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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, 2003
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission file number 1-8226
[GREY WOLF, INC. 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 10, 2004, 181,437,431 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 10, 2004 of $4.25) was approximately $718.6 million.
Indicate by a check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act) Yes [X] No [ ].
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 2004 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, 2003,
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. 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, Texas 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 reports
on Form 10-K, quarterly reports on Form 10-Q, current reports on 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. Unless the context
otherwise requires, reference in this Report on Form 10-K to "we", "us", "our"
or "Grey Wolf" refer to Grey Wolf, Inc. and its subsidiaries.
BUSINESS STRATEGY
Within the framework of a very cyclical industry, our strategy is to
maximize shareholder value during each phase of an industry cycle. To achieve
that strategy, we seek to enter each phase of our industry's cycles in a
stronger position by:
- delivering quality, value-added service to our customers;
- maintaining a leading position in certain markets where we
operate;
- responding to market conditions by balancing dayrates we
receive on our rigs with the number of rigs we market;
- 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 exercising capital spending discipline;
- maintaining a premium fleet of equipment with a 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
At the peak of the last up cycle in July 2001, there were 1,136 land
rigs working in the United States according to the Baker Hughes rotary rig
count. That number fell to 628 in April of 2002, we believe due to lower
commodity prices. From April 2002 through December 2002, commodity prices
generally improved and we saw a stabilization of the domestic land rig count at
an average of 710 rigs. From the end of 2002 through the end of January 2004,
the average closing price for natural gas, based upon the NYMEX near month
contract was $5.52 per mmbtu, while the average NYMEX near month contract price
of West Texas Intermediate Crude was $31.16 per barrel. During this time period,
the closing prices did not fall below $4.43 per mmbtu and $25.24 per barrel for
natural gas and West Texas Intermediate Crude, respectively. Over this same
period of time, the number of land rigs working domestically increased to 988.
CURRENT CONDITIONS AND OUTLOOK
The last up cycle in our industry, which began in the second half of
1999 and continued through the third quarter of 2001, was marked by rapidly
increasing dayrates, significant backlog and reactivation of rigs from
cold-stacked status and inventory. Dayrates began increasing when the U.S. land
rig count reached approximately 600 rigs on the Baker Hughes rotary rig count
and continued to rise until roughly mid-2001. Backlog, in the form of signed
contracts and non-binding oral commitments from customers, generally extended
beyond six months and through the use of term contracts extended up to two
years.
-2-
Although the domestic land rig count has increased from 628 in April
2002 to 988 at the end of January 2004, we believe that the current cycle of
increasing rig count differs from the last in that, to date, dayrates have
increased only slightly and we believe backlog has yet to build to levels seen
in 2001. We believe there are a number of factors that contribute to the overall
lack of intensity in the current up cycle.
First, the expansion of the land rig fleet in the last up cycle means
there are more rigs available to meet the demand in this cycle with little or no
additional capital expenditure. It is estimated that rigs refurbished and
reactivated in the last up cycle added between 120 and 150 rigs to the market
that are capable of working in this cycle. In addition, new-build rig programs
have added between 50 and 60 additional rigs to the market over the last two
years.
Second, the customer base that accounts for the largest portion of
working land rigs consists of independent producers of oil and gas. We believe
that this customer group has, in general, changed its management focus from
rapid oil and gas reserve expansion through drilling and acquisition to overall
financial health measured by balance sheet strength and adequate returns on
capital employed. Under the old focus, we believe that during periods when
commodity prices were high, these customers generally applied the greatest
portion of available cash to increase reserves. Today, we believe that drilling
prospects compete with debt reduction, producing property acquisitions, and
stock buybacks for available cash.
Third, we believe the nature of the competitive environment is
different. Competition in this up cycle has focused on market share rather than
obtaining higher dayrates, which received much stronger emphasis in the last up
cycle.
Finally, a general lack of deep drilling has become evident in this up
cycle, leaving high horsepower premium rigs idle or under utilized. The number
of wells drilled by the top 15 operators to depths greater than 10,000 feet has
declined approximately 30% from the peak in 2001 to the present. Also, today
there are approximately 50 fewer rigs drilling wells to target depths of 15,000
feet or deeper than were drilling at the peak of the last up cycle. This failure
of the deep drilling segment of the market to rebound as quickly as in the past
is reflected not only in the number of rigs working but also in lower average
operating margins. Rigs drilling deeper wells typically command higher margins.
We believe we are in a solid position to benefit from an increase in
drilling activity which we believe could develop in 2004. We continue to
maintain our premium fleet of equipment and retain our experienced personnel
which are essential to providing quality service to our customers and returning
our rigs to work when market conditions improve.
During each quarter in 2003, we averaged between 59 and 62 rigs working
and have averaged 63 rigs working thus far in the first quarter of 2004. We
have, however, seen an increase in the amount of future work for our rigs
currently operating as well as an increase in the dayrates we are currently
bidding for our rigs. This future work is in the form of signed contracts and
non-binding oral commitments from our customers.
OPERATIONS
At February 10, 2004, we had a rig fleet of 117 rigs, 80 of which were
marketed, 22 cold-stacked and 15 held for future refurbishment. Cold-stacked
rigs are rigs that are stacked without crews, are not currently being marketed
and do not require substantial investment to be returned to service. We estimate
that our cold-stacked rigs could be returned to service for an aggregate of
approximately $2.5 million to $3.0 million. 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.
-3-
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 2003,
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 Northeast Texas, Northern Louisiana and Southern Arkansas, and the
Mississippi/Alabama market. We currently have 19 marketed rigs in this division
which consist of 11 diesel electric rigs and eight mechanical rigs. Our
Ark-La-Tex division also operates a fleet of trucks which is 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 14 rigs working in our Ark-La-Tex division during
2003. Daywork contracts generated approximately 84% of our revenues and 72% of
the operating margin in this division during 2003, while turnkey and footage
contracts generated the remaining 16% of our revenues and 28% of our operating
margin. Operating margin is defined as revenues less drilling operations
expenses. The average revenue per rig day worked by the division during 2003 was
$10,438.
Gulf Coast Division. Our Gulf Coast division provides drilling services
in Southern Louisiana and along the upper Texas Gulf Coast. We currently have 21
marketed rigs in this division which consist of 18 diesel electric rigs and
three mechanical rigs.
We had an average of 18 rigs working in our Gulf Coast division during
2003. Daywork contracts generated approximately 40% of our revenues and 34% of
our operating margin in this division during 2003, while turnkey and footage
contracts generated the remaining 60% of our revenues and 66% of our operating
margin. The average revenue per rig day worked by the division during 2003 was
$16,002.
South Texas Division. We currently have 30 marketed rigs in this
division. The marketed rigs consist of 15 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 trucks which is used
exclusively to move our rigs.
We had an average of 22 rigs working in our South Texas division during
2003. Daywork contracts generated approximately 63% of our revenues and 38% of
our operating margin in this division during 2003, while turnkey and footage
contracts generated the remaining 37% of our revenues and 62% of our operating
margin. The average revenue per rig day worked by the division during 2003 was
$12,241.
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 four marketed rigs in this district. Two of these
rigs are 3,000 horsepower or larger diesel electric rigs while the other two
rigs are diesel electric 1,500 horsepower rigs. Daywork contracts generated 100%
of the revenue and operating margin in this market area and the average revenue
per rig day worked in the district during 2003 was $13,206. Currently, we have
three rigs 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 diesel electric rigs. During 2003, we averaged five rigs
working under daywork contracts, with an average revenue per rig day worked of
$9,856.
COLD STACKED RIGS AND RIGS HELD FOR REFURBISHMENT
We have the ability to return all 22 cold-stacked rigs to work at an
estimated aggregate cost of $2.5 million to $3.0 million, which would bring our
marketed fleet to 102 rigs. In addition, we have 15 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 2004, 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.
-4-
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 little or 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 blowouts.
We sometimes enter into term contracts to provide drilling services on
a daywork basis. Typically, the length of our term contracts have ranged from
six months to two years. They have usually included a per rig day termination
rate approximately equal to our daily operating margin under the contract. We
seek term contracts with our customers when we believe that those contracts may
mitigate the financial impact to us of a decline in dayrates during the period
in which the term contract is in effect. During late 2001 and 2002, the use of
term contracts enabled us to maintain margins that proved to be higher than was
attainable during 2002 and 2003. We also have used term contracts to
contractually assure that we receive sufficient cash flow to recover the costs
of improvements we make to the rigs under the term contract, particularly when
those improvements are requested by the customer.
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 without complications.
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 than under
a daywork contract because we assume some 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, and
risks associated with subcontractors' services, supplies, cost escalation and
personnel. Generally, the overall risk we assume is not as great as under
turnkey contracts. As with turnkey contracts, we manage additional risk through
the use of engineering expertise and bid the footage contracts accordingly. We
also maintain insurance coverage against certain drilling hazards.
-5-
CUSTOMERS AND MARKETING
Our contract drilling customers include independent producers and major
oil and gas companies. In 2003, 35% of our revenue came from major oil and gas
companies and large independent producers, while the remaining 65% came from
other independents. For the year ended December 31, 2003, no individual customer
accounted for more than 10% of our revenues. 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, workers' compensation insurance, property casualty insurance
on our rigs and drilling equipment, and "control of well" insurance. In
addition, we have commercial excess liability insurance, to cover general
liability, auto liability and workers' compensation claims which are higher than
the maximum coverage provided under those policies. The table below and the
discussion that follows highlights these coverages.
Deductible/
Limit Aggregate Self-Insured Retention
Coverage per Occurrence Limit per Occurrence
- ----------------------------- ---------------------- ---------------- ---------------------------
Workers' compensation/
Employer liability Statutory(1)/$1.0 million None $350,000
Automobile liability $1.0 million None $350,000
Commercial general liability $1.0 million $2.0 million $250,000
Commercial excess liability $10.0 million $10.0 million Underlying insurance
Commercial excess liability $65.0 million $65.0 million Underlying insurance
- ----------
(1) Workers' compensation policy limits vary depending on the laws of the
particular states in which we operate.
Our property casualty insurance coverage for 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 $125,000 maintenance
deductible per occurrence for losses on our rigs. In addition, there is a
deductible of $850,000 in the aggregate over the policy period, exclusive of the
maintenance deductible. There is a $25,000 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 $3.0 million 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.
-6-
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. 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. 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
A material or extended decline in expenditures by the oil and gas industry, due
to a decline or volatility in oil and gas prices, a decrease in demand for oil
and gas or other factors, would reduce our revenue and income.
As a supplier of land drilling services, our business depends on the
level of drilling activity by oil and 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 prices. Low oil and natural
gas prices, or the perception among oil and gas companies that prices are likely
to decline, can materially and adversely affect us in many ways, including:
- our revenues, cash flows and earnings;
- the fair market value of our rig fleet, which in turn could
trigger a writedown of the carrying value of these assets 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.
Depending on the market prices of oil and natural gas, oil and gas
exploration and production companies may cancel or curtail their drilling
programs, thereby reducing demand for our services. Even during periods when
prices for oil and natural gas are high, companies exploring for oil and natural
gas may cancel or curtail their drilling programs for a variety of other reasons
beyond our control. Any reduction in the demand for drilling services may
materially erode dayrates, the prices we receive for our turnkey drilling
services and the utilization rates for our rigs, any of which could adversely
affect our financial results. 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 instability 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.
An economic downturn may adversely affect our business.
An economic downturn may cause reduced demand for petroleum-based
products and natural gas. In addition, many oil and natural gas production
companies often reduce or delay expenditures to reduce costs, which in turn may
cause a reduction in the demand for our services during these periods. The
number of active land drilling rigs may be indicative of demand for services
that we provide. If the economic environment worsens, our business, financial
condition and results of operations may be further adversely impacted.
-7-
The intense price competition and cyclical nature of our industry could have an
adverse effect on our revenues and profitability.
The contract drilling business is highly competitive with numerous
industry participants. 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 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 during an industry downturn 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.
The contract drilling industry historically has been cyclical and has
experienced periods of low demand, excess rig supply, and low dayrates, followed
by periods of high demand, short rig supply and increasing dayrates. Periods of
excess rig supply intensify the competition in our industry and often result in
rigs being idle.
There are numerous competitors in each of the markets in which we
compete. In all of those markets, an oversupply 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.
Some of our competitors have greater financial and human resources than
do we. Their greater capabilities in these areas may enable them to:
- better withstand industry downturns;
- compete more effectively on the basis of price and technology;
- retain skilled rig personnel; and
- build new rigs or acquire and refurbish existing rigs to be
able to place rigs into service more quickly than we can.
Our drilling operations involve operating hazards which if not adequately
insured or indemnified against could adversely affect our results of operations
and financial condition.
Our operations are subject to the usual hazards inherent in the land
drilling business including the risks of:
- blowouts;
- reservoir damage;
- cratering;
- fires, pollution and explosions;
- collapse of the borehole;
- lost or stuck drill strings; and
- damage or loss from natural disasters.
-8-
If these drilling hazards occur they can produce substantial
liabilities to us which include:
- 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.
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. 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.
Our insurance or indemnification arrangements may not adequately protect us
against liability from all of the hazards of our business. If we were to incur a
significant liability for which we were not fully insured or indemnified, it
could adversely affect on our financial position and results of operations.
Our cost of insurance increased significantly in 2003 compared to prior
years, which we believe is consistent with the experience of most companies in
our industry. When we renew our current insurance policies, the premiums we pay
may again increase, which will increase our operating costs. Additionally, we
may be unable to obtain or renew insurance coverage of the type and amount we
desire at reasonable rates.
Business acquisitions entail numerous risks and may disrupt our business, dilute
shareholder value or distract management attention.
As part of our business strategy, we plan to consider acquisitions of,
or significant investments in, businesses and assets that are complementary to
ours. Any acquisition that we complete could have a material adverse affect on
our operating results and/or the price of our securities. Acquisitions involve
numerous risks, including:
- unanticipated costs and liabilities;
- difficulty of integrating the operations and assets of the
acquired business;
- our ability to properly access and maintain an effective
internal control environment over an acquired company, in
order to comply with the recently adopted and pending public
reporting requirements;
- potential loss of key employees and customers of the acquired
companies; and
- an increase in our expenses and working capital requirements.
We may incur substantial indebtedness to finance future acquisitions
and also may issue equity securities or convertible securities in connection
with any such acquisitions. Debt service requirements could represent a
significant burden on our results of operations and financial condition and the
issuance of additional equity could be dilutive to our existing stockholders.
Also, continued growth could divert the attention of our management and other
employees from our day-to-day operations and the development of new business
opportunities.
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.
-9-
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.
We have had only two profitable years since 1991.
We have a history of losses with only two profitable years since 1991.
In 1997, we had net income of $10.2 million and in 2001 we had net income of
$68.5 million. Our ability to achieve profitability 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 and
operating margin from turnkey and footage drilling contracts and we expect that
they will continue to represent a significant component of our revenues. The
occurrence of 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 services, 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.
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 into 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, we cannot assure you 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 our credit agreement may prohibit us from participation in
certain transactions that we may consider advantageous.
The indentures under which we issued our 8 7/8% Senior Notes due 2007
and 8 7/8% Senior Notes due 2007, Series B (together, the "8 7/8% 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;
-10-
- 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 subsidiary, Grey Wolf Drilling Company L.P., has entered into a
credit facility that also contains covenants restricting our ability to
undertake many of the same types of transactions and contains financial ratio
covenants when certain conditions are met. They may also limit our ability to
respond to changes in market conditions. Our ability to meet the 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 (see Note
4 to the consolidated financial statements). We may in the future incur
additional indebtedness that may contain additional covenants that may be more
restrictive than our current covenants.
Our credit facility contains default terms that effectively cross
default with any of our other debt agreements, including the indentures for our
8 7/8% Notes and our 3.75% Contingent Convertible Notes due May 2023 (the "3.75%
Notes"). Thus, if we breach the covenants in the indentures for our 8 7/8%
Notes, it could cause our default under our 8 7/8% Notes, our credit facility
and, possibly, other then outstanding debt obligations owed by us. If the
indebtedness under our credit facility or other indebtedness owed by us is more
than $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 indentures covering our 8 7/8%
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.
We have a significant amount of indebtedness and could incur additional
indebtedness, which could materially and adversely affect our financial
condition and results of operations.
We have now and will continue to have a significant amount of
indebtedness. On December 31, 2003, our total long-term indebtedness was
approximately $235.0 million in principal amount, (primarily consisting of
$150.0 million in principal amount of our 3.75% Notes and $85.0 million in
principal amount of 8 7/8% Notes).
Our substantial indebtedness could:
- increase our vulnerability to general adverse economic and
industry conditions;
- require us to dedicate a substantial portion of our cash flow
from operations to payments on our indebtedness thereby
reducing the availability of our cash flow to fund working
capital, capital expenditures and other general corporate
purposes;
- limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate;
- place us at a competitive disadvantage compared to our
competitors that have less debt; and
- limit our ability to borrow additional funds.
Neither the indenture governing our 3.75% Notes nor the terms of our
3.75% Notes limit our ability to incur additional indebtedness, including senior
indebtedness, or to grant liens on our assets. We and our subsidiaries may incur
substantial additional indebtedness and liens on our assets in the future.
Our existing senior indebtedness is, and any senior indebtedness we
incur will be, effectively subordinated to any present or future obligations to
secured creditors and liabilities of our subsidiaries.
Substantially all of our assets and the assets of our subsidiaries,
including our drilling equipment and the equity interests in our subsidiaries,
are pledged as collateral under our credit facility. Our credit facility is also
secured by our guarantee and the guarantees of our subsidiaries. The 3.75% Notes
and the 8 7/8% Notes are, and any senior indebtedness we incur will be,
effectively subordinated to all of our and our subsidiaries' existing and future
secured indebtedness, including any future indebtedness incurred under our
credit facility. As of February 10, 2004, we had the ability to borrow
approximately $58.6 million under our credit facility (after reductions for
undrawn outstanding standby letters of credit of $16.4 million). In addition,
the 3.75% Notes and the 8 7/8% Notes are effectively subordinated to the claims
of all of the creditors, including trade creditors and tort claimants, of our
subsidiaries.
To service our indebtedness, we will require a significant amount of cash. Our
ability to generate cash depends on many factors beyond our control.
Our operating activities did not provide net cash sufficient to pay our
debt service obligations for the year ended December 31, 2003 and we cannot
assure you that we will be able to generate sufficient cash flow in the
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future. Our ability to make payments on and to refinance our indebtedness and to
fund planned capital expenditures will depend on our ability to generate cash in
the future. This, to a large extent, is subject to general economic, financial,
competitive, regulatory and other factors that are beyond our control.
Our reported earnings per share may be more volatile because of the conversion
contingency provision of the 3.75% Notes.
Holders of the 3.75% Notes may convert such notes prior to the maturity
date into shares of our common stock in the following circumstances:
- during any calendar quarter, if the closing sale price per
share of our common stock for at least 20 trading days in the
period of 30 consecutive trading days ending on the last
trading day of the calendar quarter preceding the quarter in
which the conversion occurs, is more than 110% of the
conversion price per share ($7.10 per share) on that 30th
trading day;
- if we have called the 3.75% Notes for redemption;
- during any period that the credit ratings assigned to the
3.75% Notes by both Moody's Investors Service ("Moody's") and
Standard & Poors Ratings Group ("S&P") are reduced below B1
and B+, respectively;
- if neither Moody's nor S&P is rating the 3.75% Notes;
- during the five trading day period immediately following any
nine consecutive trading day period in which the average
trading price per $1,000 principal amount of the 3.75% Notes
for each day of such period was less than 95% of the product
of the closing sale price per share of our common stock on
that day multiplied by the number of shares of our common
stock issuable upon conversion of $1,000 principal amount of
the 3.75% Notes; or
- upon the occurrence of specified corporate transactions,
including a change in control.
Until one of these contingencies is met, the shares underlying the
3.75% Notes are not included in the calculation of basic or diluted earnings per
share. Should one of these contingencies be met, earnings per share could
decrease, depending on the level of net income, as a result of the inclusion of
the underlying shares in the earnings per share calculation. Volatility in our
stock price could cause this condition to be met in one quarter and not in a
subsequent quarter, increasing the volatility of diluted earnings per share.
Our indentures for the 8 7/8% Notes and our 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
credit facility prohibit the payment of dividends without the prior written
consent of the lenders and the terms of the indentures under which our 8 7/8%
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 agreement
contain certain provisions that may delay or prevent entirely a change of
control transaction not supported by our board of directors, or any transaction
which may have that general effect. These provisions 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 3.75% Notes and 8 7/8%
Notes are issued require us to offer to repurchase the 3.75% Notes and 8 7/8%
Notes then outstanding at a purchase price equal to 100% and 101%, respectively,
of the principal amount plus accrued and unpaid interest to the date of purchase
in the event that we
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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.
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 10, 2004, 181.4 million shares of our common stock were
issued and outstanding. An additional 10.2 million shares of our common stock
were issuable upon exercise of outstanding stock options (of which 5.4 million
shares are currently exercisable) and 23.3 million shares were issuable upon
conversion of the 3.75% Notes, once a contingency is met (see Note 4 to the
consolidated financial statements). 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 10, 2004, 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;
- 2004 rig activity and financial results;
- reactivation and cost of reactivation of non-marketed rigs;
- projected dayrates and operating margins per rig day;
- rigs expected to be engaged in turnkey and footage operations;
- projected tax benefit rate;
- wage rates and retention of employees;
- sufficiency of our capital resources and liquidity; and
- depreciation and capital expenditures in 2004.
Although we believe the forward-looking statements are reasonable, we
cannot assure you that these statements will prove to be correct. We have based
these statements on assumptions and analyses in light of our experience and
perception of historical trends, current conditions, expected future
developments and other factors we believe were appropriate when the statements
were made. In addition to those risks described above under "Certain Risks"
other 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;
- uninsured or underinsured casualty losses;
- 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 and footage cost overruns; and
- weather conditions.
-13-
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.
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. Domestically, land rigs generally operate 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 52 SCR diesel electric rigs.
We also own 17 mechanical rigs and one diesel electric rig that are
trailer-mounted for greater mobility. We believe that trailer-mounted rigs and
1,500 to 2,000 horsepower diesel electric rigs are in highest demand in the
South Texas 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 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 in the drill string. A top
drive also permits rotation of the drill string while moving 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 10, 2004, we owned 15 top drives.
-14-
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 10, 2004:
Maximum Rated Depth Capacity(1)
-----------------------------------------------------------
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 5 5 11
Trailer-Mounted - 1 - - 1
Mechanical - 2 3 2 7
Gulf Coast
Diesel Electric - - 1 17 18
Mechanical - 1 2 - 3
South Texas
Diesel Electric - 1 6 8 15
Trailer-Mounted - 9 - 1 10(2)
Mechanical - 4 - 1 5
Rocky Mountain
Diesel Electric - - - 4 4
West Texas
Diesel Electric - - 2 4 6
------- ------ ------- -------- -------
Total Marketed - 19 19 42 80
NON-MARKETED
Diesel Electric - - - 7 7
Trailer-Mounted 1 6 - - 7
Mechanical 1 11 8 3 23
------- ------ ------- -------- -------
Total Non-Marketed 2 17 8 10 37
------- ------ ------- -------- -------
TOTAL RIG FLEET 2 36 27 52 117
======= ====== ======= ======== =======
- ----------
(1) The actual drilling capacity of a rig may be less than its rated
capacity due to numerous factors, such as the length of the drill
string and casing size. The intended well depth and the drill site
conditions determine the length of the drill string and other equipment
needed to drill a well.
(2) Includes one diesel electric rig.
FACILITIES
The following table summarizes our significant real estate:
Location Interest Uses
- -------- -------- ----
Houston, Texas..................... Leased Corporate Office
Alice, Texas....................... Owned Division Office, Rig Yard, Truck Yard
Eunice, Louisiana.................. Owned Division Office, Rig Yard
Haughton, Louisiana................ Owned Rig Yard
Shreveport, Louisiana.............. Leased Division Office
Shreveport, Louisiana.............. Owned Rig Yard, Truck Yard
Casper, Wyoming.................... Leased District Office
Midland, Texas..................... Leased District Office
We lease approximately 22,700 square feet of office space in Houston,
Texas for our principal corporate offices at a cost of approximately $41,500 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.
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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." As of February 13, 2004, we had 976 shareholders
of record. 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, 2004 to February 10, 2004 $4.31 $3.74
Year Ended December 31, 2003
Quarter ended March 31, 2003 4.50 3.50
Quarter ended June 30, 2003 4.96 3.88
Quarter ended September 30, 2003 4.19 3.22
Quarter ended December 31, 2003 3.89 3.16
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
We have never declared or paid cash dividends on our common stock and
do not expect to pay cash dividends in 2004 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 8 7/8% Notes are issued also restrict our ability to pay
dividends under certain conditions.
On February 10, 2004, the last reported sales price of our common stock
on the AMEX was $4.25 per share.
ITEM 6. SELECTED FINANCIAL DATA
Years Ended December 31,
-------------------------------------------------------------
2003 2002 2001 2000 1999
--------- --------- --------- --------- ----------
(Amounts in thousands, except per share amounts)
Revenues (1) $ 285,974 $ 250,260 $ 433,739 $ 276,758 $ 148,465
Net income (loss) (30,200) (21,476) 68,453 (8,523) (41,262)
Net income (loss) per common share
- basic and diluted (0.17) (0.12) 0.38 (0.05) (0.25)
Total assets (1) 529,078 590,623 625,471 512,370 453,852
Senior and contingent convertible notes &
other long-term debt 234,898 249,613 250,695 249,851 249,962
- ----------
(1) Presentation revised to give effect to reclassification of certain
items to conform to the presentation in 2002 and 2003 (see Note 1 to
consolidated financial statements).
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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.
OVERVIEW
We are a leading provider of contract land drilling services in the
United States with a fleet of 117 rigs, of which 80 rigs are currently marketed.
Our customers include independent producers and major oil and gas companies. We
conduct all of our operations through our subsidiaries in the Ark-La-Tex, Gulf
Coast, Mississippi/Alabama, South Texas, West Texas and Rocky Mountain drilling
markets. Our drilling contracts generally provide compensation on a daywork,
turnkey or footage basis (see Item 1. Business).
Our business is cyclical and our financial results depend upon several
factors. These factors include the overall demand for land drilling services,
the level of demand for turnkey and footage services, the demand for deep versus
shallow drilling services, the dayrates we receive for our services and our
success drilling turnkey and footage wells.
Rig Activity
After a modest increase in our number of rigs working in the first
quarter of 2003, our rig count has remained relatively stable. Our premium rig
fleet is biased towards deep gas drilling and we believe that our activity and
market share have been adversely affected by the general lack of deep drilling
in this current industry cycle.
The table below shows the average number of land rigs working in the
United States according to the Baker Hughes rotary rig count and the average
number of our rigs working.
2002 2003 2004
Domestic ---------------------------------- ------------------------------------ ----
Land Rig Full Full Q-1 to
Count Q-1 Q-2 Q-3 Q-4 Year Q-1 Q-2 Q-3 Q-4 Year Date
--------- --- --- --- --- ---- --- --- --- --- ---- ----
Baker Hughes 679 683 722 723 695 773 903 964 988 880 995
Grey Wolf 56 54 55 54 55 59 60 62 62 61 63
Drilling Contract Bid Rates
Daywork dayrates are generally driven by utilization. Our daywork bid
rates ranged between $7,000 and $8,500 per rig day during the fourth quarter of
2002. However, as the land rig count has increased, our leading edge bid rates
have risen to between $8,000 and $9,500 per rig day. All leading edge bid rates
exclude fuel and top drives. We believe that the drilling contract dayrates have
been affected by an increase in the number of rigs available, as well as by the
focus by our competitors on market share rather than higher dayrates.
In addition to our fleet of drilling rigs, we currently own 15 top
drives for which our current bid rates range from $1,500 to $2,000 per day. Bid
rates for our top drives are in addition to the above stated bid rates for our
rigs.
Turnkey and Footage Contract Activity
Turnkey and footage work continues to be an important part of our
business and operating strategy. Our engineering and operating expertise allow
us to provide this service to our customers and has historically provided higher
revenues and operating margins per rig day worked than under daywork contracts.
However, we are typically required to bear additional operating costs (such as
drill bits) that would otherwise be paid by the customer under daywork
contracts. In 2003, our turnkey and footage operating margin (revenues less
drilling operations expenses) was $6,094 per rig day compared to a daywork
operating margin of $1,106 per rig day, and our turnkey and footage revenue was
$31,087 per rig day compared to $9,562 per rig day for daywork. For the year
ended December 31,
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2003, turnkey and footage work represented 50% of our operating margin and 16%
of total days worked compared to 20% of our operating margin and 9% of total
days worked in 2002.
The operating margins generated on turnkey and footage contracts vary
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. While demand
has been somewhat higher as evidenced by the increase in rig count, the demand
for turnkey services has not declined. We believe this is due in large part to
current daywork rates which have increased only slightly despite the increase in
rig count.
FOURTH QUARTER FINANCIAL RESULTS
The fourth quarter of 2003 exceeded our previous guidance for the
quarter. Our previous guidance for the fourth quarter was a loss per share of
$0.03 on a diluted basis and an operating margin of $10.5 million or
approximately $1,700 per rig day. Our earnings per share on a diluted basis was
actually $0.00 for the fourth quarter and our total operating margin (revenues
less drilling operations expenses) was $19.3 million, or $3,366 per rig day. The
fourth quarter operating margin consists of $9.5 million from turnkey contracts,
$6.7 million from daywork contracts, and $3.1 million from the sale of a claim
in bankruptcy, against a bankrupt customer, for revenues related to the early
termination of a long-term contract.
We exceeded our previous guidance primarily due to a record quarter
from our turnkey business and the sale of the claim noted above. We averaged 12
rigs working on turnkey contracts during the fourth quarter, representing 20% of
the total rig days and 49% of our operating margin. The operating margin per rig
day for turnkey work was $8,448 in the fourth quarter of 2003 compared to $6,123
in the fourth quarter of 2002. This increase is due mainly to the complexity and
depth of the turnkey wells drilled in the fourth quarter of 2003. We believe
that turnkey work will remain strong in the first quarter of 2004, however, we
are not expecting a repeat of the margin earned in the fourth quarter.
FIRST QUARTER 2004 OUTLOOK
Based on currently anticipated levels of activity and dayrates, we
expect to generate an operating margin of approximately $12.9 million, or $2,100
per rig day for the first quarter of 2004. Net loss per share is expected to be
approximately $0.02 on a diluted basis, projecting an annual tax benefit rate of
approximately 37%. We expect depreciation expense of approximately $12.9 million
and interest expense of approximately $3.7 million in the first quarter of 2004.
Capital expenditures for 2004 are currently projected to be $27.0 million to
$30.0 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 or the assumptions that underlie
such assumptions will prove to be correct. We expect to average between eight
and 11 rigs working under turnkey and footage contracts during the first quarter
of 2004; however, there can be no assurance that we will be able to maintain the
current level of activity or operating margins derived from turnkey and footage
contracts. See Item 1. Business-Forward-Looking Statements for important factors
that could cause actual results to be differ materially from our expectations.
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, sometimes materially. Critical accounting
policies and estimates are defined as those that are both most important to the
portrayal of our financial condition and operating results and require
management's most subjective judgments. 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 repair costs as incurred. We
estimate the useful lives of our assets are between three and fifteen years.
-18-
Impairment of Long-Lived Assets. We assess the impairment of our
long-lived assets under Statement of Financial Accounting Standards Board
("SFAS") No. 144 "Accounting for the Impairment or Disposal of 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 we determine that a triggering event, such as those
described previously, has occurred we perform a review of our rig and rig
equipment. Our review is performed by comparing the carrying value of each rig
to the estimated undiscounted future net cash flows for that rig. If the
carrying value of any rig is more than the estimated undiscounted future net
cash flows expected to result from the use of the rig, a write-down of the rig
to 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 are generally not
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 our estimates and projections.
The demand for land drilling services is cyclical and has historically
resulted in fluctuations in rig utilization. The severity and duration of the
downturn during 1998 triggered an asset impairment charge of $93.2 million. We
believe the contract drilling industry will continue to be cyclical and rig
utilization will fluctuate. The likelihood of an asset impairment increases
during extended periods of rig inactivity. Each year we evaluate our cold
stacked and inventory rigs and determine our intentions for their future use.
This evaluation takes into consideration, among other things, the physical
condition and marketability of the rig, and projected reactivation or
refurbishment cost. If we were to change our intended use of some or all of the
rigs, we could be required under SFAS No. 144 to record an impairment charge.
During the fourth quarter of 2002, we recorded a pre-tax, non-cash asset
impairment charge of $3.5 million after performing such a review. As we no
longer intended to return five of those rigs to service, but use their component
parts as spare equipment inventory, we recorded the charge to write the rigs
down to their fair market value and reduced the number of drilling rigs in our
fleet by five. In 2003, no impairment of our long-lived assets was recorded as
no change in circumstances or in our intentions indicated that the carrying
value of the assets was not recoverable. We currently have 22 cold stacked and
15 inventory rigs.
Revenue Recognition. Revenue from daywork and footage contracts is
recognized when earned as services are performed under the provisions of the
contracts. Revenue from turnkey drilling contracts is recognized using the
percentage-of-completion method based upon costs incurred to date compared to
our estimate of the total contract costs. Under the percentage-of-completion, we
make estimates of the total contract costs to be incurred, and to the extent
these estimates change, the amount of revenue recognized could be affected. The
significance of the accrued turnkey revenue varies from period to period
depending on the overall level of demand for our services and the portion of
that demand that is for turnkey services. At December 31, 2003, there were eight
turnkey wells in progress versus four wells at December 31, 2002, with accrued
revenue of $5.0 million and $3.6 million, respectively at such dates.
Anticipated losses, if any, on uncompleted contracts are recorded 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 for general liability claims. These policies
include deductibles of $350,000 per occurrence for workers' compensation
coverage and $250,000 per occurrence for general liability coverage. 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. At December 31,
2003 and 2002, we had $9.4 million and $9.7 million, respectively, accrued for
losses incurred within the deductible amounts for workers' compensation and
general liability claims. The amount accrued for the provision for losses
incurred varies depending on the number and nature of the claims outstanding at
the balance sheet date. In addition, the accrual includes management's estimate
of the future cost to settle each claim such as future changes in the severity
of the claim and increases in medical costs. In addition, 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.
Income Taxes. Our deferred tax assets consist primarily of net
operating loss carryforwards ("NOL's"). The estimated amount of our NOL's at
December 31, 2003 are $133.5 million, which expires from 2010 to 2023.
Approximately $7.2 million of these NOL's expire in 2010 and 2011, while the
remaining $126.3 million expire between 2019 and 2023. 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, 2003, we do not have a valuation allowance as we
believe that it is more likely than not that our
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future taxable income and reversal of deferred tax liabilities will be
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 nine
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 Note 3 to our consolidated financial statements for a reconciliation of our
statutory to effective tax rate.
FINANCIAL CONDITION AND LIQUIDITY
The following table summarizes our financial position as of December
31, 2003 and December 31, 2002.
December 31, 2003 December 31, 2002
---------------------- ----------------------
(In thousands)
Amount % Amount %
----------- ----- ----------- -----
Working capital $ 68,727 14 $ 114,353 21
Property and equipment, net 404,278 85 420,791 78
Other noncurrent assets 5,141 1 4,668 1
----------- ----- ----------- -----
Total $ 478,146 100 $ 539,812 100
=========== ===== =========== =====
Long-term debt $ 234,898 49 $ 249,613 46
Other long-term liabilities 47,611 10 64,941 12
Shareholders' equity 195,637 41 225,258 42
----------- ----- ----------- -----
Total $ 478,146 100 $ 539,812 100
=========== ===== =========== =====
Significant Changes in Financial Condition.
The significant changes in our financial position from December 31,
2002 to December 31, 2003 are a decrease in working capital of $45.6 million, a
decrease in other long-term liabilities of $17.3 million and a decrease in
shareholders' equity of $29.6 million. The decrease in working capital is a
result of the issuance of the 3.75% Contingent Convertible Senior Notes due 2023
(the "3.75% Notes") and partial redemption of the 8 7/8% Senior Notes due 2007
(the "8 7/8% Notes"), the net loss for the period and capital expenditures. The
decrease in shareholders' equity liabilities is due almost entirely to the net
loss for the period of $30.2 million. The decrease in other long-term
liabilities is due to the change in our net deferred tax liabilities resulting
from a deferred tax benefit of $16.4 million.
On May 7, 2003, we issued $150.0 million aggregate principal amount of
3.75% Notes. The net proceeds of $146.6 million from the sale of the 3.75% Notes
and $30.6 million of our available cash, a total of $177.2 million, were used to
redeem $165.0 million aggregate principal amount of the 8 7/8% Notes, plus
accrued but unpaid interest. The partial redemption of the 8 7/8% Notes was made
on July 1, 2003 at a redemption premium of 102.9580%. This redemption premium of
$4.9 million was included in interest expense in the second quarter of 2003.
Amortization of the previously deferred financing costs associated with the
notes was accelerated and approximately $2.5 million of additional interest
expense was recognized in the quarter ended June 30, 2003.
After the partial redemption of the 8 7/8% Notes, we continue to owe
$85.0 million in aggregate principal amount of the 8 7/8% Notes and $150.0
million in aggregate principal amount of the 3.75% Notes, for a total aggregate
principal amount of $235.0 million for both classes of senior notes. Our annual
interest expense will be reduced by approximately $9.5 million as a result of
the refinancing, including approximately $9.0 million of cash savings.
The net effect on working capital of this refinancing was a reduction
of $23.8 million consisting of a $15.0 million net reduction in debt
outstanding, $4.9 million in a redemption premium paid on the 8 7/8% Notes and
$3.9 million in financing costs related to the issuance of the 3.75% Notes.
Capital expenditures of $35.1 million during the year also contributed to the
decrease in working capital. Capital expenditures included the cash purchase of
two diesel electric SCR rigs for $9.0 million.
-20-
3.75% Notes
The 3.75% Notes bear interest at 3.75% per annum and mature on May 7,
2023. The 3.75% Notes are convertible into shares of our common stock, upon the
occurrence of certain events, at a conversion price of $6.45 per share, which is
equal to a conversion rate of approximately 155.0388 shares per $1,000 principal
amount of 3.75% Notes, subject to adjustment. We will pay contingent interest at
a rate equal to 0.5% per annum during any six-month period, with the initial
six-month period commencing May 7, 2008, if the average trading price of the
3.75% Notes per $1,000 principal amount for the five day trading period ending
on the third day immediately preceding the first day of the applicable six-month
period equals $1,200 or more. The 3.75% Notes are our 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. The 3.75% Notes and the guarantees rank equally
with our 8 7/8% Notes. Fees and expenses of approximately $3.9 million incurred
at the time of issuance are being amortized through May 2013, the first date the
holders may require us to repurchase the 3.75% Notes. We may redeem some or all
of the 3.75% Notes at any time on or after May 14, 2008, payable in cash, plus
accrued but unpaid interest, including contingent interest, if any, to the date
of redemption at various redemption prices shown in Note 4 to our consolidated
financial statements.
Holders may require us to repurchase all or a portion of their 3.75%
Notes on May 7, 2013 or May 7, 2018, and upon a change of control, as defined in
the indenture governing the 3.75% Notes, at 100% of the principal amount of the
3.75% Notes, plus accrued but unpaid interest, including contingent interest, if
any, to the date of repurchase, payable in cash.
The 3.75% Notes are convertible, at the holders' option, prior to the
maturity date into shares of our common stock in the following circumstances:
- during any calendar quarter, if the closing sale price per
share of our common stock for at least 20 trading days in the
period of 30 consecutive trading days ending on the last
trading day of the calendar quarter preceding the quarter in
which the conversion occurs, is more than 110% of the
conversion price per share ($7.10 per share) on that 30th
trading day;
- if we have called the 3.75% Notes for redemption;
- during any period that the credit ratings assigned to the
3.75% Notes by both Moody's Investors Service ("Moody's") and
Standard & Poors ("S&P") Ratings Group are reduced below B1
and B+, respectively, or if neither rating agency is rating
the 3.75% Notes;
- during the five trading day period immediately following any
nine consecutive trading day period in which the average
trading price per $1,000 principal amount of the 3.75% Notes
for each day of such period was less than 95% of the product
of the closing sale price per share of our common stock on
that day multiplied by the number of shares of common stock
issuable upon conversion of $1,000 principal amount of the
3.75% Notes; or
- upon the occurrence of specified corporate transactions,
including a change of control.
The 3.75% Notes did not meet the criteria for conversion into common
stock at any time during the year ended December 31, 2003 or during 2004 to the
date of this Report. At February 10, 2004, the credit ratings assigned to the
3.75% Notes by Moody's and S&P were B1 and BB-, respectively.
The indenture governing the 3.75% Notes does not contain any
restriction on the payment of dividends, the incurrence of indebtedness or the
repurchase of our securities, and does not contain any financial covenants.
8 7/8% Notes
At December 31, 2003, we had $85.0 million in aggregate principal
amount of 8 7/8% Notes outstanding. The 8 7/8% Notes, issued in June 1997 and
May 1998, bear interest at 8 7/8% per annum with original maturities on July 1,
2007. The 8 7/8% Notes are our 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. The unamortized fees and expenses incurred at the time of issuance
related to the principal amount outstanding are being amortized and discounts
are being accreted over the life of the 8 7/8% Notes.
We have the option to redeem the 8 7/8% Notes in whole or in part
during the twelve months 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 accrued but unpaid interest to the redemption date. Upon a
change of control as
-21-
defined in the indentures governing the 8 7/8% Notes, each holder of the 8 7/8%
Notes will have the right to require us to repurchase all or any part of such
holder's 8 7/8% Notes at a purchase price equal to 101% of the aggregate
principal amount thereof, plus accrued but unpaid interest to the date of
purchase. We may also, from time-to-time, seek to retire the 8 7/8% Notes
through redemptions, open market purchases and privately-negotiated
transactions. Upon any such transaction, any difference between the redemption
price and the face value of the 8 7/8% Notes will be recorded as interest
expense.
The indentures for the 8 7/8% 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 on the 8 7/8%
Notes, 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 8 7/8% Notes. We are in compliance with these covenants.
CIT Facility
Our subsidiary Grey Wolf Drilling Company L.P. has entered into a $75.0
million credit facility with the CIT Group/Business Credit, Inc. (the "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 the United States of America.
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%. The CIT Facility
provides up to $20.0 million available for letters of credit. 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.
The CIT Facility contains 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 which
is also secured by a guarantee of Grey Wolf, Inc. and certain of our
wholly-owned subsidiaries' guarantees. However, we 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 but had $16.4 million of undrawn letters of credit at February
10, 2004. These standby letters of credit are for the benefit of various
insurance companies as collateral for premiums and retained losses which may
become payable under the terms of the underlying insurance contracts and for
other purposes. Outstanding letters of credit reduce the amount available for
borrowing under the CIT facility.
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 (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.
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.
-22-
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 including:
- 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
outstanding common stock of Grey Wolf, Inc. 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" (as defined by the CIT Facility).
Certain Contractual Commitments
The following table summarizes certain of our contractual cash
obligations and related payments due by period at December 31, 2003 (amounts in
thousands):
Payments Due by Period (1)
------------------------------------------------------------------------
Less than 1-3 4-5 After 5
Contractual Obligation Total 1 year years years years
- ---------------------- ----------- ----------- ----------- ------------ -----------
3.75% Notes(2)
Principal $ 150,000 $ - $ - $ - $ 150,000
Interest 109,688 5,625 11,250 11,250 81,563
8 7/8% Notes(2)
Principal 85,000 - - 85,000 -
Interest 30,176 7,544 15,088 7,544 -
Operating leases 944 674 257 13 -
----------- ----------- ----------- ------------ -----------
Total contractual
cash obligations $ 375,808 $ 13,843 $ 26,595 $ 103,807 $ 231,563
=========== =========== =========== ============ ===========
- ----------
(1) This assumes no conversion under, or acceleration of maturity
dates due to redemption, breach of, or default under, the
terms of the applicable contractual obligation.
(2) See "8 7/8% Notes" and "3.75% Notes", above, for information
relating to covenants, the breach of which could cause a
default under, and acceleration of, the maturity date. Also
see "3.75% Notes" for information related to the holders'
conversion rights.
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 borrowing capacity of $58.6 million at December 31, 2003. The
following table illustrates the undrawn outstanding standby letters of credit at
December 31, 2003 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 $ 16,445 $ - $ 16,445 $ - $ -
----------- ----------- ----------- ---------- -----------
Total $ 16,445 $ - $ 16,445 $ - $ -
=========== =========== =========== ========== ===========
- ----------
(1) Assumes no acceleration of maturity date due to breach of, or
default under, the potential contractual obligation.
-23-
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,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Net cash provided by (used in):
Operating activities $ (7,040) $ 36,403 $ 148,312
Investing activities (33,927) (21,947) (101,209)
Financing activities (18,582) (1,224) 491
--------- --------- ---------
Net increase (decrease) in cash: $ (59,549) $ 13,232 $ 47,594
========= ========= =========
Our cash flows from operating activities are affected by a number of
factors including the number of rigs working 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, 2003 was $4.1 million (before changes in operating assets and
liabilities) compared to cash generated from operating activities during the
year ended December 31, 2002 of $23.4 million (before changes in operating
assets and liabilities). While the number of operating days increased by 10%
from 2002 to 2003, our operating margin declined by $12.0 million. This decline
was due in large part to the replacement of expiring term contracts with spot
market contracts at lower rates and margins. The lower operating margin
contributed to the reduction in cash flow from operating activities as did the
$4.9 million in redemption premium paid upon partial redemption of the 8 7/8%
Notes. Our cash flows from operating activities were also impacted by changes in
operating assets and liabilities which used $11.1 million and provided $13.0
million in cash flow for the years ended December 31, 2003 and 2002,
respectively.
Generally, during times of increasing demand, our changes in working
capital will result in the use of cash due primarily to the build-up of accounts
receivable. While there was a small increase in overall demand in 2003 as
compared to 2002, the $13.1 million increase in accounts receivable year over
year was primarily due to the increase in demand for turnkey services. At the
end of 2003, there were eight turnkey wells in progress while at the end of 2002
there where only four turnkey wells in progress. This is significant to our cash
flow from operations in that we are generally responsible for significantly more
costs while drilling under turnkey contracts (as opposed to daywork contracts)
but we are not compensated until the contract terms have been completely
satisfied. Under daywork contracts, we bill and are paid as work is performed.
Another significant change in working capital was the decrease in
accrued interest of $6.5 million. This reduction in accrued interest is due to
the partial redemption of the 8 7/8% Notes and the sale of the 3.75% Notes which
lowered our overall interest expense and changed the timing of our interest
payments.
Our cash flow generated from operating activities during the year ended
December 31, 2002 was $23.4 million (before changes in operating assets and
liabilities) compared to cash generated in operating activities during the year
ended December 31, 2001 of $150.6 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. The cash provided by changes in operating assets and liabilities
during 2002 was due to the decline in accounts receivable as a direct result of
the decline in operating days and operating margins.
Cash flow used in investing activities for the years ended December 31,
2003, 2002, and 2001 primarily consisted of $35.1 million, 22.3 million, and
$103.0 million of capital expenditures, respectively. These capital expenditures
included the costs of sustaining our rigs, the acquisition of drill pipe and
drill collars, the purchase of top drives, and other capital items. Also
included in capital expenditures in 2003 was the cash purchase of two diesel
electric SCR rigs for $9.0 million. In 2001, capital expenditures included
approximately $55.5 million for the reactivation of cold-stacked and inventory
rigs.
Cash flow used in financing activities for the year ended December 31,
2003 consisted of the partial redemption of the 8 7/8% Notes and the sale of the
3.75% Notes, the net effect of which was a reduction in debt outstanding of
$15.0 million.
-24-
Projected Cash Sources
We expect to use cash generated from operations to cover cash
requirements, including debt service on the 3.75% Notes and 8 7/8% Notes and
capital expenditures in 2004. Capital expenditures for 2004 are projected to be
between $27.0 million and $30.0 million, subject to the actual level of rig
activity. We make semi-annual interest payments of $3.8 million on the 8 7/8%
Notes on January 1 and July 1 of each year and semi-annual interest payments of
$2.8 million on the 3.75% Notes on May 7 and November 7 of each year through the
dates of maturity. To the extent that we are unable to generate sufficient cash
from operations we would be required to use cash on hand or draw on our CIT
Facility. At February 10, 2004, our cash and cash equivalent balance was
approximately $57.0 million.
From time to time we also review possible acquisition opportunities.
While we currently have no agreements to acquire additional businesses or
equipment, we may enter into such agreements in the future. Our ability to
consummate any such transaction will be dependent in large part on our ability
to fund, primarily through the capital markets, such a transaction. We cannot
give assurance that adequate funding will be available on satisfactory terms.
RESULTS OF OPERATIONS
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 our consolidated statement of operations rather
than being recorded net of the incurred expenses in drilling operations
expenses. This reclassification had no effect on net income or cash flows.
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, 2003, 2002 and 2001.
For the Year Ended December 31, 2003
---------------------------------------------------------
Daywork Turnkey
Operations Operations (2) Total
------------- -------------- -------------
(Dollars in thousands, except averages per rig day worked)
Rig days worked 18,700 3,447 22,147
Contract drilling revenue $ 178,818 $ 107,156 $ 285,974
Drilling operating expenses(1) 158,141 86,146 244,287
------------- ------------- -------------
Operating margin $ 20,677 $ 21,010 $ 41,687
============= ============= =============
Averages per rig day worked:
Contract drilling revenue $ 9,562 $ 31,087 $ 12,913
Drilling operating expenses 8,456 24,993 11,031
------------- ------------- -------------
Operating margin $ 1,106 $ 6,094 $ 1,882
============= ============= =============
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 $ 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 $ 2,364 $ 5,760 $ 2,674
============= ============= =============
-25-
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 $ 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 $ 5,814 $ 7,950 $ 5,963
============= ============= =============
- ----------
(1) Drilling operating expenses exclude depreciation, and general and
administrative expenses.
(2) Turnkey operations include the results from turnkey and footage
contracts.
COMPARISON OF FISCAL YEARS ENDED DECEMBER 31, 2003 AND 2002
Our operating margin decreased by $12.0 million, or 22%, to $41.7
million for the year ended December 31, 2003, from $53.7 million for the year
ended December 31, 2002. Operating margin is defined as contract drilling
revenues less drilling operating expenses. This decrease resulted from a $22.5
million decrease in operating margin from daywork operations, which was
partially offset by a $10.5 million increase in operating margin from turnkey
operations. On a per rig day basis, our total operating margin decreased by $792
per rig day, or 30%, to $1,882 in 2003 from $2,674 in 2002. This decrease
included a $1,258 per rig day decrease from daywork operations and a $334 per
rig day increase from turnkey operations.
Daywork Operations
The decrease in operating margin and operating margin per day discussed
above was due primarily to the expiration at the end of 2002 and in 2003 of term
contracts that were replaced with spot market contracts at lower rates. This
decrease was partially offset by an increase of 452 rig days worked in 2003
compared to 2002. Contract drilling revenue and contract drilling revenue per
rig day decreased as a result of these expiring term contracts. Total drilling
operating expenses increased slightly due to the increase in the number of rig
days worked; however, remained relatively constant on a per rig day basis.
Turnkey Operations
The increase in total turnkey operating margin was partially due to an
increase of 1,615 days, or 88% in the number of rig days worked in 2003 compared
to 2002. Total turnkey operating margin and operating margin per day also
increased due to differences in the complexity of the wells drilled in 2003
compared to 2002. The increase in the number of turnkey operating days along
with the difference in the complexity of the wells drilled, increased contract
drilling revenue and drilling operating expenses by $54.5 million and $44.0
million, respectively. Contract drilling revenue and drilling operating expenses
on a per rig day basis also increased because of the complexity differences.
Other
Depreciation expense increased by $3.9 million, or 8%, to $50.5 million
for the year ended December 31, 2003 compared to $46.6 million for the year
ended December 31, 2002. During the fourth quarter of 2002, we made the decision
not to return five rigs to service and reclassified the component parts of these
rigs to spare equipment, shortening the depreciable lives of this equipment. In
addition, depreciation expense is higher due to capital expenditures during
2003.
-26-
General and administrative expenses increased by $666,000, or 6%, to
$12.0 million for the year ended December 31, 2003 compared to $11.3 million for
the year ended December 31, 2002. Items affecting general and administrative
expenses include compensation expense in 2003 related to the hiring of our
Executive Vice President and Chief Operating Officer as well as higher
professional fees related to compliance with the Sarbanes-Oxley Act of 2002 and
increases in insurance costs. These items increased expenses by approximately
$1.2 million in 2003. In 2002, severance costs of $330,000 and non-cash
compensation expense of $515,000 related to stock options were recorded as a
result of the termination of employment of an executive officer.
Interest expense increased by $3.9 million, or 16%, to $27.8 million
for 2003 from $23.9 million for 2002. Interest expense in 2003 includes
approximately $8.5 million of costs associated with the partial redemption of
our 8 7/8% Notes on July 1, 2003 and interest on the $150.0 million aggregate
principal amount of 3.75% Notes issued on May 7, 2003. These costs include a
$4.9 million redemption premium for the 8 7/8% Notes, $2.5 million in
accelerated amortization of a pro-rata portion of the previously deferred
financing costs on the 8 7/8% Notes, and interest on the 3.75% Notes from May 7,
2003 to June 30, 2003. This additional interest expense was partially offset by
$4.5 million lower interest for the last six months of 2003 due to the lower
interest rate on the 3.75% Notes and $15.0 million reduction in principal amount
of total debt outstanding.
Our income tax benefit increased by $9.2 million to $17.4 million in
2003 from $8.2 million in 2002. The increase is due to the level of losses and a
change in our estimate of available state tax net operating losses in the fourth
quarter of 2003. This change in estimate increased our income tax benefit by
$938,000. Our income tax benefit is also affected by the annual amortization of
$2.8 million in permanent differences related to differences between the
financial accounting and tax basis of acquired assets. The permanent differences
are amortized as these assets are depreciated for financial accounting purposes
on a straight-line basis over their remaining useful lives of approximately nine
years at December 31, 2003. As the annual amortization of these permanent
differences is a fixed amount, our book effective tax rate can vary widely based
upon the current level of income or loss.
COMPARISON OF FISCAL YEARS ENDED DECEMBER 31, 2002 AND 2001
Our operating margin decreased by $130.7 million, or 71%, to $53.7
million for the year ended December 31, 2002, from $184.4 million for the year
ended December 31, 2001. This decrease resulted from a $124.1 million decrease
in operating margin from daywork operations and a $6.6 million decrease in
operating margin from turnkey operations. On a per rig day basis, our total
operating margin decreased by $3,289 per rig day, or 55%, to $2,674 in 2002 from
$5,963 in 2001. This decrease included a $3,450 per rig day decrease from
daywork operations and a $2,190 per rig day decrease from turnkey operations.
Daywork Operations
The decrease in operating margin and operating margin per rig day
discussed above is due to numerous factors affecting contract drilling revenue
and drilling operating expenses. First, there were 10,518 fewer rig days worked
in 2002 compared to 2001, which resulted in lower revenues and expenses. Second,
revenue and revenue per rig day decreased due to the expiration of term
contracts that were replaced with spot market contracts at lower rates. Finally,
drilling operating expenses per rig day increased 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 rig days.
Turnkey Operations
The decrease in operating margin and operating margin per day discussed
above was also due to several factors. The number of rig days worked decreased
by 326 days, or 15%, in 2002 compared to 2001. This resulted in a decrease in
contract drilling revenue, which was partially offset by an increase in the
revenue per rig day. The increase in revenue per rig day and the increase in
drilling operating expenses and drilling operating expenses per rig day resulted
from differences in the complexity of the wells drilled between 2002 and 2001.
Revenue and revenue per day were also affected by generally lower daywork
dayrates in 2002 than in 2001. Lower daywork dayrates can affect the overall
turnkey price charged to customers.
-27-
Other
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 was our
8 7/8% Notes that 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.
We recorded an income tax benefit of $8.2 million in 2002 compared to
income tax expense of $42.9 million in 2001. The change was due to losses
incurred in 2002 and is also affected by the annual amortization of $2.8 million
in permanent differences related to differences between the financial accounting
and tax basis of acquired assets. The permanent difference are amortized as
these assets are depreciated for financial accounting purposes on a
straight-line basis over their remaining useful lives of approximately 10 years
at December 31, 2002. As the annual amortization of these permanent differences
is a fixed amount, our book effective tax rate varies widely based upon the
current levels of income or loss.
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.
-28-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULE
Independent Auditors' Report.................................................... 30
Consolidated Balance Sheets as of December 31, 2003 and 2002.................... 31
Consolidated Statements of Operations for the Years
Ended December 31, 2003, 2002, and 2001................................ 32
Consolidated Statements of Shareholders' Equity and Comprehensive Income
for the Years Ended December 31, 2003, 2002, and 2001.................. 33
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2003, 2002, and 2001................................ 34
Notes to Consolidated Financial Statements...................................... 35
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts........................ 48
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.
-29-
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, 2003 and 2002, 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, 2003. In connection with our audits of the consolidated financial
statements, we have also audited the financial statement schedule for the years
ended December 31, 2003, 2002 and 2001. 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, 2003 and 2002, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2003, 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
January 30, 2004
-30-
GREY WOLF, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
December 31,
------------------------------
2003 2002
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents $ 54,350 $ 113,899
Restricted cash - insurance deposits 749 784
Accounts receivable, net of allowance
of $2,443 and $2,500, respectively 60,181 47,034
Prepaids and other current assets 4,379 3,447
----------- -----------
Total current assets 119,659 165,164
----------- -----------
Property and equipment:
Land, buildings and improvements 5,043 5,424
Drilling equipment 738,097 704,734
Furniture and fixtures 3,332 3,185
----------- -----------
Total property and equipment 746,472 713,343
Less: accumulated depreciation (342,194) (292,552)
----------- -----------
Net property and equipment 404,278 420,791
Other noncurrent assets 5,141 4,668
----------- -----------
$ 529,078 $ 590,623
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable - trade $ 27,893 $ 19,460
Accrued workers' compensation 5,295 4,947
Payroll and related employee costs 6,660 6,685
Accrued interest payable 4,664 11,160
Other accrued liabilities 6,420 8,559
----------- -----------
Total current liabilities 50,932 50,811
----------- -----------
Senior notes 84,898 249,613
Contingent convertible notes 150,000 -
Other long-term liabilities 4,115 4,789
Deferred income taxes 43,496 60,152
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; 181,283,431 and 181,037,811 issued and
outstanding, respectively 18,129 18,104
Additional paid-in capital 330,266 329,712
Accumulated deficit (152,758) (122,558)
----------- -----------
Total shareholders' equity 195,637 225,258
----------- -----------
$ 529,078 $ 590,623
=========== ===========
See accompanying notes to consolidated financial statements
-31-
GREY WOLF, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands, except per share data)
Years Ended December 31,
-------------------------------------------------
2003 2002 2001
------------ ------------ --------------
Revenues:
Contract drilling $ 285,974 $ 250,260 $ 433,739
Costs and expenses:
Drilling operations 244,287 196,570 249,328
Depreciation 50,521 46,601 41,425
Provision for asset impairment - 3,540 -
General and administrative 11,966 11,300 9,932
------------ ------------ --------------
Total costs and expenses 306,774 258,011 300,685
------------ ------------ --------------
Operating income (loss) (20,800) (7,751) 133,054
Other income (expense):
Interest expense (27,832) (23,928) (24,091)
Interest income 954 1,732 2,441
Gain on sale of assets 81 126 348
Other, net 14 128 (446)
------------ ------------ --------------
Other expense, net (26,783) (21,942) (21,748)
------------ ------------ --------------
Income (loss) before income taxes (47,583) (29,693) 111,306
Income tax expense (benefit)
Current (938) (1,871) 2,977
Deferred (16,445) (6,346) 39,876
------------ ------------ --------------
Total income tax expense (benefit) (17,383) (8,217) 42,853
------------ ------------ --------------
Net income (loss) $ (30,200) $ (21,476) $ 68,453
============ ============ ==============
Basic and diluted net income (loss) per common share $ (0.17) $ (0.12) $ 0.38
============ ============ ==============
Basic weighted average common shares outstanding 181,210 180,936 180,502
============ ============ ==============
Diluted weighted average common shares outstanding 181,210 180,936 182,447
============ ============ ==============
See accompanying notes to consolidated financial statements
-32-
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, 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
Exercise of stock options - 245 25 343 - - 368
Tax benefit of stock
option exercises - - - 211 - - 211
Comprehensive net loss - - - - (30,200) - (30,200)
------ ------- --------- ---------- ----------- ------------- ----------
Balance, December 31, 2003 - 181,283 $ 18,129 $ 330,266 $ (152,758) $ - $ 195,637
====== ======= ========= ========== =========== ============= ==========
See accompanying notes to consolidated financial statements
-33-
GREY WOLF, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Years Ended December 31,
-----------------------------------------------
2003 2002 2001
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (30,200) $ (21,476) $ 68,453
Adjustments to reconcile net income (loss) to
net cash provided by (used in) operating activities:
Depreciation 50,521 46,601 41,425
Provision for asset impairment - 3,540 -
Non-cash compensation expense - 542 -
Provision for doubtful accounts - 700 695
Gain on sale of assets (81) (126) (348)
Foreign exchange (gain) loss (14) (128) 446
Deferred income taxes (16,656) (6,555) 38,584
Accretion of debt discount 285 86 86
Tax benefit of stock options exercises 211 209 1,292
(Increase) decrease in restricted cash 35 100 (25)
(Increase) decrease in accounts receivable (13,147) 19,840 (6,540)
(Increase) decrease in other current assets (961) (1,691) 1,248
Increase (decrease) in accounts payable trade 8,476 (1,590) (4,586)
Increase (decrease) in accrued workers' compensation 348 352 (210)
Increase (decrease) in other current liabilities (8,660) (4,997) 3,888
Increase in other 2,803 996 3,904
------------ ------------ ------------
Cash provided by (used in) operating activities (7,040) 36,403 148,312
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment additions (35,102) (22,335) (103,036)
Proceeds from sales of equipment 1,175 388 1,827
------------ ------------ ------------
Cash used in investing activities (33,927) (21,947) (101,209)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 146,625 - -
Repayments of long-term debt (165,000) (1,910) (911)
Financing costs (575) - (280)
Proceeds from exercise of stock options 368 686 1,682
------------ ------------ ------------
Cash provided by (used in) financing activities (18,582) (1,224) 491
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (59,549) 13,232 47,594
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 113,899 100,667 53,073
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 54,350 $ 113,899 $ 100,667
============ ============ ============
SUPPLEMENTAL CASH FLOW DISCLOSURE
CASH PAID FOR INTEREST: $ 30,510 $ 22,817 $ 22,750
============ ============ ============
CASH PAID FOR (REFUND OF) TAXES: $ (879) $ (1,822) $ 3,019
============ ============ ============
See accompanying notes to consolidated financial statements
-34-
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 are 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 the weighted
average shares outstanding, during the applicable period, without any dilutive
effects considered. Diluted earnings per share reflects dilution from all
outstanding options and shares issuable upon the conversion of the 3.75%
Contingent Convertible Senior Notes once a contingency has been met. The
following is a reconciliation of basic and diluted weighted average common
shares outstanding (in thousands):
2003 2002 2001
------- ------- -------
Weighted average common shares
outstanding - basic 181,210 180,936 180,502
Effect of dilutive securities:
Options - Treasury Stock Method - - 1,945
------- ------- -------
Weighted average common shares
outstanding - diluted 181,210 180,936 182,447
======= ======= =======
In 2003, the Company has excluded approximately 23.3 million shares
issuable upon conversion of the 3.75% Contingent Convertible Senior Notes as
none of the contingencies have been met (see Note 4). The Company incurred net
losses for the years ended December 31, 2003 and 2002 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, 2003 and 2002
were options to purchase 10.2 million shares and 8.7 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.
-35-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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. In December 2002, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standard
("SFAS") No. 148, "Accounting for Stock-Based Compensation-Transition and
Disclosure," which amends SFAS No. 123, "Accounting for Stock-Based
Compensation," by providing alternative methods of transition for a voluntary
change to the fair value method of accounting for stock-based employee
compensation. In addition, SFAS No. 148 amends the provisions of SFAS No. 123 to
require more prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results of operations. The Company
has adopted the more prominent disclosures required by SFAS No. 148 as of March
31, 2003; however, as permitted under SFAS No. 123, the Company continues to
apply Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for its stock
option plans. These plans are more fully described in Note 5.
Accordingly, no compensation expense 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
expense for the stock option grants been determined on the fair value at the
grant dates consistent with the method of SFAS No. 123, the Company's net loss
and loss per share would have been adjusted to the pro forma amounts indicated
below (amounts in thousands, except per share amounts):
2003 2002 2001
----------- ---------- ------------
Net income (loss), as reported $ (30,200) $ (21,476) $ 68,453
Add: Stock-based employee compensation
expense included in reporting net
loss, net of related tax effects - 407 -
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards, net of related tax effects (2,523) (2,249) (1,562)
----------- ---------- ------------
Pro forma net income (loss) $ (32,723) $ (23,318) $ 66,891
=========== ========== ============
Income (loss) per share - basic and diluted
As reported $ (0.17) $ (0.12) $ 0.38
Pro forma $ (0.18) $ (0.13) $ 0.37
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 $2.36 in 2003, $1.80 in 2002 and $3.90 in 2001. The
key input variables used in valuing the options granted in 2003, 2002 and 2001
were: risk-free interest rate based on five-year Treasury strips of 2.89% to
3.35% in 2003, 2.62% in 2002, and 4.60% in 2001; dividend yield of zero in each
year; stock price volatility of 66% to 71% for 2003 and 75% for both 2002 and
2001; 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 8 7/8% Senior Notes at December 31, 2003 and 2002
was $87.6 million and $252.5 million, respectively, compared to the face value
of $85.0 million and $250.0 million, respectively. The fair value of the 3.75%
-36-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Contingent Convertible Senior Notes was $141.2 million at December 31, 2003
versus a face value of $150.0 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 which are used as collateral for letters of
credit securing insurance deposits and other purposes. 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.
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 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 adopted
SFAS No. 143 on January 1, 2003. The adoption of SFAS No. 143 did not have an
effect on the Company's financial condition or results of operations for the
year ended December 31, 2003.
In April, 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment to FASB Statement No. 13, and Technical
Corrections." 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 adopted SFAS No. 145 on January 1, 2003. The adoption of
SFAS No. 145 did not have a material effect on the Company's financial position
or results of operations for the year ended December 31, 2003.
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 adoption of SFAS No. 146 did not have
an effect on the Company's financial position or results of operations for the
year ended December 31, 2003.
-37-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative
Instruments and Hedging Activities," in April 2003. SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149 is effective for existing contracts and
new contracts entered into after June 30, 2003. The provisions of SFAS No. 149
did not have a material impact on the Company's consolidated financial
statements for the year ended December 31, 2003.
The FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity," in May 2003.
SFAS No. 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. SFAS No. 150 is effective for financial instruments entered into or
modified after May 31, 2003 and is otherwise effective at the beginning of the
first interim period beginning after June 15, 2003. The provisions of SFAS No.
150 did not have a material impact on the Company's consolidated financial
statements for the year ended December 31, 2003.
The FASB issued Interpretation ("FIN") No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others," in November 2002. FIN No. 45 is applicable on a
prospective basis for initial recognition and measurement provisions to
guarantees issued after December 2002. FIN No. 45 requires a guarantor to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligations undertaken in issuing the guarantee and expands the required
disclosures to be made by the guarantor about its obligation under certain
guarantees that it has issued. The adoption of FIN No. 45 did not have a
material impact on the Company's financial position or results of operations for
the year ended December 31, 2003.
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 other amounts in 2001 and 2002 have been
reclassified to conform to the presentation in 2003.
(2) SIGNIFICANT PROPERTY TRANSACTIONS
On June 4, 2003, the Company purchased two working rigs for an
aggregate of $9.0 million in cash. One of the rigs purchased is a 1,200
horsepower diesel electric SCR rig capable of drilling to 17,000 feet and the
other is a 1,000 horsepower diesel electric SCR rig capable of drilling to
15,000 feet.
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 an aggregate of $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.
-38-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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,
----------------------------------------------------
2003 2002 2001
------------- ------------ -------------
Current
Federal $ - $ (1,871) $ 1,870
State (938) - 1,107
------------- ------------ -------------
$ (938) $ (1,871) $ 2,977
============= ============ =============
Deferred
Federal $ (14,958) $ (7,080) $ 38,557
State (1,487) 734 1,319
------------- ------------ -------------
$ (16,445) $ (6,346) $ 39,876
============= ============ =============
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 effects of the Company's temporary differences and
carryforwards are as follows (amounts in thousands):
December 31,
--------------------------------
2003 2002
------------ ------------
Deferred tax assets
Net operating loss carryforwards $ 47,964 $ 27,008
Tax credit carryforwards 14 14
Workers compensation accruals 3,501 3,622
Other 1,411 1,229
------------ ------------
52,890 31,873
Deferred tax liabilities
Depreciation 96,386 92,025
------------ ------------
Net deferred tax liability $ 43,496 $ 60,152
============ ============
At December 31, 2003 and 2002, the Company had U.S. net operating loss
("NOL") carryforwards of $154.5 million and $98.2 million, respectively, which
expire at various times from 2010 through 2023. 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 and reversal of deferred tax liabilities 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.
-39-
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,
----------------------------------------------------
2003 2002 2001
------------- ------------ ------------
Income tax expense (benefit) at statutory rate $ (16,654) $ (10,393) $ 38,957
Increase (decrease) in taxes resulting from:
Permanent differences, primarily due to
basis differences in acquired assets 1,208 1,707 1,320
Foreign (income) loss 17 (12) 95
State taxes, net (1,576) 477 1,576
Other (378) 4 905
------------- ------------ ------------
Income tax expense (benefit) $ (17,383) $ (8,217) $ 42,853
============= ============ ============
(4) LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
December 31,
--------------------------
2003 2002
----------- -----------
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 semi-annually $ 84,898 $ 249,613
Contingent convertible senior notes due May 2023, general unsecured
senior obligations guaranteed by the Company's domestic subsidiaries,
bearing interest at 3.75% per annum payable semi-annually 150,000 -
----------- -----------
234,898 249,613
Less current maturities - -
----------- -----------
Long-term debt $ 234,898 $ 249,613
=========== ===========
3.75% Contingent Convertible Senior Notes due May 2023.
On May 7, 2003, the Company issued $150.0 million aggregate principal
amount of 3.75% Contingent Convertible Senior Notes due 2023 (the "3.75% Notes")
in a private offering that yielded net proceeds of $146.6 million. The 3.75%
Notes bear interest at 3.75% per annum and mature on May 7, 2023. The 3.75%
Notes are convertible, upon the occurrence of certain events, at a conversion
price of $6.45 per share, which is equal to a conversion rate of approximately
155.0388 shares per $1,000 principal amount of the 3.75% Notes, subject to
adjustment. The Company will pay contingent interest at a rate equal to 0.50%
per annum during any six-month period, with the initial six-month period
commencing May 7, 2008, if the average trading price of the 3.75% Notes per
$1,000 principal amount for the five day trading period ending on the third day
immediately preceding the first day of the applicable six-month period equals
$1,200 or more. The 3.75% 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. The 3.75% Notes and the guarantees rank equally
with the Company's 8 7/8% Notes due July 2007 (the "8 7/8% Notes"). Fees and
expenses of $3.9 million incurred at the time of issuance are being amortized
through May 2013, the first date the holders may require the Company to
repurchase the 3.75% Notes.
-40-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company may redeem some or all of the 3.75% Notes at any time on or
after May 14, 2008, at a redemption price shown below, payable in cash, plus
accrued but unpaid interest, including contingent interest, if any, to the date
of redemption:
Redemption
Period Price
------ -----
May 14, 2008 through May 6, 2009........................................... 101.88%
May 7, 2009 through May 6, 2010............................................ 101.50%
May 7, 2010 through May 6, 2011............................................ 101.13%
May 7, 2011 through May 6, 2012............................................ 100.75%
May 7, 2012 through May 6, 2013............................................ 100.38%
May 7, 2013 and thereafter................................................. 100.00%
Holders may require the Company to repurchase all or a portion of the
3.75% Notes on May 7, 2013 or May 7, 2018, and upon a change of control, as
defined in the indenture governing the 3.75% Notes, at 100% of the principal
amount of the 3.75% Notes, plus accrued but unpaid interest, including
contingent interest, if any, to the date of repurchase, payable in cash.
The 3.75% Notes are convertible, at the holders' option, prior to the
maturity date into shares of our common stock under the following circumstances:
- during any calendar quarter, if the closing sale price per
share of our common stock for at least 20 trading days in the
period of 30 consecutive trading days ending on the last
trading day of the calendar quarter preceding the quarter in
which the conversion occurs, is more than 110% of the
conversion price per share ($7.10 per share) on that 30th
trading day;
- if the Company has called the 3.75% Notes for redemption;
- during any period that the credit ratings assigned to the
3.75% Notes by both Moody's Investors Service and Standard &
Poor's Ratings Group are reduced below B1 and B+,
respectively, or if neither rating agency is rating the 3.75%
Notes;
- during the five trading day period immediately following any
nine consecutive trading day period in which the average
trading price per $1,000 principal amount of the 3.75% Notes
for each day of such period was less than 95% of the product
of the closing sale price per share of the Company's common
stock on that day multiplied by the number of shares of common
stock issuable upon conversion of $1,000 principal amount of
the 3.75% Notes; or upon the occurrence of specified corporate
transactions, including a change of control.
The 3.75% Notes did not meet the criteria for conversion into common
stock at any time during the year ended December 31, 2003. At February 10, 2004,
the credit ratings assigned to the 3.75% Notes by Moody's Investor Service and
Standard & Poor's Ratings Group were B1 and BB-, respectively.
8 7/8% Notes due July 2007.
At December 31, 2003, the Company had $85.0 million in principal amount
of 8 7/8% Notes outstanding. The 8 7/8% Notes bear interest at 8 7/8% per annum
and mature on July 1, 2007. The 8 7/8% 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.
On July 1, 2003, the $146.6 million of net proceeds from the issuance
of the 3.75% Notes plus $30.6 million of available cash were used to redeem
$165.0 million aggregate principal amount of 8 7/8% Notes previously outstanding
at 102.9580%, plus accrued interest. The redemption premium of $4.9 million was
included in interest expense in the second quarter of 2003. Amortization of the
previously deferred financing costs associated with the partial redemption of
the 8 7/8% Notes on July 1, 2003 was accelerated and approximately $2.5 million
in additional
-41-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
interest expense was recognized in the quarter ended June 30, 2003. All other
fees and expenses incurred at the time of issuance are being amortized and
discounts are being accreted over the life of the 8 7/8% Notes.
The Company has the option to redeem the 8 7/8% Notes in whole or in
part during the twelve month periods 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 8 7/8%
Notes will have the right to require the Company to repurchase all or any part
of such holder's 8 7/8% 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 8 7/8% Notes
through redemption, open market purchases and privately negotiated transactions.
Any difference between the redemption price and the face value of the 8 7/8%
Notes will be recorded as interest expense.
The indentures for the 8 7/8% 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 on the 8 7/8%
Notes, 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 8 7/8% Notes. As of December 31, 2003 we are in compliance
with these covenants.
CIT Facility. The Company's subsidiary Grey Wolf Drilling Company L.P.
has a $75.0 million credit facility with the CIT Group/Business Credit, Inc.
(the "CIT Facility") which expires during January 2006. The CIT 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. 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 1.50%. The CIT Facility provides up to $20.0 million available for
letters of credit. 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.
The CIT Facility contains 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 which is also secured by a guarantee of Grey Wolf, Inc.
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 the contiguous 48 states of the United States of America.
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.
-42-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. 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 including:
- 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" (as defined by the CIT
Facility).
The Company currently has no outstanding balance under the CIT Facility
and had $16.4 million of undrawn standby letters of credit at December 31, 2003.
These standby letters of credit are for the benefit of various insurance
companies as collateral for premiums and retained losses which may become
payable under the terms of the underlying insurance contracts and for other
purposes. Outstanding letters of credit reduce the amount available for
borrowing under the CIT facility.
The Company had non-cash activities for the years ended December 31,
2002 and 2001 related to vehicle additions under capital leases. The non-cash
amounts excluded from cash used in investing activities and cash provided by
financing activities were $199,000 and $1.7 million for the years ended December
31, 2002 and 2001, respectively.
(5) CAPITAL STOCK AND STOCK OPTION PLANS
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 2003 Incentive Plan (the "2003 Plan") was approved by shareholders
in May 2003. The 2003 Plan authorizes the grant of the following equity-based
awards:
- incentive stock options;
- non-statutory stock options;
- restricted shares; and
- other stock-based and cash awards.
-43-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 2003 Plan replaced the Company's 1996 Employee Stock Option Plan
(the "1996 Plan"); provided, however that outstanding options previously granted
shall continue to be exercisable subject to the terms and conditions of such
grants. The 1996 Plan allowed for grants of non-statutory options to purchase
common stock, but no further grants of common stock will be made under the 1996
Plan. The 2003 Plan reserves a maximum of 17.0 million shares of the Company's
common stock underlying all equity-based awards, but is reduced by the shares of
common stock subject to previous grants under the 1996 Plan. At December 31,
2003, there were 6.5 million shares of common stock available for grant under
the 2003 Plan until March 2013. Prior to 2003, the Company also granted options
under stock option agreements with its chief executive officer and directors
that are outside of the 2003 Plan. At December 31, 2003, these individuals had
options outstanding to purchase an aggregate of 2.0 million shares of common
stock.
The exercise price of stock options approximates the fair market value
of the stock at the time the option is granted. 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 created 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,
2003, 2002 and 2001 was as follows (number of shares in thousands):
2003 2002 2001
-------------------- --------------------- ---------------------
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 8,721 $ 2.85 7,512 $ 2.85 7,318 $ 2.25
Granted 2,161 3.91 2,302 2.88 1,149 6.08
Exercised (246) 1.50 (312) 2.20 (846) 1.99
Cancelled (427) 3.43 (781) 3.16 (109) 3.16
------ -------- ------ --------- ------ ---------
Outstanding - end of year 10,209 $ 3.09 8,721 $ 2.85 7,512 $ 2.85
====== ======== ====== ========= ====== =========
-44-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company had stock options exercisable at December 31, 2003 of 5.4
million with a range of exercise prices from $.69 to $6.37. At December 31, 2002
and 2001, there were 4.0 million stock options exercisable, with a range of
exercise prices from $0.69 to $6.37, and 3.2 million stock options exercisable
from $0.69 to $4.50, respectively.
The following table summarizes information about stock options
outstanding at December 31, 2003:
Weighted
Average Weighted
Remaining Average
Number Contractual Exercise
Range of Exercise Prices Outstanding Life(1) Price
- ------------------------ ----------- ----------- ---------
$0.69 to $1.63 2,674 3.78 $ 1.28
$1.75 to $4.38 6,516 7.42 3.35
$4.44 to $6.37 1,019 7.11 6.12
------ ---- ---------
10,209 6.44 $ 3.09
====== ==== =========
- --------------------------
(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 2003, 2002 and 2001 were $4.1 million, $3.4 million and $6.0 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, 2003: 2004 - $674,000; 2005 - $201,000; 2006 - $56,000; 2007 -
$7,000; 2008 - $7,000; and $0 thereafter.
Lease expense under operating leases for 2003, 2002 and 2001 were
approximately $718,000, $680,000 and $618,000, respectively.
-45-
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 $873,000,
$1.3 million, and $1.3 million for the years ended December 31, 2003, 2002 and
2001, 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, 2003, 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, 2003 and 2001.
(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 No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets." After
review of rigs held for future refurbishment, the Company no longer intended to
return five of those rigs to service, but instead decided to 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 Company revised the number of drilling rigs in its
fleet. The fair market value was based on an appraisal obtained from a third
party appraiser.
-46-
GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(13) QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for years ended December 31, 2003,
2002 and 2001 are set forth below (amounts in thousands, except per share
amounts).
Quarter Ended
---------------------------------------------------------
March June September December
2003 2003 2003 2003
----------- ----------- ----------- -----------
Revenues $ 62,387 $ 66,949 $ 72,383 $ 84,255
Gross profit (operating margin) (1) 7,102 7,380 7,866 19,339
Operating income (loss) (8,435) (7,892) (7,678) 3,205
Loss before income taxes (14,148) (21,921) (11,183) (331)
Net income (loss) (9,621) (14,185) (6,950) 556
Net income (loss) per common share
- basic and diluted (0.05) (0.08) (0.04) 0.00
Quarter Ended
---------------------------------------------------------
March June September December
2002 2002 2002 2002
----------- ----------- ----------- -----------
Revenues $ 64,912 $ 62,854 $ 61,118 $ 61,376
Gross profit (operating margin) (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 (0.01) (0.02) (0.03) (0.05)
Quarter Ended
---------------------------------------------------------
March June September December
2001 2001 2001 2001
----------- ----------- ----------- -----------
Revenues $ 101,136 $ 114,967 $ 128,030 $ 89,606
Gross profit (operating margin) (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 0.07 0.11 0.14 0.05
- -----------------------------
(1) Gross profit (operating margin) is computed as consolidated
revenues less operating expenses (which excludes expenses for
depreciation and general and administrative.
-47-
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, 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
========= ======== ========= =========
Year Ended December 31, 2003
Allowance for doubtful accounts receivable $ 2,500 $ - $ (57) $ 2,443
========= ======== ========= =========
-48-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
As of December 31, 2003, 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 control over
financial reporting that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
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 2004 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, 2003.
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 2004 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, 2003.
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 2004 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, 2003.
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 2004
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, 2003.
-49-
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item as to accounting fees and
services is hereby incorporated by reference to such information appearing under
the caption "Independent Auditors" in our definitive proxy statement for our
2004 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, 2003.
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
8 7/8% Senior Notes due 2007 by 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
8 7/8% 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).
-50-
4.8 -- Indenture, dated as of May 7, 2003, relating to the 3.75%
Contingent Convertible Senior Notes due 2023 between the
Company, the Guarantors, and JPMorgan Chase Bank, a New York
Banking Corporation, as Trustee (incorporated herein by
reference to Exhibit 4.2 to the Company's Registration Statement
on Form S-3 No. 333-106997 filed July 14, 2003).
4.9 -- Supplemental Indenture, dated as of May 22, 2003, relating to
the 3.75% Contingent Convertible Senior Notes due 2023 between
the Company, the Guarantors, and JPMorgan Chase Bank, a New York
Banking Corporation, as Trustee (incorporated herein by
reference to Exhibit 4.3 to the Company's Registration Statement
on Form S-3 No. 333-106997 filed July 14, 2003).
10.1 -- 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).
10.2 -- 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).
10.3 -- 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).
10.4 -- Grey Wolf, Inc. 1996 Employee Stock Option Plan (incorporated
herein by reference to Grey Wolf, Inc. 1996 Annual Meeting of
Shareholders definitive proxy materials).
10.5 -- 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).
10.6 -- 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).
10.7 -- 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).
10.8 -- 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).
10.9 -- Form of Non-Qualified 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).
10.10 -- 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).
10.11 -- 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).
10.12 -- 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) (incorporated herein by reference to Grey Wolf,
Inc. Annual Report on Form 10-K for the year ended December 31,
2002).
-51-
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 -- Employment Agreement effective March 31, 2003 by and between the
Company and William E. Chiles (incorporated herein by reference
to Grey Wolf, Inc. Quarterly Report on Form 10-Q for the quarter
ended March 31, 2003).
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 -- Grey Wolf, Inc. 2003 Incentive Plan (incorporated herein by
reference to Grey Wolf, Inc. 2003 Annual Meeting of Shareholders
definitive proxy materials).
*21.1 -- List of Subsidiaries of Grey Wolf, Inc.
*23.1 -- Consent of KPMG LLP
*31.1 -- Certification of Chief Executive Officer pursuant to Rule
13a-14(a).
*31.2 -- Certification of Chief Financial Officer pursuant to Rule
13a-14(a).
*32.1 -- 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 and David W. Wehlmann, Executive Vice President and
Chief Financial Officer.
- --------
* Filed herewith
-52-
(b) Reports on Form 8-K
1. We furnished a Report on Form 8-K under Item 12 with the
Securities and Exchange Commission on October 23, 2003 with
regard to our press release announcing operating results for
the quarter ended September 30, 2003.
2. We furnished a Report on Form 8-K under Item 12 with the
Securities and Exchange Commission on February 2, 2004 with
regard to our press release announcing operating results for
the quarter and year ended December 31, 2003.
-53-
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 12th day of
February, 2004.
Grey Wolf, Inc.
By: /s/ David W. Wehlmann
--------------------------------------
David W. Wehlmann, Executive 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 February 12, 2004
----------------------------------------------------------------------------
Thomas P. Richards, Chairman, President and Chief Executive Officer
(Principal Executive Officer)
By: /s/ David W. Wehlmann February 12, 2004
----------------------------------------------------------------------------
David W. Wehlmann, Executive Vice President and Chief Financial Officer
By: /s/ Merrie S. Costley February 12, 2004
----------------------------------------------------------------------------
Merrie S. Costley, Vice President and Controller
By: /s/ William R. Ziegler February 12, 2004
----------------------------------------------------------------------------
William R. Ziegler, Director
By: /s/ Frank M. Brown February 12, 2004
----------------------------------------------------------------------------
Frank M. Brown, Director
By: /s/ William T. Donovan February 12, 2004
----------------------------------------------------------------------------
William T. Donovan, Director
By: /s/ James K. B. Nelson February 12, 2004
----------------------------------------------------------------------------
James K. B. Nelson, Director
By: /s/ Robert E. Rose February 12, 2004
----------------------------------------------------------------------------
Robert E. Rose, Director
By: /s/ Steven A. Webster February 12, 2004
----------------------------------------------------------------------------
Steven A. Webster, Director
-54-
INDEX TO 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
8 7/8% Senior Notes due 2007 by 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
8 7/8% 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).
4.8 -- Indenture, dated as of May 7, 2003, relating to the 3.75%
Contingent Convertible Senior Notes due 2023 between the
Company, the Guarantors, and JPMorgan Chase Bank, a New York
Banking Corporation, as Trustee (incorporated herein by
reference to Exhibit 4.2 to the Company's Registration Statement
on Form S-3 No. 333-106997 filed July 14, 2003).
4.9 -- Supplemental Indenture, dated as of May 22, 2003, relating to
the 3.75% Contingent Convertible Senior Notes due 2023 between
the Company, the Guarantors, and JPMorgan Chase Bank, a New York
Banking Corporation, as Trustee (incorporated herein by
reference to Exhibit 4.3 to the Company's Registration Statement
on Form S-3 No. 333-106997 filed July 14, 2003).
10.1 -- 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).
10.2 -- 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).
10.3 -- 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).
10.4 -- Grey Wolf, Inc. 1996 Employee Stock Option Plan (incorporated
herein by reference to Grey Wolf, Inc. 1996 Annual Meeting of
Shareholders definitive proxy materials).
10.5 -- 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).
10.6 -- 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).
10.7 -- 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).
10.8 -- 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).
10.9 -- Form of Non-Qualified 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).
10.10 -- 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).
10.11 -- 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).
10.12 -- 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) (incorporated herein by reference to Grey Wolf,
Inc. Annual Report on Form 10-K for the year ended December 31,
2002).
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 -- Employment Agreement effective March 31, 2003 by and between the
Company and William E. Chiles (incorporated herein by reference
to Grey Wolf, Inc. Quarterly Report on Form 10-Q for the quarter
ended March 31, 2003).
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 -- Grey Wolf, Inc. 2003 Incentive Plan (incorporated herein by
reference to Grey Wolf, Inc. 2003 Annual Meeting of Shareholders
definitive proxy materials).
*21.1 -- List of Subsidiaries of Grey Wolf, Inc.
*23.1 -- Consent of KPMG LLP
*31.1 -- Certification of Chief Executive Officer pursuant to Rule
13a-14(a).
*31.2 -- Certification of Chief Financial Officer pursuant to Rule
13a-14(a).
*32.1 -- 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 and David W. Wehlmann, Executive Vice President and
Chief Financial Officer.
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* Filed herewith