilling operations 196,570 249,328 220,713
Depreciation 46,601 41,425 36,768
Provision for asset impairment 3,540 - -
General and administrative 11,300 9,932 8,131
------------ ------------ --------------
Total costs and expenses 258,011 300,685 265,612
------------ ------------ --------------
Operating income (loss) (7,751) 133,054 11,146
Other income (expense):
Interest expense (23,928) (24,091) (23,936)
Interest income 1,732 2,441 3,090
Gain on sale of assets 126 348 69
Other, net 128 (446) (30)
------------ ------------ --------------
Other income (expense), net (21,942) (21,748) (20,807)
------------ ------------ --------------
Income (loss) before income taxes (29,693) 111,306 (9,661)
Income tax expense (benefit)
Current (1,871) 2,977 -
Deferred (6,346) 39,876 (1,138)
------------ ------------ --------------
Total income tax expense (benefit) (8,217) 42,853 (1,138)
------------ ------------ --------------
Net income (loss) $ (21,476) $ 68,453 $ (8,523)
============ ============ ==============
Basic and diluted net income (loss) per common share $ (.12) $ .38 $ (.05)
============ ============ ==============
Basic weighted average common shares outstanding 180,936 180,502 175,866
============ ============ ==============
Diluted weighted average common shares outstanding 180,936 182,447 175,866
============ ============ ==============
See accompanying notes to consolidated financial statements
-30-
GREY WOLF, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(Amounts in thousands)
Series B
Junior
Participating
Preferred Common Cumulative
Stock Stock Additional Comprehensive
$1 par Common $.10 par Paid-in Income
Value Shares Value Capital Deficit Adjustments Total
-------------- --------- ---------- ------------ --------- ------------- -----
Balance, December 31, 1999 - 165,167 $ 16,516 $ 270,527 $ (161,012) $ (454) $ 125,577
Issuance of common stock - 13,000 1,300 50,334 - - 51,634
Exercise of stock options - 1,714 172 3,047 - - 3,219
Tax benefit of stock
option exercises - - - 1,509 - - 1,509
Comprehensive net loss - - - - (8,523) - (8,523)
------- -------- --------- ---------- ---------- --------- ----------
Balance, December 31, 2000 - 179,881 17,988 325,417 (169,535) (454) 173,416
Exercise of stock options - 845 85 1,597 - - 1,682
Tax benefit of stock
option exercises - - - 1,292 - - 1,292
Cumulative foreign
translation losses - - - - - 454 454
Net income - - - - 68,453 - 68,453
------- -------- --------- ---------- ---------- --------- ----------
Comprehensive net income - - - - 68,453 454 68,907
------- -------- --------- ---------- ---------- --------- ----------
Balance, December 31, 2001 - 180,726 18,073 328,306 (101,082) - 245,297
Exercise of stock options - 312 31 655 - - 686
Non-cash compensation
expense - - - 542 - - 542
Tax benefit of stock
option exercises - - - 209 - - 209
Comprehensive net loss - - - - (21,476) - (21,476)
------- -------- --------- ---------- ---------- --------- ----------
Balance, December 31, 2002 - 181,038 $ 18,104 $ 329,712 $ (122,558) $ - $ 225,258
======= ======== ========= ========== ========== ========= ==========
See accompanying notes to consolidated financial statements
-31-
GREY WOLF, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Years Ended December 31,
-----------------------------------------------
2002 2001 2000
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (21,476) $ 68,453 $ (8,523)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation 46,601 41,425 36,768
Provision for asset impairment 3,540 - -
Non-cash compensation expense 542 - -
Provision for doubtful accounts 700 695 92
Gain on sale of assets (126) (348) (69)
Foreign exchange loss (128) 446 30
Deferred income taxes (6,555) 38,584 (2,647)
Tax benefit of stock options exercises 209 1,292 1,509
(Increase) decrease in restricted cash 100 (25) (97)
(Increase) decrease in accounts receivable 19,840 (6,540) (24,819)
(Increase) decrease in other current assets (1,691) 1,248 (816)
Increase (decrease) in accounts payable trade (1,590) (4,586) 3,714
Increase (decrease) in accrued workers' compensation 352 (210) 1,733
Increase (decrease) in other current liabilities (4,997) 3,888 8,340
Increase (decrease) in other 996 3,904 1,095
------------ ------------ ------------
Cash provided by operating activities 36,317 148,226 16,310
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment additions (22,335) (102,950) (38,612)
Proceeds from sales of equipment 388 1,827 76
------------ ------------ ------------
Cash used in investing activities (21,947) (101,123) (38,536)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt (1,824) (911) (1,060)
Financing costs - (280) -
Issuance of common stock - - 51,634
Proceeds from exercise of stock options 686 1,682 3,219
------------ ------------ ------------
Cash provided by (used in) financing activities (1,138) 491 53,793
------------ ------------ ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 13,232 47,594 31,567
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 100,667 53,073 21,506
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 113,899 $ 100,667 $ 53,073
============ ============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURE
CASH PAID FOR INTEREST: $ 22,817 $ 22,750 $ 22,667
============ ============ ============
CASH PAID FOR (REFUND OF) TAXES: $ (1,822) $ 3,019 $ -
============ ============ ============
See accompanying notes to consolidated financial statements
-32-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations. Grey Wolf, Inc. is a Texas corporation formed in
1980. Grey Wolf, Inc. is a holding company with no independent assets or
operations but through its subsidiaries is engaged in the business of providing
onshore contract drilling services to the oil and gas industry. Grey Wolf, Inc.,
through its subsidiaries, currently conducts operations in Alabama, Arkansas,
Louisiana, Mississippi, New Mexico, Texas and Wyoming. The consolidated
financial statements include the accounts of Grey Wolf, Inc. and its
majority-owned subsidiaries (the "Company" or "Grey Wolf"). All significant
intercompany accounts and transactions are eliminated in consolidation.
Property and Equipment. Property and equipment is stated at cost.
Depreciation is calculated using the straight-line method over the estimated
useful lives of the assets, between three and fifteen years.
Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed
Of. The Company reviews its long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Impairment of assets to be held and used is determined by a
comparison of the carrying amount of an asset to undiscounted future net cash
flows expected to be generated by an asset. If such assets are considered to be
impaired, the impairment to be recognized is measured by an amount by which the
carrying amount of the assets exceeds the fair value of the assets. Assets to be
disposed of are reported at the lower of the carrying amount or fair value less
costs to sell. During the fourth quarter of 2002, we recorded a pretax non-cash
asset impairment charge of $3.5 million (See Note 12).
Revenue Recognition. Revenue from daywork and footage contracts is
recognized when earned as services are performed under the provisions of the
contract. Revenue from turnkey drilling contracts is recognized as earned using
the percentage-of-completion method based upon costs incurred to date and
estimated total contract costs. Provision is made currently for anticipated
losses, if any, on uncompleted contracts.
Earnings per Share. Basic earnings per share is based on weighted
average shares outstanding without any dilutive effects considered. Diluted
earnings per share reflects dilution from all contingently issuable shares,
including options. The following is a reconciliation of basic and diluted
weighted average shares outstanding (in thousands):
2002 2001 2000
------------ ------------ ------------
Weighted average common shares
outstanding - basic 180,936 180,502 175,866
Effect of dilutive securities:
Options - Treasury Stock Method - 1,945 -
------------ ------------ ------------
Weighted average common shares
outstanding - diluted 180,936 182,447 175,866
============ ============ ============
The Company incurred net losses for the years ended December 31, 2002
and 2000 and has, therefore, excluded certain securities from the computation of
diluted earnings per share as the effect would be anti-dilutive. Securities
excluded from the computation of diluted earnings per share for the years ended
December 31, 2002 and 2000 were options to purchase 8.7 million shares and 7.3
million shares, respectively. Options to purchase 4.1 million shares for the
three months ended December 31, 2001 and September 30, 2001 and 998,500 shares
for the three months ended June 30, 2001 and March 31, 2001 were not included in
the computation of diluted EPS because the options' exercise price was greater
than the average market price of the common shares.
Income Taxes. The Company records deferred tax liabilities utilizing an
asset and liability approach. This method gives consideration to the future tax
consequences associated with differences between the financial accounting and
tax basis of assets and liabilities. The effect on deferred tax assets and
liabilities of a change in tax
-33-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
rates is recognized in income in the period that includes the enactment date.
The Company and its domestic subsidiaries file a consolidated federal income tax
return.
Stock-Based Compensation. The Company applies Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees", and related
interpretations in accounting for its stock option plans, which are more fully
described in Note 5. Accordingly, no compensation cost has been recognized for
stock option grants as all options granted had an exercise price equal to the
market value of the underlying common stock on the date of grant. Had
compensation cost for the stock option grants been determined on the fair value
at the grant dates consistent with the method of SFAS No. 123, "Accounting for
Stock-Based Compensation", the Company's net income (loss) and income (loss) per
share would have been adjusted to the pro forma amounts indicated below (amounts
in thousands, except per share amounts):
2002 2001 2000
----------- ----------- -----------
Net income (loss), as reported $ (21,476) $ 68,453 $ (8,523)
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards, net of related tax effects (1,880) (1,116) (909)
----------- ----------- -----------
Pro forma net income (loss) $ (23,356) $ 67,337 $ (9,432)
=========== =========== ===========
Income (loss) per share - basic and diluted
As reported $ (.12) $ .38 $ (.05)
Pro forma $ (.13) $ .37 $ (.05)
For purposes of determining compensation costs using the provisions of
SFAS No. 123, the fair value of option grants was determined using the
Black-Scholes option-valuation model. The weighted-average fair value per share
of stock options granted was $1.80 in 2002 and 2000 and $3.90 in 2001. The key
input variables used in valuing the options granted in 2002, 2001 and 2000 were:
risk-free interest rate based on five-year Treasury strips of 2.62% in 2002,
4.60% in 2001 and 4.80% in 2000; dividend yield of zero in each year; stock
price volatility of 75% for both 2002 and 2001, and 67% in 2000; and expected
option lives of five years for each year presented.
Fair Value of Financial Instruments. The carrying amount of the
Company's cash and short-term investments approximates fair value because of the
short maturity of those instruments. The carrying amount of the Company's credit
facility approximates fair value as the interest is indexed to the prime rate or
LIBOR. The fair value of the Senior Notes at December 31, 2002 and 2001 was
$252.5 million and $245.0 million, respectively, compared to the carrying value
of $250.0 million. Fair value was estimated based on quoted market prices.
Cash Flow Information. Cash flow statements are prepared using the
indirect method. The Company considers all unrestricted highly liquid
investments with a maturity of three months or less at the time of purchase to
be cash equivalents.
Restricted Cash. Restricted cash consists of investments in interest
bearing certificates of deposit totaling $784,000 at December 31, 2002 and
$884,000 at December 31, 2001, as collateral for a letter of credit securing
insurance deposits. The carrying value of the investments approximates the
current market value.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
requires the use of certain estimates and assumptions relating to the reporting
of assets and liabilities and the disclosure of contingent assets and
liabilities. Actual results could differ from those estimates.
Concentrations of Credit Risk. Substantially all of the Company's
contract drilling activities are conducted with major and independent oil and
gas companies in the United States. Historically, the Company has not required
collateral or other security for the related receivables from such customers.
However, the Company has required certain customers to deposit funds in escrow
prior to the commencement of drilling. Actions typically taken by the Company in
the event of nonpayment include filing a lien on the customer's producing
properties and filing suit against the customer.
-34-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Comprehensive Income. Comprehensive income includes all changes in a
company's equity during the period that result from transactions and other
economic events, other than transactions with its shareholders.
Recent Accounting Pronouncements. In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 142, "Goodwill and Other
Intangible Assets," which changes how goodwill and other intangible assets are
accounted for subsequent to their initial recognition. Under this standard,
goodwill and other intangible assets having identifiable useful lives are no
longer amortized, but are subjected to periodic assessments of impairment. SFAS
No. 142 is effective for fiscal years beginning after December 15, 2001 and
because the Company has no goodwill it had no impact on the Company's financial
position or results of operations for the year ended December 31, 2002.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which addressed financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement applies to all entities that
have legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development or normal use of the
asset. SFAS 143 is effective for fiscal years beginning after June 15, 2002. The
Company does not expect the adoption of SFAS 143 to have a significant impact on
its financial condition or results of operations.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which addresses financial
accounting and reporting for the impairment or disposal of long-lived assets.
While SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of," it retains many
of the fundamental provisions of that statement. SFAS No. 144 also supersedes
the accounting and reporting provisions of APB Opinion No. 30, "Reporting the
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," for the disposal of a segment of a business. SFAS No. 144 is
effective for fiscal years beginning after December 15, 2001 and interim periods
within those fiscal years. The Company adopted SFAS No. 144 for our fiscal year
beginning January 1, 2002 (see Note 12).
In April, 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment to FASB Statement 13, and Technical
Corrections". SFAS No. 145 is effective for fiscal years beginning after May 15,
2002. Under the provisions of this statement, gains and losses from
extinguishment of debt generally will no longer be classified as extraordinary
items. In addition, this statement eliminates an inconsistency between the
required accounting for sale-leaseback transactions and the required accounting
for certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. This statement also makes various technical
corrections, clarifies meanings, or describes their applicability under changed
conditions. The Company does not expect the adoption of SFAS No. 145 to have a
material effect on its financial position or results of operations.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Cost
Associated with Exit or Disposal Activities". SFAS No. 146 is effective for exit
or disposal activities that are initiated after December 31, 2002. The Statement
addresses financial accounting and reporting for costs associated with exit or
disposal activities and requires companies to recognize costs associated with
exit or disposal activities when they are incurred rather than at the date of a
commitment to an exit or disposal plan. SFAS No. 146 nullifies Emerging Issues
Task Force Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." The Company does not expect the adoption of
SFAS No. 146 to have a material effect on its financial position or results of
operations.
Reclassification. In accordance with Emerging Issues Task Force Issue
No. 01-14 "Income Statement Characterization of Reimbursements Received for
Out-of-Pocket Expenses Incurred," the Company has revised the presentation of
reimbursements received for certain expenses in the periods presented. These
reimbursements are now included in contract drilling revenues on the income
statement versus previously being recorded net of the incurred expenses in
drilling operations expenses. This reclassification had no effect on net income
or cash flows. In addition, certain balance sheet amounts in 2001 and 2000 have
been reclassified to conform to the presentation in 2002.
-35-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) SIGNIFICANT PROPERTY TRANSACTIONS
During the second quarter of 2001, the Company moved its five Venezuela
rigs to the United States and in the third quarter of 2001 sold three of the
five rigs for $1.3 million. This sale resulted in a gain of approximately
$602,000. As a result of moving its Venezuela rigs to the United States, the
Company realized $454,000 of previously unrealized foreign currency translation
losses during the second quarter of 2001.
(3) INCOME TAXES
The Company and its U.S. subsidiaries file consolidated federal income
tax returns. The components of the provision for income taxes consisted of the
following (amounts in thousands):
For the Years Ended December 31,
----------------------------------------------------
2002 2001 2000
------------- ------------ -------------
Current
Federal $ (1,871) $ 1,870 $ -
State - 1,107 -
------------- ------------ -------------
$ (1,871) $ 2,977 $ -
============= ============ =============
Deferred
Federal $ (7,080) $ 38,557 $ (1,366)
State 734 1,319 228
------------- ------------ -------------
$ (6,346) $ 39,876 $ (1,138)
============= ============ =============
Deferred income taxes are determined based upon the difference between
the carrying amount of assets and liabilities for financial reporting purposes
and amounts used for income tax purposes, and net operating loss and tax credit
carryforwards. The tax affects of the Company's temporary differences and
carryforwards are as follows (amounts in thousands):
December 31,
--------------------------------
2002 2001
------------ ------------
Deferred tax assets
Net operating loss carryforwards $ 27,008 $ 10,549
Tax credit carryforwards 14 1,885
Workers compensation accruals 3,622 3,345
Other 1,229 187
------------ ------------
31,873 15,966
Deferred tax liabilities
Depreciation 92,025 82,673
------------ ------------
Net deferred tax liability $ 60,152 $ 66,707
============ ============
At December 31, 2002 and 2001, the Company had U.S. net operating loss
("NOL") carryforwards of $98.2 million and $51.1 million, respectively, which
expire at various times from 2010 through 2022. The NOL carryforwards are
subject to annual limitations as a result of the changes in ownership of the
Company in 1989, 1994 and 1996. Management believes it is more likely than not
that future earnings will be sufficient to permit the Company to realize its
deferred tax assets.
For financial reporting purposes, approximately $21.0 million of the
NOL carryforwards was utilized to offset the book versus tax basis differential
in the recording of the assets acquired in transactions prior to 1999.
-36-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following summarizes the differences between the federal statutory
tax rate of 35% (amounts in thousands):
For the Years Ended December 31,
----------------------------------------------------
2002 2001 2000
------------- ------------ ------------
Income tax expense (benefit) at statutory rate $ (10,393) $ 38,957 $ (3,381)
Increase (decrease) in taxes resulting from:
Expiration of NOL carryforwards - - 830
Permanent differences, primarily due to
basis differences in acquired assets 1,707 1,320 1,226
Foreign (income) loss (12) 95 250
State taxes (net) 477 1,576 148
Other 4 905 (211)
------------- ------------- ------------
Income tax expense (benefit) $ (8,217) $ 42,853 $ (1,138)
============= ============ ============
(4) LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
December 31,
--------------------------
2002 2001
----------- -----------
$250,000 senior notes due July 2007,
general unsecured senior obligations guaranteed by the
Company's domestic subsidiaries, bearing interest
at 8 7/8% per annum payable semiannually $ 249,613 $ 249,526
Capital leases, secured by transportation equipment,
bearing interest at 10% - 1,712
----------- -----------
249,613 251,238
Less current maturities - 543
----------- -----------
Long-term debt $ 249,613 $ 250,695
=========== ===========
In June 1997 and May 1998, the Company concluded public offerings of
$175.0 million and $75.0 million, respectively, in principal amount of the
senior notes. The senior notes ("Notes") bear interest at 8 7/8% per annum and
mature July 1, 2007. The Notes are general unsecured senior obligations of the
Company and are fully and unconditionally guaranteed, on a joint and several
basis, by all domestic wholly-owned subsidiaries of the Company. Non-guarantor
subsidiaries are immaterial. All fees and expenses incurred at the time of
issuance are being amortized and discounts are being accreted over the life of
the Notes.
The Company has the option to redeem the Notes in whole or in part
during the twelve months beginning July 1, 2002 at 104.4375%, beginning July 1,
2003 at 102.9580%, beginning July 1, 2004 at 101.4792% and beginning July 1,
2005 and thereafter at 100.0000% together with any interest accrued and unpaid
to the redemption date. Upon a change of control as defined in the indentures,
each holder of the Notes will have the right to require the Company to
repurchase all or any part of such holder's Notes at a purchase price equal to
101% of the aggregate principal amount thereof, plus accrued and unpaid interest
to the date of purchase. We may also, from time-to-time, seek to retire the
Notes through open market purchases and privately-negotiated transactions.
The Company has a $75.0 million credit facility with the CIT
Group/Business Credit, Inc. (the "CIT Facility") which expires during January
2006. The Company previously incurred $280,000 in financing costs when it
amended its credit facility in 2001, which is being amortized over the remaining
life of the CIT Facility. The CIT
-37-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Facility provides the Company with the ability to borrow up to the lesser of
$75.0 million or 50% of the orderly liquidation value (as defined in the
agreement) of certain drilling rig equipment located in the 48 contiguous states
of the United States of America. At December 31, 2002, the orderly liquidation
value was greater than $75.0 million. The CIT Facility is a revolving facility
with automatic renewals after expiration unless terminated by the lender on any
subsequent anniversary date and then only upon 60 days prior notice. Periodic
interest payments are due at a floating rate based upon the Company's debt
service coverage ratio within a range of either LIBOR plus 1.75% to 3.50% or
prime plus 0.25% to 1.5%. The Company recently amended the CIT Facility to
increase the availability of letters of credit from $10.0 million to $20.0
million. This was done to enable us to issue additional letters of credit for
the benefit of various insurance companies as collateral for retrospective
premiums and retained losses which may become payable under the terms of the
underlying insurance contracts. See Item 1 - "Business Insurance." The Company
is required to pay a commitment fee of 0.375% per annum on the unused portion of
the CIT Facility and letters of credit accrue a fee of 1.25% per annum.
Outstanding letters of credit reduce the amount available for borrowing under
the CIT facility.
The CIT Facility contains certain affirmative and negative covenants
and the Company is in compliance with these covenants. Substantially all of the
Company's assets, including its drilling equipment, are pledged as collateral
under the CIT Facility and it is also secured by the Company's guarantees and
certain of the Company's wholly-owned subsidiaries guarantees. The Company,
however, retains the option, subject to a minimum appraisal value, under the CIT
Facility to extract $75.0 million of the equipment out of the collateral pool in
connection with the sale or exchange of such collateral or relocation of
equipment outside of the contiguous 48 states of the United States of America.
The Company currently has no outstanding balance under the CIT facility and had
$7.4 million of unddrawn letters of credit outstanding at December 31, 2002.
The Company had non-cash activities for the years ended December 31,
2002, 2001, and 2000 related to vehicle additions under capital leases. The
non-cash amounts excluded from cash used in investing activities and cash
provided by financing activities was $199,000, $1.8 million and $663,000 for the
years ended December 31, 2002, 2001, and 2000, respectively.
(5) CAPITAL STOCK AND STOCK OPTION PLANS
On April 4, 2000, the Company completed an offering of 13,000,000
shares of its common stock which yielded net proceeds to the Company of $51.6
million. The shares were purchased by the underwriter for $4.00 per share and
the underwriter advised the Company that the shares were resold to the public at
a price of $4.125 per share. The proceeds from the issuance of the shares of
common stock, net of offering costs were used to purchase top drive units, for
capital expenditures to return some of the Company's rigs to marketed status and
for general corporate purposes, including working capital.
On September 21, 1998, the Company adopted a Shareholder Rights Plan
(the "Plan") in which rights to purchase shares of Junior Preferred stock will
be distributed as a dividend at the rate of one Right for each share of common
stock.
Each Right will entitle holders of the Company's common stock to buy
one-one thousandth of a share of Grey Wolf's Series B Junior Participating
Preferred stock at an exercise price of $11. The Rights will be exercisable only
if a person or group acquires beneficial ownership of 15% or more of Grey Wolf's
common stock or announces a tender or exchange offer upon consummation of which
such person or group would beneficially own 15% or more of Grey Wolf's common
stock. Furthermore, if any person becomes the beneficial owner of 15% or more of
Grey Wolf's common stock, each Right not owned by such person or related parties
will enable its holder to purchase, at the Right's then-current exercise price,
shares of common stock of the Company having a value of twice the Right's
exercise price. The Company will generally be entitled to redeem the Rights at
$.001 per Right at any time until the 10th day following public announcement
that a 15% position has been acquired.
The Company's 1982 Stock Option and Long-term Incentive Plan for Key
Employees (the "1982 Plan") was canceled in March 1999; however, prior to that
date, there were 2,500,000 shares of the Company's common stock reserved for
issuance upon the exercise of options. The Company's 1996 Employee Stock Option
Plan (the
-38-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
"1996 Plan") reserves 17,000,000 shares of the Company's common stock for
issuance upon the exercise of options. At December 31, 2002, options under the
1996 Plan to purchase 8,290,065 shares of common stock were available for grant
until July 29, 2006. The exercise price of stock options under the 1982 Plan and
the 1996 Plan approximates the fair market value of the stock at the time the
option is granted. The Company has 2,025,500 shares outstanding for other Stock
Option Agreements between the Company and its' executive officers and directors.
A portion of the outstanding options became exercisable upon issuance and the
remaining become exercisable in varying increments over three to five-year
periods. The options expire on the tenth anniversary of the date of grant.
On November 13, 2001, the Company amended all outstanding stock option
agreements issued under the 1996 Employee Stock Option Plan and certain
outstanding stock option agreements issued to executive officers and directors.
Based upon the occurrence of certain events ("triggering events"), the
amendments provide for accelerated vesting of options and the extension of the
period in which a current employee option holder has to exercise his options.
The provisions of the amendments provide for accelerated vesting of options
after termination of employment of a current option holder within one year of a
change of control of the Company (as defined in the amendment). Triggering
events that cause an extension of the exercise period, but not longer than the
remaining original exercise period, include termination of employment as a
result of any reason not defined as termination for cause, voluntary
resignation, or retirement in the amendment.
In accordance with Accounting Principles Board Opinion 25 ("APB 25"),
the amendments to the stock option agreements create a new measurement date of
November 13, 2001. APB 25 requires the Company to determine the intrinsic value
of the options at the measurement date and recognize non-cash compensation
expense upon the occurrence of a triggering event. The amount of compensation
expense that would be recognized upon the occurrence of a triggering event is
the difference between the fair market value of the Company's stock on the
measurement date and the original exercise prices of the options.
In March 2002, a triggering event occurred when an officer's employment
terminated. As a result, the Company recognized approximately $515,000 of
non-cash compensation expense along with approximately $330,000 of severance
cost. In addition, the Company recognized approximately $27,000 of non-cash
compensation expense during the remainder of 2002. These amounts have been
included in general and administrative expenses on the consolidated statement of
operations.
Stock option activity for all stock options issued as of December 31,
2002, 2001 and 2000 was as follows (number of shares in thousands):
2002 2001 2000
--------------------- --------------------- ---------------------
Weighted Weighted Weighted
Average Average Average
No. of Exercise No. of Exercise No. of Exercise
Shares Price Shares Price Shares Price
------ -------- ------ --------- ------ ---------
Outstanding - beginning of
the year 7,512 $ 2.85 7,318 $ 2.25 7,169 $ 1.91
Granted 2,302 2.88 1,149 6.08 2,031 3.15
Exercised (312) 2.20 (846) 1.99 (1,714) 1.88
Cancelled (781) 3.16 (109) 3.16 (168) 2.44
------ -------- ------ --------- ------ ---------
Outstanding - end of year 8,721 $ 2.85 7,512 $ 2.85 7,318 $ 2.25
====== ======== ====== ========= ====== =========
The Company had stock options exercisable at December 31, 2002 of 4.0
million with a range of exercise prices from $.69 to $6.37. At December 31, 2001
and 2000, there were 3.2 million stock options exercisable, with a range of
exercise prices from $.69 to $4.50, and 2.8 million stock options exercisable
from $.69 to $4.38, respectively.
-39-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about stock options
outstanding at December 31, 2002:
Weighted
Average Weighted
Remaining Average
Number Contractual Exercise
Range of Exercise Prices Outstanding Life(1) Price
- ------------------------ ----------- ----------- ---------
$.69 to $1.63 2,885 4.85 $ 1.26
$1.75 to $4.38 4,806 7.60 $ 3.10
$4.44 to $6.37 1,030 8.07 $ 6.15
----- ---- ---------
8,721 6.75 $ 2.85
===== ==== =========
- ---------------------------
(1) Represents weighted average remaining contractual life in years.
(6) SEGMENT INFORMATION AND ACCUMULATED COMPREHENSIVE INCOME
The Company manages its business as one reportable segment. Although
the Company provides contract drilling services in several markets domestically,
these operations have been aggregated into one reportable segment based on the
similarity of economic characteristics among all markets including the nature of
the services provided and the type of customers of such services.
Prior to the third quarter of 2001, the Company managed its business as
two reportable segments; domestic operations and foreign operations. Late in the
first quarter of 1999, the Company suspended all operations in Venezuela but
retained the option to begin operations at any time. However, during the second
quarter of 2001, the Company moved its five Venezuela rigs to the United States
and in the third quarter of 2001 sold three of the five rigs for $1.3 million.
This sale resulted in a gain of approximately $602,000. As a result of moving
the Venezuela rigs to the United States, the Company realized $454,000 of
previously unrealized foreign currency translation losses during the second
quarter of 2001.
(7) RELATED-PARTY TRANSACTIONS
The Company performed contract drilling services for affiliates of one
of the Company's directors. Total revenues recognized from these affiliates
during 2002, 2001 and 2000 were $3.4 million, $6.0 million and $2.2 million,
respectively. During 2001, the Company also purchased equipment for $119,000
from an affiliate of the Chairman, President and Chief Executive Officer of the
Company.
(8) LEASE COMMITMENTS
Aggregate minimum lease payments required under noncancellable
operating leases having terms greater than one year are as follows as of
December 31, 2002: 2003 - $627,000; 2004 - $514,000; 2005 - $129,000; and $0
thereafter.
Lease expense under operating leases for 2002, 2001 and 2000 were
approximately $680,000, $618,000 and $589,000, respectively.
Capital leases for the Company's field trucks and automobiles are
included in long-term debt in 2001 and 2000. There were no outstanding capital
lease obligations at December 31, 2002.
-40-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(9) CONTINGENCIES
The Company is involved in litigation incidental to the conduct of its
business, none of which management believes is, individually or in the
aggregate, material to the Company's consolidated financial condition or results
of operations.
(10) EMPLOYEE BENEFIT PLAN
The Company has a defined contribution employee benefit plan covering
substantially all of its employees. The Company matches 100% of the first 3% of
individual employee contributions and 50% of the next 3% of individual employee
contributions. Employer matching contributions under the plan totaled $1.3
million, $1.3 million, and $1.0 million for the years ended December 31, 2002,
2001 and 2000, respectively. Participants vest in employer matching
contributions over a five year period based upon service with the Company.
(11) CONCENTRATIONS
Substantially all of the Company's contract drilling activities are
conducted with independent and major oil and gas companies in the United States.
Historically, the Company has not required collateral or other security to
support the related receivables from such customers. However, the Company has
required certain customers to deposit funds in escrow prior to the commencement
of drilling. Actions typically taken by the Company in the event of nonpayment
include filing a lien on the customer's producing property and filing suit
against the customer.
For the three months ended December 31, 2002, the Company had one
customer which represented approximately 11% of total revenue. For the year
ended December 31, 2002, the Company also had one customer which represented
approximately 11% of total revenue. There were no customers with revenue greater
than 10% for the years ended December 31, 2001 and 2000.
(12) PROVISION FOR ASSET IMPAIRMENT
During the fourth quarter of 2002, the Company recorded a pre-tax
non-cash asset impairment charge of $3.5 million in accordance with SFAS 144.
After review of rigs held for future refurbishment, the Company no longer
intends to return five of those rigs to service, but will instead use their
component parts as spare equipment inventory. This decision was made based upon
the physical condition of the five rigs and the estimated cost of refurbishment.
As such, an asset impairment charge was recorded to write the rigs down to their
fair market value and the number of drilling rigs in our fleet was revised from
121 to 116, including one non-owned rig that we operate for a third party. The
fair market value was based on an appraisal obtained from a third party
appraiser. The after tax effect of this impairment was $.01 per diluted share.
-41-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
`
(13) QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for years ended December 31, 2002,
2001 and 2000 are set forth below (amounts in thousands, except per share
amounts).
Quarter Ended
---------------------------------------------------------
March June September December
2002 2002 2002 2002
----------- ----------- ----------- -----------
Revenues $ 64,912 $ 62,854 $ 61,118 $ 61,376
Gross profit (1) 17,264 14,136 11,317 10,973
Operating income (loss) 2,655 (170) (3,014) (7,222)
Loss before income taxes (2,756) (5,544) (8,626) (12,767)
Net loss (2,177) (4,048) (6,131) (9,120)
Net loss per common share
- basic and diluted (.01) (.02) (.03) (.05)
Quarter Ended
---------------------------------------------------------
March June September December
2001 2001 2001 2001
----------- ----------- ----------- -----------
Revenues $ 101,136 $ 114,967 $ 128,030 $ 89,606
Gross profit (1) 39,624 53,008 58,481 33,993
Operating income 27,534 40,381 45,559 19,580
Income before income taxes 22,270 34,553 40,268 14,215
Net income 13,362 20,732 25,378 8,981
Net income per common share
- basic and diluted .07 .11 .14 .05
Quarter Ended
---------------------------------------------------------
March June September December
2000 2000 2000 2000
----------- ----------- ----------- -----------
Revenues $ 59,862 $ 56,156 $ 75,462 $ 85,278
Gross profit (1) 8,674 8,589 13,693 25,181
Operating income (loss) (2,069) (2,376) 2,369 13,222
Income (loss) before income taxes (7,788) (7,435) (2,655) 8,217
Net income (loss) (5,692) (5,472) (2,331) 4,972
Net income (loss) per common share
- basic and diluted (.03) (.03) (.01) .03
- ---------------------------
(1) Gross profit is computed as consolidated revenues less operating
expenses (which excludes expenses for depreciation and general and
administrative.
-42-
SCHEDULE II
GREY WOLF, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
Balance at Additions Collections Balance at
Beginning Charged to and End
of Period Allowance Write-Offs of Period
---------- ---------- ----------- ----------
Year Ended December 31, 2000
Allowance for doubtful accounts receivable $ 1,708 $ 92 $ - $ 1,800
========= ======== ========= =========
Year Ended December 31, 2001
Allowance for doubtful accounts receivable $ 1,800 $ 695 $ (695) $ 1,800
========= ======== ========= =========
Year Ended December 31, 2002
Allowance for doubtful accounts receivable $ 1,800 $ 700 $ - $ 2,500
========= ======== ========= =========
-43-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item as to our directors and executive
officers is hereby incorporated by reference to such information appearing under
the captions "Directors" and "Executive Officers" in our definitive proxy
statement for our 2003 Annual Meeting of Shareholders and is to be filed with
the Securities and Exchange Commission (the "Commission") pursuant to the
Securities Exchange Act of 1934 within 120 days of the end of our fiscal year on
December 31, 2002.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item as to the compensation of our
management is hereby incorporated by reference to such information appearing
under the caption "Executive Compensation" in our definitive proxy statement for
our 2003 Annual Meeting of Shareholders and is to be filed with the Commission
pursuant to the Securities Exchange Act of 1934 within 120 days of the end of
our fiscal year on December 31, 2002.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED SHAREHOLDERS' MATTERS
The information required by this item as to the ownership by our
management and others of our securities is hereby incorporated by reference to
such information appearing under the caption "Nominees for Director", "Ownership
by Management and Certain Shareholders" and "Executive Compensation Plans" in
our definitive proxy statement for our 2003 Annual Meeting of Shareholders and
is to be filed with the Commission pursuant to the Securities Exchange Act of
1934 within 120 days of the end of our fiscal year on December 31, 2002.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item as to certain business
relationships and transactions with our management and other parties related to
us is hereby incorporated by reference to such information appearing under the
caption "Certain Transactions" in our definitive proxy statement for our 2003
Annual Meeting of Shareholders and is to be filed with the Commission pursuant
to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal
year on December 31, 2002.
ITEM 14. CONTROLS AND PROCEDURES
Within 90 days prior to the filing of this report, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that our
disclosure controls and procedures are effective. Disclosure controls and
procedures are controls and procedures that are designed to ensure that
information required to be disclosed in our reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules and forms.
There have been no significant changes in our internal controls or in
other factors that could significantly affect internal controls subsequent to
the date we carried out this evaluation.
-44-
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. AND 2. FINANCIAL STATEMENTS AND SCHEDULE
The consolidated financial statements and supplemental schedule of Grey
Wolf, Inc. and Subsidiaries are included in Part II, Item 8 and are
listed in the Index to Consolidated Financial Statements and Financial
Statement Schedule therein.
3. EXHIBITS
Exhibit No. Documents
- ---------- ---------
3.1 -- Articles of Incorporation of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 3.1 to
Form 10-Q dated May 12, 1999).
3.2 -- By-Laws of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 99.1 to Form 8-K dated
March 23, 1999).
4.1 -- Form of Trust Indenture, dated June 27, 1997, relating to the senior notes due 2007 of the Company and Texas
Commerce Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.2 to the
Company's Registration Statement on Form S-3 No. 333-26519 filed June 24, 1997).
4.2 -- Supplemental Indenture (to the Trust Indenture dated June 27, 1997), dated as of March 31, 1998, among the
Company, the New Guarantor, the Existing Guarantors, and Chase Bank of Texas National Association, as
Trustee. (incorporated herein by reference to Exhibit 4.5 to Form 8-K filed May 21, 1998).
4.3 -- Second Supplemental Indenture (to the Trust Indenture dated June 27, 1997), dated as of May 8, 1998, by and
among the Company, the Guarantors, and Chase Bank of Texas, National Association, as Trustee (incorporated
herein by reference to Exhibit 4.5 to Form 8-K filed May 21, 1998).
4.4 -- Third Supplemental Indenture (to the Trust Indenture dated June 27, 1997), dated as of January 4, 1999, among
the Company, the New Guarantors, the Existing Guarantors, and Chase Bank of Texas, National Association, as
Trustee (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
4.5 -- Form of Trust Indenture, dated May 8, 1998, relating to the senior notes due 2007 by and among the Company,
the Guarantors, and Chase Bank of Texas, National Association, as Trustee (incorporated herein by reference
to Exhibit 4.3 to Form 8-K filed May 21, 1998).
4.6 -- Supplemental Indenture (to the Trust Indenture dated May 8, 1998), dated as of January 4, 1999, among the
Company, the New Guarantors, the Existing Guarantors and Chase Bank of Texas, National Association, as
Trustee (incorporated herein by reference to Grey Wolf, Inc. Annual Report on From 10-K for the year ended
December 31, 2001).
4.7 -- Rights Agreement dated as of September 21, 1998 by and between the Company and American Stock Transfer and
Trust Company as Rights Agent (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed September
22, 1998).
10.1 -- Indemnification Agreement dated as of March 6, 1997, by and between Grey Wolf Drilling Company and James K.B.
Nelson (incorporated herein by reference to Exhibit 10.5 to Form 8-K dated March 10, 1997).
10.2 -- Form of Non-Qualified Stock Option Agreement dated September 3, 1996, by and between the Company and Thomas
P. Richards (incorporated herein by reference to Exhibit 10.2 to Registration Statement No. 333-14783).
10.3 -- Form of Incentive Stock Option Agreement dated September 3, 1996, by and between the Company and Ronnie E.
McBride (incorporated herein by reference to Exhibit 10.14 to Post Effective Amendment No. 1 to Registration
Statement No. 333-14783).
-45-
10.4 -- Form of Non-Qualified Stock Option Agreement dated September 3, 1996, by and between the Company and Ronnie
E. McBride. (incorporated herein by reference to Exhibit 10.15 to Post Effective Amendment No. 1 to
Registration Statement No. 333-14783).
10.5 -- Grey Wolf, Inc. 1996 Employee Stock Option Plan (incorporated herein by reference to Grey Wolf, Inc. 1996
Annual Meeting of Shareholders definitive proxy materials).
10.6 -- Grey Wolf Inc. Amendment to 1996 Employee Stock Option Plan (incorporated herein by reference to Grey Wolf,
Inc. 1999 Annual Meeting of Shareholders definitive proxy materials filed April 9, 1999).
10.7 -- Grey Wolf, Inc. Second Amendment to 1996 Employee Stock Option Plan dated May 14, 2002 (incorporated herein
by reference to Exhibit 4.6 to Grey Wolf, Inc. Registration Statement on Form S-8 No. 333-90888 filed June
21, 2002).
10.8 -- Drillers Inc. 1982 Stock Option and Long-Term Incentive Plan for Key Employees (incorporated by reference to
Drillers Inc. 1982 Annual Meeting definitive proxy solicitation materials.)
10.9 -- Form of Incentive Stock Option Agreement dated March 17, 1997, by and between the Company and Gary D. Lee
(incorporated by reference to DI Industries, inc. Annual Report of Form 10-K for the year ended December 31,
1996.)
10.10 -- Form of Incentive Stock Option Agreement dated February 10, 1998, by and between the Company and David W.
Wehlmann (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 1997.)
10.11 -- Revolving Credit Agreement dated as of January 14, 1999 among Grey Wolf Drilling Company LP (as borrower),
Grey Wolf, Inc. (as guarantor), The CIT Group/Business Credit, Inc. (as agent) and various financial
institutions (as lenders). (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated January 26,
1999.)
10.12 -- First Amendment to Loan Agreement dated as of December 20, 2001, by and among Grey Wolf Drilling Company, LP
(as borrower) and Grey Wolf, Inc. (as guarantor) and the CIT Group/Business Credit, Inc. (as agent) and
various financial institutions (as lenders) (incorporated herein by reference to Grey Wolf, Inc. Annual
Report on Form 10-K for the year ended December 31, 2001).
10.13 -- Non-Qualified Stock Option Agreement dated January 16, 1999, by and between the Company and Edward S. Jacob,
III. (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 1999.)
10.14 -- Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the
Company and Thomas P. Richards (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form
10-K for the year ended December 31, 2001).
10.15 -- Form of Amendment to Non-Qualified Stock Option Agreement dated November 13, 2001, by and among the Company
(f.k.a. DI Industries, Inc.), Thomas P. Richards and Richards Brothers Interests, L.P (incorporated herein by
reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001).
10.16 -- Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the
Company and each of David W. Wehlmann, Edward S. Jacob III, Gary D. Lee, Ronnie E. McBride, Merrie S.
Costley, and Donald J. Guedry, Jr. (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form
10-K for the year ended December 31, 2001).
10.17 -- Grey Wolf, Inc. Executive Severance Plan effective November 15, 2001 (incorporated herein by reference to
Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001).
-46-
10.18 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Thomas P.
Richards (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.19 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and David W.
Wehlmann (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.20 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Edward S.
Jacob III (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.21 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Gary D. Lee
(incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December
31, 2001).
10.22 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Ronnie E.
McBride (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.23 -- Form of Non-Qualified Stock Option Agreement dated as of February 13, 2002, by and between the Company and
each of Frank M. Brown, William T. Donovan, James K.B. Nelson, Robert E. Rose, Steven A. Webster, and William
R. Ziegler (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
*10.24 -- Second Amendment to Loan Agreement dated as of February 7, 2003 by and among Grey Wolf Drilling Company L.P.
(as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit,
Inc. and various financial institutions (as lenders).
*21.1 -- List of Subsidiaries of Grey Wolf, Inc.
*23.1 -- Consent of KPMG LLP
*99.1 -- Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 of Thomas P. Richards, Chairman, President and Chief Executive Officer.
*99.2 -- Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 of David W. Wehlmann, Senior Vice President and Chief Financial Officer.
- ---------
* Filed herewith
(b) Reports on Form 8-K
None
-47-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, this 6th day of March,
2003
Grey Wolf, Inc.
By: /s/ David W. Wehlmann
----------------------------------------
David W. Wehlmann, Senior Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signatures and Capacities Date
- ------------------------- -----------------
By: /s/ Thomas P. Richards March 6, 2003
----------------------------------------------------------------------------
Thomas P. Richards, Chairman, President and Chief Executive Officer
(Principal Executive Officer)
By: /s/ David W. Wehlmann March 6, 2003
----------------------------------------------------------------------------
David W. Wehlmann, Senior Vice President and Chief Financial Officer
By: /s/ Merrie S. Costley March 6, 2003
----------------------------------------------------------------------------
Merrie S. Costley, Vice President and Controller
By: /s/ William R. Ziegler March 6, 2003
----------------------------------------------------------------------------
William R. Ziegler, Director
By: /s/ Frank M. Brown March 6, 2003
----------------------------------------------------------------------------
Frank M. Brown, Director
By: /s/ William T. Donovan March 6, 2003
----------------------------------------------------------------------------
William T. Donovan, Director
By: /s/ James K. B. Nelson March 6, 2003
----------------------------------------------------------------------------
James K. B. Nelson, Director
By: /s/ Robert E. Rose March 6, 2003
----------------------------------------------------------------------------
Robert E. Rose, Director
By: /s/ Steven A. Webster March 6, 2003
----------------------------------------------------------------------------
Steven A. Webster, Director
-48-
CERTIFICATIONS
I, Thomas P. Richards, certify that:
1. I have reviewed this annual report on Form 10-K of Grey Wolf, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves
management or other employees who have a significant role in
the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: March 6, 2003 By: /s/ Thomas P. Richards
----------------------------------------
Thomas P. Richards
Chairman, Chief Executive Office, and President
-49-
CERTIFICATIONS
I, David W. Wehlmann, certify that:
1. I have reviewed this annual report on Form 10-K of Grey Wolf, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves
management or other employees who have a significant role in
the registrant's internal controls; and
7. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: March 6, 2003 By: /s/ David W. Wehlmann
----------------------------------------
David W. Wehlmann Senior Vice President
and Chief Financial Officer
-50-
EXHIBIT INDEX
Exhibit No. Documents
- ---------- ---------
3.1 -- Articles of Incorporation of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 3.1 to
Form 10-Q dated May 12, 1999).
3.2 -- By-Laws of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 99.1 to Form 8-K dated
March 23, 1999).
4.1 -- Form of Trust Indenture, dated June 27, 1997, relating to the senior notes due 2007 of the Company and Texas
Commerce Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.2 to the
Company's Registration Statement on Form S-3 No. 333-26519 filed June 24, 1997).
4.2 -- Supplemental Indenture (to the Trust Indenture dated June 27, 1997), dated as of March 31, 1998, among the
Company, the New Guarantor, the Existing Guarantors, and Chase Bank of Texas National Association, as
Trustee. (incorporated herein by reference to Exhibit 4.5 to Form 8-K filed May 21, 1998).
4.3 -- Second Supplemental Indenture (to the Trust Indenture dated June 27, 1997), dated as of May 8, 1998, by and
among the Company, the Guarantors, and Chase Bank of Texas, National Association, as Trustee (incorporated
herein by reference to Exhibit 4.5 to Form 8-K filed May 21, 1998).
4.4 -- Third Supplemental Indenture (to the Trust Indenture dated June 27, 1997), dated as of January 4, 1999, among
the Company, the New Guarantors, the Existing Guarantors, and Chase Bank of Texas, National Association, as
Trustee (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
4.5 -- Form of Trust Indenture, dated May 8, 1998, relating to the senior notes due 2007 by and among the Company,
the Guarantors, and Chase Bank of Texas, National Association, as Trustee (incorporated herein by reference
to Exhibit 4.3 to Form 8-K filed May 21, 1998).
4.6 -- Supplemental Indenture (to the Trust Indenture dated May 8, 1998), dated as of January 4, 1999, among the
Company, the New Guarantors, the Existing Guarantors and Chase Bank of Texas, National Association, as
Trustee (incorporated herein by reference to Grey Wolf, Inc. Annual Report on From 10-K for the year ended
December 31, 2001).
4.7 -- Rights Agreement dated as of September 21, 1998 by and between the Company and American Stock
Transfer and Trust Company as Rights Agent (incorporated herein by reference to Exhibit 4.1 to
Form 8-K filed September 22, 1998).
10.1 -- Indemnification Agreement dated as of March 6, 1997, by and between Grey Wolf Drilling Company and James K.B.
Nelson (incorporated herein by reference to Exhibit 10.5 to Form 8-K dated March 10, 1997).
10.2 -- Form of Non-Qualified Stock Option Agreement dated September 3, 1996, by and between the Company and Thomas
P. Richards (incorporated herein by reference to Exhibit 10.2 to Registration Statement No. 333-14783).
10.3 -- Form of Incentive Stock Option Agreement dated September 3, 1996, by and between the Company and Ronnie E.
McBride (incorporated herein by reference to Exhibit 10.14 to Post Effective Amendment No. 1 to Registration
Statement No. 333-14783).
10.4 -- Form of Non-Qualified Stock Option Agreement dated September 3, 1996, by and between the Company and Ronnie
E. McBride. (incorporated herein by reference to Exhibit 10.15 to Post Effective Amendment No. 1 to
Registration Statement No. 333-14783).
10.5 -- Grey Wolf, Inc. 1996 Employee Stock Option Plan (incorporated herein by reference to Grey Wolf, Inc. 1996
Annual Meeting of Shareholders definitive proxy materials).
10.6 -- Grey Wolf Inc. Amendment to 1996 Employee Stock Option Plan (incorporated herein by reference to Grey Wolf,
Inc. 1999 Annual Meeting of Shareholders definitive proxy materials filed April 9, 1999).
10.7 -- Grey Wolf, Inc. Second Amendment to 1996 Employee Stock Option Plan dated May 14, 2002 (incorporated herein
by reference to Exhibit 4.6 to Grey Wolf, Inc. Registration Statement on Form S-8 No. 333-90888 filed June
21, 2002).
10.8 -- Drillers Inc. 1982 Stock Option and Long-Term Incentive Plan for Key Employees (incorporated by reference to
Drillers Inc. 1982 Annual Meeting definitive proxy solicitation materials.)
10.9 -- Form of Incentive Stock Option Agreement dated March 17, 1997, by and between the Company and Gary D. Lee
(incorporated by reference to DI Industries, inc. Annual Report of Form 10-K for the year ended December 31,
1996.)
10.10 -- Form of Incentive Stock Option Agreement dated February 10, 1998, by and between the Company and David W.
Wehlmann (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 1997.)
10.11 -- Revolving Credit Agreement dated as of January 14, 1999 among Grey Wolf Drilling Company LP (as borrower),
Grey Wolf, Inc. (as guarantor), The CIT Group/Business Credit, Inc. (as agent) and various financial
institutions (as lenders). (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated January 26,
1999.)
10.12 -- First Amendment to Loan Agreement dated as of December 20, 2001, by and among Grey Wolf Drilling Company, LP
(as borrower) and Grey Wolf, Inc. (as guarantor) and the CIT Group/Business Credit, Inc. (as agent) and
various financial institutions (as lenders) (incorporated herein by reference to Grey Wolf, Inc. Annual
Report on Form 10-K for the year ended December 31, 2001).
10.13 -- Non-Qualified Stock Option Agreement dated January 16, 1999, by and between the Company and Edward S. Jacob,
III. (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 1999.)
10.14 -- Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the
Company and Thomas P. Richards (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form
10-K for the year ended December 31, 2001).
10.15 -- Form of Amendment to Non-Qualified Stock Option Agreement dated November 13, 2001, by and among the Company
(f.k.a. DI Industries, Inc.), Thomas P. Richards and Richards Brothers Interests, L.P (incorporated herein by
reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001).
10.16 -- Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the
Company and each of David W. Wehlmann, Edward S. Jacob III, Gary D. Lee, Ronnie E. McBride, Merrie S.
Costley, and Donald J. Guedry, Jr. (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form
10-K for the year ended December 31, 2001).
10.17 -- Grey Wolf, Inc. Executive Severance Plan effective November 15, 2001 (incorporated herein by reference to
Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001).
10.18 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Thomas P.
Richards (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.19 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and David W.
Wehlmann (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.20 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Edward S.
Jacob III (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.21 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Gary D. Lee
(incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December
31, 2001).
10.22 -- Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Ronnie E.
McBride (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
10.23 -- Form of Non-Qualified Stock Option Agreement dated as of February 13, 2002, by and between the Company and
each of Frank M. Brown, William T. Donovan, James K.B. Nelson, Robert E. Rose, Steven A. Webster, and William
R. Ziegler (incorporated herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).
*10.24 -- Second Amendment to Loan Agreement dated as of February 7, 2003 by and among Grey Wolf Drilling Company L.P.
(as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit,
Inc. and various financial institutions (as lenders).
*21.1 -- List of Subsidiaries of Grey Wolf, Inc.
*23.1 -- Consent of KPMG LLP
*99.1 -- Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 of Thomas P. Richards, Chairman, President and Chief Executive Officer.
*99.2 -- Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 of David W. Wehlmann, Senior Vice President and Chief Financial Officer.
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* Filed herewith