OMNI ENERGY SERVICES CORP - 10-K Annual Report

Back to GetFilings.com

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 2001

[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934

COMMISSION FILE NUMBER 0-23383

OMNI ENERGY SERVICES CORP.
(Exact name of registrant as specified in our charter)

LOUISIANA 72-1395273
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

4500 N.E. EVANGELINE THRUWAY 70520
CARENCRO, LOUISIANA (Zip Code)
(Address of principal executive offices)

Registrant's telephone number, including area code: (337) 896-6664

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $0.01 par value per share

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 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. [ ]

The aggregate market value of the voting stock held by non-affiliates
of the registrant at March 25, 2002 was $ 11,078,100.

The number of shares of the Registrant's common stock, $0.01 par value
per share, outstanding at March 25, 2002 was 27,295,474.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant's Proxy Statement for our 2002 annual
meeting of shareholders have been incorporated by reference into Part III of
this Form 10-K.

OMNI ENERGY SERVICES CORP.
ANNUAL REPORT ON FORM 10-K FOR
THE FISCAL YEAR ENDED DECEMBER 31, 2001

TABLE OF CONTENTS

-i-

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

GENERAL

We, OMNI Energy Services Corp., are an oilfield service company
specializing in providing an integrated range of onshore seismic drilling,
permitting, survey and helicopter support services to geophysical companies
operating in logistically difficult and environmentally sensitive terrain in the
United States. Our principle market is the marsh, swamp, shallow water and
contiguous dry land areas along the U.S. Gulf Coast (the "Transition Zone"),
primarily in Louisiana and Texas, where we are the leading provider of seismic
drilling support services. During the latter part of 1997, we commenced
operations in the mountainous regions of the Western United States. Prior to
1999 we had operations in Canada and Bolivia, but in 1999 we ceased our
international operations pending improvements in the international marketplace.

We own and operate a fleet of specialized seismic drilling and
transportation equipment for use in the Transition Zone. We believe we are the
only company that currently can both provide an integrated range of seismic
drilling, permitting, survey and helicopter support services in all of the
varied terrains of the Transition Zone and simultaneously support operations for
multiple, large-scale seismic projects. We recently announced that we had
acquired all of the assets of AirJac Drilling, a division of Veritas Land DGC.
This acquisition creates the largest domestic provider of seismic drilling
services to geophysical companies. We maintain a fleet of helicopters, aviation
and turbine engine inventories and miscellaneous flight and other equipment used
in providing aviation services to our customers.

We were founded in 1987, as OMNI Drilling Corporation, to provide
drilling services to the geophysical industry. In July 1996, OMNI Geophysical,
L.L.C. acquired substantially all of the assets of OMNI Geophysical Corporation,
the successor to the business of OMNI Drilling Corporation. OMNI Energy Services
Corp. ("OMNI") was formed as a Louisiana corporation on September 11, 1997. On
December 4, 1997, we completed a share exchange, pursuant to which the holders
of common units in OMNI Geophysical, L.L.C. exchanged all of the outstanding
common units of OMNI Geophysical, L.L.C. for 12,000,000 shares of OMNI's common
stock, $0.01 par value per share (the "Common Stock"), and completed an initial
public offering of 3,450,000 shares of Common Stock.

INDUSTRY OVERVIEW

Seismic data generally consists of computer-generated three-dimensional
("3-D") images or two dimensional ("2-D") cross sections of subsurface geologic
formations and is used in the exploration for new hydrocarbon reserves and as a
tool for enhancing production from existing reservoirs. Onshore seismic data is
acquired by recording subsurface seismic waves produced by an energy source,
usually dynamite, at various points ("source points") at a project site.
Historically, 2-D surveys were the primary technique used to acquire seismic
data. However, advances in computer technology have made 3-D seismic data, which
provides a more comprehensive geophysical image, a practical and capable oil and
gas exploration and development tool. 3-D seismic data has proven to be more
accurate and effective than 2-D data at identifying potential
hydrocarbon-bearing geological formations. The use of 3-D seismic data to
identify locations to drill both exploration and development wells has improved
the economics of finding and producing oil and gas reserves, which in turn has
created increased demand for 3-D seismic surveys and seismic support services.

Oil and gas companies generally contract with independent geophysical
companies to acquire seismic data. Once an area is chosen for seismic analysis,
permits and landowner consents are obtained, either by us, the geophysical
company or special permitting agents. The geophysical company then determines
the layout of the source and receiving points. For 2-D data, the typical
configuration of source and receiving points is a straight line with a source
point and small groups of specialized sensors ("geophones") or geophone
stations, placed evenly every few hundred feet along the line. For 3-D data, the
configuration is generally a grid of perpendicular lines spaced a few hundred to
a few thousand feet apart, with geophone stations spaced evenly every few
hundred feet along one set of parallel lines, and source points spaced evenly
every few hundred feet along the perpendicular lines. This configuration is
designed by the geophysical company to provide the best imaging of the targeted
geological structures while taking into account surface obstructions such as
water wells, oil and gas wells, pipelines and areas where landowner consents
cannot be obtained. The source points and geophone locations are then marked by
a survey team, and the source points are drilled and loaded with dynamite.

-1-

After the source points have been drilled and loaded and the network of
geophones and field recording boxes deployed over a portion of the project area,
the dynamite is detonated at a source point. Seismic waves generated by the
blast move through the geological formations under the project area and are
reflected by various subsurface strata back to the surface where they are
detected by geophones. The signals from the geophones are collected and
digitized by recording boxes and transmitted to a central recording system. In
the case of 2-D data, the geophones and recording devices from one end of the
line are then shuttled, or "rolled forward," to the other end of the line and
the process is repeated. In the case of 3-D data, numerous source points,
typically located between the first two lines of a set of three or four parallel
lines of geophone stations, are activated in sequence. The geophone stations and
recording boxes from the first of those lines are then rolled forward to form
the next line of geophone stations. The process is repeated, moving a few
hundred feet at a time, until the entire area to be analyzed has been covered.

After the raw seismic data has been acquired, it is sent to a data
processing facility. The processed data can then be manipulated and viewed on
computer work stations by geoscientists to map the subsurface structures to
identify formations where hydrocarbons are likely to have accumulated and to
monitor the movement of hydrocarbons in known reservoirs. Domestically, seismic
drilling and survey services are typically contracted to companies such as OMNI
as geophysical companies have found it more economical to outsource these
services and focus their efforts and capital on the acquisition and
interpretation of seismic data.

DESCRIPTION OF OPERATIONS

We provide an integrated range of onshore seismic drilling, operational
support, permitting, survey and helicopter support services to geophysical
companies operating in logistically difficult and environmentally sensitive
terrain in the United States.

SEISMIC DRILLING SERVICES. Our primary activity is the drilling and
loading of source points for seismic analysis. Once the various source points
have been plotted by the geophysical company and a survey crew has marked their
locations, our drill crews are deployed to drill and load the source points.

In the Transition Zone, we use water pressure rotary drills mounted on
various types of vehicles to drill the source holes. The type of vehicle used is
determined by the nature, accessibility and environmental sensitivity of the
terrain surrounding the source point. Transition Zone source holes are generally
drilled to depths of 40 to 180 feet depending on the nature of the terrain and
the needs of the geophysical company, using ten-foot sections of drill pipe
which are carried with the drilling unit. Our Transition Zone vehicles are
typically manned with a driver and one or two helpers. The driver is responsible
for maneuvering the vehicle into position and operating the drilling unit, while
the helper sets and guides the drill into position, attaches the drilling unit's
water source, if drilling in dry areas, and loads the drill pipe sections used
in the drilling process. Once the hole has been drilled to the desired depth, it
is loaded with dynamite, which is carried onboard our vehicles in special
containers. The explosive charge is set at the bottom of the drill hole and then
tested to ensure that the connection has remained intact. Once the charge has
been tested, the hole is plugged in accordance with local, state and federal
regulations and marked so that it can be identified for detonation by the
geophysical company at a later date. This process is repeated throughout the
survey area until all source points have been drilled and loaded.

In seismic rock drilling, we use compressed air rotary/hammer drills to
drill holes that are typically shallower than Transition Zone holes. Rock drills
are manned by a two-man or three-man crew and are transported to and from
locations by hand, surface vehicle or helicopter. Once the hole has been drilled
to the desired depth, it is loaded with explosives which are delivered to the
job site in an explosive magazine carried by hand, vehicle or helicopter.

-2-

OPERATIONAL SUPPORT SERVICES. We are able to coordinate a variety of
related services to customers performing 3-D seismic data acquisition projects
that produce significant economies and value. Our substantial base of experience
gained from years of work supporting 3-D seismic projects enables us to provide
significant pre-job planning information to the customer during job design
analysis. Typical 3-D seismic data acquisition projects in the field involve
large amounts of equipment, personnel and logistics coordination. Coordination
of movements between permitting, drilling, survey and recording crews is of
critical importance to timely, safe and cost effective execution of the job. We
have a pool of senior field supervisors who have broad seismic industry
experience and are able to coordinate the activities of drill crews, permit
agents and survey teams with the recording crews to achieve improved results.
These personnel also have the ability to recommend changes to the customer field
representatives in the manner of executing the job in the field to improve
performance and reduce costs. By having the ability to perform significant field
coordination, we are able to streamline field decision making and information
flow and reduce customer overhead costs that otherwise would be required to
perform these supervisory tasks. We also have one of the industry's leading
Health, Safety and Environmental ("HSE") programs. The involvement of our
experienced personnel monitoring HSE field practices greatly reduces customer
involvement in this area. By offering the only integrated combination of seismic
drilling, permit acquisition, seismic survey and operational support, in
addition to an equipment fleet that is one of the largest in terms of number of
units and most diverse in the industry, we provide significant operational
advantages to the customer.

PERMITTING SERVICES. In November 2000, we created a "Geophysical Permit
Acquisition Division." Our staff of contract permit agents first conduct
research in public land title records to determine ownership of the lands
located in the seismic projects. The permit agents then contact, negotiate and
acquire permits and landowner consents for the survey, drilling and recording
crews to conduct their operations. Throughout the seismic data acquisition
process, the permit agents assist the crews in the field with landowner
relations and permit restrictions in order to reduce field-crew downtime for
noncompliance with landowner requests. Our permit services are enhanced with the
assistance of a proprietary database software program specifically designed for
efficient management of seismic projects.

At December 31, 2001 we had 9 permit agents under contract conducting
services throughout the Gulf Coast States. These agents have significant
experience in the permit acquisition and management process.

SURVEY SERVICES. Once all permits and landowner consents for a seismic
project have been obtained and the geophysical company has determined the
placement of source and receiving points, survey crews are sent into the field
to plot each source and receiving point prior to drilling. We employ both GPS
(global positioning satellite) equipment, which is more efficient for surveying
in open areas, and conventional survey equipment, which is generally used to
survey wooded areas. We have successfully integrated both types of equipment in
order to complete projects throughout the varied terrain of the Transition Zone
and elsewhere. In addition, the survey crews have access to our extensive fleet
of specialized transportation equipment, as opposed to most other survey
companies which must rent this equipment.

HELICOPTER SUPPORT SERVICES. Through our Aviation division, created
with the acquisition of substantially all of the assets of American Aviation
Incorporated ("American Aviation") in July 1997, we provide helicopter support
services to geophysical companies throughout the continental United States.
Also, we have ongoing offshore contracts with service companies operating in the
Gulf of Mexico, and we provide helicopter support to certain federal and state
governmental agencies when needed. We use long-line helicopters to shuttle
geophones and recorders used to collect seismic data between receiving points.
Once seismic data has been acquired from a portion of the project site, the
geophones and recorders must be moved into position to collect data from the
next area to be analyzed. By using helicopters, we are able to reduce delays in
completing stages of a seismic project by transporting the geophones and
recording boxes to the next receiving points in the survey area in an efficient
manner and with minimal environmental impact. Our helicopters are also used to
transport heli-portable drilling units into remote or otherwise inaccessible
terrain in an efficient and environmentally sensitive manner.

At December 31, 2001 we operated 12 helicopters, 11 of which were
owned. We have decided to reduce the number of aircraft used in our seismic
support services to improve the utilization of our fleet. Since December 31,
2001, we have sold one of the aircraft used in our seismic operations and we are
currently considering plans to sell additional aircraft. Our pilots have an
average of approximately 10,000 flight hours. We perform all routine maintenance
and repairs on our aircraft at our facilities in Carencro, Louisiana.

-3-

INTERNATIONAL OPERATIONS. We commenced line cutting and survey services
in South America in July 1998, in conjunction with the formation of our joint
venture, OMNI International Energy Services - South America, Ltd. During 1999,
we removed a portion of our equipment from South America and reduced operating
levels to a minimum pending improvements in market conditions. We are currently
trying to sell our remaining assets in South America.

FABRICATION AND MAINTENANCE. At our Carencro facilities, we perform all
routine repairs and maintenance for our Transition Zone and highland drilling
equipment. We design and fabricate aluminum marsh all terrain vehicles (ATVs), a
number of our support boats and pontoon boats, and the drilling units we use on
all of our Transition Zone equipment. We purchase airboats directly from the
manufacturer and then modify the airboats to install the drilling equipment. We
have also designed and built a limited number of highland drilling units by
installing our drilling equipment on tractors bought directly from the
manufacturer. We also fabricate rock drilling equipment and have the capability
of fabricating other key equipment, such as swamp ATVs. Because of our ability
to fabricate and maintain much of our equipment, we do not believe that we are
dependent on any one supplier for our drilling equipment or parts.

FACILITIES AND EQUIPMENT

Facilities. In early 1998, we completed the construction of two new
buildings which house our corporate headquarters, fabrication facility and
primary maintenance facility. The buildings are located on approximately 34
acres of land in Carencro, Louisiana. The buildings provide approximately 20,000
square feet of office space and 32,000 square feet of covered maintenance and
fabrication space. From 1999 to 2001, we leased from an affiliate two additional
buildings adjacent to our main headquarters. The buildings provided
approximately 2,500 square feet of office space and 19,000 square feet of
covered maintenance, fabrication and warehouse space. We used these buildings
for the storage and maintenance of a portion of our survey and aviation assets.
The lease on these facilities expired in 2001, at which point we moved the
remaining assets and personnel to our other facilities.

We lease an operations base in Loveland, Colorado to support our rock
drilling operations. We own an office and warehouse facility in Santa Cruz,
Bolivia, which is currently for sale.

Transition Zone Transportation and Drilling Equipment. Because of the
varied terrain throughout the Transition Zone and the prevalence of
environmentally sensitive areas, we employ a wide variety of drilling vehicles.
We believe that we are the only company currently operating in the Transition
Zone that owns and operates all of the following types of equipment:

(1) Twenty-four of these drilling units are currently dedicated to seismic
rock drilling operations outside of the Transition Zone.

(2) Eight of these drilling units are currently being held for sale by us
(See Note 5 to the Consolidated Financial Statements).

Because of our extensive fleet of Transition Zone transportation and
seismic drilling equipment, much of which we fabricate, we believe that we are
the only company that currently can provide an integrated range of seismic
drilling and

-4-

survey services in all of the varied terrains of the Transition Zone and
simultaneously support operations for multiple, large-scale seismic projects.

Highland Drilling Units and Water Buggies. We currently own and operate
59 highland drilling units for seismic drilling in dry land areas, 24 of which
are currently dedicated to our seismic rock drilling operations outside of the
Transition Zone. These units generally consist of a tractor-like vehicle with a
drilling unit mounted on the rear of the vehicle. This highland drilling unit
can be driven over land from point to point and is accompanied by a unit
referred to as a "water buggy" that carries water required for water pressure
rotary drills. This type of vehicle is used around the world for this type of
terrain.

Marsh ATVs. The environmentally sensitive wetlands along the U.S. Gulf
Coast containing water grasses on dry land and in shallow water and areas mixed
with open water are referred to as marsh areas. When there is a minimum amount
of water in these areas, marsh ATVs, which are amphibious vehicles supported by
pontoons that are surrounded by tracks, are used to provide seismic drilling
services. The pontoons enable the marsh ATV to float while the tracks propel the
vehicle through the water and over dry marsh areas. Each marsh ATV is equipped
with a drilling unit and a small backhoe for digging and a small hole to collect
water necessary for drilling.

Some marsh areas have sufficient surrounding water to support drilling
without an external water source, but often water must be pumped into the area
from a remote water source or a portable supply must be carried by the marsh
ATV.

We own and operate 27 marsh ATVs, of which 8 are made of stainless
steel and 19 are made of aluminum. All of the stainless steel marsh ATVs are
being held for sale. The aluminum ATVs are lighter than steel vehicles and are
specifically designed for the environmentally sensitive areas typically found in
marsh terrain. Landowner consents will often require the use of aluminum ATVs in
an effort to reduce the environmental impact of seismic drilling. The aluminum
marsh ATV is the most widely accepted marsh vehicle for drilling operations in
all Louisiana state and federal refuges. We fabricate our own aluminum marsh
ATVs at our facilities in Carencro, Louisiana.

Airboat Drilling Units. We own and operate 35 airboat drilling units.
An airboat drilling unit consists of a drilling unit fabricated and installed by
us on a large, three-engine airboat. Because of their better mobility, airboat
drilling units are used in shallow waters and all marsh areas where sufficient
water is present.

Swamp ATVs and Pullboats. Wooded lowland typically covered with water
are referred to as the "swamp areas" of the Transition Zone. Our swamp ATVs are
used to provide drilling services in these areas. Swamp ATVs are smaller,
narrower versions of the marsh ATVs. The smaller unit is needed in swamp areas
due to the dense vegetation typical in the terrain. Because of its smaller size,
the swamp ATV uses a skid-mounted drilling unit installed in a pullboat, a
non-motorized craft towed behind the swamp ATV. We own and operate 25 swamp ATVs
and 16 pullboats. Swamp ATVs are also used in connection with survey operations
in swamp areas.

Pontoon Boats. We own and operate 16 pontoon boats that are used in
shallow or protected inland bays and lakes and shallow coastal waters. Each
pontoon boat uses a skid-mounted drilling unit installed on board.

Jack-Up Rigs. When a seismic survey requires source points to be
drilled in deeper inland bays or lakes or in deeper coastal waters, we use
jack-up rigs equipped with one of our skid-mounted drilling units. Seismic
activity in water deeper than approximately 20 feet is generally conducted by
using offshore seismic techniques that do not include the drilling and loading
of source points.

Skid-Mounted Drilling Units. A skid-mounted drilling unit is a drilling
unit mounted on I-beam supports, which allows the drilling unit to be moved
easily between pullboats, pontoon boats, jack-up rigs and other equipment we
operate based on customer needs. We manufacture our skid-mounted drilling units
at our facilities in Carencro, Louisiana and we own 17 of these units, one of
which is located outside of the Transition Zone.

Miscellaneous. We own and operate 88 single engine airboats and 21
outboard powered boats, which we use to ferry personnel and supplies to
locations throughout the Transition Zone. We also maintain a fleet of 5
tractor-trailer trucks and numerous other trucks, trailers and vehicles to move
our equipment and personnel to projects throughout the Transition Zone.

-5-

Heli-portable and Seismic Rock Drilling Equipment. We have 37
heli-portable and man-portable drilling units and 36 highland drilling units
dedicated to seismic rock drilling. We also have the ability to manufacture our
own heli-portable and man-portable seismic rock drilling units, and often export
and provide servicing of heli-portable and man-portable drilling units.

Aviation Equipment. The following table sets forth the type and number
of helicopters that are operated by our Aviation division:

(1) We lease this aircraft.

(2) We sold this aircraft subsequent to December 31, 2001.

MATERIALS AND EQUIPMENT

The principal materials and equipment we use in our operations, which
include drills, heli-portable and man-portable drills, drill casings, drill
bits, engines, gasoline and diesel fuel, dynamite, aluminum and steel plate,
welding gasses, trucks and other vehicles, are currently in adequate supply from
many sources. We do not depend upon any single supplier or source for such
materials.

SAFETY AND QUALITY ASSURANCE

We maintain a stringent safety assurance program to reduce the
possibility of costly accidents. Our HSE department establishes guidelines to
ensure compliance with all applicable state and federal safety regulations and
provides training and safety education through orientations for new employees,
which include first aid and CPR training. Our HSE manager reports directly to
our Chief Executive Officer and supervises two HSE field advisors and one
instructor who provides OSHA-mandated training. We believe that our safety
program and commitment to quality are vital to attracting and retaining
customers and employees.

Each drilling crew is supervised at the project site by a field
supervisor and, depending on the project's requirements, an assistant supervisor
and powderman who is in charge of all explosives. For large projects or when
required by a customer, a separate advisor from our HSE department is also
located at the project site. Management is provided with daily updates for each
project and believes that our daily review of field performance together with
the on-site presence of supervisory personnel helps ensure high quality
performance for all of our projects.

Our pilots are trained to FAA FAR 135 (non-scheduled commercial
passenger) or 133 (external load) standards and must satisfy annual FAA
check-rides. Licensed maintenance personnel are deployed to each project site at
which aircraft are used.

-6-

CUSTOMERS; MARKETING; CONTRACTING

Customers. Our customers are primarily geophysical companies, although
in many cases the oil and gas company participates in determining which
drilling, permitting, survey or aviation company will be used on our seismic
projects. A large portion of our revenue has historically been generated by a
few customers. For example, our largest customers (those which individually
accounted for more than 10% of revenue in a given year, listed alphabetically)
collectively accounted for 60% (Eagle Geophysical, Veritas and Western
Geophysical), 34% (Western Geophysical), and 71% (Grant Geophysical, Quantum
Geophysical and Western Geophysical) of revenue for fiscal 1999, 2000 and 2001,
respectively.

Marketing. Our services traditionally have been marketed by our
principal executive officers. We believe that this marketing approach helps us
preserve long-term relationships established by our executive officers. As our
geographical and service capabilities expand, we intend to continue implementing
our marketing efforts in the Transition Zone from our principal offices in
Carencro, Louisiana and in the Rocky Mountain region from Loveland, Colorado.

Contracting - Seismic Drilling. We generally contract with our
customers for seismic drilling services on a unit-price basis, either on a per
hole or per foot basis. These contracts are often awarded after a competitive
bidding process. We price our contracts based on detailed project specifications
provided by the customer, including the number, location and depth of source
holes and the project's completion schedule. As a result, we are generally able
to make a relatively accurate determination prior to pricing a contract of the
type and amount of equipment required to complete the contract on schedule.

Because of unit-price contracting, we frequently bear the risk of
production delays that are beyond our control, such as those caused by adverse
weather. We often bill the customer standby charges if our operations are
delayed due to delays in permitting or surveying or for other reasons within the
geophysical company's control.

Contracting - Permitting Services. We contract with our customers for
permitting services on a day rate or per project basis. Under the per project
basis, revenue is recognized when certain percentages of the permitting process
are completed. Contracts are often awarded to us only after competitive bidding.
In the case of the per project basis, we determine the price after we have taken
into account such factors as the number of permit agents, the number of permits
and the detailed project specification provided by the customer.

Contracting - Survey Services. We contract with our customers for
seismic survey services on a day rate or per mile basis. Under the per mile
basis, revenue is recognized when the source or receiving point is marked by one
of our survey crews. Contracts are often awarded to us only after competitive
bidding. In each case, the price is determined after we have taken into account
such factors as the number of surveyors and other personnel, the type of terrain
and transportation equipment, and the precision required for the project based
on detailed project specifications provided by the customer.

COMPETITION

Seismic Drilling Services. The principal competitive factors for
seismic drilling services are price and the ability to meet customer schedules,
although other factors including safety, capability, reputation and
environmental sensitivity are also considered by customers when deciding upon a
provider of seismic drilling services. We have numerous competitors in the
Transition Zone and, in particular, in the highland areas in which we operate.
We believe that no other company operating in the Transition Zone owns a fleet
of Transition Zone seismic drilling equipment as varied or as large as we ours.
Our extensive and diverse equipment base allows us to provide drilling services
to our customers throughout the Transition Zone with the most efficient and
environmentally appropriate equipment. We believe there are numerous competitors
offering rock and heli-portable drilling in the Rocky Mountain region and
internationally.

Helicopter Support Services. We have numerous competitors that provide
helicopter support services to geophysical companies operating in the Transition
Zone and service companies operating offshore in the Gulf of Mexico. We believe
that we are the only company offering both seismic drilling and long-line
support services in the Transition Zone. We believe that there are numerous
companies offering helicopter services in rock drilling and other mountain
areas, as well as internationally. All of these companies have greater
experience in these areas and several operate more aircraft than we do in these
areas.

-7-

Permitting Services. Our competitors include a number of established
companies with a number of permit agents comparable to us and numerous larger
companies.

Survey Services. Our competitors include a number of established
companies with a number of crews comparable to us and numerous larger companies.

SEASONALITY AND WEATHER RISKS

Our operations are subject to seasonal variations in weather conditions
and daylight hours. Since our activities take place outdoors, the average number
of hours worked per day, and therefore the number of holes drilled or surveyed
per day, generally is less in winter months than in summer months, due to an
increase in rainy, foggy and cold conditions and a decrease in daylight hours.
Furthermore, demand for seismic data acquisition activity by oil and gas
companies in the first quarter is generally lower than at other times of the
year. As a result, our revenue and gross profit during the first quarter of each
year are typically low as compared to the other quarters. Operations may also be
affected by the rainy weather, lightning, hurricanes and other storms prevalent
along the Gulf Coast throughout the year and by seasonal climatic conditions in
the Rocky Mountain area. In addition, prolonged periods of dry weather result in
slower drill rates in marsh and swamp areas as water in the quantities needed to
drill is more difficult to obtain and equipment movement is impeded. Adverse
weather conditions and dry weather can also increase maintenance costs for our
equipment and decrease the number of vehicles available for operations.

BACKLOG

Our backlog represents those seismic drilling projects for which a
customer has hired us and has scheduled a start date for the project. Projects
currently included in our backlog are subject to termination or delay without
penalty at the option of the customer, which could substantially reduce the
amount of backlog currently reported.

As of December 31, 2001, our backlog was approximately $29.3 million
compared to $18.5 million at December 31, 2000. Backlog at December 31, 2001
includes seismic drilling projects in the Transition Zone in addition to seismic
rock drilling projects. We recently announced that our backlog for the year
ending 2002 now exceeds $37.0 million. Our aviation division historically has
not measured backlog due to the nature of our business and our contracts are
generally cancelable by either party with thirty days written notice.

GOVERNMENTAL REGULATION

Our operations and properties are subject to and affected by various
types of governmental regulation, including laws and regulations governing the
entry into and restoration of wetlands, the handling of explosives and numerous
other federal, state and local laws and regulations. To date our cost of
complying with such laws and regulations has not been material, but because such
laws and regulations are changed frequently, it is not possible for us to
accurately predict the cost or impact of such laws and regulations on our future
operations.

Furthermore, we depend on the demand for our services by the oil and
gas industry and are affected by tax legislation, price controls and other laws
and regulations relating to the oil and gas industry generally. The adoption of
laws and regulations curtailing exploration and development drilling for oil and
gas in our areas of operations for economic, environmental or other policy
reasons would adversely affect our operations by limiting demand for our
services. We cannot determine to what extent our future operations and earnings
may be affected by new legislation, new regulations or changes in existing
regulations.

Aviation. As a commercial operator of small aircraft, we are subject to
regulations pursuant to the Federal Aviation Administration Authorization Act of
1994, as amended (the "Federal Aviation Act"), and other statutes. The FAA
regulates our flight operations, and in this respect, exercises jurisdiction
over personnel, aircraft, ground facilities and other aspects of our operations.

We carry persons and property in our aircraft pursuant to authority
granted by the FAA. Under the Federal Aviation Act it is unlawful to operate
certain aircraft for hire within the United States unless such aircraft are
registered with the FAA and the operator of such aircraft has been issued an
operating certificate by the FAA. We have all FAA certificates required to
conduct our helicopter and aviation operations, and all of our aircraft are
registered with the FAA.

-8-

Generally, aircraft may be registered under the Federal Aviation Act
only if the aircraft is owned or controlled by one or more citizens of the
United States and operated pursuant to an operating certificate, which may be
granted only to a citizen of the Untied States. For purposes of these
requirements, a corporation is deemed to be a citizen of the United States only
if, among other things, at least 75% of the voting interest therein is owned or
controlled by United States citizens. In the event that persons other than
United States citizens should come to own or control more than 25% of the voting
interest in us, we have been advised that our aircraft may be subject to
deregistration under the Federal Aviation Act and loss of the privilege of
operating within the United States. None of our aircraft are currently owned, in
whole or in part, by a foreign entity. Our Articles of Incorporation and bylaws
include provisions that are designed to ensure compliance with this requirement.

Explosives. Because we load the holes that are drilled with dynamite,
we are subject to various local, state and federal laws and regulations
concerning the handling and storage of explosives and are specifically regulated
by the Bureau of Alcohol, Tobacco and Firearms of the U.S. Department of
Justice. We must take daily inventories of the dynamite and blasting caps that
we keep for our seismic drilling and are subject to random checks by state and
federal officials. We are licensed by the Louisiana State Police as an
explosives handler. Any loss or suspension of these licenses would result in a
material adverse effect on our results of operations and financial condition. We
believe that we are in compliance with all material laws and regulations with
respect to our handling and storage of explosives.

Environmental. Our operations and properties are subject to a wide
variety of increasingly complex and stringent federal, state and local
environmental laws and regulations, including those governing discharges into
the air and water, the handling and disposal of solid and hazardous wastes, the
remediation of soil and groundwater contaminated by hazardous substances and the
health and safety of employees. In addition, certain areas where we operate are
federally protected or state-protected wetlands or refuges where environmental
regulation is particularly strict. These laws may provide for "strict liability"
for damages to natural resources and threats to public health and safety,
rendering a party liable for environmental damage without regard to negligence
or fault on the part of such party. Sanctions for noncompliance may include
revocation of permits, corrective action orders, administrative or civil
penalties and criminal prosecution. Certain environmental laws provide for
strict, joint and several liability for remediation of spills and other releases
of hazardous substances, as well as damage to natural resources. In addition, we
may be subject to claims alleging personal injury or property damage as a result
of alleged exposure to hazardous substances. Such laws and regulations may also
expose us to liability for the conduct of, or conditions caused by, others, or
for our acts that were in compliance with all applicable laws at the time such
acts were performed.

The Comprehensive Environmental Response, Compensation, and Liability
Act of 1980, as amended, and similar laws provide for responses to and liability
for releases of hazardous substances into the environment. Additionally, the
Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act,
the Safe Drinking Water Act, the Emergency Planning and Community Right to Know
Act, each as amended, and similar state or local counterparts to these federal
laws, regulate air emissions, water discharges, hazardous substances and wastes,
and require public disclosure related to the use of various hazardous
substances. Compliance with such environmental laws and regulations may require
the acquisition of permits or other authorizations for certain activities and
compliance with various standards or procedural requirements. We believe that
our facilities are in substantial compliance with current regulatory standards.

Worker Safety. Our operations are governed by laws and regulations
relating to workplace safety and worker health, primarily the Occupational
Safety and Health Act and regulations promulgated thereunder. In addition,
various other governmental and quasi-governmental agencies require us to obtain
certain permits, licenses and certificates with respect to our operations. The
kind of permits, licenses and certificates required in our operations depend
upon a number of factors. We believe that we have all permits, licenses and
certificates necessary to the conduct of our existing business.

-9-

INSURANCE

Our operations are subject to the inherent risks of inland marine
activity, heavy equipment operations and the transporting and handling of
explosives, including accidents resulting in personal injury, the loss of life
or property, environmental mishaps, mechanical failures and collisions. We
maintain insurance coverage against certain of these risks, which we believe are
reasonable and customary in the industry. We also maintain insurance coverage
against property damage caused by fire, flood, explosion and similar
catastrophic events that may result in physical damage or destruction to our
equipment or facilities. All policies are subject to deductibles and other
coverage limitations. We believe our insurance coverage is adequate.
Historically, we have not experienced an insured loss in excess of our policy
limits; however, there can be no assurance that we will be able to maintain
adequate insurance at rates which we consider commercially reasonable, nor can
there be any assurance such coverage will be adequate to cover all claims that
may arise.

EMPLOYEES

As of December 31, 2001, we had approximately 236 employees, including
approximately 204 operating personnel and 32 corporate, administrative and
management personnel. These employees are not unionized or employed pursuant to
any collective bargaining agreement or any similar agreement. We believe our
relations with our employees are generally good.

EXECUTIVE OFFICERS OF THE REGISTRANT

The name, age and offices held by each of the executive officers as of
March 29, 2002 are as follows:

James C. Eckert was appointed our President and Chief Executive Officer in
March 2001. He served as Vice-President for Business Development of Veritas DGC
Land Inc. from 1998 to 2000. Prior to 1998, Mr. Eckert supervised the highland
and transition seismic acquisitions of Veritas DGC Land Inc. Prior to 1992, he
served as President of GFS Company, a company which he co-founded in 1985, until
its acquisition in 1992 by Digicon, Inc., a predecessor by merger to Veritas,
Inc. Mr. Eckert graduated from University of Southern Mississippi in 1971.

Burton T. Zaunbrecher is currently serving as our Company's Executive
Vice-President and Chief Operating Officer. Mr. Zaunbrecher joined us in
November 2000. He served as president of Burton T. Zaunbrecher, Inc., an oil,
gas and mineral lease, and geophysical permit acquisition company, which he
founded in 1990. Prior to 1990, Mr. Zaunbrecher conducted independent
abstracting and land services. Mr. Zaunbrecher graduated from the University of
Southwestern Louisiana in 1984.

G. Darcy Klug is our Chief Financial Officer. He joined us in May 2001
after being involved in private investments since 1987. Between 1983 and 1987,
Mr. Klug held various positions with a private oil and gas fabrication company
including the position of Chief Operating Officer and Chief Financial Officer.
Prior to 1983 he held various financial positions with Galveston-Houston
Company, a manufacturer of oil and gas equipment listed for trading on the New
York Stock Exchange. Between 1973 and 1979, he was a member of the audit staff
of Pricewaterhouse Coopers. Mr. Klug is a graduate of Louisiana State University
and is a member of the Louisiana State Board of Certified Public Accountants.

ITEM 3. LEGAL PROCEEDINGS

We are involved in various legal and other proceedings which are
incidental to the conduct of our business. We believe that none of these
proceedings, if adversely determined, would have a material effect on our
financial condition, results of operations or cash flows.

-10-

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the Company's Annual Meeting of Shareholders held on October 11,
2001, a proposal to elect the nominees listed in the following table as
directors of the Company was submitted to a vote of the Company's shareholders.
The following table shows the results of voting as to each nominee:

At the same meeting, the following proposal was also approved by the
Company's shareholders:

-11-

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

(a) Our Common Stock is listed for quotation on the Nasdaq National
Market under the symbol "OMNI". At March 25, 2002 we had 115 shareholders of
record of Common Stock. The following table sets forth the range of high and low
sales prices of our Common Stock as reported by the Nasdaq National Market for
the periods indicated.

We have never paid cash dividends on our Common Stock. We intend to
retain future earnings, if any, to meet our working capital requirements and to
finance the future operations of our business. Therefore, we do not plan to
declare or pay cash dividends to holders of our Common Stock in the foreseeable
future. In addition, certain of our credit arrangements contain provisions that
limit our ability to pay cash dividends on our Common Stock.

-12-

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data as of and for the five years ended December
31, 2001 are derived from our audited consolidated financial statements. The
following information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the consolidated financial statements and notes thereto included elsewhere in
this Annual Report.

(1) Reflects an increase in interest expense as a result of the incurrence of
indebtedness to finance the repurchase of outstanding preferred units of
OMNI Geophysical and the distribution to the members of OMNI Geophysical,
as if such event had occurred on January 1, 1997.

-13-

(2) Each of OGC, OMNI Geophysical and American Aviation was an S corporation
or a limited liability company exempt from income tax at the entity
level, and thus the historical consolidated financial statements prior to
December 4, 1997 show no provision for income taxes. Effective December
4, 1997, we became subject to income taxes at the corporate level. This
pro forma adjustment reflects a provision for income taxes on our net
income at a combined federal and state tax rate of 40%.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

Management's Discussion and Analysis of Financial Condition and Results
of Operations contains certain "forward looking statements" within the meaning
of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section
21E of the Securities Exchange Act of 1934 (the "Exchange Act"), which reflect
management's best judgment based on factors currently known. Actual results
could differ materially from those anticipated in these "forward looking
statements" as a result of a number of factors, including but not limited to
those discussed under the heading "Cautionary Statements." "Forward looking
statements" provided by us pursuant to the safe harbor established by the
federal securities laws should be evaluated in the context of these factors.

This discussion and analysis should be read in conjunction with our
consolidated financial statements and notes thereto.

RECENT DEVELOPMENTS

In the fourth quarter of 2000, we began experiencing a significant increase
in the number of bid requests from our customers. This resulted in an increase
in our backlog from December 31, 2000 of $18.5 million to $29.3 million at
December 31, 2001.

In November 2001 we completed negotiations with our lenders to extend the
maturity of all of our senior credit facilities to August 2004, restructure the
amortization of the term debt, and reduce the rate of interest paid on certain
outstanding indebtedness.

We recently announced the acquisition of the assets of AirJac Drilling, a
division of Veritas DGC Land, Inc., a seismic drilling support company
headquartered in New Iberia, Louisiana. The aggregate purchase price was $2.0
million cash. In this acquisition we acquired the following types of equipment:

GENERAL

Demand. We receive our revenues from customers in the energy industry.
Demand for our services is principally impacted by conditions affecting
geophysical companies engaged in the acquisition of 3-D seismic data. The level
of activity among geophysical companies is primarily influenced by the level of
capital expenditures by oil and gas companies for seismic data acquisition
activities. A number of factors affect the decision of oil and gas companies to
pursue the acquisition of seismic data, including (i) prevailing and expected
oil and gas demand and

-14-

prices; (ii) the cost of exploring for, producing and developing oil and gas
reserves; (iii) the discovery rate of new oil and gas reserves; (iv) the
availability and cost of permits and consents from landowners to conduct seismic
activity; (v) local and international political and economic conditions; (vi)
governmental regulations; and (vii) the availability and cost of capital. The
ability to finance the acquisition of seismic data in the absence of oil and gas
companies' interest in obtaining the information is also a factor as some
geophysical companies will acquire seismic data on a speculative basis.

During 1999, with the reduction in the price of oil and gas, we began
to experience a decrease in demand for our services. In 2001, the market
experienced a rebound. For the years ended December 31, 1999, 2000 and 2001, our
operating revenues were $32.7 million, $16.6 million, and $23.7 million,
respectively.

Seasonality and Weather Risks. Our operations are subject to seasonal
variations in weather conditions and daylight hours. Since our activities take
place outdoors, on average, fewer hours are worked per day and fewer holes are
generally drilled or surveyed per day in winter months than in summer months due
to an increase in rainy, foggy, and cold conditions and a decrease in daylight
hours.

RESULTS OF OPERATIONS

The following discussion provides information related to the results of
our operations.

Year Ended December 31, 2000 Compared to the Year Ended December 31,
2001

Operating revenues increased 43%, or $7.1 million, from $16.6 million
to $23.7 million for the years ended December 31, 2000 and 2001, respectively.
This increase was due primarily to an upswing in the seismic market in 2001. As
a result, drilling revenues doubled from $8.9 million for the year ended
December 31, 2000 to $18.0 million for the year ended December 31, 2001. Our
newly formed permitting division reported revenues of $1.5

-15-

million for the year ended December 31, 2001 with no revenues reported for the
corresponding period of 2000. Survey revenues decreased from $1.4 million for
the year ended December 31, 2000 to $0.6 million for the year ended December 31,
2001, primarily due to our decision to concentrate our personnel, equipment and
available working capital on the more profitable segments of the seismic
industry. Aviation revenues decreased from $6.3 million for the year ended
December 31, 2000 to $3.7 million for the year ended December 31, 2001 as we
continue to reduce our seismic aviation fleet to concentrate on the more
profitable offshore market. Operating revenues in 2002 are expected to continue
to increase due to an increased demand for our services.

Operating expenses increased 3%, or $0.7 million, from $20.2 million in
2000 to $20.9 million in 2001. Operating payroll expense increased $0.4 million
from $8.0 million to $8.4 million for the years ended December 31, 2000 and
2001, respectively. The significant increase in seismic activity has resulted in
a corresponding increase in the amount of personnel employed, as the average
number of field employees has increased to 172 in 2001 compared to 155 in 2000.
Also, as a result of the increased activity levels in 2001 as compared to 2000,
explosives expenses increased $1.1 million from $0.9 million for the year ended
December 31, 2000 to $2.0 million for the year ended December 31, 2001.
Contracting services increased $2.2 million from $0.2 million for the year ended
December 31, 2000 to $2.4 million for the year ended December 31, 2001
principally as a result of the commencement of our newly formed permitting
division. These increases were partially offset by a $2.5 million decrease in
the repairs and maintenance expense, rental expense and related insurance
expense on leased aviation equipment. The decreases resulted from fewer
helicopters being leased from third parties during 2001 compared to 2000.
Depreciation expense and property and casualty insurance expense decreased $0.5
million from the year ended December 31, 2000 to the year ended December 31,
2001 because of an overall reduction in our operating equipment. Operating
expenses are expected to continue to increase in 2002 as operating revenues
increase.

Gross profit increased $6.4 million, or 178%, from a gross loss of
$(3.6 million) to a gross profit of $2.8 million for the years ended December
31, 2000 and 2001, respectively. This increase is a result of increased business
activity in our more profitable business segments, increased prices received for
the services provided and more stringent controls over operating expenses.

General and administrative expenses decreased $2.9 million, or 48%,
from $6.0 million for 2000 compared to $3.1 million for 2001. Payroll expenses
accounted for 45% of this decrease as they decreased $1.3 million from $2.5
million for the year ended December 31, 2000 to $1.2 million for the year ended
December 31, 2001. This decrease is due to a 30% reduction in the average number
of administrative employees between the periods, as well as significantly
reduced base compensation levels of our management. We realized approximately
$1.2 million in savings during 2001 by renegotiating certain lease and vendor
agreements with terms more favorable to us than those agreements in 2000. We
experienced a $0.1 million reduction in each of entertainment and communications
expenses from the year ended December 31, 2000 to the year ended December 31,
2001. Amortization expense decreased $0.2 million from $0.4 million to $0.2
million for the years ended December 31, 2000 and 2001, respectively, due to the
asset impairment charges realized in the latter part of 2000 (See Note 5).
General and administrative expenses are expected to increase slightly in 2002
due to increased business activity.

During 2001, we realized asset impairment charges of $0.6 million (See
Note 5) compared to $11.3 million in 2000..

Interest expense was $1.3 million for the year ended December 31, 2001
compared to $3.0 million for the year ended December 31, 2000.

Other income increased $9.8 million from $(1.8) million for the year
ended December 31, 2000 to $7.9 million for the year ended December 31, 2001.
The increase is primarily from the receipt of $7.5 million in proceeds from a
key-man life insurance policy procured on the life our CEO, who was killed in a
private aircraft accident in February 2001. The increase was also due to $1.8
million of net losses on the sale of assets in 2000 offset by $0.1 million in
interest income in 2001.

For the year ended December 31, 2000 and 2001, losses incurred by us
generated additional net operating loss carryforwards for which a reserve has
been provided (see Note 10), resulting in income tax benefit/expense of $0 in
each year.

-16-

Accretion of preferred stock increased $0.7 million from $0 for the
year ended December 31, 2000 to $0.7 million for the year ended December 31,
2001. The increase is due to the accretion of dividends at 8% during the free
dividend period from April 2001 through June 2002 for our preferred stock.

Year Ended December 31, 1999 Compared to the Year Ended December 31,
2000

Operating revenues decreased 49%, or $16.1 million, from $32.7 million
to $16.6 million for the years ended December 31, 1999 and 2000, respectively.
The decrease was due primarily to a depressed seismic market throughout 2000. As
a result of the decline in the seismic activity and adverse pricing during the
last year, drilling and survey revenues decreased $7.3 million and $3.1 million,
to $8.9 million and $1.4 million, respectively, for the year ended December 31,
2000. No revenues were generated from our South American joint venture for the
year ended December 31, 2000 compared to $2.3 million in the prior year.

Operating expenses decreased 43%, or $15.2 million, from $35.4 million
in 1999 to $20.2 million in 2000. Declines in payroll costs accounted for 59% of
this decrease as operating payroll expense decreased from $16.8 million to $8.0
million for the years ended December 31, 1999 and 2000, respectively. The
significant decrease in seismic activity has resulted in a corresponding
decrease in the amount of personnel employed, as the average number of field
employees has declined to 155 in 2000 compared to 291 in 1999. Also, as a result
of the lower activity levels in 2000 as compared to 1999, explosives, repairs
and maintenance and rentals and leases expenses decreased $3.7 million from $8.7
million for the year ended December 31, 1999 to $5.0 million for the year ended
December 31, 2000.

Gross operating loss increased $0.8 million, or 29%, from $(2.8
million) to $(3.6 million) for the years ended December 31, 1999 and 2000,
respectively, primarily as a result of substantially lower domestic revenues
from our Drilling, Aviation and Survey segments.

-17-

General and administrative expenses were $12.3 million for 1999
compared to $6.0 million for 2000, resulting in a 51% decrease. Payroll expenses
decreased $2.4 million from $4.9 million for the year ended December 31, 1999 to
$2.5 million for the year ended December 31, 2000. These decreases are due to
the reduction in the workforce implemented by us due to the declines in the
market environment. Bad debt expense decreased $2.4 million from $2.4 million in
December 31, 1999, all of which in 1999 related to a customer that filed
bankruptcy. We experienced a 53% reduction in travel, office and supplies,
communications, and rentals and leases expenses due to decreased activity levels
from $1.5 million to $0.7 million in the years ended December 31, 1999 and 2000,
respectively. Amortization expense decreased $0.5 million from $0.9 million to
$0.4 million for the years ended December 31, 1999 and 2000, respectively, due
to the asset impairment charges realized in 2000 (See Note 5).

During 2000, we realized asset impairment charges of $11.3 million (See
Note 5) compared to $10.3 million in 1999.

Interest expense was $3.0 million for each of the years ended December
31, 1999 and 2000.

Due to losses in the year ended December 31, 1999, we recorded an
income tax benefit of $1.3 million. For the year ended December 31, 2000, losses
incurred by us generated additional net operating loss carryforwards for which a
reserve has been provided (see Note 10) resulting in a $0 income tax benefit for
the year ended December 31, 2000.

LIQUIDITY AND CAPITAL RESOURCES

During the second half of fiscal 2000 and the first half of fiscal
2001, we significantly improved our capital structure and future liquidity
prospects by experiencing an increase in customer bidding activity, receiving a
series of new capital contributions, receiving a significant life insurance
settlement and completing a series of financial restructurings. During the
fourth quarter of 2000 and the first quarter of 2001, we successfully raised
$5.1 million of new equity capital, and after the death of our CEO, we received
$7.5 million in proceeds from a key-man life insurance policy. With the proceeds
we repaid approximately $2.0 million of secured indebtedness. We reached an
agreement to eliminate all of the remaining subordinated debt to an affiliate by
the payment of approximately $1.0 million to satisfy $2.0 million of the
indebtedness and the issuance of shares of Series B Preferred Stock for the
remaining outstanding balance. We extended the maturity dates for all of our
secured indebtedness outstanding; and negotiated a 1.5% fixed interest rate
reduction on approximately $6.9 million of this secured indebtedness. Our
backlog at December 31, 2001 approximated $29.3 million, compared to $18.5
million at December 31, 2001.

In the years ended December 31, 1999, 2000 and 2001, we privately
placed a total of $7.5 million, $3.4 million and $1.5 million, respectively, in
subordinated debentures with an affiliate. The debentures had interest rates of
either a fixed rate of 12% or a rate that started at 12% and escalated over the
life of the note to 20%. The debentures were due five years from the date of
issuance with interest payable quarterly. In connection with these debentures,
we issued warrants to purchase 5,738,500 shares of our common stock. The
warrants had vesting periods from immediate vesting to four years and exercise
prices from $0.75 to $5.00. We recorded each warrant at its relative fair value
at date of issuance.

In July 2000, we entered into a series of transactions with an
affiliate that enabled us to factor, with recourse to us, substantially all of
the trade receivables of a major customer totaling approximately $1.0 million.
This receivable had become ineligible under the terms of our revolving credit
facility with Hibernia National Bank. In exchange for us transferring ownership
rights and title in the trade receivables of the major customer to the
affiliate, the affiliate forgave approximately $1.0 million in principal on the
oldest subordinated debt. We incurred a fixed interest rate charge of 1.5% on
the $1.0 million in principal advanced against the trade receivables
transferred. We guaranteed repayment of the trade receivables and as of December
2001 have received $0.8 of the $1.0 million due. The remaining $0.2 million has
been classified as due to affiliate.

On October 31, 2000, we completed the private placement of
approximately 6.9 million shares of common stock for approximately $4.3 million.
The purchasers of the common stock also received options or warrants to acquire
approximately 2.8 million shares of common stock at an exercise price of $0.75
per share. The terms of the private

-18-

placement gave the shareholders the right to put their stock back to us in the
event of the death of our CEO. To secure this put right, we purchased key-man
life insurance on our CEO in the amount of $7.5 million. In addition, we issued
800 shares of Series A Preferred Stock for $0.8 million in cash and also
converted approximately $4.6 million of subordinated debt to 4,550 shares of
Series A Preferred Stock. This conversion reduced the amount of outstanding
subordinated debentures to $5.5 million at December 31, 2000. In connection with
the completion of these capital transactions, we reached agreements with our
secured lenders to extend the maturity dates of approximately $13 million in
outstanding indebtedness until January 2002.

The proceeds of the private placement of stock were used to repay $1.3
million of secured indebtedness and provide working capital.

On February 10, 2001, our CEO was killed in a private aircraft
accident. As a result of this event, we received $7.5 million in proceeds from
the key-man life insurance policy purchased in connection with the
aforementioned private placement. We received from the private placement
shareholders waivers of their put rights upon his death. In connection with the
receipt of these waivers, we also obtained from our secured lenders commitments
to modify the existing agreements upon our receipt of the life insurance
proceeds. Under these revised commitments, the maturity dates were extended to
August 31, 2002 from January 2002. Additionally, we negotiated an interest rate
reduction on $6.9 million of the secured indebtedness from prime plus 3% to
prime plus 1.5%. In connection with the revised commitments, we were required to
repay $2.0 million of existing term indebtedness and convert into preferred
stock the remain outstanding subordinated debt. We used a portion of the
insurance proceeds to fund the $2.0 million payment of existing term
indebtedness. The outstanding balance on the secured indebtedness at December
31, 2001 is $4.0 million.

In May 2001, we reached an agreement with the holders of our
outstanding subordinated debt, to repay $1.0 million in satisfaction of $2.0
million of indebtedness and issue shares of Series B Preferred Stock to satisfy
the remaining outstanding principal and interest owed under the agreements. The
number of shares to be issued was 100 shares per $1,000 of principal and
interest owed on the date of the exchange.

At December 31, 2001, we had approximately $1.2 million in cash
compared to approximately $0.3 million at December 31, 2000. We had working
capital of approximately $2.3 million at December 31, 2001, compared to
approximately ($3.4 million) at December 31, 2000. The increase in working
capital is due to improved profitability resulting in a significant decrease in
accrued expenses, a significant increase in accounts receivable, and the
classification of the line of credit as long-term.

Cash provided by (used in) operating activities was $6.4 million and
($5.6 million) in the years ended December 31, 2001 and 2000, respectively. Our
net income (loss) was the single largest contributing factor in both years.

We have outstanding a revolving line of credit agreement (the Line)
with a bank. Availability under the Line is the lower of: (i) $5.0 million or
(ii) the sum of 80% of eligible accounts receivable, plus 25% of eligible
aviation inventory of parts and supplies. The Line accrues interest at the prime
interest rate plus 1.5% (6.25% at December 31, 2001) and matures on August 31,
2004. The weighted-average interest rate on the Line was 12.1% and 9.2% for the
years ended December 31, 2000 and 2001, respectively. The Line is collateralized
by our accounts receivable and inventory. As of December 31, 2001 we had $2.0
million outstanding under the Line. Additional borrowing capacity under the Line
was $1.0 million as of December 31, 2001.

At December 31, 2001, we also had approximately $8.0 million in other
loans outstanding, including approximately $2.4 million in outstanding debt
pursuant to agreements with a financing company. This loan is an asset-based
financing loan bearing interest at LIBOR plus 5.0%. As previously mentioned, we
have renegotiated an extended maturity to August 31, 2004 from August 31, 2002.
Also included in the $8.0 million in other loans is approximately $4.7 million
in outstanding debt to a financing company pursuant to our acquisition of our
aviation fleet previously operated under an operating lease. This loan is
secured by the aviation fleet, amortizes over ten years, accrues interest at 8%
per annum and matures January 1, 2007.

-19-

Historically, our capital requirements have primarily related to the
purchase or fabrication of new seismic drilling equipment and related support
equipment and business acquisitions. In 2001 we acquired approximately $0.4
million of new vehicles accounted for as a capital lease. Other than the
acquisitions discussed in Notes 12 and 14, we have no material commitments
outstanding for expenditures nor do we anticipate acquiring a significant amount
of capital assets in 2002.

CONTRACTUAL COMMITMENTS

We have the following contractual obligations as of December 31, 2001:

We believe that cash flow generated from operations in 2002 will be
sufficient to fund our working capital needs and debt service requirements for
at least the next twelve months.

CAUTIONARY STATEMENTS

This Annual Report contains "forward-looking statements." Such
statements include, without limitation, statements regarding our expectations
regarding revenue levels, profitability and costs, the expected results of our
business strategy, and other plans and objectives of management for future
operations and activities.

Important factors that could cause actual results to differ materially
from our expectations include, without limitation, our dependence on activity in
the oil and gas industry, risks associated with our rapid growth, dependence on
a relatively small number of significant customers, seasonality and weather
risks, the hazardous conditions and difficult terrain in which we operate, and
risks associated with our international expansion. Many of these factors are
beyond our control.

RELATED PARTY TRANSACTIONS

During the year ended December 31, 2001 we leased a facility from a
major shareholder at a total lease expense of $0.1 million, which approximated
market values. We were under a lease contract for a portion of 2001 (See Note
8). See also Notes 4 and 9 for other transactions with our affiliates.

In July 2000, we entered into a series of transactions with the same
affiliate that enabled us to factor, with recourse, approximately $1.0 million
of the trade receivable of a major customer. This receivable had become
ineligible under the terms of our Line. As of December 31, 2001 we are liable to
the affiliate for approximately $0.2 million, which is payable in twelve equal
monthly installments commencing 30 days after execution of the definitive
repayment agreement between us and the affiliate.

During the years ended December 31, 1999, 2000 and 2001, we privately
placed with an affiliate subordinated debentures totaling $7.5 million, $3.4
million and $1.5 million, respectively. The debentures matured five years from
their date of issue and accrued interest at various rates ranging from a fixed
rate of 12% per annum to a variable rate of interest starting at 12% per annum
and escalating to 20% per annum. In October 2000, we agreed to convert $4.6
million of the subordinated debentures into our Series A Preferred Stock. In May
2001, we agreed to pay the affiliate $3.0 million cash plus issue to the
affiliate $4.6 million of the Company's Series B

-20-

Preferred Stock in full satisfaction of all of the remaining outstanding
subordinated debentures including accrued interest of $1.8 million. This
transaction resulted in the affiliate agreeing to forgive $1.0 million of
indebtedness which has been reflected as a capital contribution from the
affiliate rather than as income in the accompanying financial statements. (See
Note 9 regarding the accounting for preferred stock.)

In connection with the original issuance of the subordinated
debentures, we issued to the affiliate detachable warrants to purchase 5,738,500
shares of our common stock, of which 2,901,000 have been cancelled as of
December 31, 2001. The remaining 2,837,500 warrants outstanding are all
exercisable with exercise prices ranging from $0.75 to $2.00 per share.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The discussion and analysis of financial condition and results of
operation are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses, and related disclosure of contingent assets and
liabilities. We evaluate our estimates on an on-going basis, based on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions.

We believe the following critical accounting policies affect our more
significant judgments and estimates used in the preparation on our consolidated
financial statements.

We extend credit to customers and other parties in the normal course of
business. We regularly review outstanding receivables, and provide for estimated
losses through an allowance for doubtful accounts. In evaluation the level of
established reserves, we make judgments regarding the parties' ability to make
required payments, economic events and other factors. As the financial condition
of these parties change, circumstances develop or additional information becomes
available, adjustments to the allowance for doubtful account may be required.
Due to the nature of our industry, we have a concentration of credit risks. As a
result, adjustments to the allowance for doubtful accounts may be significant.

We have made significant investments in inventory to service our
equipment. On a routine basis, we use judgments in determining the level of
reserves required to state inventory at the lower of cost or market. Our
estimates are primarily influenced by technological innovations, market activity
levels and the physical condition of products. Changes in these or other factors
may result in adjustments to the carrying value of inventory.

Deferred tax assets and liabilities are recognized for differences
between the book basis and tax basis of our net assets. In providing for
deferred taxes, we consider current tax regulations, estimates of future taxable
income and available tax planning strategies. We have established reserves to
reduce our net deferred tax assets to estimated realizable value. If tax
regulations change, operating results or the ability to implement tax planning
strategies vary, adjustments to the carrying value of our net deferred tax
assets and liabilities may be required.

We record liabilities for environmental obligations when remedial
efforts are probable and the costs can be reasonably estimated. Our estimates
are based on currently enacted laws and regulations. As more information becomes
available or environmental laws and regulations change, such liabilities may be
required to be adjusted. Additionally, in connection with acquisitions, we
obtain indemnifications from the seller related to environmental matters. If the
indemnifying parties do not fulfill their obligations, adjustments of recorded
amounts may be required.

We maintain insurance coverage for various aspects of our business and
operations. We retain a portion of losses that occur through the use of
deductibles and self-funded insurance programs. We regularly review estimates of
reported and unreported claims and provide for losses through insurance
reserves. As claims develop and additional information becomes available,
adjustments to loss reserves may be required.

-21-

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities," establishes
accounting and reporting standards that every derivative instrument be recorded
in the balance sheet as either an asset or a liability measured at our fair
value. We adopted SFAS 133 on January 1, 2001; however, adoption did not have a
material impact on our financial position.

In July 2001, SFAS No. 141, " Business Combinations" and SFAS No. 142,
" Goodwill and Other Intangible Assets" were issued. SFAS 141 requires all
business combinations initiated after June 30, 2001 to be accounted for using
the purchase method. Under SFAS 142, goodwill and intangible assets with
indefinite lives are no longer amortized but are reviewed annually (or more
frequently if impairment indicators arise) for impairment. Separable intangible
assets that are not deemed to have indefinite lives will continue to be
amortized over their useful lives (but with no maximum life). The amortization
provisions of SFAS 142 apply to goodwill and intangible assets acquired after
June 30, 2001. With respect to goodwill and intangible assets acquired prior to
July 1, 2001, we are required to adopt SFAS 142 effective January 1, 2002. As of
December 31, 2001, we have goodwill, net of accumulated amortization, of $2.0
million. We believe that adoption of the provisions of SFAS 142 that are
effective January 1, 2002 will not have an adverse effect on our results of
operations and financial condition. We recognized approximately $103,000 and
$21,000 in goodwill amortization expense for the year ended December 31, 2001
and 2000, respectively.

In August 2001, SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" was issued. These new rules on asset impairment
supersede SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed Of," and will be effective for our fiscal
year beginning January 1, 2002. We are currently evaluating the impact that
adoption of this standard will have on our financial statements.

On June 29, 2001 the American Institute of Certified Public
Accountants (AICPA) released an exposure draft of a proposed Statement of
Position (SOP), " Accounting for Certain Costs and Activities Related to
Property, Plant, and Equipment." This proposed SOP would change, among other
things, the method by which companies would account for normal, recurring or
periodic repairs and maintenance costs related to "in-service" fixed assets. It
would require that these types of expenses would be recognized when incurred
rather than accruing these expenses while the asset is in service. We are
assessing the impact of the change should this SOP be adopted.

-22-

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We are exposed to interest rate risk due to changes in interest rates,
primarily in the United States. Our policy is to manage interest rates through
the use of a combination of fixed and floating rate debt. We currently do not
use any derivative financial instruments to manage our exposure to interest rate
risk. The table below provides information about the future maturities of
principal for outstanding debt instruments at December 31, 2001. All instruments
described are non-traded instruments and approximated fair value.

Foreign Currency Risks

Our transactions are in U.S. dollars. Previously, we had one
subsidiary, which conducted our operations in Canadian dollars. However, those
operations were closed in July 1999. Currently, the South American joint venture
transacts all of its activity in U.S. dollars. Operations in South America have
been curtailed pending future developments in that market.

-23-

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

-24-

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of OMNI Energy Services Corp.:

We have audited the accompanying consolidated balance sheets of OMNI Energy
Services Corp. and subsidiaries, a Louisiana corporation, as of December 31,
2000 and 2001, and the related consolidated statements of operations, changes in
equity and comprehensive loss and cash flows for each of the three years in the
period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit 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 financial statements referred to above present fairly, in
all material respects, the financial position of OMNI Energy Services Corp. and
subsidiaries as of December 31, 2000 and 2001 and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
March 14, 2002

-25-

OMNI ENERGY SERVICES CORP.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 2001

The accompanying notes are an integral part of these
consolidated financial statements.

-26-

OMNI ENERGY SERVICES CORP.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 2001

LIABILITIES AND STOCKHOLDERS' EQUITY

The accompanying notes are an integral part of these
consolidated financial statements.

-27-

OMNI ENERGY SERVICES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001

The accompanying notes are an integral part of these
consolidated financial statements.

-28-

OMNI ENERGY SERVICES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND COMPREHENSIVE LOSS
FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001
(DOLLARS IN THOUSANDS)

The accompanying notes are an integral part of these
consolidated financial statements.

-29-

OMNI ENERGY SERVICES CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001

The accompanying notes are an integral part of these
consolidated financial statements.

-30-

OMNI ENERGY SERVICES CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of OMNI Energy
Services Corp., a Louisiana corporation, and subsidiaries in which we have a
greater than 50% ownership. All material intercompany accounts and transactions
have been eliminated in these financial statements. Certain prior year amounts
have been reclassified to conform with current year financial statement
presentation.

Nature of Business and Current Operating Environment

We are an oilfield service company specializing in providing an integrated range
of on-shore seismic drilling and survey services to geophysical companies
operating in logistically difficult and environmentally sensitive terrain in the
continental United States. Our primary market is the marsh, swamp, shallow water
and contiguous dry land areas along the U.S. Gulf Coast (the "Transition Zone"),
primarily Louisiana and Texas, where we are the leading provider of seismic
drilling services.

We receive our revenues from customers in the energy industry. The seismic
market remained in a depressed state throughout most of 1999 and 2000 due
primarily to the excess capacity of available seismic data in the market. This
volatile market has impacted our ability, as well as that of our customers and
others in the industry, to change their forecasts and budgets in response to
future uncertainties of commodity pricing. These fluctuations can rapidly impact
our cash flows as supply and demand factors impact the number and size of
seismic projects available.

During 1999 and 2000, we continued to adjust our operations to current market
conditions by downsizing our operations through closure of certain operating
locations, disposing of excess equipment and reducing our corporate overhead
structure (see Note 5).

During the later half of 2000, we began to experience an increase in bidding
activity from our customers. During this same time we were continuing our
efforts to renegotiate our loan agreements with our primary creditors and raise
additional capital. During the fourth quarter of 2000, we completed a financial
restructuring through the renegotiation of our secured indebtedness together
with the raising of additional equity capital.

On October 31, 2000 we completed the sale of 6,960,000 shares of common stock
for approximately $4.3 million through a private placement offering. The
purchasers of the common stock also received options to acquire an additional
2,827,500 shares of common stock at an exercise price of $0.75 per share. The
private placement agreement gave the shareholders the right to put their shares
back to us in the event of the death of our CEO. We agreed to assign a portion
of the insurance benefits to the shareholders to secure this agreement. In
addition, we sold 800 shares of Series A preferred stock for $0.8 million in
cash and also converted $4.6 million in subordinated debt into 4,550 shares of
Series A preferred stock. In connection with the completion of these capital
transactions, we reached agreements with our secured lenders to extend the
maturity dates of approximately $13 million in secured indebtedness. The
proceeds from the sale of stock were used to repay debt and provide working
capital.

On February 10, 2001, our CEO was killed in a private plane accident. As a
result of this accident, we received $7.5 million of proceeds from the life
insurance policy purchased in connection with the private placement discussed
above, which is included as "other income" in the Statement of Operations. We
received, from all of the private placement shareholders, waivers of their put
rights of their common shares back to us. In connection with obtaining these
waivers, we also obtained from our secured lenders commitments to modify the
existing loan agreements. Under these revised agreements, the maturity dates
were extended with principal amortization remaining substantially the same.
Additionally, the interest rate on $6.9 million of the indebtedness was reduced
from prime plus 3% to prime plus 1.5%. In connection with the revised
agreements, we repaid $2.0 million of the then existing

-31-

term indebtedness and restructured all subordinated debt outstanding. We used a
portion of the insurance proceeds to fund the $2.0 million repayment.

In May 2001 we reached an agreement with our affiliate, the holders of our
outstanding subordinated debt, to pay $1.0 million in full satisfaction of $2.0
million of indebtedness. We agreed to issue shares of Series B Preferred Stock
to satisfy the remaining outstanding principal and accrued interest owed under
the agreements (See Note 4).

In November 2001 we renegotiated with our secured lenders the amortization of
certain term indebtedness, the maturity dates all of all secured debt and a
reduction in the interest rates of approximately $2.6 million of secured debt
from the then existing rate equal to prime interest rate plus 3% to the current
rate equal to LIBOR plus 5%.

Use of Estimates

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and the disclosures of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenue and expenses during the reporting period. The
more significant estimates include asset impairment reserves, useful lives for
depreciation and amortization, receivables reserve requirements and the
realizability of deferred tax assets. Actual results could differ from those
estimates.

Recent Pronouncements

Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities," establishes accounting and
reporting standards that every derivative instrument be recorded in the balance
sheet as either an asset or a liability measured at our fair value. We adopted
SFAS No. 133 on January 1, 2001; however, adoption did not have a material
impact on our financial position.

In July 2001, SFAS No. 141, " Business Combinations" and SFAS No. 142, "
Goodwill and Other Intangible Assets" were issued. SFAS No. 141 requires all
business combinations initiated after June 30, 2001 to be accounted for using
the purchase method. Under SFAS No. 142, goodwill and intangible assets with
indefinite lives are no longer amortized but are reviewed annually (or more
frequently if impairment indicators arise) for impairment. Separable intangible
assets that are not deemed to have indefinite lives will continue to be
amortized over their useful lives (but with no maximum life). The amortization
provisions of SFAS No. 142 apply to goodwill and intangible assets acquired
after June 30, 2001. With respect to goodwill and intangible assets acquired
prior to July 1, 2001, we are required to adopt SFAS No. 142 effective January
1, 2002. As of December 31, 2001, we have goodwill, net of accumulated
amortization, of $2.0 million. We believe that adoption of the provisions of
SFAS No. 142 that are effective January 1, 2002 will not have an adverse effect
on our results of operations and financial condition. We recognized
approximately $21,000 and $103,000 in goodwill amortization expense for the year
ended December 31, 2000 and 2001, respectively.

In August 2001, SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" was issued. These new rules on asset impairment supersede
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," and will be effective for our fiscal year
beginning January 1, 2002. Under SFAS No. 144 an impairment loss shall be
recognized if an evaluation of the carrying amount of an asset against the
indiscounted future cash flows associated with it is not sufficient to cover the
carrying value of such assets. An impairment loss shall also be recognized on
assets held for sale if the carrying amount of a long-lived asset or asset group
is not recognizable and exceeds the fair value. We are currently evaluating the
impact that adoption of this standard will have on our financial statements.

On June 29, 2001 the American Institute of Certified Public Accountants (AICPA)
released an exposure draft of a proposed Statement of Position (SOP), "
Accounting for Certain Costs and Activities Related to Property, Plant, and
Equipment." This proposed SOP would change, among other things, the method by
which companies would account for normal, recurring or periodic repairs and
maintenance costs related to "in-service" fixed assets. It would require that
these types of expenses would be recognized when incurred rather than accruing
these expenses while the asset is in service. We are assessing the impact of the
change should this SOP be adopted.

-32-

Impairment of Long-Lived Assets

Through December 31, 2001, we evaluate our long-lived assets for financial
impairment when events or changes in circumstances indicate that the carrying
amount of such assets may not be fully recoverable. We evaluate the
recoverability of long-lived assets not held for sale by measuring the carrying
amount of the assets against the estimated undiscounted future cash flows
associated with them. At the time such evaluations indicate that the future
undiscounted cash flows of certain long-lived assets are not sufficient to cover
the carrying value of such assets, the assets are adjusted to their estimated
fair values. See "Recent Pronouncements" regarding our new policy for evaluating
the recoverability of long-lived assets effective January 1, 2002.

Revenue Recognition

We recognize revenue as service is rendered. Revenue from our drilling
operations is recognized on a per hole basis. Once we have drilled and loaded a
source point, revenue from the drilling of such source point is recognized.
Similarly, revenue is recognized from our seismic survey operations either on a
day rate or per mile basis. Under the per mile basis, revenue is recognized when
the source or receiving point is marked by one of our survey crews. Permitting
is recognized on a per day basis as services are incurred. Our aircraft, which
are usually either chartered with a monthly guaranteed rate or for a guaranteed
minimum number of hours per day, generate revenue pursuant to a fixed hourly
rate.

Cash and Cash Equivalents

We consider investments with an original maturity of 90 days or less to be cash
equivalents. Due to its short-term nature the fair value of cash and cash
equivalents approximates book value.

Accounts Receivable

Trade and other receivables are stated at net realizable value. We grant
short-term credit to our customers, primarily geophysical companies. We
regularly review outstanding receivables and provide for estimated losses
through our allowance for doubtful accounts.

Inventories

Inventories consist of parts and supplies used for our drilling and aviation
operations. All inventories are valued at lower of average cost or market.

Property and Equipment

Property and equipment are stated at cost less accumulated depreciation. We
provide for depreciation by charging operations in amounts estimated to allocate
the cost of the assets over their estimated useful lives and salvage values as
follows:

Additions to property and equipment and major replacements are capitalized.
Gains and losses on dispositions, maintenance, repairs and minor replacements
are reflected in the Statement of Operations. Drilling equipment, which is
fabricated, is comprised of direct and indirect costs incurred during
fabrication. Costs include materials and labor consumed during fabrication.
Interest is also capitalized during the fabrication period. Included in property

-33-

and equipment at December 31, 2001 is approximately $425,000, which is net of
accumulated depreciation of approximately $40,300 for vehicles purchased under
capital lease obligations.

Goodwill

Goodwill represents the excess of the purchase price of acquisitions over the
fair value of the net assets acquired. Such excess costs are being amortized on
a straight-line basis over a twenty-five year period. As of December 31, 2000
and 2001, accumulated goodwill amortization totaled approximately $21,191 and
$123,811 respectively. Through December 31, 2001, we periodically assessed the
recoverability of the unamortized balance based on expected future profitability
and undiscounted future cash flows of the acquisitions and their contribution to
our overall operation. (See Note 5 for impairment charges related to goodwill.)
See "Recent Pronouncements" regarding our policy of evaluating the
recoverability of goodwill effective January 1, 2002.

Income Taxes

We provide for deferred taxes in accordance with SFAS No. 109, "Accounting for
Income Taxes," which requires an asset and liability approach for measuring
deferred taxes and liabilities due to temporary differences existing at year-end
using currently enacted rates.

Foreign Currency Translation

Our Canadian subsidiary maintained its accounting records in the local currency
(Canadian Dollar) before this operation was closed in July 1999. The currency
was converted to United States Dollars with the effect of the foreign currency
translation reflected as a component of shareholders' equity in accordance with
SFAS No. 52, and SFAS No. 130, "Reporting Comprehensive Income." Currently, all
other international activity is transacted in United States Dollars. Foreign
currency transaction gains or losses are credited or charged to income, and such
amounts are insignificant for the periods presented.

Overhaul and Repair Costs

Overhaul and repair costs for our owned aircraft are capitalized as incurred and
depreciated over service hours flown. Overhaul and repair costs to bring leased
aircraft to specifications required at the termination of our operating leases
are accrued on the basis of hours flown.

2. VALUATION ALLOWANCE ACCOUNTS

The allowance for uncollectible accounts consists of the following (in
thousands):

(1) $2.4 million of the expense recorded in 1999 and the write-off in 2000
pertain to a receivable of a customer who filed bankruptcy; this receivable was
factored with an affiliate (see Note 6).

-34-

The accrual to bring leased aircraft back to repair specifications at the
termination of the operating lease is as follows (in thousands):

3. LONG-TERM DEBT AND LINE OF CREDIT

Annual maturities of long-term debt during each of the following years ended
December 31, are as follows (in thousands):

2002 $ 2,750
2003 1,965
2004 3,643
2005 409
2006 404
2007 2,868
-------
$12,039
=======

The estimated fair value of long-term debt, based on borrowing rates currently
available to us for notes with similar terms and average maturities,
approximated the carrying value as of December 31, 2000 and 2001.

-35-

We have outstanding a revolving line of credit agreement (the Line) with a bank.
Availability under the Line is the lower of: (i) $5.0 million or, (ii) the sum
of 80% of eligible accounts receivable, plus 25% of eligible aviation inventory
of parts and supplies. The Line accrues interest at the prime interest rate plus
1.5% (6.25% at December 31, 2001) and matures on August 31, 2004. The
weighted-average interest rate on the Line was 12.1% and 9.2% for the years
ended December 31, 2000 and 2001, respectively. The Line is collateralized by
our accounts receivable and inventory. As of December 31, 2001 we had $2.0
million outstanding under the Line. Additional borrowing capacity under the Line
was $1.0 million as of December 31, 2001.

The current loan agreements contain customary financial covenants requiring,
among other things, minimum levels of EBITDA, working capital and debt to EBITDA
ratios. As of December 31, 2001 we were in compliance with all of these
covenants.

4. SUBORDINATED DEBT

During the years ended December 31, 1999, 2000 and 2001, we privately placed
with an affiliate subordinated debentures totaling $7.5 million, $3.4 million
and $1.5 million, respectively. The debentures matured five years from their
date of issue and accrued interest at various rates ranging from a fixed rate of
12% per annum to a variable rate of interest starting at 12% per annum and
escalating to 20% per annum. In October 2000, we agreed to convert $4.6 million
of the subordinated debentures into our Series A Preferred Stock. In May 2001,
we agreed to pay the affiliate $3.0 million cash plus issue to the affiliate
$4.6 million of the Company's Series B Preferred Stock in full satisfaction of
all of the remaining outstanding subordinated debentures including accrued
interest of $1.8 million. This transaction resulted in the affiliate agreeing to
forgive $1.0 million of indebtedness which has been reflected as a capital
contribution from the affiliate rather than as income in the accompanying
financial statements. (See Note 9 regarding the accounting for preferred stock.)

In connection with the original issuance of the subordinated debentures, we
issued to the affiliate detachable warrants to purchase 5,738,500 shares of our
common stock, of which 2,901,000 have been cancelled as of December 31, 2001.
The remaining 2,837,500 warrants outstanding are all exercisable with exercise
prices ranging from $0.75 to $2.00 per share.

The following table summarizes the exercise prices of warrants as of December
31, 2001:

5. ASSET IMPAIRMENT AND OTHER NON-RECURRING CHARGES

During 1997 and the first half of 1998, we experienced significant growth
through a series of strategic acquisitions, and increasing demand for our
services. Due to a significant decrease in the price of oil and gas and the
resultant impact on drilling activity, we experienced a sharp decline in the
demand for our services during the second half of

-36-

1998 through 2000. This decline in customer demand materialized quickly from the
previous growth period and caused us to reassess our overall operations. This
change in our market and reassessment of operations resulted in our recording of
the following charges to asset impairment during 1999, 2000, and 2001 (in
thousands):

During 1998 and continuing into 1999, the aviation division experienced
recurring losses and several assets have been sold or are currently held for
sale. In 1999 we wrote off all of the goodwill associated with the aviation
division of $6.9 million, aviation equipment and inventory of $2.9 million and
other assets of $0.5 million. In 1999, we wrote off $1.9 million of goodwill,
$2.9 million of aviation equipment and $0.5 million of other assets, all
associated the aviation division.

As a result of the continuing market decline during 2000, we recorded an asset
impairment of $11.3 million. The principal component of this charge was a net
$7.5 million writeoff of goodwill, which consisted of $4.9 million related
primarily to the international drilling and line cutting segments and $2.6
million related to the survey segment. Based on historical and projected
undiscounted revenue and expense trends, we do not believe that these segments
will generate sufficient activity to realize the carrying value of the goodwill.
The $3.4 million of impairment of drilling, aviation and field equipment
represents the writedown to estimated fair value of excess equipment that we
have identified that is no longer needed to support future operations. We have
recorded the assets at their estimated selling price. The assets include
leasehold improvements for an aviation hanger no longer used by the aviation
division, estimated losses on the return of aircraft under an operating lease
and certain domestic and international seismic drill units and related field
equipment. The $0.3 million of other assets represents loan closing costs
written off that are related to loans that have been renegotiated with various
lenders during 2000.

In 2001 we revalued the tractors being held for sale to prices that more closely
approximated their fair market values. In doing so, we recognized asset
impairment charges of $0.2 million for the year ended December 31, 2001. All of
the tractors were sold by the end of 2001 at prices that approximated their
newly assigned values. We also revalued the steel marsh buggies being held for
sale to their appraised fair market values as of December 31, 2001. This
revaluation resulted in an additional $0.4 million charge to asset impairment
for the year ended December 31, 2001.

At December 31, 2000 and 2001, we had $1.7 million and $0.6 million in assets
held for sale. As of December 31, 2001, assets held for sale include 8 steel
marsh buggies as well as the remaining assets of our South American operation,
for which we have specific agreements to sell. We expect to dispose of the
remaining assets held for sale during 2002. The carrying values, which we
believe approximate fair market value of our assets held for sale at December
31, 2001 is as follows (in thousands):

-37-

6. RELATED PARTY TRANSACTIONS

During the year ended December 31, 2001 we leased a facility from a major
shareholder at a total lease expense of $0.1 million, which approximated market
values. We were under a lease contract for a portion of 2001 (See Note 8). See
also Notes 4 and 9 for other transactions with our affiliates.

In July 2000, we entered into a series of transactions with the same affiliate
that enabled us to factor, with recourse, approximately $1.0 million of the
trade receivable of a major customer. This receivable had become ineligible
under the terms of our Line. As of December 31, 2001 we are liable to the
affiliate for approximately $0.2 million, which is payable in twelve equal
monthly installments commencing 30 days after execution of the definitive
repayment agreement between us and the affiliate.

We also placed subordinated debt with our major shareholder, which was
subsequently converted to preferred stock (See Notes 4 and 9).

7. CUSTOMER CONCENTRATION

During the year ended December 31, 1999, three customers accounted for 60% (33%,
17% and 10%, respectively) of our total revenues. Included in accounts
receivable as of December 31, 1999, are amounts owed from these customers
totaling approximately 41% (8%, 32% and 1%, respectively) of total accounts
receivable.

During the year ended December 31, 2000, three customers accounted for 49% (34%,
8% and 7%, respectively) of our total revenues. Included in accounts receivable
as of December 31, 2000, are amounts owed from these customers totaling
approximately 39% (27%, 12% and 0%, respectively) of total accounts receivable.

During the year ended December 31, 2001, three customers accounted for 71% (43%,
16% and 12%, respectively) of our total revenues. Included in accounts
receivable as of December 31, 2001, are amounts owed from these customers
totaling approximately 74% (7%, 34% and 33%, respectively) of total accounts
receivable.

8. COMMITMENTS AND CONTINGENCIES

Leases

During 1999, we entered into a sale leaseback transaction with our aviation
fleet. We received $8.0 million upon sale of the aircraft and entered into an
operating lease for a period of 10 years. Monthly rental payments under the
lease were approximately $80,000. In December 2001, we exercised our purchase
option to acquire the aviation fleet previously under this lease obligation
resulting in a $4.7 million note payable at December 31, 2001 (See Note 3).
Future payments under this agreement will be recorded as a reduction in
principal of the debt.

Total rental expense was $3,763,815, $2,612,840 and $1,558,767 for the years
ended December 31, 1999, 2000 and 2001, respectively. At December 31, 2001 we
leased certain offices, warehouse facilities and drilling equipment under
noncancellable operating lease agreements which expire at various times. The
noncancelable operating leases that were in effect as of December 31, 2001
require us to make the following future minimum lease payments (in thousands):

-38-

Insurance

We carried workers compensation insurance coverage with a deductible amount of
$250,000 per incident for claims incurred in 1997. In 1999, we changed insurance
carriers and had no deductible. Management is not aware of any significant
workers compensation claims or any significant claims incurred but not reported
as of December 31, 2001.

Litigation

In the normal course of our business, we become involved in various litigation
matters including, among other things, claims by third parties for alleged
property damages, personal injuries and other matters. While we believe we have
meritorious defenses against these claims, management has used estimates in
determining our potential exposure and has recorded reserves in our financial
statements related thereto where appropriate. It is possible that a change in
our estimates of that exposure could occur, but we do not expect such changes in
estimate costs will have a material effect on our financial position or results
of operations.

Employment Agreements

We have entered into employment agreements with certain key executive officers
which include base salaries and terms of employment.

9. STOCKHOLDERS' EQUITY

Preferred Stock

At December 31, 2001 we had a total of 7,500 shares of Series A Preferred Stock,
and in March 2002 issued 4,600 shares of Series B Preferred Stock, at a total
liquidation value of $12.1 million.

The Series A Preferred Stock has an 8% cumulative dividend rate, is convertible
into our common stock with a conversion rate of $0.75, is redeemable at our
option at $1,000 per share plus accrued dividends, contains a liquidation
preference of $1,000 per share, has voting rights on all matters submitted to a
vote of our shareholders, has separate voting rights with respect to matters
that would affect the rights of the holders of the Preferred Stock, and has
aggregate voting rights of the affiliate limited to 49% of our total outstanding
common and preferred shares with voting rights. In respect to the Series A
Preferred Stock, the affiliate has agreed to waive its conversion rights until
our EBITDA (as defined) reaches a mutually agreed upon level. The preferred
shareholders have also agreed that dividends would not accrue on the outstanding
stock from April 2001 through June 2002. Dividends are being accreted at 8%
during the free dividend period. As of April 2001 there were approximately $0.3
million of dividends in arrears relating to these outstanding shares of Series A
Preferred Stock.

In May 2001, we committed to issue 4,600 shares of Series B Preferred Stock to
an affiliate of ours in satisfaction of all outstanding principal and interest
owed under the subordinated debt agreements (See Note 4). These shares were
issued in March 2002. The Series B Preferred Stock has an 8% cumulative dividend
rate, is convertible into our common stock with an initial conversion rate of
$1.25, is redeemable at our option at $1,000 per share plus accrued dividends,
contains a liquidation preference of $1,000 per share and has no voting rights
until such time as it becomes convertible. The Series B Preferred Stock does not
have conversion rights until our EBITDA (as defined) reaches a mutually agreed
upon level, and until all shares of Series A Preferred Stock become convertible.
We have also agreed that dividends would not accrue on the outstanding stock
from May 2001 through June 2002. Dividends are being accreted at 8% during the
free dividend period. As of May 2001 there were no dividends in arrears relating
to the outstanding shares of Series B Preferred Stock.

-39-

Stock Options

In September 1997, we adopted and our sole shareholder approved the Stock
Incentive Plan (the "Incentive Plan") to provide long-term incentives to our key
employees, officers, directors who are our employees, and our consultants and
advisors and non-employee directors ("Eligible Persons"). Under the incentive
plan, we may grant incentive stock options, non-qualified stock options,
restricted stock, other stock-based awards, or any combination thereof to
Eligible Persons. Options generally vest over a four-year period and expire if
unused after ten years. The exercise price of any stock option granted may not
be less than the fair market value of the common stock on the date of grant. A
total of 3,000,000 shares of common stock have been authorized under the
Incentive Plan, of which 516,166 remain available for issuance at December 31,
2001.

In January 1999, we approved the Stock Option Plan (the "Option Plan") to
provide for the grant of options to purchase shares of our common stock to
non-officer employees of our company and our subsidiaries in lieu of year-end
cash bonuses. The Option Plan is intended to increase shareholder value and
advance our interests by providing an incentive to employees and by increasing
employee awareness of us in the marketplace. Under the Option Plan, we may grant
options to any of our employees with the exception of our officers. The options
become exercisable immediately with respect to one-half of the shares, and the
remaining one-half shall be exercisable one year following the date of the
grant. The exercise price of any stock option granted may not be less than the
fair market value of the common stock on the effective date of the grant. A
total of 300,000 shares of common stock are authorized, of which 48,783 remain
available for issuance at December 31, 2001.

We account for employee stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees". Accordingly, the provisions of SFAS
No. 123, "Accounting for Stock-Based Compensation," do not affect our reported
results of operations. Pro forma disclosures as if we had adopted the provisions
of SFAS No. 123 are presented below.

Had compensation cost been determined based on the fair value at the grant date
consistent with the provisions of SFAS No. 123, our net income and earnings per
common share would have approximated the pro forma amounts below:

-40-

A summary of our stock options as of December 31, 1999, 2000 and 2001, and
changes during the years then ended are presented below:

The weighted average fair value at date of grant for options granted during 1999
was $1.94 per option. The fair value of options granted is estimated on the date
of grant using the Black-Scholes option-pricing model with the following
assumptions: (a) dividend yield of 0.00%; (b) expected volatility ranging from
75% to 82%; (c) average risk-free interest rate of 5.70%; and (d) expected life
of 6.5 years.

The weighted average fair value at date of grant for options granted during 2000
was $0.54 per option. The fair value of options granted is estimated on the date
of grant using the Black-Scholes option-pricing model with the following
assumptions: (a) dividend yield of 0.00%; (b) expected volatility 111%; (c)
average risk-free interest rate of 5.86%; and (d) expected life of 6.5 years.

The weighted average fair value at date of grant for options granted during 2001
was $0.66 per option. The fair value of options granted is estimated on the date
of grant using the Black-Scholes option-pricing model with the following
assumptions: (a) dividend yield of 0.00%; (b) expected volatility 94%; (c)
average risk-free interest rate of 4.17%; and (d) expected life of 6.5 years.

-41-

The following table summarizes information about stock options outstanding as of
December 31, 2001:

Common Stock

We currently have 45,000,000 shares of our $0.01 par value common stock
authorized; of these authorized shares, there were 26,911,724 and 27,295,474
issued at December 31, 2000 and 2001, respectively. In November 2000, 3,907,469
new shares were issued in conjunction with the acquisition of Gulf Coast
Resources (See Note 12) and 6,960,000 were issued in conjunction with the
private placement (See Note 1). In 2001 we repurchased 1,085,400 shares which
are classified as treasury shares.

On October 31, 2001 we authorized the repurchase of up to 1,000,000 shares of
our common stock. We expect to repurchase our shares from time to time through
open market purchases or privately negotiated transactions. The timing and
amount of shares repurchased will depend on prevailing share market prices and
trading volume. We expect to fund future repurchases of our common stock with
operating cash or through our credit facility.

Earnings Per Share

Basic EPS excludes dilution and is determined by dividing income available to
common stockholders by the weighted average number of shares of common stock
outstanding during the period. Diluted EPS reflects the potential dilution that
could occur if options and other contracts to issue shares of common stock were
exercised or converted into common stock. We had 1,415,061, 1,616,950 and
1,115,096 options outstanding in the years ended December 31, 1999, 2000 and
2001, respectively, that were excluded from the calculation of diluted EPS as
antidilutive. In addition, warrants to purchase up to 1,937,500, 5,738,500 and
554,167 shares of common stock were also excluded for the years ended December
31, 1999, 2000 and 2001, respectively.

The following table sets forth the computation of basic and diluted weighted
average shares for the years ended December 31, 1999, 2000 and 2001 (in
thousands):

-42-

10. INCOME TAXES

The components of deferred tax assets and liabilities as of December 31, 2000
and 2001 are as follows (in thousands):

The income tax expense (benefit) for the years ended December 31, 1999, 2000 and
2001 consisted of the following (in thousands):

The reconciliation of Federal statutory and effective income tax rates for the
years ended December 31, 1999, 2000 and 2001 is shown below:

As of December 31, 2001, for tax purposes, we had net operating loss
carryforwards (NOLs) of approximately $34.9 million. The NOLs will expire
commencing 2019. We account for income taxes under the provision of SFAS No. 109
which requires recognition of future tax benefits (NOLs and other temporary
differences), subject to a valuation allowance based on the likelihood of a
concept of "more-likely-than-not" of realizing such benefit. In determining
whether it is "more-likely-than-not" that we will realize such benefits, SFAS
No. 109 requires that all negative and positive evidence be considered (with
more weight given to evidence that is "objective and verifiable") in making the
determination. SFAS No. 109 indicated that "forming a conclusion that a
valuation allowance is not needed is difficult when there is negative evidence
such as cumulative losses in recent years"; therefore we determined that it was
required by the provision of SFAS No. 109 to maintain a valuation allowance of
$10.6 million for all of the

-43-

recorded net deferred tax assets. This determination was based primarily on
historical losses without considering the impact of any potential upturn in our
business due to improvements in the seismic market, refinancing of current
indebtedness or new capital infusion, or other changes to our operations.
Accordingly, future favorable adjustments to the valuation allowance may be
required if and when circumstances change.

11. SEGMENT INFORMATION

SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information," which requires that companies disclose segment data based on how
management makes decisions about allocating resources to segments and measuring
their performance. Currently, we operate principally in four segments, which
operate in North America. As of December 31, 2001, approximately $0.5 million of
our assets are located in South America. All remaining assets are located in
North America.

Drilling revenue is derived primarily from drilling and loading of the source
points for seismic analysis. Aviation revenue is derived through transport of
geophones and recorders used to collect the seismic data between receiving
points. Helicopters are also used to transport heli-portable drilling units into
remote or otherwise inaccessible terrain, as well as to transport people and
equipment to offshore oil rigs. Survey revenue is recorded after the customer
has determined the placement of source and receiving points, and after survey
crews are sent into the field to plot each source and receiving point prior to
drilling. Permitting revenue is derived from services provided in conjunction
with obtaining permits from landowners. In 1998, we expanded internationally
into South America. In 2000 we ceased providing services in South America.

The following shows industry segment information for the years ended December
31, 1999, 2000 and 2001:

(1) Consists of line-cutting services in South America

-44-

(2) In December 2001, we exercised our purchase option to acquire the aviation
fleet previously under lease obligation.

12. ACQUISITION

Effective October 31, 2000, we acquired Gulf Coast Resources, a seismic drilling
support company headquartered in Broussard, Louisiana. The aggregate purchase
price was $3.7 million consisting of $0.8 million in cash and 3,907,469 shares
of common stock valued at $2.4 million. The excess cost over the estimated fair
value of the net assets resulted in goodwill of approximately $2.1 million which
is being amortized on a straight-line basis over 20 years. Our pro forma results
as though Gulf Coast Resources transaction had taken place on January 1, 2000
would have resulted in revenues, net loss and basic loss per share of $20
million, $(25.7) million and $(1.24), respectively. The pro forma effect on our
1999 revenues, net income or per share earnings was not material. The operating
results of Gulf Coast Resources have been included in consolidated statements of
income from the effective date of acquisition.

-45-

13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

(1) The fourth quarter of 1999 and 2000 include a provision for valuation
allowance of and $5.8 million and $10.9 million, respectively. (See
Note 10).

(2) The fourth quarter of 2001 includes an insurance premium receivable
recorded of approximately $0.3 million and an inventory book to
physical adjustment of approximately $0.4 million.

(3) The second and third quarters have been restated to record accretion of
preferred stock (See Note 9).

-46-

14. EVENTS SUBSEQUENT TO DATE OF AUDITORS' REPORT (unaudited):

On March 25, 2002, we announced the acquisition of the assets of AirJac
Drilling, a division of Veritas DGC Land, Inc., a seismic drilling support
company headquartered in New Iberia, Louisiana. The aggregate purchase price was
$2.0 million cash. In this acquisition we acquired the following types of
equipment:

-47-

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information concerning our directors and officers called for by this
item will be included in our definitive Proxy Statement prepared in connection
with the 2002 Annual Meeting of shareholders and is incorporated herein by
reference.

ITEM 11. EXECUTIVE COMPENSATION

Information concerning the compensation of our executives called for by
this item will be included in our definitive Proxy Statement prepared in
connection with the 2002 Annual Meeting of shareholders and is incorporated
herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information concerning security ownership of certain beneficial owners
and management called for by this item will be included in our definitive Proxy
Statement prepared in connection with the 2002 Annual Meeting of shareholders
and is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information concerning certain relationships and related transactions
called for by this item will be included in our definitive Proxy Statement
prepared in connection with the 2002 Annual Meeting of shareholders and is
incorporated herein by reference.

ITEM. 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) The following financial statements, schedules and exhibits are filed as
part of this Report:

(1) Financial Statements. Reference is made to Item 8 hereof.

(2) Financial Statement Schedules: None.

(3) Exhibits. See Index to Exhibits on page E-1. We will furnish to any
eligible shareholder, upon written request of such shareholder, a copy of any
exhibit listed upon the payment of a reasonable fee equal to our expenses in
furnishing such exhibit.

(b) Reports on Form 8-K:

-48-

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
our behalf by the undersigned, thereunto duly authorized.

OMNI ENERGY SERVICES CORP.
(Registrant)

By: /s/ James C. Eckert
-------------------------------------
James C. Eckert
President and Chief Executive Officer
(Principal Executive Officer)

Date: April 1, 2002

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.

S-1

OMNI ENERGY SERVICES CORP.

EXHIBIT INDEX

EXHIBIT
NUMBER
------

2.1 Exchange Agreement between the members of OMNI Geophysical,
L.L.C. and OMNI Energy Services Corp. (the "Company")(1)

2.2 Exchange Agreement by and among American Aviation
Incorporated, American Aviation L.L.C. and OMNI Geophysical,
L.L.C., dated as of July 1, 1997.(2)

2.3 Agreement and Plan of Merger dated as of November 16, 2000
among us, Gulf Coast Acquisition Company, Inc., Gulf Coast
Resources, Inc. and the shareholders listed therein. (7)

3.1 Composite Articles of Incorporation of OMNI Energy Services
Corp.(as of November 7, 2000). (7)

3.2 Form of Articles of Amendment - Articles of Incorporation

3.3 Bylaws of OMNI, as amended. (5)

4.1 See Exhibit 3.1 and 3.2 for provisions of our Articles of
Incorporation and By-laws defining the rights of holders of
Common Stock.

4.2 Specimen Common Stock Certificate.(2)

4.3 Form of Stock Purchase Agreement effective October 31, 2000
between us and each of Dixie Chris OMNI LLC, Advantage
Capital Partners X Limited Partnership, RJP Investment
Company, LLC, Charles Chatelain, Adrian M. Vega, Jr.,
William W. Rucks, IV, Burton T. Zaunbrecher and Gerald
Hanchey. (7)

10.1 Form of Indemnity Agreement by and between us and each of
our directors and executive officers. (2)

10.2 Stock Incentive Plan.(2)

10.3 Form of Stock Option Agreements under our Stock Incentive
Plan.(2)

10.4 Intangible Asset Purchase Agreement by and among American
Aviation Incorporated, American Aviation L.L.C. and OMNI
Geophysical, L.L.C., dated as of July 1, 1997. (2)

10.5 Joint Venture Agreement among us, OMNI International Energy
Services, Ltd. and Edwin Waldman Attie effective July 1,
1999. (3)

10.6 Third Amended and Restated Loan Agreement by and among us,
certain of our subsidiaries and Hibernia National Bank,
dated October 30, 2001. (6)

10.7 Agreement by and among us and the holders of Series A 8%
convertible Preferred Stock dated May 8, 2001.

21.1 Subsidiaries of OMNI

23.1 Consent of Arthur Andersen LLP.

99.1 Letter to SEC regarding Arthur Andersen LLP

E-1

(1) Incorporated by reference to our Annual Report on Form 10-K for the
fiscal year ended December 31, 1997

(2) Incorporated by reference to our Registration Statement on Form S-1
(Registration Statement No. 333-36561).

(3) Incorporated by reference to our Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999.

(4) Incorporated by reference to our Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999.

(5) Incorporated by reference to our Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001.

(6) Incorporated by reference to our Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001.

(7) Incorporated by reference to our Annual Report on Form 10-K for the
fiscal year ended December 31, 2000.

E-2