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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
[ ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF
THE SECURITIES EXCHANGE ACT OF 1934
OR
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER: 1-14614
PETROLEUM GEO-SERVICES ASA
(Exact name of registrant as specified in its charter)
KINGDOM OF NORWAY
(Jurisdiction of incorporation or organization)
STRANDVEIEN 50E, P.O. BOX 89, N-1325 LYSAKER, NORWAY
(Address of principal executive offices)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
<S> <C>
American Depositary Shares, each representing New York Stock Exchange
one
share of nominal value NOK 5 per share
PGS Trust I 9 5/8% Trust Preferred Securities New York Stock Exchange
</TABLE>
Securities registered or to be registered pursuant to Section 12(g) of the
Act: None
Securities for which there is a reporting obligation pursuant to Section
15(d) of the Act: None
As of December 31, 1999, the number of shares outstanding was 101,609,587.
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 which financial statement item the registrant has
elected to follow.
Item 17 [ ] Item 18 [X]
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PETROLEUM GEO-SERVICES ASA
ANNUAL REPORT ON FORM 20-F FOR THE
FISCAL YEAR ENDED DECEMBER 31, 1999
TABLE OF CONTENTS
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PAGE
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Certain Definitions and U.S. Dollar Presentations..................... 3
Forward-Looking Information........................................... 3
PART I
ITEM 1. Description of Business..................................... 4
ITEM 2. Description of Property..................................... 23
ITEM 3. Legal Proceedings........................................... 23
ITEM 4. Control of Registrant....................................... 23
ITEM 5. Nature of Trading Market.................................... 24
ITEM 6. Exchange Controls and Other Limitations Affecting Security 25
Holders...................................................
ITEM 7. Taxation.................................................... 25
ITEM 8. Selected Financial Data..................................... 28
ITEM 9. Management's Discussion and Analysis of Financial Condition
and Results of
Operations.................................................. 31
ITEM 9A. Quantitative and Qualitative Disclosures About Market 37
Risk......................................................
ITEM 10. Directors and Officers of Registrant........................ 38
ITEM 11. Compensation of Directors and Officers...................... 39
ITEM 12. Options to Purchase Securities from Registrant or 40
Subsidiaries..............................................
ITEM 13. Interest of Management in Certain Transactions.............. 41
PART III
ITEM 15. Defaults upon Senior Securities............................. 42
ITEM 16. Changes in Securities, Changes in Security for Registered 42
Securities and Use of Proceeds............................
PART IV
ITEM 18. Financial Statements........................................ 42
ITEM 19. Financial Statements and Exhibits........................... 42
</TABLE>
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Note: Omitted items are inapplicable.
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CERTAIN DEFINITIONS AND U.S. DOLLAR PRESENTATIONS
We are a public limited liability company established under the laws of the
Kingdom of Norway. We are organized as a holding company that owns subsidiary
companies. Our subsidiary companies conduct substantially all of our business.
Unless we inform you otherwise or the context indicates otherwise, references to
us in this annual report on Form 20-F are to Petroleum Geo-Services ASA, its
predecessors and its majority-owned subsidiaries.
In this annual report, references to "U.S. dollars" and "$" are to United
States dollars; references to "NOK" are to Norwegian kroner; and references to
"British pounds" and "L" are to British pounds sterling.
FORWARD-LOOKING INFORMATION
Some of the statements contained in this annual report are "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. These statements:
- address activities, events or developments that we expect, believe,
anticipate or estimate will or may occur in the future
- are based on assumptions and analyses that we have made and that we
believe were reasonable under the circumstances when made
- are based on many assumptions, uncertainties and other factors, many of
which are beyond our control
Any one of these assumptions, uncertainties or other factors, or a
combination of these assumptions, uncertainties or other factors, could
materially affect our future results of operations, financial position, cash
flows and whether the forward-looking statements ultimately prove to be
accurate. These forward-looking statements are not guarantees of our future
performance, and our actual results, financial position, cash flows and future
developments may differ materially from those projected in the forward-looking
statements. When considering these forward-looking statements, you should keep
in mind the risk factors and other cautionary statements elsewhere in this
annual report. We will not update these statements unless the securities laws
require us to do so. Please read "Description of Business -- Risk Factors
Relating to Our Business" in Item 1 of this annual report.
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PART I
ITEM 1. DESCRIPTION OF BUSINESS
OVERVIEW OF WHO WE ARE
We are a technologically focused oilfield service company. Our business
includes:
- acquiring, processing, managing and marketing seismic data. Oil and gas
companies use the data to explore for new oil and gas reserves, to
develop existing oil and gas reservoirs and to manage producing oil and
gas fields.
- providing floating production, storage and offloading, or FPSO, vessels.
These vessels permit oil and gas companies to produce oil and gas from
offshore fields and to process, store and offload the oil and gas for
transport to refineries, distribution companies and end-users. We also
provide various production management services related to these
operations.
- providing geophysical and other services that help oil and gas companies:
- store, organize and retrieve seismic data
- monitor producing oil and gas reservoirs to increase ultimate recoveries
BUSINESS STRATEGIES
Our principal business strategies include:
- using, developing and investing in advanced technologies for the
acquisition, processing, management and marketing of seismic data
- expanding our production services, including FPSO and other production
management services, and 4D seismic and reservoir monitoring services by
using our advanced geophysical technologies, reservoir expertise and
proprietary rights in the Ramform vessel design
- pursuing opportunities to acquire both multi-client and contract seismic
data in active oil and gas exploration and production areas around the
world
- pursuing acquisitions that complement our core businesses
MARINE SEISMIC BACKGROUND
Overview
Oil and gas companies use geophysical or seismic surveys to help them find
oil and gas and to determine the size and structure of known oil and gas
reservoirs. Seismic projects generally consist of planning a seismic survey and
acquiring, processing and interpreting seismic data. Such data are then used to
produce computer-generated graphic two-dimensional, or 2D, cross-sections or
three-dimensional, or 3D, images of the subsurface. Oil and gas companies use
these seismic images in evaluating whether to acquire new leases or licenses in
areas with potential accumulations of oil and gas, in selecting drilling
locations and in managing producing reservoirs.
We refer to the repetition of identical 3D surveys over the same area at
different time intervals as "4D" data or surveys. Oil and gas companies use
these surveys to gain an understanding of changing subsurface geophysical
conditions over time.
How We Acquire Marine Seismic Data
To acquire marine seismic data through conventional streamer operations, we
discharge a wave of acoustic energy just below the water's surface from one or
more energy sources towed behind one or more survey vessels. We typically
generate this acoustic wave with "air guns" that release a burst of compressed
air. As the wave travels through the water and subsurface earth, portions of the
wave are reflected back at
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rock layer boundaries. The reflections are detected by hydrophones contained in
streamers towed behind the survey vessels. The streamers convert the reflected
waves into digital data that are then transmitted to a recording unit onboard
the survey vessel. We then analyze the acquired data for quality control
purposes before inputting the data into a processing system to produce maps of
prospective drilling areas and producing oil and gas reservoirs. In addition to
conventional streamer operations, we also acquire marine seismic data through
ocean bottom seismic operations, in which we place recording cables on the ocean
floor and retrieve them as data are acquired. We also use specialized 4D and
multi-component acquisition techniques that do not use conventional streamers or
ocean bottom cables. Please read "-- 3D and 4D Seismic Operations," "-- Marine
Seismic Data Acquisition -- Ocean Bottom Seismic/Multi-Component Operations,"
and "-- Reservoir Monitoring."
Contract and Multi-Client Data
We acquire marine seismic data both on an exclusive contract basis for our
customers and on our own behalf as multi-client data for licensing on a
non-exclusive basis to others. We acquire contract data for the specific client
that requests the data. We acquire and retain ownership of multi-client data for
licensing from time to time to customers on a non-exclusive basis. In some of
our projects, we share interests in the revenue from the sales of the
multi-client data with third parties.
Where We Acquire Seismic Data
We conduct the majority of our seismic data acquisition business in the
North Sea and offshore South America and West Africa. We also acquire seismic
data in other active oil and gas exploration and/or production areas around the
world from time to time, including:
- the Gulf of Mexico
- offshore China
- offshore India
- the Sakhalin area of Russia
- offshore Australia, Indonesia and other countries in the Asia Pacific
region
- offshore Canada
- the Middle East
- the Caspian Sea area
Demand for Marine Seismic Services
Various factors influence the demand for marine seismic services,
including:
- the demand for and prices of oil and gas
- the level of exploration and production spending
- developments in technology that affect the cost, quality and reliability
of marine seismic data
Because of improvements in the quality and reductions in the per unit cost
of 3D marine seismic surveys, we believe that oil and gas companies have
increased their use of 3D marine seismic data for development and production
purposes. As a result, the demand for certain types of data have become somewhat
less sensitive to changes in exploratory drilling activity and in oil and gas
prices.
3D and 4D Seismic Operations
We no longer perform 2D seismic surveys. By briefly discussing 2D seismic,
however, we can better describe for you our 3D and 4D seismic operations.
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A 2D marine seismic survey typically is produced by a single survey vessel
towing a single streamer and one energy source. The seismic data acquired
generally represent a vertical cross-section along the line tracked by the
streamer, which we refer to as a "seismic line." We acquire 3D data by combining
parallel 2D seismic lines that can be processed to produce a three-dimensional
image of subsurface strata. When we perform a 3D seismic survey, we acquire a
dense grid of seismic data using multiple streamer configurations over a
precisely defined area. Such data acquisition requires the use of sophisticated
navigation equipment that permits the constant and precise determination of the
positions of streamers and energy sources during the acquisition process. This
determination of position is essential to producing accurate subsurface images.
When we perform a 4D seismic survey, we repeat a series of 3D seismic surveys
over the same survey area at different time intervals. This series of surveys
shows the changing subsurface geophysical conditions over time.
In acquiring 3D marine seismic data, we may use multiple vessels and
multiple streamers and energy sources to acquire more rapidly and
cost-effectively the large number of seismic lines needed to produce a 3D data
volume. By increasing the number of streamers and energy sources used, we can
perform large surveys more rapidly and cost-effectively. Dual vessel operations,
with one vessel acting as a source/ recording vessel and the other as a
recording vessel, permit us to acquire data in areas where production platforms
or other obstructions interfere with seismic operations. Dual vessel operations
also generally allow us to use shorter streamers, which improves efficiency and
reduces the chance of collision or entanglement with obstructions. In addition,
we use multiple vessel and streamer configuration operations to acquire data for
imaging deep targets.
Useful 4D seismic information requires a high density of 3D seismic data
and increased computing capacity to reflect the subtle changes in geophysical
conditions that occur over time. Our Ramform seismic vessels, with their large
streamer towing capacity, are well suited for this purpose. We believe that oil
and gas companies will find 4D seismic surveys and related reservoir monitoring
services to be particularly useful in their efforts to increase recoveries from
producing petroleum reservoirs. Please read "-- Reservoir Monitoring."
FPSO BACKGROUND
Overview
In the remainder of this "Description of Business" section, we will use the
acronym "FPSO" to refer to floating production, storage and offloading.
An FPSO system is a type of mobile production unit that produces,
processes, stores and offloads oil and gas from offshore fields with widely
differing production characteristics, sizes and water depths. The selection of a
particular mobile production unit from among the several types of readily
movable offshore production systems depends on an overall technical and
financial evaluation of the field to be developed. FPSO systems typically
perform the same function as fixed offshore platforms in the offshore production
of oil and gas, with the exceptions of drilling and heavy well maintenance.
However, FPSO systems provide a number of advantages over fixed platforms
including:
- being suitable for a wide range of field sizes and water depths
- being reusable on more than one developed reservoir
- generally costing less and being easier to install and remove than fixed
platforms
- reducing the time from the discovery of oil and gas to production
An FPSO vessel may be either a newly constructed vessel specifically
designed to function in an FPSO system or an existing tanker or other marine
vessel converted to function in an FPSO system. A typical FPSO life-of-field
system consists of wells completed using subsea wellheads that are connected to
the FPSO vessel by flexible tubing, which we call risers. Risers carry the oil
and gas from the ocean floor to the vessel. The flexible risers are connected to
a turret, which is moored in place by an anchoring
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system. This mooring allows the FPSO vessel to rotate according to the
prevailing weather and current conditions. The FPSO system controls the flow of
oil and gas from the wells through control "umbilicals" that extend from the
turret to the subsea wellhead. The oil and gas are processed onboard the FPSO
vessel and the resulting oil is exported, either by a subsea pipeline or an
off-take system using shuttle tankers. Natural gas may be exported by subsea
pipeline, reinjected into the reservoir or, in some circumstances, flared.
Demand for FPSO Services
How the FPSO Market Differs from the Seismic Market. The market for FPSO
services differs fundamentally from the seismic market. Offshore production,
either for test purposes or for full exploitation, generally takes place a
relatively long time after exploration drilling has been completed. Oil and gas
companies typically make production-related decisions based on different
financial parameters and with different views about changes in oil and gas
prices than are used for decisions relating to seismic or drilling activities.
Oil and gas companies in a number of oil producing areas have increasingly
focused on the development of smaller fields with relatively smaller or
uncertain reservoir estimates and/or shorter expected producing lives. For
development of these smaller fields to be profitable, the oil and gas companies
must reduce cost levels and financial exposure. As a result, producers have
focused increasingly on subsea installations and FPSO systems instead of the
more traditional fixed steel and concrete platforms.
The FPSO Market. The market for FPSO systems can generally be divided into
three segments:
- extended well tests or production testing
- early production
- life-of-field development
In production testing, the oil and gas company produces oil and gas from
one or more producing formations or zones, and from one or more wells, to
confirm various characteristics of a reservoir. The oil and gas company then
uses this information, among other things, to make better estimates of the
productivity and extent of the reservoir and to position production facilities.
From the perspective of an FPSO operator, use of FPSO systems for production
testing, which is relatively short-term in nature, involves a greater risk that
the FPSO system will not maintain high utilization rates due to downtime between
contracts.
The early production phase of development follows the decision to develop a
tested field into full production. During this phase, production facilities are
engineered, built and installed. By increasing production during this phase, the
overall financial performance of the field can be enhanced by reducing the need
for or level of financing and by providing income and cash flow at an earlier
stage than would otherwise be the case.
In life-of-field development, the FPSO system is designed for production
for the life of the field and the operator generally attempts to adapt either
the production facility to the reservoir requirements or the reservoir strategy
to the production facility.
SEISMIC CREW AND VESSEL INFORMATION
Our Fleet and Crews
We believe that we operate the most advanced marine seismic data
acquisition fleet in the world. To improve crew productivity and efficiency, we
emphasize a high ratio of streamers towed to crews in operation. As of December
31, 1999, we had a total of eight 3D marine seismic streamer crews operating ten
seismic vessels. In addition, as of December 31, 1999, we had one ocean bottom
seismic crew and one multi-component crew. Please read "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Results of
Operations -- 1999 Compared with 1998" in Item 9 of this annual
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report for a discussion of steps we have taken to reduce the size of our fleet,
the number of crews and operating costs.
We acquire marine seismic data using seismic crews on both owned and
chartered vessels that have been constructed or modified to our specifications
and outfitted with a full complement of data acquisition, recording, navigation
and communications equipment. Our crews direct the positioning of a vessel using
sophisticated navigation equipment, deploy and retrieve streamers and energy
sources, and operate all of the seismic systems. Our seismic crews do not
operate the vessels. The vessel crews are employees of either the owner of the
chartered vessels or a contract operator for our vessels.
Equipment Used on Our Seismic Vessels. Most of our seismic vessels, other
than those used in ocean bottom seismic or multi-component operations, have an
equipment complement consisting of the following:
- recording instrumentation
- digital recording streamers
- streamer and seismic data location systems
- multiple navigation systems
- except for vessels that record only, a source control system that
controls the synchronization of the energy sources and a firing system
that generates acoustic energy
In addition, we have deployed massively parallel processing supercomputer
systems for all of our 3D seismic data acquisition crews. Please read
"-- Seismic Data Processing Operations."
For ocean bottom seismic operations, the Carlson Tide, the Jonathan Chouest
and the Dickerson Tide each have a dynamic positioning system and recording
instrumentation that permits the recording of data from up to 48 kilometers of
ocean bottom cables. These vessels also have equipment to deploy and recover
cables automatically.
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Vessel Information. We provide in the following table information as of
December 31, 1999 about our marine seismic data acquisition vessels.
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MAXIMUM
STREAMERS
DEPLOYED
TOTAL TOTAL LONG-LENGTH (THROUGH OWNED OR
YEAR RIGGED/ LENGTH BEAM STREAMER DECEMBER 31, CHARTER
VESSEL NAME CONVERTED (FEET) (FEET) CAPABILITY 1999) EXPIRATION
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3D SEISMIC VESSELS:
Ramform Challenger......... 1996 284 130 16 12 Owned
Ramform Explorer........... 1995 270 130 12 12 Owned
Ramform Valiant............ 1998 284 130 20 12 2023(1)
Ramform Viking............. 1998 284 130 20 12 2023(1)
Ramform Victory............ 1999 284 130 20 12 2024(1)
Ramform Vanguard........... 1999 284 130 20 12 2024(1)
Ocean Explorer(2).......... 1993/95 269 59 6 6 Owned
Atlantic Explorer.......... 1994 300 58 6 6 Owned
American Explorer.......... 1994 306 59 6 6 Owned
Nordic Explorer(2)......... 1993 209 54 6 6 Owned
Orient Explorer(2)......... 1995/96 246 49 4 4 2001
Geo Explorer(2)(3)(4)...... 1991 215 46 3 3 2002
Malene Ostervold(2)(4)..... 1992 224 36 3 3 2000
Walther Herwig(2)(3)(4).... 1997 254 56 5 4 2005
Falcon Explorer(4)......... 1997 266 53 N/A N/A 2002
Kondor Explorer(4)......... 1997 197 43 N/A N/A 2002
OBS/MULTI-COMPONENT
VESSELS(4):
Betty Chouest(2)........... 1995 195 40 N/A N/A 2000
Elda Chouest(2)............ 1992 214 40 N/A N/A 2000
Carlson Tide............... 1995 194 40 N/A N/A 2001
Dickerson Tide............. 1995 194 40 N/A N/A 2001
Beulah Chouest............. 1996 195 40 N/A N/A 2000
Owen Tide II............... 1995 184 38 N/A N/A 2000
Jonathan Chouest........... 1996 180 34 N/A N/A 2000
Bergen Surveyor............ 1997 217 48 N/A N/A 2002
</TABLE>
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(1) We have executed U.K. lease arrangements with respect to each of the Ramform
Valiant, the Ramform Viking, the Ramform Victory and the Ramform Vanguard
under which we have (a) novated the construction contract for each vessel in
favor of a U.K. financial institution, (b) leased each vessel from the
institution under a 25-year charter that gives us the option to purchase
each vessel for a de minimis amount at the end of the charter period, and
(c) used a substantial portion of the proceeds we received in return for the
novation to legally defease the present value of our future charter
obligations.
(2) Idle. Subsequent to year end, the Nordic and Orient re-commenced operations,
and the Malene Ostervold, Betty Chouest and Elda Chouest went off charter.
(3) Chartered from a limited partnership owned 50% by us.
(4) These vessels operate in a multi-vessel configuration of vessels working
together.
Our Ramform Seismic Vessels
As of December 31, 1999, we operated six Ramform design vessels in our
marine seismic data acquisition operations. Each of the Ramform seismic vessels
is a state-of-the-art vessel that is capable of pulling a relatively large
number of streamers and is built according to a design in which we own
proprietary rights. Our four Ramform seismic vessels delivered in 1998 and 1999
are designed to deploy up to 20 streamers.
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We believe that our Ramform design seismic vessels represent the most
advanced seismic vessels currently in operation in the world. Because of their
size and unique design, including their extreme maximum width in relation to
their overall length, Ramform design seismic vessels have increased streamer
towing capacity as compared to conventional seismic vessels. In addition, the
Ramform vessels have increased stability and improved motion characteristics
over conventional seismic vessels. Among other things, these characteristics
allow these vessels to leave seismic equipment deployed during more severe
weather conditions than is possible for conventional seismic vessels. As a
result, these vessels can resume production more quickly once conditions have
stabilized and thereby acquire seismic data for more sustained periods of time.
The size and unique design of the Ramform seismic vessels, together with our
advanced techniques for rapid deployment and retrieval of seismic streamers,
allow us to acquire marine seismic data more efficiently. The Ramform design
seismic vessels are also well-suited for acquiring high-definition surveys,
which require the use of multiple streamer configurations with narrower
distances between streamers in order to generate the necessary volume and
resolution of seismic data.
MARINE SEISMIC DATA ACQUISITION
Contract Operations
Overview. When we acquire marine seismic data on a contract basis, our
customer directs the scope and extent of the survey and retains ownership of the
data obtained. Contracts for marine seismic data acquisition, which are often
awarded on a competitive bid basis, are distance-based contracts. Under this
distance method, our customers pay us based upon the number of seismic lines or
kilometers of seismic data collected and bear most of the risk of business
interruption, except in winter months when we assume greater responsibility for
weather-related interruption. We generally require progress payments unless we
expect to complete the survey in a brief period of time.
Geographic Mix of Operations. We expect in the near term to focus on
contract revenue in the North Sea, offshore Brazil, in the Asia Pacific region
and offshore West Africa. However, we also intend to seek opportunities for
contract revenue in other areas of the world where offshore oil and natural gas
operations exist. During 1999, we performed or secured contract work in the
North Sea, offshore West Africa, India, the Sakhalin area of Russia, Australia,
Mexico, China and in the Middle East. For more information regarding the
geographic mix of our operations, please read note 18 of the notes to our
financial statements.
Multi-Client Operations
Overview. We continue to build and market our marine seismic data library
(including ocean bottom seismic and multi-component seismic data), with a
particular emphasis on the Gulf of Mexico and the North Sea. We expect to
continue this geographic focus in the future, but also intend to acquire multi-
client seismic data in additional geographic areas from time to time, including
offshore China, Australia and other countries in the Asia Pacific region, West
Africa, Brazil and the Middle East. We acquire multi-client seismic data in
areas where oil and gas companies have identified geological features that are
favorable for accumulations of oil and gas.
From the perspective of an oil and gas company, purchasing multi-client
seismic data is less expensive on a per unit basis than contracting to have
seismic data acquired on an exclusive basis. From our perspective, multi-client
seismic data are more cost effective to acquire and may be sold a number of
times to different customers over a period of years. As a result, multi-client
seismic data may be more profitable than contract data, but when we acquire
multi-client seismic data we assume the risk that future sales may not cover the
cost of acquiring and processing such seismic data. We reduce this risk by
obtaining prefunding for a portion of such costs. The level of prefunding
obtained for each multi-client
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seismic survey is determined, in part, by evaluating various factors affecting
the sales potential of each survey. These factors include:
- the existence, quality and age of any seismic data that may already exist
in the area
- the amount of leased acreage in the area
- the existing infrastructure in the region to transport oil and gas to
market
- the historical turnover of the leased acreage
- the level of interest from oil and gas companies in the area
We attempt to protect our multi-client seismic data from misuse by
customers primarily through contractual provisions that permit use of the data
only by that particular customer on a nontransferable basis. Such provisions can
be effective only if we can detect misuse of our data by customers or third
parties and enforce our rights through legal actions.
Geographic Areas Covered by Multi-Client Seismic Data. As of December 31,
1999, approximately 36% of our total multi-client marine seismic library, as
measured by square kilometers, was from the Gulf of Mexico. A substantial
portion of this data was acquired offshore Louisiana and Texas. In recent
periods, we have concentrated our Gulf of Mexico acquisition activities in
deepwater areas. We believe that deepwater areas in the Gulf of Mexico, the
North Sea, Brazil and offshore West Africa will be among the most active
offshore exploration and development areas in the near future. We also believe
that the relatively high cost of locating and producing deepwater oil and gas
reservoirs will contribute to increased demand for high density marine seismic
data and other specialized geophysical services. Our seismic data acquisition
techniques and processing capabilities are well-suited to deepwater areas, and
we intend to concentrate our future acquisition activities in those areas. We
also believe that the desire of oil and gas companies to increase ultimate
recoveries from existing reservoirs in the Gulf Coast area will provide
additional demand for Gulf of Mexico multi-client seismic data. For more
information regarding the geographic mix of our operations, please read note 18
of the notes to our financial statements.
Marketing Arrangements. We market multi-client data through our own
organization and through various arrangements with third parties. Outside of the
Gulf of Mexico, we primarily market our multi-client data ourselves.
Under arrangements relating to our multi-client seismic data in the Gulf of
Mexico, a third-party marketing company generally presents to us seismic survey
projects for our consideration. We acquire and process (or have a designee
process) the data for the surveys that we choose to undertake. We generally
retain ownership of the data acquired, with the marketing company earning a
commission on the data it sells. We may grant an ownership interest in the data
to the marketing company under a risk-sharing arrangement.
Ocean Bottom Seismic/Multi-Component Operations
As of December 31, 1999, we had one ocean bottom seismic crew and one
multi-component crew. In some situations, ocean bottom seismic acquisition
operations perform better than acquisition by conventional streamer towing
operations because:
- the ocean bottom seismic cables can be laid in places where the
conventional streamer vessels cannot operate
- the ocean bottom receiver cables can record higher quality seismic data
because the cables are on the ocean floor
- the ocean bottom receiver cables can record broader bandwidth data with
their dual sensor technology than conventional streamers can record
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In multi-component seismic acquisition operations, both hydrophone and
geophone information are recorded simultaneously for a reservoir, generally
through proprietary ocean bottom dragged array or vertical cable techniques. By
processing this information together, the geophysicist can better describe the
reservoir and, in particular, the oil/gas contact within the reservoir. We
provide multi-component acquisition services as well as multi-component
interpretation services.
SEISMIC DATA PROCESSING OPERATIONS
We generally compete for data processing contracts on a bid basis. These
contracts generally provide for the customer to pay a flat fee per mile or
kilometer processed for a prescribed set of processing procedures. Additional
procedures may be quoted separately.
We provide seismic data processing services for our own seismic data
acquisition operations and, to a lesser extent, for third parties. We operate
four land-based seismic data processing centers, located in Houston, Texas,
U.S.A.; Cairo, Egypt; London, England; and Perth, Australia. Each of these
centers is equipped with supercomputers for data processing. We also have a
processing center in Oslo, Norway that is linked to our other centers'
supercomputers. We use a proprietary operating system for our supercomputers,
which is designed to take advantage of supercomputer architecture and can be
converted to operate on a variety of supercomputers. These supercomputers offer
processing capacities for the large data volumes and computer-intensive
algorithms requiring numerous simultaneous calculations that are inherent in
seismic data processing. Through our seismic data processing operations we
provide:
- 3D data processing of land and marine seismic surveys
- onboard (vessel) seismic data processing for reduced delivery times and
enhanced real-time quality control for data
- multi-component and 4D seismic data processing for reservoir
characterization and monitoring
- imaging of subsurface structures in deepwater and in the vicinity of salt
formations
We have deployed the onboard supercomputer processing systems for all of
our marine seismic data acquisition crews and have stationed processing
personnel onboard the vessels to process and provide quality control of the
seismic data as they are acquired. We believe that onboard processing and
quality control provide a competitive advantage because we can process the large
volume of data associated with seismic surveys concurrently with data
acquisition. This concurrent process allows us to shorten the period of time
required to deliver high-quality finished data to the customer. In addition,
onboard processing and quality control allow us to decide whether we should
resurvey particular areas to fill gaps in the original data while the vessel and
crew are on the prospect areas. As a result, we can resurvey more quickly and
less expensively.
FPSO OPERATIONS
We currently own and operate four FPSO systems and operate seven additional
offshore production facilities for oil and gas companies. We believe that our
advanced geophysical technologies and reservoir expertise allow our FPSO
customers to increase the amounts of oil and gas produced from the reservoirs
served by our FPSO systems and assist in the identification of satellite fields
that can be economically produced or "tied back" through the same systems. We
believe that we can increase our revenue and operating profit from any
incremental production through our FPSO systems through the use of contracts
with a variable compensation component based on the amount of oil produced. As a
result of these factors, we believe that we have a competitive advantage over
other FPSO operators.
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FPSO Vessels
We provide in the following table information as of December 31, 1999 about
our FPSO vessels.
<TABLE>
<CAPTION>
APPROXIMATE APPROXIMATE PRODUCTION
TOTAL TOTAL CAPACITY DISPLACEMENT STORAGE
YEAR LENGTH WIDTH (BARRELS (METRIC CAPACITY
FPSO VESSEL NAME DELIVERED (FEET) (FEET) PER DAY) TONS) (BARRELS)
---------------- --------- ----------- ----------- ---------- ------------ ---------
<S> <C> <C> <C> <C> <C> <C>
Ramform Banff(1)................. 1998 395 175 95,000 32,100 120,000
Petrojarl I...................... 1986 686 105 40,000 51,000 190,000
Petrojarl Foinaven............... 1996 820 112 140,000 72,000 280,000
Petrojarl Varg................... 1999 702 125 56,000 100,000 470,000
</TABLE>
---------------
(1) We have executed a U.K. lease arrangement with respect to the vessel's
topside production equipment under which we have (a) novated the
construction contract for the equipment in favor of a U.K. financial
institution, (b) leased the equipment from the institution under a long-term
charter that gives us the option to purchase the equipment for a de minimis
amount at the end of the charter period, and (c) used a substantial portion
of the proceeds we received in return for the novation to legally defease
the present value of our future charter obligations.
Banff and Kyle Field Contracts
In February 1997, Conoco awarded us a long-term contract to provide an FPSO
system to produce the hydrocarbon reserves of the Banff field in the U.K. sector
of the North Sea. Oil production from the field commenced in late January 1999.
At that time, we began receiving a fixed day rate designed to cover operating
expenses and a fixed tariff per barrel of stabilized crude oil produced. Under
the Banff contract, 75% of production amounts called for by a predetermined
production schedule will be guaranteed by Conoco. The contract, as amended,
provides that Conoco will recover from us a fixed amount per day for each day
that actual production under the Banff FPSO system is delayed (beyond July 19,
1998) for reasons other than force majeure, which includes weather-related
delays, or a failure by Conoco to fulfill its contractual obligations. We have
had discussions with Conoco with a view towards resolving issues that have
arisen under the contract relating to periods when production from the Banff
FPSO system has been negatively affected. These discussions could result in
further amendments to the Conoco contract. We do not expect any such amendments
to have a material effect on our financial position or results of operations.
Conoco will have the right to terminate the contract in late January 2002.
In the event of a breach by us of our obligations, bankruptcy or a force majeure
event lasting six months or more, Conoco may terminate the contract prior to
January 2002. In addition, if actual production averages less than a
predetermined production volume for a period of 90 days, and continues to
average less than that volume for two years thereafter, Conoco has the right to
terminate the contract two years after the end of the initial 90-day period. We
cannot assure you that actual production will equal the guaranteed level or the
amounts contemplated by the predetermined production schedule in the aggregate
or in any particular period. If the cumulative oil production during the initial
three-year production period exceeds a predetermined amount, we will receive a
lower tariff per barrel for all production in excess of such predetermined
amount. The initial production profile provided by Conoco covers a period of
seven years.
The Conoco contract also applies to any third-party production while the
Banff FPSO system is producing the Banff field reserves, and provides for the
incremental revenue above costs derived from such additional production volumes
to be shared 66 2/3% to us and 33 1/3% to Conoco.
If Conoco terminates this contract after the initial three-year period,
based on its assessment of market conditions, we believe, but cannot assure you,
that we will be able to deploy the Ramform Banff on other projects.
We also have entered into an agreement with Ranger Oil (U.K.) Ltd., on
behalf of a production consortium, to produce through the Banff FPSO system the
reserves of the Kyle field, which is located
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<PAGE> 14
approximately seven miles from the Banff field. We expect commencement of
production of the Kyle field through the Banff FPSO system during the second
half of 2000.
In January 2000, we entered into an agreement with Ranger to perform an
extended well test for the continuing appraisal of the Kyle field. The agreement
has a minimum term of 130 days with no guaranteed minimum production volume.
Under the agreement, we receive a base tariff per barrel of oil produced. We
also will receive an additional tariff per barrel depending on the ultimate per
barrel sales price that Ranger achieves for oil produced from the Kyle field.
The per barrel tariff is all-inclusive and includes the cost of subsea
installation, riser and umbilical connection, shuttle tanker fees, port charges
and fuel.
This extended well test, which commenced in the second quarter of 2000, is
being performed by the Petrojarl I. The Petrojarl I achieved first oil on the
Kyle field in May 2000. Upon completion of the test, the Petrojarl I is
scheduled to undergo a standard regulatory inspection and an upgrade. We intend
to secure a new contract for the vessel that will commence after the inspection
and upgrade.
Blenheim Contract
During the second quarter of 2000, the Petrojarl I completed its contract
for production and offloading of oil from the Blenheim and Bladon fields located
in the U.K. sector of the North Sea. Please read "-- Banff and Kyle Field
Contracts" above.
Foinaven Contract
The Petrojarl Foinaven is under contract with Britoil PLC, a subsidiary of
BP Amoco p.l.c., for production of the Foinaven field to the west of the
Shetlands. Commercial production on the field commenced in November 1997. The
Foinaven contract is not limited as to time. Britoil may terminate the contract
on the fifth anniversary of commencement of commercial production or later, with
a minimum of two years' notice. In the event of cancellation at the end of the
fifth anniversary, the contract provides that Britoil must pay a cancellation
fee of $60 million, which fee reduces by $12 million per year after the fifth
anniversary so that no cancellation fee is payable at the end of the tenth
anniversary or thereafter. Britoil may also terminate the contract without
paying a cancellation fee if, among other things:
- the Petrojarl Foinaven becomes a total loss
- there is a breach of the FPSO contracts by the FPSO contractor that is
not remedied within agreed deadlines
- the FPSO contractor or its guarantors enter into debt negotiations with
creditors or go into liquidation, are placed under administration or
change ownership to the detriment of Britoil
- force majeure events occur that are expected to continue for more than
365 days
In addition, the contract may be terminated:
- by us on or after November 26, 2003, with a minimum of two years' notice,
if the production-dependent tariff falls to less than the equivalent of
$102,250 per day
- from the same date with one year's notice if the production-dependent
tariff falls below $35,000 per day
- under additional circumstances, including war
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<PAGE> 15
The contract provides for compensation consisting of a fixed day rate and a
production-dependent tariff. The current day rate (as of June 2000) is
approximately $66,000 per day and is subject to adjustment according to agreed
indices. The production-dependent tariff:
- is not subject to adjustment based on any index
- is equal to $3.50 per barrel for the first 25,000 barrels of production
per day and $2.95 per barrel for production in excess of 25,000 barrels
per day
- may depend upon a guaranteed minimum production volume equal to 95% of
the predetermined production profile during the first five years of the
contract
As long as the Petrojarl Foinaven is fully operational, Britoil will be
required, in periods during the first five-year period where the actual
production falls below the guaranteed minimum production, to make payments based
on the guaranteed minimum production less credits for rate payments already made
for volumes in excess of the guaranteed minimum production. If actual production
is greater than the guaranteed minimum production in periods during the first
five-year period, Britoil will make payments based on actual production less
credits for rate payments already made for volumes below the guaranteed minimum
production. During periods after the first five-year period in which the
Petrojarl Foinaven is fully operational, the day rate will be equal to the
greatest of:
- actual production
- 90% of the highest of two expected annual oil production rates reported
by Britoil and the planned production profile for the year in question or
- 10,000 barrels per day
The guaranteed minimum production amounts under the contract are 80,750
barrels per day in each of years 2 through 4 and 70,775 barrels per day in year
5. In periods when the Petrojarl Foinaven is not fully operational, the day rate
payable is to be based on actual production. A reduction in production volume
during the first five years that is due to matters for which we are responsible
triggers a day rate equal to $60,000, as adjusted to reflect indexation, plus an
additional $52,500 until production is resumed. After five years, the day rate
under such circumstances will be $60,000, as adjusted to reflect indexation.
In periods of production stoppage covered by the contract's repair and
start-up quota, we will be entitled to receive the full production rate. We can
accumulate credits under the quota at a rate of 24 hours per month, up to an
annual maximum of 14 days, to be offset by any downtime taken. In periods when
production is prevented or reduced due to force majeure, we will receive reduced
income for 60 days, and the full production rate thereafter.
Britoil has the right to add production from a satellite field, the
Foinaven East field, to the contract. To the extent that production from the
Foinaven East field, when aggregated with Foinaven field production, is within
the guaranteed minimum production level, the normal rate structure under the
contract will apply. Foinaven East production in excess of the guaranteed
minimum production amount will be paid at an incremental rate of at least $0.75
per barrel.
We have additional obligations that may arise under the contract relating
to the Foinaven project, including obligations to:
- compensate Britoil up to a maximum of $10 million for breaches of
contract due to deficiencies that provide Britoil a right to terminate
the production contract
- contribute up to 80% of the payments expected to be made by Britoil under
the contract for the year following the discovery of hidden defects
toward the correction of those defects, where such correction involves
extraordinary expense
- pay for pollution damage caused by diesel or lubricants used on the
Petrojarl Foinaven during production
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Varg Contract
In July 1999, we:
- purchased the newly constructed FPSO vessel Petrojarl Varg from Saga
Petroleum ASA, with Saga acting on behalf of the owners of the production
license relating to the Varg field offshore Norway, for $350 million in
cash
- chartered the vessel back to the license owners and
- agreed to operate the vessel on behalf of the license owners and to
provide various other operational services relating to the vessel
The charter agreement provides for:
- a lease term for at least the full productive life of the Varg field,
with a minimum term of three years, subject to termination by the license
owners either with or without cause, with a minimum advance notice of
nine months. If termination is without cause, we are entitled to receive
the applicable charter hire rate indicated below for the minimum term.
- an option in favor of the license owners, exercisable within one year
after the commencement of the charter, to extend the minimum term to ten
years
- after the minimum term, continuation of the charter until termination by
the license owners with a minimum advance notice of nine months
- a day rate of:
- $177,000 for the minimum three-year term
- $162,000 after the initial three-year term
- $157,500 if the license owners exercise their option to extend the
minimum term to ten years, which amount will apply during the ten-year
term retroactively to the date we began to operate the vessel
The operating agreement provides:
- that we will provide various operating services for the license owners
relating to the Petrojarl Varg and be compensated for those services in
NOK at a day rate of approximately NOK 450,000, subject to escalation
based on various price indices
- for a minimum three-year term, subject to termination by the license
owners either for breaches by us or without cause. If termination is
without cause, we are entitled to receive the applicable contractual
compensation, less savings we realize from not being obligated to perform
the agreement
The Petrojarl Varg currently operates in the Varg field, where production
began in December 1998. The Varg license is owned 35% by Saga Petroleum and 65%
by Statoil, including 30% owned by the Norwegian government.
RESERVOIR MONITORING
We believe that the high-resolution 4D seismic data used in connection with
reservoir monitoring will help oil and gas companies maximize production and
increase the ultimate recoveries from producing hydrocarbon reservoirs,
particularly as the level of production from such reservoirs begins to decline.
In
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addition to the equipment and technology required for a 3D seismic survey, a 4D
seismic survey may require or use:
- time-lapse streamer technology
- vertical cable technology
- retrievable ocean bottom recording cables and retrievable multi-component
acquisition systems
- an ocean bottom dragged array of seismic receivers
- permanent seabed installations of seismic receivers
4D seismic information requires a higher density of 3D data and increased
computing capacity to reflect the subtle changes in geophysical conditions that
occur over time. With our advanced vessel fleet, the large streamer capacity of
our Ramform design seismic vessels, our expertise in acquiring, processing and
interpreting 4D seismic data and our processing capacity, we believe that we are
well positioned to meet future demand for 4D seismic surveys.
LAND SEISMIC DATA ACQUISITION
We have established a group to develop and enhance products related to
seismic data acquisition and reservoir monitoring on land. We believe that the
cost of developing these products on land will be less than developing them
offshore. Our land crews work in the United States, the Middle East and the
Caspian Sea area, and work on a mixture of traditional 3D contract and
multi-client seismic data acquisition projects and specialized research and
development projects.
In January 2000, we entered into a contract with Saudi Arabian Oil Company
(Saudi Aramco), the national oil company of Saudi Arabia, to acquire onshore 3D
seismic data in that country. The project is expected to commence in the late
second or early third quarter of 2000. The contract has an initial term of three
years, with an option for Saudi Aramco to extend the contract for an additional
two years. Our compensation under the contract is composed of fees for each
point of seismic information acquired. The fees vary depending on the type of
terrain involved. If we fail to meet the minimum monthly production of data
specified in the contract, the fees will be discounted. The contract allows
Saudi Aramco to terminate it at any time. We may terminate the contract only if
Saudi Aramco commits a substantial breach and fails to remedy the breach for
thirty days.
DATA MANAGEMENT
We provide seismic data storage, retrieval and management services on a
contract basis to customers worldwide and in connection with the marketing of
our multi-client library. Through our data management operations, we also:
- maintain a current database of various offshore information, including
production facilities and ocean floor geography
- produce customized maps and other information based on such data
We believe that most major oil and gas companies spend a significant amount
of time and effort to locate, copy or otherwise format seismic data. Our data
management system allows an oil and gas company to store its seismic data in a
fully automated data management and retrieval system that functions much like an
electronic jukebox. An oil and gas company can use this system to download
electronically its seismic data, or our data, use the information for
interpretation purposes and return the data to the data management system after
the information has been evaluated. We expect to benefit by selling these data
management services, by licensing our data management and interpretation
application software and by providing a new market outlet for the sale of our
multi-client library.
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OTHER BUSINESS OPPORTUNITIES
We pursue various oil and gas business opportunities, typically in
conjunction with utilization of our geophysical expertise. We intend to continue
to pursue such opportunities and, in connection therewith, to provide technical
consulting services, reservoir studies, enhanced recovery services, prospect
identification, seismic data interpretation, seismic data reprocessing services
or other geophysical services in exchange for cash or other forms of
compensation. In this manner, we have acquired and may continue to acquire
various interests in exploration and production companies and in oil and gas
properties or concessions. The revenue from and value of these interests depend
upon the operations of the entities or properties acquired.
We consider from time to time acquisitions in areas that complement our
existing portfolio of services to the oil and gas industry.
RESEARCH AND PRODUCT DEVELOPMENT
We desire to be an industry leader in those oilfield service markets in
which our advanced technologies and services may be used by customers to
discover and produce oil and gas in demanding environments. We are committed to
providing our customers with innovative services that help to lower the costs of
finding and producing oil and gas. As a result, we incur research and
development costs in an attempt to keep our key assets and services at the
forefront of engineering and technical advances. For information regarding our
research and development expenditures, please see our financial statements.
COMPETITION
The seismic data acquisition and processing businesses are very competitive
worldwide. Many oil and gas companies acquire seismic data primarily for their
own use, while other companies develop and maintain their own seismic data
libraries for sale to third parties. We compete for available seismic surveys
based on a number of factors, including technology, price, performance,
dependability and crew availability. In addition, the first company to acquire
multi-client seismic data in an area generally has a competitive advantage in
that area. Our largest competitors on a global basis are Geco-Prakla, a
subsidiary of Schlumberger Limited, and Baker Atlas, a division of Baker Hughes
Incorporated.
All of our major competitors in seismic data acquisition both acquire and
process 3D seismic data. Our processing operations compete primarily with Baker
Atlas, Compagnie Generale de Geophysique, S.A., Geco Geophysical Co., Inc.,
which is a subsidiary of Schlumberger Limited, and Veritas DGC Inc. for time
processing contracts. We compete for time processing contracts based primarily
on price, but processing capacity and turnaround time, technology and processing
center location are also important factors.
Our FPSO operations will generally compete from time to time with other
FPSO operators, with fixed installations and tension leg platforms, with subsea
production installations and with semi-submersible and jack-up platforms.
Competition between FPSO systems and other offshore production systems is based
on a number of factors including water depth, the availability or proximity of
transportation infrastructure, the size of the producing field and time
considerations. In addition to the FPSO operations and other offshore production
systems of the major oil and gas companies, our FPSO competitors include
numerous companies that own a small number of FPSO vessels.
CUSTOMERS
Our major customers include multi-national oil and gas companies, foreign
national oil and gas companies, major independent oil and gas companies and
seismic marketing companies. For the year ended December 31, 1999, one customer
accounted for approximately 16% of our revenue, all of which was production
services revenue. For the years ended December 31, 1998 and 1997, no single
customer accounted for more than 10% of our consolidated revenue. Due to the
nature of our operations, significant portions of future consolidated revenue
may, from time to time, be attributable to a few customers.
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SEASONALITY
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Overview -- Seasonality" in Item 9 of this annual
report for a description of how seasonality and weather affect our business.
EMPLOYEES
At December 31, 1999, we employed approximately 3,800 full-time personnel.
We have not experienced any material work stoppages related to union activities
and consider our relations with our employees to be good.
OPERATING CONDITIONS AND INSURANCE
Our operations often are conducted under extreme weather and other
hazardous conditions. These operations are subject to risks of injury to
personnel and loss of equipment. We have safety compliance programs staffed by
full-time professional employees. We also carry insurance against the
destruction of or damage to our vessels and equipment in amounts, generally
equal to replacement value, that we consider adequate. From time to time,
however, we may not be able to obtain insurance against all risks or for
equipment located in all geographic areas. Under the terms of our vessel
charters, we are not generally responsible for damage to chartered vessels.
We have established our own captive insurance company to provide insurance
for our seismic equipment and limited business interruption. This insurance is
subject to deductibles and limits on coverage and is supplemented by commercial
reinsurance arrangements.
INTERNATIONAL OPERATIONS
We conduct the majority of our operations in the North Sea and offshore
South America and West Africa. We also conduct significant business operations
in other areas of the world from time to time, including:
- the Gulf of Mexico
- offshore China
- offshore India
- the Sakhalin area of Russia
- offshore Australia, Indonesia and other countries in the Asia Pacific
region
- offshore Canada
- the Middle East
- the Caspian Sea area
Please read "-- Marine Seismic Background," "-- Marine Seismic Data
Acquisition," "-- Seismic Data Processing Operations" and "-- Risk Factors
Relating to Our Business -- As we expand our international operations, we
increase our exposure to risks inherent in doing business abroad." Please read
note 18 of the notes to our financial statements for information regarding the
geographic mix of our operations.
GOVERNMENTAL REGULATION
In the North Sea, we are required to obtain licenses to acquire
multi-client seismic data. We currently have licenses to conduct such activities
in portions of the Norwegian, U.K. and Irish territorial waters. In other areas
of the world, licensing requirements vary widely. There are no such licensing
requirements in the Gulf of Mexico, offshore Brazil or in the onshore areas
where we operate, although we
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are required to obtain permits for our operations. We believe that our relations
with the licensing and permitting authorities are good.
In addition, our operations are affected by the licensing activities of
various governmental authorities. The timing and extent of licensing of areas
for exploration and production activities influence the level of seismic
activity within a particular country. Prospective licensees often purchase
multi-client seismic data prior to the award of licenses. Following a license
award, license holders will generally acquire seismic data from the newly
licensed areas. In the North Sea, the governments of Norway and the United
Kingdom generally hold licensing rounds for exploration and production every two
years. In the Gulf of Mexico, licensing of blocks for exploration and production
are held twice each year, once offshore Texas and once offshore Louisiana. In
other areas, the timing and extent of these licensing rounds tend to be
irregular. The length of the actual license to explore for oil and gas varies
from region to region and is subject to governmental regulation.
Our operations are affected by a variety of other laws and regulations,
including laws and regulations relating to:
- the protection of the environment
- exports and imports
- occupational health and safety
- permitting or licensing agreements for oil and gas exploration,
development and production activities
We believe that we are currently in compliance in all material respects
with the requirements of environmental, export/import and occupational health
and safety laws and regulations. Please read "-- Risk Factors Relating to our
Business -- Unpredictable changes in governmental regulations could increase our
operating costs and reduce demand for our services."
RISK FACTORS RELATING TO OUR BUSINESS
You should carefully consider the risks described below. The risks and
uncertainties described below are not the only ones facing our company.
Additional risks and uncertainties not presently known to us or that we
currently do not believe are material may also impair our business operations.
If any of the following risks actually occur, our business, financial condition
or results of operations could be materially adversely affected.
OUR BUSINESS COULD BE ADVERSELY AFFECTED IF LOW OIL AND GAS PRICES DECREASE
DEMAND FOR OUR SERVICES.
Our business and operations depend upon exploration, development and
production spending by oil and gas companies. Low oil and gas prices, and
concerns about possible low oil and gas prices in the future, may reduce the
level of that spending. As overall conditions in the oil and gas industry
deteriorate, demand for our services and products may decrease and our business
may be adversely affected. Furthermore, recoveries in oil and gas prices do not
immediately increase exploration, development and production spending, so
improved demand for our services and products will generally lag oil and gas
price increases.
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WE INVEST SIGNIFICANT AMOUNTS OF MONEY IN ACQUIRING AND PROCESSING SEISMIC DATA
FOR OUR DATA LIBRARY WITHOUT KNOWING HOW MUCH OF THE DATA WE WILL BE ABLE TO
SELL OR AT WHAT PRICE WE WILL BE ABLE TO SELL THE DATA.
We invest significant amounts in acquiring and processing seismic data that
we own, which we call multi-client data. By making such investments, we assume
the risk that:
- we may not fully recover the costs of the data through future sales
- the value of our investment in multi-client data could be significantly
adversely affected if any material adverse change occurred in the general
prospects for oil and gas exploration, development and production
activities in the areas where we acquire multi-client data
THE AMOUNTS WE AMORTIZE FROM OUR DATA LIBRARY EACH PERIOD MAY FLUCTUATE
SIGNIFICANTLY, AND THESE FLUCTUATIONS CAN HAVE A SIGNIFICANT EFFECT ON OUR
REPORTED RESULTS OF OPERATIONS.
How we account for our data library could have a significant effect on our
reported results of operations. We amortize the cost of our multi-client data
library based in part on our estimates of future sales of data. These estimates
are inherently imprecise and may vary from period to period depending upon
market developments and our expectations. Substantial changes in amortization
rates can have a significant effect on our reported results of operations.
UNPREDICTABLE CHANGES IN GOVERNMENTAL REGULATIONS COULD INCREASE OUR OPERATING
COSTS AND REDUCE DEMAND FOR OUR SERVICES.
Our operations are affected by a variety of laws and regulations, including
laws and regulations relating to:
- the protection of the environment
- exports and imports
- occupational health and safety
- permitting or licensing requirements for seismic activities and for oil
and gas exploration, development and production activities
We and our customers are required to invest financial and managerial
resources to comply with these laws and regulations. These expenditures
historically have not been material to us. Because these laws and our business
change from time to time, we cannot predict the future costs of complying with
these laws, and our expenditures could be material in the future. Modification
of existing laws or regulations or adoption of new laws or regulations limiting
exploration or production activities by oil and gas companies or imposing more
stringent restrictions on seismic or hydrocarbon production-related operations
could adversely affect us by increasing our operating costs and/or reducing the
demand for our services.
OUR RESULTS OF OPERATIONS COULD SUFFER AS A RESULT OF RISKS ARISING FROM OUR
FLOATING PRODUCTION, STORAGE AND OFFLOADING CONTRACTS.
Our floating production, storage and offloading contracts involve various
risks, including risks of:
- failure to timely commence production from floating production, storage
and offloading vessels
- termination
- redeployment of vessels following expiration of long-term contracts
- not producing expected amounts of oil and gas under contracts where the
amount that we are paid depends on the amount of oil and gas produced,
since actual production will likely vary from estimates, and the
variances may be material
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AS WE EXPAND OUR INTERNATIONAL OPERATIONS, WE INCREASE OUR EXPOSURE TO RISKS
INHERENT IN DOING BUSINESS ABROAD.
A significant portion of our revenue is derived from operations outside the
United States and Norway and is subject in varying degrees to risks inherent in
doing business abroad. As we expand the scope and extent of our operations
outside of the Gulf of Mexico and the North Sea, where our past operations were
primarily centered, these risks may become more prevalent. These risks include:
- the possibility of unfavorable changes in tax or other laws
- partial or total expropriation
- restrictions on currency repatriation
- the disruption of operations from labor and political disturbances
- insurrection or war
- the disruption or delay of licensing or leasing activities
- the requirements of partial local ownership of operations
WE ARE SUBJECT BOTH TO HAZARDS CUSTOMARY FOR MARINE OPERATIONS AND TO THOSE MORE
SPECIFIC TO OUR SEISMIC AND FLOATING PRODUCTION, STORAGE AND OFFLOADING
OPERATIONS.
Substantially all of our operations are subject to perils that are
customary for marine operations, including capsizing, grounding, collision and
damage from severe weather conditions. Our floating production, storage and
offloading operations are subject to additional hazards, such as fire,
explosions and environmental contamination from spillage. Any of these risks
could result in damage to or destruction of vessels or equipment, personal
injury and property damage, suspension of operations or environmental damage. In
addition, our operations involve risks of a technical and operational nature.
BECAUSE WE DO NOT HAVE INSURANCE TO COVER SOME OPERATING RISKS, OUR RESULTS OF
OPERATIONS COULD BE ADVERSELY AFFECTED IF ONE OR MORE OF THOSE RISKS OCCURRED.
We cannot always obtain insurance for our operating risks. Although we
carry insurance against the destruction of or damage to our seismic and floating
production, storage and offloading vessels and equipment in amounts that we
consider adequate, such insurance may not always be available at acceptable
rates in the future for all risks and all geographic areas.
IF WE CANNOT KEEP OUR VESSELS AND OTHER EQUIPMENT UTILIZED, OUR OPERATING
RESULTS WILL BE ADVERSELY IMPACTED.
Our businesses are capital intensive and generally require significant
investments in vessels and processing, seismic and other equipment. As a result,
we incur relatively high fixed costs in our operations. If we cannot keep our
vessels and other equipment utilized, our operating results will be adversely
affected.
BECAUSE WE GENERATE REVENUE AND INCUR EXPENSES IN VARIOUS CURRENCIES, EXCHANGE
RATE FLUCTUATIONS AND DEVALUATIONS COULD HAVE A MATERIAL IMPACT ON OUR RESULTS
OF OPERATIONS.
Currency exchange rate fluctuations and currency devaluations could have a
material impact on our results of operations from time to time. Although we
periodically undertake hedging activities in an attempt to reduce certain
currency fluctuation risks, these activities do not provide complete protection
from currency-related losses.
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OUR DEBT AGREEMENTS MAY LIMIT OUR FLEXIBILITY IN RESPONDING TO CHANGING MARKET
CONDITIONS OR IN PURSUING BUSINESS OPPORTUNITIES.
Our debt agreements contain restrictions and requirements relating to,
among other things:
- the issuance of additional indebtedness
- the maintenance of financial ratios
- the encumbrance or sale of assets
- the payment of dividends
- mergers
- sale/leaseback transactions
These restrictions and requirements may limit our flexibility in responding
to changing market conditions or in pursuing business opportunities that we
believe would have a positive effect on our business.
BECAUSE WE ARE A FOREIGN COMPANY AND MANY OF OUR DIRECTORS AND EXECUTIVE
OFFICERS ARE NOT RESIDENTS OF THE UNITED STATES, YOU MAY HAVE DIFFICULTY SUING
US AND OBTAINING OR ENFORCING JUDGMENTS AGAINST US.
We are incorporated in the Kingdom of Norway, and many of our current
directors and executive officers do not reside in the United States. All or a
substantial portion of the assets of these persons and of PGS is located outside
the United States. As a result, you may have difficulty:
- suing us or our directors and executive officers in the United States
- obtaining a judgment in Norway in an original action based solely on
United States federal securities laws
- enforcing in Norway judgments obtained in the United States courts that
are based upon the civil liability provisions of the United States
federal securities laws
ITEM 2. DESCRIPTION OF PROPERTY
Our principal offices are in Lysaker, Norway and in Houston, Texas, in
leased premises. We also maintain leased premises in Oslo and other cities in
Norway and the United States, the United Kingdom, Egypt, Venezuela, Singapore,
Australia, Brazil, the United Arab Emirates, Russia and China. We believe that
all leased properties are well maintained and are suitable and adequate for our
present activities.
We incorporate by reference in response to this item the information under
"Description of Business" in Item 1 of this annual report relating to our
vessels and other operational equipment and in note 18 of the notes to our
financial statements in Item 18 of this annual report.
ITEM 3. LEGAL PROCEEDINGS
We are involved in or threatened with various legal proceedings from time
to time arising in the ordinary course of business. Our management does not
believe that any liabilities resulting from such proceedings will have a
material adverse effect on our consolidated results of operations, cash flows or
financial position.
ITEM 4. CONTROL OF REGISTRANT
As of December 31, 1999, to our knowledge, no person beneficially owned
more than 10% of our outstanding shares or the outstanding American Depositary
Shares representing our shares. In addition, there were no arrangements at
December 31, 1999 which would cause a change in control of us.
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<PAGE> 24
As of December 31, 1999, the total number of our shares and American
Depositary Shares ("ADSs") beneficially held by our directors and executive
officers as a group (23 persons) was 535,471, representing approximately 0.5% of
the outstanding shares. This amount excludes 3,784,800 shares that could be
acquired upon the exercise of options, including options that were not yet
vested as of December 31, 1999. See "Options to Purchase Securities from
Registrant or Subsidiaries" in Item 12 of this annual report.
ITEM 5. NATURE OF TRADING MARKET
Our shares are listed on the Oslo Stock Exchange and trade on that exchange
under the symbol "PGS." These shares are not listed on any other stock exchange
and have not been publicly traded outside Norway. Each ADS represents one share.
Citibank, N.A. serves as the depositary for the ADSs. Our ADSs are listed on the
New York Stock Exchange and trade on that exchange under the symbol "PGO."
AMERICAN DEPOSITARY SHARES
We have presented in the table below, for the periods indicated, the
reported high and low closing prices for our ADSs on the New York Stock
Exchange, as adjusted to reflect the two-for-one stock split effected in June
1998.
<TABLE>
<CAPTION>
PRICE PER ADS
---------------
CALENDAR PERIOD HIGH LOW
--------------- ------ ------
<S> <C> <C>
1999
First Quarter............................................. $17.00 $11.19
Second Quarter............................................ 18.13 13.25
Third Quarter............................................. 24.19 14.94
Fourth Quarter............................................ 18.56 12.81
1998
First Quarter............................................. $31.75 $25.25
Second Quarter............................................ 37.38 28.25
Third Quarter............................................. 31.56 11.81
Fourth Quarter............................................ 22.88 12.00
</TABLE>
As of December 31, 1999, there were 187 record holders of ADSs, all of
which had registered addresses in the United States except for one record holder
in Canada and 17 record holders in the United Kingdom. These 187 record holders
held ADSs representing 33,667,145 shares, which represented approximately 33% of
the total number of our shares outstanding as of that date.
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<PAGE> 25
SHARES
We have presented in the table below, for the periods indicated, the
reported high and low closing prices for our shares on the Oslo Stock Exchange,
as adjusted to reflect the two-for-one stock split effected in June 1998. Please
read "Selected Financial Data -- Exchange Rates" in Item 8 of this annual report
for information about exchange rates applicable to the periods presented below.
<TABLE>
<CAPTION>
PRICE PER SHARE
-------------------
CALENDAR PERIOD HIGH LOW
--------------- -------- --------
<S> <C> <C>
1999
First Quarter............................................. NOK125.0 NOK84.0
Second Quarter............................................ 140.5 96.0
Third Quarter............................................. 185.5 117.0
Fourth Quarter............................................ 143.5 106.0
1998
First Quarter............................................. NOK242.5 NOK195.0
Second Quarter............................................ 282.0 215.5
Third Quarter............................................. 242.0 101.0
Fourth Quarter............................................ 164.0 91.5
</TABLE>
Based upon information available from Verdipapirsentralen, the Norwegian
centralized registry of securities, as of December 31, 1999, there were
101,609,587 shares outstanding held by 6,949 record holders of shares, of which
105 had registered addresses in the United States. These United States holdings
represented 43,066,427 shares, or approximately 42% of the total number of our
shares outstanding as of that date. For this purpose, Citibank, in its capacity
as the depositary, represents one record holder of shares. The above numbers may
not be representative of the actual number of United States beneficial holders
or of shares beneficially held by United States persons.
ITEM 6. EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS
Under Norwegian foreign currency exchange controls currently in effect,
transfers of capital to and from Norway are not subject to prior governmental
approval except for the physical transfer of payments in currency, which is
restricted to licensed banks. As a result, a non-Norwegian resident may receive
dividend, principal and interest payments on our securities without a Norwegian
exchange control consent, but the payments must be made through a licensed bank.
There are no limitations imposed by Norwegian law or our articles of
association on the right to hold or vote shares that apply differently to
non-Norwegian owners than to Norwegian owners.
ITEM 7. TAXATION
GENERAL
The following discussion generally summarizes the principal Norwegian and
United States federal income tax consequences of the ownership and disposition
of our American Depositary Receipts ("ADRs"), which evidence our ADSs, and our
shares to holders of ADRs and shares who are residents of the United States or
otherwise subject to United States federal income taxation on a net income basis
for ADRs and shares and who are not residents of Norway ("U.S. Holders"). The
summary applies only to holders who will hold ADRs or shares as capital assets
and does not address certain classes of holders, such as holders who own,
directly or indirectly, at least 10% of our outstanding shares, that may be
subject to special rules. Because it is a general summary, prospective
purchasers of ADRs or shares who would be U.S. Holders are advised to consult
their own tax advisors about the United States federal, state and local tax
consequences and the Norwegian tax consequences of the ownership and disposition
of ADRs and shares that are applicable in their particular tax situations,
including the effects of recent and possible future changes in the applicable
tax laws.
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<PAGE> 26
The summaries of United States and Norwegian tax laws provided below are
based on the tax laws of the United States and Norway, the income tax convention
between the United States and Norway (the "Convention") and interpretations by
the relevant tax authorities that are in effect as of the date of this annual
report and are subject to any changes that may occur after that date (possibly
with retroactive effect).
For United States and Norwegian tax purposes, U.S. Holders of ADRs will be
treated as the owners of the shares represented by the ADRs. Unless we have
otherwise stated below, the Norwegian tax consequences and the United States
federal income tax consequences discussed below apply equally to U.S. Holders of
ADRs and U.S. Holders of shares.
TAXATION OF DIVIDENDS
Under Norwegian tax law, dividends paid to foreign shareholders of
Norwegian corporations are, unless otherwise provided for in an applicable tax
treaty, subject to a withholding tax in Norway of 25%. Under the Convention, the
maximum rate of withholding tax on dividends paid by a Norwegian corporation to
a "resident of the United States," as defined in the Convention, is 15%. The 15%
withholding rate will apply to any dividends paid on our shares held directly by
U.S. Holders who properly demonstrate to us and to the Norwegian tax authorities
that they are entitled to the benefits of the Convention. Dividends paid to
Citibank, as depositary, will be subject to withholding at the 25% rate. U.S.
Holders of ADRs who believe they are entitled to the benefits of the Convention
may apply to the Norwegian tax authorities for a refund of amounts withheld in
excess of 15%. The application is to be filed with the Norwegian Tax
Directorate. There is some uncertainty, however, as to whether and when such a
refund may be obtained.
We intend to file any reports with the Norwegian authorities or agencies
necessary to obtain the benefits of the Convention for those entitled to them.
We will exercise our right under the deposit agreement to reasonably request
from Citibank such information from its records that will enable us to file the
reports.
If, however, the recipient of a dividend is determined to be engaged in a
business activity taxable in Norway and our shares or ADSs with respect to which
the dividend is paid are effectively connected with that activity, then the
amount distributed to the U.S. Holder will be treated as taxable domestic
dividend income in Norway, subject to the provisions of the Convention, where
applicable.
To the extent paid out of our current or accumulated earnings and profits,
distributions made on our shares or ADSs, other than certain distributions of
our capital stock or rights to subscribe for shares of our capital stock, will
be includible in the income of a U.S. Holder for United States federal income
tax purposes as ordinary dividend income. In the case of a U.S. Holder of an
ADR, such dividend income will be recognized on the date Citibank receives the
distribution. Dividends we pay will not be eligible for the dividends-received
deduction generally allowed to corporations under the U.S. Internal Revenue Code
of 1986, as amended (the "Code"). The amount of dividend distribution for tax
purposes will equal the U.S. dollar value of the amount of the distribution in
Norwegian kroner (including the amount of Norwegian taxes withheld from the
distribution), calculated by reference to the exchange rate in effect on the
date of the distribution. Upon the ultimate conversion by Citibank into U.S.
dollars of the Norwegian kroner received in a distribution, U.S. Holders of ADRs
generally will recognize gain or loss for United States federal income tax
purposes equal to the difference, if any, between such U.S. dollars and the U.S.
dollar value of such Norwegian kroner on the date of the distribution. Such gain
or loss will be treated as ordinary income or loss.
Norwegian taxes imposed on dividend distributions on our shares or ADSs
generally will be eligible for credit against the U.S. Holder's United States
federal income taxes. The amount of the Norwegian taxes eligible for this
foreign tax credit will be equal to the amount of such taxes withheld from the
dividend distributions, reduced by the amount of any refunds of such taxes
subsequently received, translated into U.S. dollars at the exchange rate in
effect on the date the taxes originally were paid. Under the foreign tax credit
limitations of the Code, the foreign tax credit can offset United States federal
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<PAGE> 27
income taxes imposed on foreign-source income but not on United States-source
income. In addition, foreign taxes imposed on income in certain categories
specified in the Code may only be used to offset United States taxes on income
in the same category. Subject to the special rule we describe below, dividends
we pay will generally be foreign-source income within either the "passive
income" category or the "financial services income" category, depending on the
particular U.S. Holder's circumstances.
The Code contains a provision that could, in certain circumstances, cause a
portion of the dividends we pay to be treated as United States-source income.
Even if that provision applied to dividends we pay to a U.S. Holder, because of
the source rules contained in the Convention, no portion of such a dividend
would be recharacterized as United States-source income if the U.S. Holder
includes the dividend as a separate category of income for purposes of the
foreign tax credit limitation.
TAXATION OF DISPOSITIONS
A U.S. Holder normally is not taxed in Norway on gains from the sale or
other disposal of our shares or ADSs. Such a holder may be subject to taxation
if the shareholding is effectively connected with a business carried out by the
shareholder through a permanent establishment in Norway. In addition, a
shareholder may be subject to taxation on gains if the shareholder is an
individual who has been a resident of Norway for income tax purposes and the
disposal takes place within five years after the calendar year in which the
shareholder ceased to be a resident of Norway. The same rules apply to gains
realized upon complete liquidation of us or upon redemption of our shares or
ADSs. Repayment in connection with a reduction of our share capital by reducing
the nominal value of the shares is, however, subject to withholding tax as a
dividend distribution, if exceeding paid-in capital.
A U.S. Holder will recognize capital gain or loss for United States federal
income tax purposes on a sale or other disposition of our shares or ADSs (or
rights to subscribe for our shares), including a sale or other disposition by
Citibank of shares (or rights to subscribe for shares) received as dividends on
the ADSs, in the same manner as on the sale or other disposition of any other
shares held as capital assets (or rights to acquire such shares). Any such gain
or loss will generally be United States-source income or loss.
Deposits and withdrawals of our shares in exchange for ADRs will not result
in taxable gain or loss for United States or Norwegian tax purposes.
U.S. BACKUP WITHHOLDING
Certain payments, including certain dividends and proceeds from sales of
stock, may be subject to United States "backup withholding" at a 31% rate if the
recipient of such a payment fails to furnish to the payor certain information,
including the recipient's taxpayer identification number, or otherwise fails to
establish an exemption from withholding. Any amounts so withheld would be
allowed as a credit against the recipient's United States federal income tax
liability for the year. Because we are a foreign corporation for United States
federal income tax purposes, dividends we pay with respect to our shares or ADSs
are not subject to backup withholding under the regulations that are currently
in effect. However, under more recently issued regulations, which are currently
scheduled to become effective on January 1, 2001, dividends we pay to a U.S.
Holder generally would be subject to backup withholding under the circumstances
described in the first sentence of this paragraph.
NORWEGIAN TRANSFER TAX
There is no Norwegian stock transfer tax or capital tax upon the
acquisition or subsequent disposition of our shares or ADSs.
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<PAGE> 28
NORWEGIAN INHERITANCE TAX
There is no Norwegian inheritance tax or gift tax on our shares or ADSs if
the deceased, at the time of death, or the donor at the time the gift is made,
is neither a resident nor a national of Norway. If the deceased, at the time of
death, is not a resident of Norway, but is a national of Norway, Norwegian
inheritance tax will be levied unless inheritance tax or similar tax is levied
in the country of residence and the shares are not effectively connected to a
permanent establishment in Norway. Under all circumstances, a transfer of shares
or ADSs will be subject to gift tax in Norway if the donor at the time of the
gift is a Norwegian national.
NORWEGIAN PROPERTY TAXES OR SIMILAR TAXES
U.S. Holders of our shares or ADSs are not subject to Norwegian property
tax or similar taxes (e.g., wealth taxes) with respect to those shares or ADSs,
unless the shareholding is effectively connected with a business carried out by
the shareholder through a permanent establishment in Norway.
ITEM 8. SELECTED FINANCIAL DATA
We have presented below, on the basis of United States generally accepted
accounting principles,
our selected consolidated financial data for the five-year period ended December
31, 1999.
PricewaterhouseCoopers LLP, independent accountants, has audited our
consolidated financial statements for each of the three years in the period
ended December 31, 1999. PricewaterhouseCoopers DA, independent accountants, has
audited our consolidated financial statements for each of the two years in the
period ended December 31, 1996. From these consolidated financial statements, we
have derived the financial data presented below for such periods and as of such
dates. You should read the financial data for the three-year period ended
December 31, 1999 and as of December 31, 1999 and 1998 in conjunction with, and
the financial data are qualified in their entirety by reference to, our
consolidated financial statements and notes included in Item 18 of this annual
report. We have reclassified certain prior year amounts to conform to the
current year's presentation.
We have presented in the table EBITDA to provide additional information
about us. Our management uses EBITDA as a supplemental financial measurement in
the evaluation of our business. You should not consider EBITDA as an alternative
to net income, as an indicator of operating performance or as an alternative to
cash flows as a measure of liquidity.
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<PAGE> 29
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1999 1998 1997(5) 1996 1995
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT FOR SHARE DATA)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA
Revenue.................................. $ 788,160 $ 761,762 $ 539,381 $ 451,258 $ 317,520
Cost of sales, including research and
technology costs....................... 348,919 251,155 181,520 158,884 127,039
Depreciation and amortization............ 238,576 273,799 191,693 170,010 106,862
Selling, general and administrative
costs.................................. 71,738 67,103 39,812 31,841 26,183
Unusual items(1)......................... 89,855 25,737 -- -- --
---------- ---------- ---------- ---------- ----------
Total operating expenses................. 749,088 617,794 413,025 360,735 260,084
---------- ---------- ---------- ---------- ----------
Operating profit......................... 39,072 143,968 126,356 90,523 57,436
Income (loss) from equity investments.... (4,935) 854 1,966 1,315 1,439
Financial expense, net................... (95,969) (40,241) (24,665) (20,633) (6,090)
Other income (expense), net(2)........... 23,650 38,966 2,092 941 (781)
---------- ---------- ---------- ---------- ----------
Income (loss) before income taxes........ (38,182) 143,547 105,749 72,146 52,004
Provision (benefit) for income taxes..... (41,890) 31,950 28,165 21,850 15,573
---------- ---------- ---------- ---------- ----------
Income before extraordinary charge and
cumulative effect of accounting
change(3)(4)........................... 3,708 111,597 77,584 50,296 36,431
---------- ---------- ---------- ---------- ----------
Extraordinary charge, net of tax(3)...... -- -- (3,447) -- --
Cumulative effect of accounting change,
net of tax(4).......................... (19,977) -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income (loss)........................ $ (16,269) $ 111,597 $ 74,137 $ 50,296 $ 36,431
========== ========== ========== ========== ==========
Earnings per share before extraordinary
charge and cumulative effect of
accounting change(3)(4)
Basic(5)............................... $ 0.04 $ 1.36 $ 1.20 $ 0.90 $ 0.69
Diluted(5)............................. $ 0.04 $ 1.32 $ 1.15 $ 0.88 $ 0.67
Earnings (loss) per share
Basic(5)............................... $ (0.17) $ 1.36 $ 1.15 $ 0.90 $ 0.69
Diluted(5)............................. $ (0.17) $ 1.32 $ 1.10 $ 0.88 $ 0.67
Basic shares outstanding(5).............. 94,767,967 82,260,652 64,519,503 55,921,976 52,860,415
Diluted shares outstanding(5)............ 95,840,199 84,794,836 67,358,004 56,963,730 54,028,213
OTHER DATA
EBITDA(6)................................ $ 367,503 $ 443,504 $ 318,049 $ 260,533 $ 164,298
Cash flows from operating activities..... 200,678 274,656 228,686 212,406 159,645
Capital expenditures..................... 667,869 521,630 468,872 172,910 119,434
Investment in multi-client library....... 338,718 388,228 203,267 137,475 118,744
BALANCE SHEET DATA
Cash and cash equivalents................ $ 63,044 $ 53,273 $ 127,491 $ 125,250 $ 38,237
Multi-client library, net................ 816,423 553,415 325,181 236,258 203,346
Total assets............................. 4,176,651 3,425,105 1,677,848 1,081,389 724,091
Total long-term debt and capital lease
obligations............................ 1,998,530 1,421,670 550,450 331,499 226,589
Shareholders' equity..................... 1,589,877 1,397,151 811,347 499,845 324,202
</TABLE>
---------------
(1) Unusual items for the year ended December 31, 1999 include $74.0 million in
restructuring charges and $15.9 million in asset impairments. Unusual items
in 1998 include $22.7 million in asset impairments and $3.0 million in
merger costs for the acquisition of Acadian Geophysical Services, Inc.
("Acadian") in July 1998, which was accounted for as a pooling of interests.
(2) Other income (expense), net for 1999 and 1998 includes $19.1 million and
$32.5 million, respectively, in UK lease gains.
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<PAGE> 30
(3) During March 1997, we prepaid our $30 million 7.12% senior notes due
February 2004 and our $95 million 7.33% senior notes due February 2006. As a
result, we incurred an extraordinary charge of $3.4 million, net of tax
benefits of $1.3 million. The extraordinary charge consisted of a write-off
of the associated debt issuance costs and the prepayment premium.
(4) Effective January 1, 1999, we adopted Statement of Position ("SOP") 98-5,
"Reporting on the Costs of Start-up Activities." This SOP requires that the
initial, one-time costs related to introducing new products and services,
conducting business in new territories or commencing new operations be
expensed as incurred. Accordingly, we have recognized a charge to income of
$20.0 million, net of tax benefits of $8.1 million, as the cumulative effect
of the change in accounting principle.
(5) We effected a stock split during June 1998. All share data have been
restated to reflect this stock split and all 1997 information has been
restated to reflect the acquisition of Acadian.
(6) We define EBITDA for this purpose as operating profit before depreciation
and amortization and unusual items.
EXCHANGE RATES
Fluctuations in the exchange rate between the NOK and the U.S. dollar will
affect the U.S. dollar equivalent of the NOK price of our shares traded on the
Oslo Stock Exchange and, as a result, may affect the market price of our
American Depositary Shares in the United States.
We have presented in the table below, for the periods and dates indicated,
information about the exchange rate for the NOK against the U.S. dollar based on
the noon buying rate in New York City for cable transfers in foreign currencies
as certified for customs purposes by the Federal Reserve Bank of New York on the
indicated date. The average rate presented in the table is the average of the
noon buying rates on the last business day of each month during the year.
NOK/U.S. DOLLAR EXCHANGE RATES
(NOK PER U.S. DOLLAR)
<TABLE>
<CAPTION>
AT END AVERAGE
CALENDAR YEAR OF PERIOD RATE HIGH LOW
------------- --------- ------- ---- ----
<S> <C> <C> <C> <C>
1995........................................................ 6.33 6.35 6.60 6.16
1996........................................................ 6.46 6.47 6.58 6.38
1997........................................................ 7.37 7.10 7.64 6.49
1998........................................................ 7.58 7.55 7.81 7.38
1999........................................................ 8.01 7.84 8.10 7.40
</TABLE>
For information regarding currency fluctuations, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Currency Fluctuations" in Item 9 of this annual report.
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<PAGE> 31
ITEM 9. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
You should read the discussion under this caption in conjunction with our
consolidated financial statements and the related notes in Item 18 of this
annual report and "Selected Financial Data" in Item 8 of this annual report.
This discussion is based upon, and the financial statements have been prepared
in accordance with, United States generally accepted accounting principles. The
following information contains forward-looking statements. You should refer to
the section in this annual report captioned "Forward-Looking Information" for
cautionary statements relating to forward-looking statements.
OVERVIEW
How We Categorize Our Business
Our services may be divided into two general categories consisting of:
- geophysical services, which includes:
- seismic data acquisition and processing
- reservoir characterization, monitoring and consulting services
- data management services and sales of software and reports
- production services, which includes:
- floating production, storage and offloading ("FPSO") operations
- production management services
Seasonality
Our business has historically reflected seasonality as a result of
weather-related factors. Our first and fourth quarters, in particular, are
generally negatively affected by adverse weather conditions in the North Sea,
which prevent full operation of seismic crews and vessels. During such periods,
we generally repair our seismic vessels and relocate them to areas with more
favorable weather conditions to conduct seismic activities. On the other hand,
fourth quarter revenue has historically been positively affected by end-of-year
sales of multi-client data to oil and gas companies. In addition, licensing
activities and oil and gas lease sales may affect quarterly operating results.
As our FPSO and our production management services become more significant to
our overall business, the impact of seasonal fluctuations should be reduced.
Industry Overview
Overall oil and gas market conditions deteriorated in 1998 and the first
half of 1999, as oil prices decreased to close to $11 per barrel and oilfield
service activity declined to historic lows. Despite the recent significant
improvement in oil and gas prices, the recovery in exploration and production
spending has been negatively affected by continued caution among our customers
about the long-term hydrocarbon price environment. In addition, the continuing
consolidation in the oil and gas industry generally has delayed the beginning of
a number of exploration and development projects. As a result, the demand for
our geophysical services has been reduced, resulting in reduced geophysical
services revenue. During 1999, we undertook a number of restructuring efforts to
adjust our businesses to current and expected market conditions. During 1999, we
reduced our seismic acquisition capacity in both marine and land operations and
reduced a portion of our data processing capacity. These adjustments to our
operations have resulted in a reduction of our workforce. The financial impact
of these restructuring efforts is discussed further below under the caption
"Results of Operations -- 1999 Compared with 1998." We believe that the demand
for our services will recover during 2000 and begin to grow during the second
half of the year.
Accounting for Multi-Client Sales and Data Library
We derive a substantial portion of our revenue from marine seismic
acquisition contracts performed on an exclusive basis for our customers and from
sales of multi-client marine seismic data. Revenue from sales of multi-client
data is either (1) in the form of prefunding, defined as amounts funded by
customers prior to or during the acquisition phase and recognized as revenue on
a percentage-of-completion basis, or (2) in the form of sales of data from our
multi-client library that are recognized as revenue when we
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<PAGE> 32
obtain a non-cancelable commitment from the customer. For multi-client surveys,
we typically obtain prefunding for a portion of the costs of such surveys from a
small number of oil and gas companies that desire to obtain seismic data in the
areas to be covered by the surveys. As a result, we assume the risk that future
sales of such data may not ultimately cover the remaining costs. We include the
direct and indirect costs of acquiring and processing multi-client data in our
multi-client library and charge such costs to operating expense based on a
percentage of current period multi-client revenue to total estimated multi-
client revenue. Our accounting rules also require us to amortize these costs at
minimum rates and to periodically evaluate the library for impairment.
In determining the amortization rates applied to surveys in our
multi-client library, we consider expected future multi-client sales and market
developments as well as past experience. These expectations include
consideration of geographic location, prospectivity, political risk, exploration
license periods and general economic conditions. Our ability to recover costs
included in the multi-client library through sales of the data depends upon
continued demand for the data and an absence of technological changes or other
developments that would render the multi-client data obsolete or less valuable.
RESULTS OF OPERATIONS
1999 Compared with 1998
Revenue for the year ended December 31, 1999 totaled $788.2 million, an
increase of approximately 3% over revenue for the year ended December 31, 1998.
The production services group contributed $368.3 million of 1999 revenue versus
$139.5 million for 1998. The increase in production services revenue in 1999
resulted from the FPSO operations acquired from Awilco ASA in May 1998; the
operations of Atlantic Power Group Limited acquired in August 1998; the Ramform
Banff, which began production in January 1999; and the Petrojarl Varg, which we
acquired in July 1999. Geophysical services revenue for 1999 totaled $419.9
million, a decline of 33%, or $202.4 million, from 1998. The significant
decrease in exploration and development spending by oil and gas companies and
the resulting depressed market for oilfield services during 1999 resulted in
lower multi-client and contract sales revenue compared to 1998 levels.
Cost of sales for the year ended December 31, 1999 increased by $97.8
million, or 39%, as compared to the prior year. Cost of sales as a percentage of
revenue was 44% in 1999 as compared to 33% in 1998. The increase in cost of
sales primarily reflected the expansion of our production services, as noted
above, partially offset by lower overall costs in our geophysical services from
our 1999 capacity reductions and restructuring efforts.
Depreciation and amortization for the year ended December 31, 1999 declined
by $35.2 million, or 13%, as compared to the prior year. Depreciation and
amortization represented 30% and 36% of 1999 and 1998 revenue, respectively. The
decrease in 1999 resulted primarily from reduced multi-client seismic revenue in
that year (although the overall amortization rate remained consistent with that
of 1998) and the retirement of assets as part of our geophysical services
restructuring efforts. This decrease was partially offset by (1) higher
depreciation related to the Ramforms Victory and Vanguard, which were delivered
in 1999 and therefore not a part of 1998 operations, and (2) the expansion of
our production services, as noted above.
Selling, general and administrative costs for 1999 increased $4.6 million,
or 7%, as compared to 1998. This increase was primarily due to acquisitions and
expanded operations in our production services group, which was a part of our
operations for only a portion of 1998.
Unusual items for the year ended December 31, 1999 totaled $89.9 million
and included $74.0 million in restructuring charges as well as $15.9 million in
asset impairments caused by market conditions. During 1999, we experienced a
significant decrease in the demand for our geophysical services due to the low
price of oil during 1998 and the first half of 1999. As a result of these
reduced activity levels, we
32
<PAGE> 33
implemented certain restructuring efforts and recorded charges during the first
and third quarters related to these efforts, as summarized below:
<TABLE>
<CAPTION>
ACCRUED
BALANCE AT
AMOUNTS PAID DECEMBER 31,
TOTAL CHARGE IN 1999 1999
------------ ------------ ------------
(IN MILLIONS)
<S> <C> <C> <C>
Cash charges:
Severance for approximately 500 employees............. $12.7 $ 6.1 $ 6.6
Lease termination, derigging and other obligations.... 38.7 28.0 10.7
----- ----- -----
Cash charges....................................... 51.4 $34.1 $17.3
----- ----- -----
Non-cash charges-write-off and write-down of property
and equipment......................................... 22.6
-----
Total cash and non-cash charges............... $74.0
=====
</TABLE>
The employees terminated were primarily field and support personnel
associated with marine, transition zone and land seismic crews that we removed
from service, and employees within our data processing operations. Approximately
400 employees had been terminated as of December 31, 1999. We based the accrued
charges on the positions eliminated, length of service and any statutory or
legal requirements applicable within the country where the terminations
occurred. We estimate that all of the accrued severance at December 31, 1999
will be paid during 2000.
We accrued $38.7 million for costs to (1) derig marine vessels removed from
operations, (2) settle contractual obligations associated with leased vessels
and equipment removed from service, and (3) accrue for other incremental costs
associated with our restructuring efforts.
The impairment of property and equipment primarily consisted of (1) the
write-down of geophysical assets that are either being scrapped, disposed of or
will not benefit future operations, and (2) the write-off of leasehold
improvements associated with leased vessels and equipment removed from service.
We also recognized $15.9 million in impairment charges for certain software,
equity investment and other assets. Impairment charges were based on a
comparison of the assets' carrying amounts to internal estimates of the
realizable fair market values.
Net financial expense for the year ended December 31, 1999 increased by
$55.7 million as compared to the prior year. The increase was primarily due to
an increase in outstanding debt during 1999, incurred primarily to finance the
delivery of the Ramforms Victory and Vanguard and the acquisition of the
Petrojarl Varg.
Other income, net for the year ended December 31, 1999 totaled $23.7
million, a decrease of 39% as compared to the prior year. For 1999, other
income, net included $19.1 million in gains associated with UK leases that we
implemented on some of our vessels and equipment. For 1998, other income, net
included $32.5 million in such gains.
An income tax benefit was provided on the current income from operations as
a result of (1) losses relating to operations in high-tax rate jurisdictions due
to depressed conditions in the oilfield services market during 1999; (2)
significant income earned in low or no-tax rate jurisdictions; and (3) the
recognition of $15.3 million in tax gains related to the successful resolution
of certain tax issues.
As a result of the depressed market conditions for oilfield services in
1999, and the restructuring charges and asset impairments that we took in
response to these market conditions, we recognized a loss on our geophysical
services in 1999. Included in this loss was the substantial portion of a net
$55.5 million in charges consisting of the $89.9 million in restructuring and
impairment charges, the $19.1 million in UK lease gains and the $15.3 million in
tax gains discussed above.
Effective January 1, 1999, we adopted Statement of Position ("SOP") 98-5,
"Reporting on the Costs of Start-up Activities." Accordingly, we expensed as a
cumulative effect of an accounting change all previously capitalized start-up
costs. The $20.0 million in expensed costs, net of income tax benefits of
33
<PAGE> 34
$8.1 million, included costs related to the start-up of our floating production
business, our reservoir monitoring business and our multi-component, vertical
cable and land seismic businesses, as well as costs related to the opening of
various worldwide offices. Subsequent to adoption, all start-up costs are
expensed as incurred.
1998 Compared with 1997
Revenue for the year ended December 31, 1998 was $761.8 million, an
increase of $222.4 million, or 41%, over revenue for the year ended December 31,
1997. This increase resulted primarily from the inclusion of the revenue
attributable to our production services group, which was not part of 1997
activities, and the commencement of operations by the Ramform Valiant (delivered
in January 1998) and the Ramform Viking (delivered in March 1998).
Cost of sales for the year ended December 31, 1998 increased by $64.4
million, or 37%, as compared to the prior year, but was slightly lower as a
percentage of revenue at 31% for 1998, as compared to approximately 32% for
1997. The increase primarily reflected our production services group, which was
not a part of 1997 activities.
Depreciation and amortization for the year ended December 31, 1998
increased by $82.1 million, or 43%, as compared to the prior year, but remained
constant as a percentage of revenue; depreciation and amortization represented
approximately 36% of 1998 and 1997 revenue. This increase resulted primarily
from depreciation on production services assets and the Ramforms Valiant and
Viking seismic vessels, which were not a part of 1997 activities.
Selling, general and administrative costs for the year ended December 31,
1998 increased by 69% as compared to the prior year. As a percentage of revenue,
these costs increased to 9% for 1998 versus 7% for 1997. These increases were
generally due to the addition of the production services group during 1998.
Unusual items for the year ended December 31, 1998 totaled $25.7 million,
which included $22.7 million for asset write-downs related to certain library,
property and equity investment items, as well as $3.0 million in direct and
other merger-related costs for the acquisition of Acadian Geophysical Services,
Inc.
Net financial expense for the year ended December 31, 1998 increased by 63%
as compared to the prior year. This increase was primarily attributable to an
increase in outstanding debt during 1998 as a result of the acquisition of the
FPSO operations of Awilco ASA and the construction of the Ramforms Banff, Viking
and Victory.
Other income, net for the year ended December 31, 1998 increased by $36.9
million over 1997 and included approximately $32.5 million in gains associated
with the removal of contingencies on U.K. leases relating to seismic and
production services assets. Extraordinary charges in 1997 included a charge of
$3.4 million, net of tax benefits of $1.3 million, associated with the March
1997 prepayment of long-term debt.
FINANCIAL CONDITION
Capital Requirements
Our capital requirements consist primarily of capital expenditures related
to:
- seismic vessels and equipment
- FPSO vessels and equipment
- investments in our 3D multi-client library
- computer processing, data management and reservoir monitoring equipment
- working capital related to the growth and seasonal nature of our business
34
<PAGE> 35
In prior years, our capital requirements have related not only to normal ongoing
equipment replacement and refurbishment needs, but also to increases in
capacity. The most significant additions to capacity occurred in our seismic
data acquisition operations and our FPSO operations. In 2000, we expect to
significantly reduce capital expenditures related to capacity additions.
Capital expenditures of $667.9 million for 1999 related primarily to the
acquisition of the Petrojarl Varg in July 1999; final payments on the Ramform
Victory (delivered in January 1999), the Ramform Vanguard (delivered in April
1999) and the Ramform Banff (which commenced production in the first quarter of
1999); and ongoing maintenance capital expenditures.
During 1999, we invested $338.7 million in our multi-client library,
primarily in strategic, deepwater seismic surveys in the North Sea, the Gulf of
Mexico, offshore Brazil and in the West African and Asia Pacific regions. These
investments reflected our evaluation of the future market demand for
non-exclusive surveys.
Despite the recent volatility in the oil and gas environment, we believe
that our multi-client investment provides a valuable revenue base. Approximately
90% of the investment in our multi-client library as of December 31, 1999 was
acquired during the preceding 24 months, while the remainder is less than five
years old. We believe that our multi-client library provides oil and gas
companies with a cost-effective exploration and development product, and one
that is available immediately. In difficult market conditions, the multi-client
data allow oil and gas companies to focus their investments and efforts on
readily identifiable exploration and development opportunities.
A substantial amount of our capital expenditures and investments in our
multi-client library is discretionary, and we expect to substantially reduce
such expenditures and investments in 2000. In addition, we currently do not have
any major commitments for future capital expenditures. We intend, however, to
pursue additional opportunities to provide FPSO systems and advanced geophysical
services to our customers. We expect that any substantial investment in FPSO
assets will be subject to obtaining long-term contracts for those assets.
Capital Resources and Liquidity
We have historically financed our activities through cash flows from
operations, bank credit facilities, equity financing and the issuance of debt.
In June 1999, one of our special-purpose subsidiaries sold $143.8 million
liquidation amount of 9 5/8% trust preferred securities, resulting in net
proceeds to us of $138.9 million. These securities have an annual distribution
rate of 9.6%, payable quarterly in arrears. We may, however, defer distributions
for up to five years without penalty. We can redeem these securities at their
liquidation amount ($25 per security) after June 2004, and we must redeem them
no later than June 2039. We used the net proceeds from this trust preferred
offering to repay amounts outstanding under our revolving bank credit and
short-term credit facilities.
In connection with the acquisition of the Petrojarl Varg, we obtained a
$350.0 million bank bridge loan facility. We borrowed the full amount of this
facility in July 1999 to pay for the acquisition of the Petrojarl Varg.
In July 1999, we issued $200.0 million of 8.15% senior notes due 2029. We
used the net proceeds from the offering, totaling $195.7 million, to repay
indebtedness outstanding under the facility used to fund the Petrojarl Varg
acquisition.
In August 1999, we completed an offering of 11,159,500 American Depositary
Shares and shares, resulting in net proceeds of $214.1 million. We used the net
proceeds to repay the remaining indebtedness outstanding under the Petrojarl
Varg bank bridge loan facility and other indebtedness outstanding under our
revolving bank credit facility.
At December 31, 1999, we had $30.0 million in an available committed
revolving bank credit facility. Our unsecured five-year $430.0 million revolving
bank credit facility bears interest at a LIBOR-based rate
35
<PAGE> 36
plus a margin of either 0.35% per annum or 0.40% per annum, depending upon the
level of our indebtedness.
In March 2000, we issued $225.0 million of senior unsecured notes. The
notes carry a floating interest rate equal to 0.7% over the three-month LIBOR
rate for US dollar deposits, subject to quarterly adjustment, with interest
payable quarterly. The notes mature in March 2002, but we can redeem them at our
option, in whole or in part, on any interest payment date beginning March 2001
at par plus accrued and unpaid interest. We used the net proceeds from this
issuance primarily to repay indebtedness outstanding under our revolving bank
credit facility.
We expect to finance our future capital expenditures, multi-client
investments and working capital needs through a combination of operating cash
flows, sales of non-core assets, our revolving bank credit facility, equity
offerings and other debt financing. We cannot assure you that such sources of
funds will be available in the future or be available at costs acceptable to us.
As a result, in addition to analyzing operating market conditions and/or the
award of long-term contracts, we routinely analyze our available sources of
financing before committing to significant capital expenditures.
We believe that cash on hand, operating cash flows and our committed
available bank credit facility will be adequate to meet our current commitments
for capital expenditures, anticipated multi-client investments and working
capital requirements.
Dividend Restrictions
Our ability to meet parent company-level payment obligations depends upon
dividends, distributions, advances and other intercompany transfers from our
subsidiaries. Under Norwegian law, dividends in cash or in kind as a
distribution of our profit and the profits of our Norwegian subsidiaries are
only payable annually, and any proposal by the board of directors to pay a
dividend must be recommended by the directors and approved by the shareholders
at a general meeting. The shareholders may vote to reduce, but not to increase,
the dividends proposed. Dividends in cash or in kind are payable only out of (1)
the annual profit according to the income statement for the last financial year,
(2) retained profit from previous years and (3) other unrestricted equity, after
deduction of (a) accumulated losses, (b) the book value of research and
development, goodwill and net deferred tax assets recorded on the balance sheet
and (c) any part of the annual profit that, according to law or our articles of
association and the articles of each of our Norwegian subsidiaries, must be
allocated to restricted funds. Neither we nor our Norwegian subsidiaries can
declare dividends if the equity, according to the balance sheet, amounts to less
than 10% of the balance sheet, or dividends in excess of an amount that is
compatible with good and careful business practice with due regard to any losses
that may have occurred after the last balance sheet date or that may be expected
to occur.
Additionally, the terms of our debt agreements impose limitations on the
payment of dividends.
We do not currently intend to declare or pay dividends, but intend to
reinvest any profit.
CURRENCY FLUCTUATIONS
The primary functional currencies for our operations are the U.S. dollar,
the Norwegian kroner and the British pound. A strengthening or weakening of the
Norwegian kroner or the British pound against the U.S. dollar will generally
have an impact on operating profit. During 1997, we changed our functional
currency and the functional currency of our principal Norwegian subsidiaries
from the Norwegian kroner to the U.S. dollar, as key financing, investing and
operational transactions shifted to U.S. dollars. We typically hedge a portion
of our exposure to foreign currency exchange rate fluctuations by generally
attempting to balance our asset and liability positions and, to a lesser extent,
by purchasing foreign currency exchange contracts and other foreign currency
exchange instruments.
In 1999, we recorded $4.1 million in net foreign exchange gains, as the
U.S. dollar strengthened against the Norwegian kroner. (Accordingly,
kroner-denominated liabilities were reduced as reported in U.S. dollars.) In
1998, net foreign exchange gains were minimal. During 1998, the U.S. dollar
remained
36
<PAGE> 37
relatively stable against the Norwegian kroner, and therefore changes in the
exchange rate between the U.S. dollar and the Norwegian kroner did not have a
material impact on our operating profit and shareholders' equity. In 1997, we
recorded net foreign exchange gains of $4.4 million. During that year, the U.S.
dollar appreciated against the Norwegian kroner. (Accordingly, our net revenue
and earnings as reported in U.S. dollars were reduced. This appreciation of the
U.S. dollar also resulted in a decrease to equity, which has been included in
other comprehensive income.)
As we increase our level of international operations and the revenue and
expenses that we generate in other currencies, our exposure to foreign currency
exchange rate fluctuations will also increase. These fluctuations could have a
material impact on our results of operations.
Under Norwegian foreign exchange controls currently in effect, transfers of
capital to and from Norway are not subject to prior government approval except
for the physical transfer of payments in currency, which is restricted to
licensed banks.
INCOME TAXES
Statement of Financial Accounting Standard ("SFAS") No. 109, "Accounting
for Income Taxes," requires that our provision for income taxes be determined
based upon the liability method, in which we recognize deferred tax assets and
liabilities based on differences between the financial statement and tax bases
of assets. The liability method requires us to evaluate our deferred tax assets
for realization based on a "more likely than not" standard, and to provide a
valuation allowance where realization is not determined to be "more likely than
not." We have not provided a valuation allowance against our deferred tax assets
because we have realized taxable earnings for the substantial portion of our
operational history and anticipate that our results of operations in future
years are more likely than not to generate taxable income sufficient to allow
utilization of the existing deferred tax assets.
NEW ACCOUNTING STANDARD
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS
No. 133 establishes accounting and reporting standards requiring that every
derivative financial instrument be recorded in the balance sheet as either an
asset or a liability measured at its fair value, with certain changes in fair
value recognized currently in earnings. In June 1999, the FASB amended SFAS No.
133, delaying the effective date to January 1, 2001. We will adopt this standard
through a cumulative effect of an accounting change, but have not yet determined
the impact of adoption.
ITEM 9A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our earnings and cash flows are subject to fluctuations due to changes in
foreign currency exchange rates. We periodically enter into forward foreign
currency exchange contracts and option contracts to hedge firm commitments but
not for speculative or trading purposes. Our business contracts generally
provide for payment in U.S. dollars, and we do not maintain significant foreign
currency cash balances. Our tax equalization swap contracts carried weighted
average exchange rate floors of 7.4 NOK and 6.7 NOK to the U.S. dollar at
December 31, 1999 and 1998, respectively. Under each tax equalization swap
contract, if the NOK to U.S. dollar exchange rate at any settlement date is less
than the contract's exchange rate floor, we will neither incur a liability nor
accrue a benefit for the exchange rate differential below the floor. At December
31, 1999 (after the determination of the December 1999 interim settlement), the
base exchange rate on the contracts was reset to approximately 8.0 NOK to the
U.S. dollar; the December 2000 interim settlement will be measured against this
base exchange rate and the then current exchange rate, subject to the exchange
rate floor. Accordingly, we will incur a liability if the NOK to U.S. dollar
exchange rate exceeds the base exchange rate, or we will accrue a benefit if
such exchange rate is less than the base exchange rate (subject to the exchange
rate floor). Please read notes 1 and 15 of the notes to our financial statements
in Item 18 of this annual report. We specifically incorporate by reference in
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<PAGE> 38
response to this item the information under the captions "Foreign Currency
Translation" and "Derivative Financial Instruments" in note 1 and the
information in note 15.
Our earnings and cash flows are also exposed to changes in interest rates
on our long-term debt obligations. We present below the weighted average
interest rate for the scheduled maturities of our fixed rate long-term debt
obligations as of December 31, 1999 and 1998 (in thousands of dollars):
<TABLE>
<CAPTION>
ESTIMATED
1999 2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
------- ------- ------- ------- -------- -------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
AS OF DECEMBER 31, 1999,
Fixed Rate Debt:
Amount Due............ $ -- $10,635 $11,181 $11,810 $258,517 $ 10,200 $1,293,664 $1,596,007 $1,510,484
Weighted Average
Interest Rate....... --% 7.4% 7.4% 7.5% 6.3% 8.3% 7.4% 7.2% --
AS OF DECEMBER 31, 1998,
Fixed Rate Debt:
Amount Due............ $28,927 $15,026 $11,544 $11,981 $256,553 $ 10,200 $1,097,391 $1,431,622 $1,426,380
Weighted Average
Interest Rate....... 7.6% 7.4% 7.4% 7.5% 6.3% 8.3% 7.3% 7.1% --
</TABLE>
Our fixed rate debt includes Norwegian kroner-denominated debt totaling
$9.3 million and $13.1 million at December 31, 1999 and 1998, respectively.
We had $5.0 million and $15.1 million in U.S. dollar-denominated long-term
debt carrying floating interest rates at December 31, 1999 and 1998,
respectively. We also utilize an unsecured five-year $430.0 million revolving
bank credit facility that bears interest at a LIBOR-based rate plus a margin of
either 0.35% or 0.40%, depending on the level of our indebtedness.
Please read note 8 of the notes to our financial statements in Item 18 of
this annual report. We specifically incorporate by reference in response to this
item the information in note 8.
ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT
BOARD OF DIRECTORS
The table below provides information about our directors:
<TABLE>
<CAPTION>
DIRECTOR
NAME (AGE) POSITION SINCE TERM EXPIRES
---------- -------- -------- ------------
<S> <C> <C> <C>
Reidar Michaelsen (56)................................. Chairman 1993 2001
Michael S. Mathews (59)................................ Vice Chairman 1993 2001
Bjarte Bruheim (44).................................... Director 1999 2001
Jens Gerhard Heiberg (61).............................. Director 1993 2001
Mark G. Frantz (53).................................... Director 1994 2000
John R. Milligan (59).................................. Director 1998 2000
Jan Aage Strand (46)................................... Director 1996 2000
Endre Ording Sund (50)................................. Director 1998 2000
</TABLE>
38
<PAGE> 39
EXECUTIVE OFFICERS
The table below provides information about our executive officers:
<TABLE>
<CAPTION>
EXECUTIVE
OFFICER
NAME (AGE) POSITION SINCE
---------- -------- ---------
<S> <C> <C>
Reidar Michaelsen (56)............ Chief Executive Officer 1991
Bjarte Bruheim (44)............... President and Chief Operating Officer 1991
J. Christopher Boswell (39)....... Senior Vice President and Chief Financial Officer 1995
Sam R. Morrow (51)................ Senior Vice President -- Finance and Treasurer 1996
Svein Vaage (51).................. Senior Vice President -- Geophysical Technology 1994
Karl Andreas Berteussen (55)...... Senior Vice President -- Reservoir Technology 1999
Ian D. McMillan (44).............. Senior Vice President -- Marine Technology 1999
Olve Torvanger (55)............... Senior Vice President -- Business Development 1992
Inge Olsen (43)................... Senior Vice President -- Mergers and Acquisitions 1995
William E. Harlan (41)............ Vice President, Chief Accounting Officer and 1996
Controller
David C. Wilson (54).............. Managing Director of Atlantis Technology Services 1994
Group
Knut Haavardsen (57).............. General Counsel 1992
Magne A. Reiersgard (38).......... President of PGS Asia Pacific 1997
Anthony Ross Mackewn (52)......... President -- Exploration EAME 1999
Edgar Alsaker (48)................ Managing Director of Golar-Nor Offshore AS 1998
David Workman (39)................ Managing Director of Atlantic Power Group Limited 1999
</TABLE>
ITEM 11. COMPENSATION OF DIRECTORS AND OFFICERS
For the year ended December 31, 1999, the aggregate amount we paid for
compensation to our directors and executive officers as a group (23 persons) for
services in all capacities was approximately $7.5 million (exclusive of any
compensation attributable to any exercises of stock options). Mr. Michaelsen,
our Chief Executive Officer, received compensation for services to us during
1999 (exclusive of any compensation attributable to any exercises of stock
options) of approximately $1.5 million. Mr. Bruheim, our Chief Operating Officer
and managing director, received compensation for services to us during 1999
(exclusive of any compensation attributable to any exercises of stock options)
of $1.2 million.
We have established a discretionary Senior Management Incentive Bonus Plan
designed primarily to compensate designated members of our senior management
when we achieve specified annual performance-related goals. Participants in the
plan are designated by the compensation committee of our board of directors,
which currently consists of Messrs. Heiberg, Mathews and Frantz. Performance
goals and related award schedules for award periods may be established under the
plan periodically and generally cannot be changed once established. Awards that
accrue for each year are contingent until paid, unless earlier vested due to a
change in control of us, plan termination or a participant's involuntary
termination of employment without cause, including by reason of death or
disability. Unless earlier vested, any awards that accrue during an award period
are forfeited by a participant who is no longer employed by us or our
subsidiaries on the date award payments are made. Payment of accrued awards is
deferred until after the end of the award period and is made in a cash lump sum.
The maximum individual award potentially payable with respect to any year is
100% of a participant's base salary ($850,000 for Mr. Michaelsen and $650,000
for Mr. Bruheim). The compensation committee has established a base award period
for the plan covering the three years from 1996 to 1999 with a granted extension
period through 2001, with annual awards during such periods accruing based in
part (75%) on targeted operating profit levels and increases in our earnings per
share. The remaining 25% of any annual award is granted at the discretion of the
compensation committee.
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<PAGE> 40
ITEM 12. OPTIONS TO PURCHASE SECURITIES FROM REGISTRANT OR SUBSIDIARIES
We have established an option plan under which the compensation committee
is authorized to grant to our key employees options to purchase our shares. Each
employee to whom we grant options has the right to buy shares within the time
period specified in the grant at the market price in effect at the time of the
grant. Options granted to employees subject to U.S. federal income taxation are
intended to constitute "incentive stock options" under the Code. Our
shareholders have authorized the board of directors to issue up to 10,800,000
shares prior to the end of 2002 in connection with the plan without further
action by the shareholders. As of December 31, 1999, 1,618,596 shares remained
available for grant under this authorization.
We have presented in the table below information relating to the
outstanding stock options under the plan as of December 31, 1999. We have
translated the NOK amounts in the table solely for convenience into U.S. dollars
at the noon buying rate on December 31, 1999 ($1.00 = NOK 8.01).
<TABLE>
<CAPTION>
NUMBER OF EXERCISE PRICE
OUTSTANDING --------------
EXERCISE DATES OPTIONS NOK $
-------------- ----------- ---- -------
<S> <C> <C> <C>
July 1, 1998 - July 1, 2000................................. 1,059,400 89 11.11
July 1, 1999 - July 1, 2001................................. 128,000 75 9.36
July 1, 1999 - July 1, 2001................................. 1,060,600 99 12.36
July 1, 2000 - July 1, 2002................................. 664,000 137.5 17.17
July 1, 2000 - July 1, 2002................................. 2,536,000 162 20.22
July 1, 2001 - July 1, 2003................................. 1,771,404 111 13.86
July 1, 2002 - July 1, 2004................................. 135,000 131.5 16.42
July 1, 2002................................................ 20,000 131.5 16.42
---------
7,374,404
=========
</TABLE>
At the 1996 annual general meeting, the shareholders authorized the
adoption of an option plan for our nonemployee directors. The terms of this plan
are similar to those of the employee stock option plan described above. Our
shareholders have authorized the board of directors to issue up to 500,000
shares prior to the end of 2000 in connection with this plan without further
action by the shareholders. As of December 31, 1999, 78,200 shares remained
available for grant under this authorization.
We have presented in the table below information relating to the
outstanding stock options under the plan as of December 31, 1999. We have
translated the NOK amounts in the table solely for convenience into U.S. dollars
at the noon buying rate on December 31, 1999 ($1.00 = NOK 8.01).
<TABLE>
<CAPTION>
NUMBER OF EXERCISE PRICE
OUTSTANDING ---------------
EXERCISE DATES OPTIONS NOK $
-------------- ----------- ---- --------
<S> <C> <C> <C>
July 1, 1999 - July 1, 2001................................. 60,000 99 12.36
July 1, 2000 - July 1, 2002................................. 80,000 162 20.22
July 1, 2001 - July 1, 2003................................. 60,000 229.5 28.65
July 1, 2002 - July 1, 2004................................. 60,000 128.5 16.04
July 1, 2002................................................ 56,800 128.5 16.04
-------
316,800
=======
</TABLE>
Each of the employee option plan and the nonemployee director option plan
described above contains a provision that all awards made under the plan become
immediately exercisable upon the occurrence of a change in control of us. A
"change in control" is generally defined to include certain changes in our board
of directors, the acquisition of a certain percentage of our outstanding shares,
certain merger transactions and certain dispositions of all or substantially all
of our assets.
40
<PAGE> 41
At the annual general meeting of shareholders in June 1999, our
shareholders authorized our board of directors to issue up to 33,950,000 shares
and American Depositary Shares through June 2001 for any purpose the board of
directors determines to be in our best interest, which could include issuances
pursuant to the employee stock option plan and the nonemployee director option
plan.
As of December 31, 1999, our directors and executive officers as a group
held options for 3,784,800 shares. As of that date, Mr. Michaelsen and Mr.
Bruheim held options as shown in the table below. We have translated the NOK
amounts in the table solely for convenience into U.S. dollars at the noon buying
rate on December 31, 1999 ($1.00 = NOK 8.01).
<TABLE>
<CAPTION>
NUMBER OF EXERCISE PRICE
OUTSTANDING ---------------
NAME EXERCISE DATES OPTIONS NOK $
---- --------------------------- ----------- ----- -------
<S> <C> <C> <C> <C>
Reidar Michaelsen......................... July 1, 1998 - July 1, 2000 240,000 89 11.11
July 1, 1999 - July 1, 2001 240,000 99 12.36
July 1, 2000 - July 1, 2002 720,000 162 20.22
Bjarte Bruheim............................ July 1, 1998 - July 1, 2000 200,000 89 11.11
July 1, 1999 - July 1, 2001 200,000 99 12.36
July 1, 2000 - July 1, 2002 600,000 162 20.22
</TABLE>
ITEM 13. INTEREST OF MANAGEMENT IN CERTAIN TRANSACTIONS
Not applicable.
41
<PAGE> 42
PART III
ITEM 15. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 16. CHANGES IN SECURITIES, CHANGES IN SECURITY FOR REGISTERED SECURITIES
AND USE OF PROCEEDS
None.
PART IV
ITEM 18. FINANCIAL STATEMENTS
We specifically incorporate by reference in response to this item the
auditors' reports, the consolidated financial statements and the notes to the
consolidated financial statements appearing on pages F-1 through F-29.
ITEM 19. FINANCIAL STATEMENTS AND EXHIBITS
(a) INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CONSOLIDATED FINANCIAL STATEMENTS OF PETROLEUM GEO-SERVICES
ASA AND SUBSIDIARIES
Report of Independent Accountants........................... F-1
Consolidated Statements of Operations for the years ended
December 31, 1999, 1998 and 1997.......................... F-2
Consolidated Balance Sheets as of December 31, 1999 and
1998...................................................... F-3
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997.......................... F-4
Consolidated Statements of Changes in Shareholders' Equity
for the years ended December 31, 1999, 1998 and 1997...... F-5
Notes to Consolidated Financial Statements.................. F-6
</TABLE>
(b) INDEX TO EXHIBITS
<TABLE>
<CAPTION>
NUMBER
------
<C> <S>
1.1 -- Articles of Association, as amended (English translation)
2.1 -- Indenture, dated as of April 1, 1998, between Petroleum
Geo-Services ASA and Chase Bank of Texas, National
Association, as trustee, in respect of senior debt
securities (incorporated by reference to exhibit 2.12 of
the Annual Report of Petroleum Geo-Services ASA on Form
20-F for the year ended December 31, 1997 (SEC File No.
1-14614))
2.2 -- First Supplemental Indenture, dated as of April 1, 1998,
between Petroleum Geo-Services ASA and Chase Bank of
Texas, National Association, as trustee, in respect of
6 5/8% Senior Notes due 2008 and 7 1/8% Senior Notes due
2028 (incorporated by reference to exhibit 2.13 of the
Annual Report of Petroleum Geo-Services ASA on Form 20-F
for the year ended December 31, 1997 (SEC File No.
1-14614))
</TABLE>
42
<PAGE> 43
<TABLE>
<CAPTION>
NUMBER
------
<C> <S>
2.3 -- Revolving Credit Agreement dated as of September 4, 1998
among Petroleum Geo-Services ASA, Chase Manhattan PLC, as
arranger, Chase Manhattan International Limited, as
agent, and the financial institutions listed therein
(incorporated by reference to exhibit 2.5 of the Annual
Report of Petroleum Geo-Services ASA on Form 20-F for the
year ended December 31, 1998 (SEC File No. 1-14614))
Petroleum Geo-Services ASA and its consolidated subsidiaries are party to several
debt instruments under which the total amount of securities authorized does not
exceed 10% of the total assets of Petroleum Geo-Services ASA and its subsidiaries on
a consolidated basis. Pursuant to paragraph A.2(iii) of the instructions to the
exhibits to Form 20-F, Petroleum Geo-Services ASA agrees to furnish a copy of such
instruments to the SEC upon request.
3 -- Upon request of the SEC, Petroleum Geo-Services ASA will
file as an exhibit a list or diagram of all its
subsidiaries
23.1 -- Consent of PricewaterhouseCoopers LLP
</TABLE>
43
<PAGE> 44
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act
of 1934, the registrant certifies that it meets all of the requirements for
filing on Form 20-F and has duly caused this annual report to be signed on its
behalf by the undersigned, thereunto duly authorized.
PETROLEUM GEO-SERVICES ASA
Date: June 16, 2000
By: /s/ WILLIAM E. HARLAN
----------------------------------
William E. Harlan
Vice President, Chief Accounting
Officer and Controller
44
<PAGE> 45
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
PETROLEUM GEO-SERVICES ASA
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of cash flows and of changes in
shareholders' equity present fairly, in all material respects, the financial
position of Petroleum Geo-Services ASA and its subsidiaries at December 31, 1999
and 1998, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1999, all expressed in United
States dollars, in conformity with accounting principles generally accepted in
the United States. 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 of these
statements in accordance with auditing standards generally accepted in the
United States which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 31, 2000
F-1
<PAGE> 46
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------------
1999 1998 1997
-------------- -------------- --------------
(IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
<S> <C> <C> <C>
Revenue............................................... $ 788,160 $ 761,762 $ 539,381
----------- ----------- -----------
Cost of sales......................................... 333,060 236,647 172,223
Depreciation and amortization......................... 238,576 273,799 191,693
Research and technology costs......................... 15,859 14,508 9,297
Selling, general and administrative costs............. 71,738 67,103 39,812
Unusual items......................................... 89,855 25,737 --
----------- ----------- -----------
Total operating expenses.................... 749,088 617,794 413,025
----------- ----------- -----------
Operating profit...................................... 39,072 143,968 126,356
Income (loss) from equity investments................. (4,935) 854 1,966
Financial expense, net................................ (95,969) (40,241) (24,665)
Other income, net..................................... 23,650 38,966 2,092
----------- ----------- -----------
Income (loss) before income taxes..................... (38,182) 143,547 105,749
Provision (benefit) for income taxes.................. (41,890) 31,950 28,165
----------- ----------- -----------
Income before extraordinary charge and cumulative
effect of accounting change......................... 3,708 111,597 77,584
Extraordinary charge, net of tax...................... -- -- (3,447)
Cumulative effect of accounting change, net of tax.... (19,977) -- --
----------- ----------- -----------
Net income (loss)........................... $ (16,269) $ 111,597 $ 74,137
=========== =========== ===========
Basic earnings per share before extraordinary charge
and cumulative effect of accounting change.......... $ 0.04 $ 1.36 $ 1.20
Extraordinary charge, net of tax...................... -- -- (0.05)
Cumulative effect of accounting change, net of tax.... (0.21) -- --
----------- ----------- -----------
Basic earnings (loss) per share....................... $ (0.17) $ 1.36 $ 1.15
=========== =========== ===========
Diluted earnings per share before extraordinary charge
and cumulative effect of accounting change.......... $ 0.04 $ 1.32 $ 1.15
Extraordinary charge, net of tax...................... -- -- (0.05)
Cumulative effect of accounting change, net of tax.... (0.21) -- --
----------- ----------- -----------
Diluted earnings (loss) per share..................... $ (0.17) $ 1.32 $ 1.10
=========== =========== ===========
Basic shares outstanding.............................. 94,767,967 82,260,652 64,519,503
=========== =========== ===========
Diluted shares outstanding............................ 95,840,199 84,794,836 67,358,004
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
<PAGE> 47
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998
----------- -----------
(IN THOUSANDS OF DOLLARS,
EXCEPT FOR SHARE DATA)
<S> <C> <C>
Cash and cash equivalents................................... $ 63,044 $ 53,273
Accounts receivable, net.................................... 240,634 247,694
Other current assets, net................................... 94,926 130,881
---------- ----------
Total current assets.............................. 398,604 431,848
Multi-client library, net................................... 816,423 553,415
Property and equipment, net................................. 2,429,848 1,948,635
Goodwill, net............................................... 264,354 271,952
Other long-term assets, net................................. 267,422 219,255
---------- ----------
Total assets...................................... $4,176,651 $3,425,105
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt and current portion of long-term debt
and capital lease obligations............................. $ 22,409 $ 157,413
Accounts payable............................................ 88,065 96,643
Accrued expenses............................................ 144,212 137,178
Income taxes payable........................................ 9,805 23,724
---------- ----------
Total current liabilities......................... 264,491 414,958
Long-term debt.............................................. 1,986,143 1,402,695
Long-term capital lease obligations......................... 12,387 18,975
Other long-term liabilities................................. 104,737 109,794
Deferred tax liabilities.................................... 79,852 81,532
---------- ----------
Total liabilities................................. 2,447,610 2,027,954
---------- ----------
Commitments and contingencies (Note 10)
Guaranteed preferred beneficial interest in PGS junior
subordinated debt securities (Note 9)..................... 139,164 --
Shareholders' equity
Common stock, par value NOK 5; authorized 133,788,087
shares; issued and outstanding 101,609,587 shares at
December 31, 1999 and 89,540,537 shares at December 31,
1998................................................... 70,126 62,312
Additional paid-in capital................................ 1,208,873 996,499
Retained earnings......................................... 327,385 343,654
Accumulated other comprehensive income.................... (16,507) (5,314)
---------- ----------
Total shareholders' equity........................ 1,589,877 1,397,151
---------- ----------
Total liabilities and shareholders' equity........ $4,176,651 $3,425,105
========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE> 48
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1999 1998 1997
----------- --------- ---------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)...................................... $ (16,269) $ 111,597 $ 74,137
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization charged to expense.... 238,576 273,799 191,693
Non-cash charges.................................... 83,805 22,700 --
Provision (benefit) for deferred income taxes....... (53,471) 4,917 19,979
Changes in current assets and current liabilities... (33,106) (138,843) (64,568)
(Gain) loss on sale of assets....................... 3,256 1,366 (361)
Other items......................................... (22,113) (880) 7,806
----------- --------- ---------
Net cash provided by operating activities...... 200,678 274,656 228,686
----------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in multi-client library..................... (338,718) (388,228) (203,267)
Capital expenditures................................... (667,869) (521,630) (468,872)
Cash acquired in purchase acquisition.................. -- 55,398 --
Other items, including net proceeds from UK leases..... 5,496 37,652 (19,423)
----------- --------- ---------
Net cash used in investing activities.......... (1,001,091) (816,808) (691,562)
----------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of long-term debt........... 195,712 891,506 378,078
Net proceeds from issuance of guaranteed preferred
beneficial interest in PGS junior subordinated debt
securities.......................................... 138,914 -- --
Net proceeds from issuance of common stock............. 220,024 7,940 241,957
Repayment of long-term debt............................ (29,924) (486,797) (144,707)
Net increase in revolving and short-term debt.......... 283,334 79,385 23,188
Principal payments under capital lease obligations..... (13,437) (24,380) (31,225)
Lease financing of owned property and equipment........ 15,512 -- 1,217
----------- --------- ---------
Net cash provided by financing activities...... 810,135 467,654 468,508
----------- --------- ---------
Effect of exchange rate changes in cash and cash
equivalents......................................... 49 280 (3,391)
Net increase (decrease) in cash and cash equivalents... 9,771 (74,218) 2,241
Cash and cash equivalents at beginning of year......... 53,273 127,491 125,250
----------- --------- ---------
Cash and cash equivalents at end of year....... $ 63,044 $ 53,273 $ 127,491
=========== ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE> 49
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL
----------------------- PAID-IN RETAINED
NUMBER PAR VALUE CAPITAL EARNINGS
----------- --------- ---------- --------
(IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
<S> <C> <C> <C> <C>
Balance at December 31,
1996...................... 63,261,768 $23,936 $ 314,262 $159,555
Comprehensive income:
Net income.............. 74,137
Other comprehensive
income (loss).........
Issuance of common stock,
including former Acadian
shares.................. 9,138,350 3,575 236,211
Exercise of stock
options................. 578,450 193 2,814
----------- ------- ---------- --------
Balance at December 31,
1997...................... 72,978,568 27,704 553,287 233,692
Comprehensive income:
Net income.............. 111,597
Other comprehensive
loss..................
Issuance of common
stock................... 16,084,969 6,288 468,655
Exercise of stock
options................. 477,000 287 2,590
Stock split............... 28,033 (28,033)
Distributions to former
Acadian shareholders.... (1,635)
----------- ------- ---------- --------
Balance at December 31,
1998...................... 89,540,537 62,312 996,499 343,654
Comprehensive income:
Net loss................ (16,269)
Other comprehensive
loss..................
Issuance of common
stock................... 11,159,500 7,232 205,674
Exercise of stock
options................. 909,550 582 6,700
----------- ------- ---------- --------
Balance at December 31,
1999...................... 101,609,587 $70,126 $1,208,873 $327,385
=========== ======= ========== ========
<CAPTION>
ACCUMULATED OTHER
COMPREHENSIVE INCOME
----------------------------
FOREIGN LONG-TERM
CURRENCY INTERCOMPANY TOTAL OTHER
TRANSLATION CURRENCY COMPREHENSIVE SHAREHOLDERS'
ADJUSTMENTS GAINS (LOSSES) INCOME EQUITY
----------- -------------- ------------- -------------
(IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
<S> <C> <C> <C> <C>
Balance at December 31,
1996...................... $15,610 $(13,518) $ 2,092 $ 499,845
Comprehensive income:
Net income.............. 74,137
Other comprehensive
income (loss)......... (6,950) 1,522 (5,428) (5,428)
Issuance of common stock,
including former Acadian
shares.................. 239,786
Exercise of stock
options................. 3,007
------- -------- -------- ----------
Balance at December 31,
1997...................... 8,660 (11,996) (3,336) 811,347
Comprehensive income:
Net income.............. 111,597
Other comprehensive
loss.................. (1,083) (895) (1,978) (1,978)
Issuance of common
stock................... 474,943
Exercise of stock
options................. 2,877
Stock split............... --
Distributions to former
Acadian shareholders.... (1,635)
------- -------- -------- ----------
Balance at December 31,
1998...................... 7,577 (12,891) (5,314) 1,397,151
Comprehensive income:
Net loss................ (16,269)
Other comprehensive
loss.................. (5,387) (5,806) (11,193) (11,193)
Issuance of common
stock................... 212,906
Exercise of stock
options................. 7,282
------- -------- -------- ----------
Balance at December 31,
1999...................... $ 2,190 $(18,697) $(16,507) $1,589,877
======= ======== ======== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE> 50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis Of Presentation. Petroleum Geo-Services ASA (the "Company") provides
geophysical services and production services. See further discussion of the
Company's services in Note 18.
The Company is a Norwegian limited liability company and has prepared its
consolidated financial statements in accordance with generally accepted
accounting principles ("GAAP") in the United States of America ("US"). The
Company's consolidated financial statements include all accounts of Petroleum
Geo-Services ASA and its wholly owned and majority-owned subsidiaries.
Investments in associated entities (companies and joint ventures) in which the
Company's ownership interests range from 20% to 50% and over which the Company
exercises significant influence in operating and financial policies are
accounted for under the equity method; other investments are accounted for at
cost. All significant intercompany accounts and transactions are eliminated in
consolidation. The Company did not have any significant transactions with
acquired companies in the periods prior to acquisition. The consolidated
financial statements for 1998 and 1997 give retroactive effect to the
acquisition of Acadian Geophysical Services, Inc. ("Acadian") under the pooling
of interests method of accounting (Note 2).
Certain reclassifications have been made to prior year amounts to conform
to the current year's presentation.
Foreign Currency Translation.
Although the Company's activities span the globe, its transactions are
primarily denominated in US dollars; therefore, the Company has adopted the US
dollar ("$") as its reporting currency. During 1997, the Company changed the
functional currency for its parent holding company and certain of its Norwegian
subsidiaries from the Norwegian kroner to the US dollar, to reflect the shift of
key financing, investing and operating transactions at these entities to US
dollars.
The financial statements of non-US subsidiaries using the US dollar as
their functional currency are translated as follows: non-monetary assets, share
par value and paid-in capital are translated at historical exchange rates;
revenue and expenses are translated at the average rates of exchange in effect
during the period, except for depreciation and amortization, which are
translated at historical exchange rates; and all other financial statement
accounts are translated at the rate of exchange in effect at period end.
Remeasurement adjustments are credited or charged directly to income, except for
adjustments relating to long-term intercompany borrowings, which are accumulated
as a separate component of shareholders' equity.
The financial statements of non-US subsidiaries using their local currency
as their functional currency are translated using the current rate method.
Assets and liabilities are translated at the rate of exchange in effect at
period end; share par value and paid-in capital are translated at historical
exchange rates; and revenue and expenses are translated at the average rates of
exchange in effect during the period. Translation adjustments are recorded as a
separate component of shareholders' equity.
The exchange rate between the Norwegian kroner and US dollar at December
31, 1999 and 1998 was 8.01 and 7.58, respectively. The Company recorded $4.1
million, $0.1 million and $4.4 million in net foreign exchange gains for 1999,
1998 and 1997, respectively.
Accounting Estimates.
The preparation of financial statements in conformity with US GAAP requires
management to make various estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities. In addition, such estimates and assumptions can have a material
effect on the amount of reported revenue and expenses during a particular
period. Actual amounts may differ from these estimates.
F-6
<PAGE> 51
In determining the amortization rates applied to surveys in the
multi-client library, management considers expected future sales and market
developments as well as past experience. These expectations include
consideration of geographic location, prospectivity, political risk, exploration
license periods and general economic conditions. Because of the inherent
difficulty in estimating future sales and market developments, it is reasonably
possible that amortization rates could deviate significantly from period to
period.
The modified units-of-production depreciation method used for the Company's
FPSO vessels is based on an estimate of the total barrels to be produced from
the fields where the vessels are operating. Because the actual number of barrels
may ultimately differ from these estimates, it is possible that depreciation
rates could deviate significantly over time.
Cash And Cash Equivalents.
Cash and cash equivalents are stated at cost plus accrued interest and
approximate fair value. Cash and cash equivalents include demand deposits and
all highly liquid financial instruments purchased with original maturities of
three months or less.
Receivables Credit Risk.
The Company extends credit to various companies in the oil and gas industry
worldwide, which may be affected by changes in economic or other external
conditions. At December 31, 1999 and 1998, accounts receivable (both current and
long-term) were primarily from multinational integrated oil companies and
independent oil and gas companies, including companies owned in whole or in part
by foreign governments. The Company manages its exposure to credit risk through
ongoing credit evaluations of its customers and has provided for potential
credit losses through an allowance for doubtful accounts. Management does not
believe that the Company is exposed to concentrations of credit risk that are
likely to have a material impact on the Company's financial position or results
of operations.
Multi-Client Library.
The multi-client library consists of finished and in-process seismic
surveys that are licensed on a non-exclusive basis. All costs directly or
indirectly incurred in acquiring, processing and otherwise completing seismic
surveys are capitalized into the multi-client library, including the applicable
portion of the Company's interest costs.
The multi-client library is stated at the lower of survey costs less
accumulated amortization or net realizable value (total estimated future sales
less selling expenses). Amortization of the capitalized survey costs is recorded
in proportion to revenue recognized to date for each survey as a percentage of
the total estimated revenue for that survey. Seismic surveys are reviewed for
impairment at each balance sheet date through a comparison of the undiscounted
cash flows expected from each survey to the carrying amount of each survey. Each
survey is also subject to minimum amortization that reduces its book value to
zero over a designated period of time, currently ranging from five to eight
years.
F-7
<PAGE> 52
Property And Equipment.
Property and equipment are stated at cost less accumulated depreciation.
Depreciation is calculated using a modified units-of-production method for FPSO
vessels and equipment and the straight-line method for all other property and
equipment, after allowing for residual values. Equipment that is temporarily
idled is depreciated at 20% of the normal rate, subject to an 18-month maximum
period. The estimated useful lives for the Company's property and equipment are
as follows:
<TABLE>
<CAPTION>
YEARS
-----
<S> <C>
Seismic vessels and FPSO vessels and equipment.............. 20-30
Seismic and operations computer equipment................... 3-20
Leasehold improvements -- seismic vessels................... 1-30
Buildings and related leasehold improvements................ 10-30
Fixtures, furniture and fittings............................ 3-5
</TABLE>
Expenditures for major property and equipment additions and improvements
are capitalized, while minor replacements, maintenance and repairs are charged
to expense. The Company capitalizes interest costs to major capital projects
that require a period of time to complete. When property and equipment are
retired or otherwise disposed of, the related cost and accumulated depreciation
are removed from the accounts, and any resulting gain or loss is included in the
results of operations.
Goodwill.
Goodwill is stated at cost less accumulated amortization. Goodwill
amortization is calculated on a straight-line basis over the estimated life,
with a maximum life of 40 years.
Other Long-Term Assets.
Other long-term assets consist of investments in associated entities,
long-term receivables, deferred tax assets, direct costs of software product
development, patents, royalties, licenses and deferred loan costs. Except for
investments in associated entities and deferred tax assets, other long-term
assets are stated at cost less accumulated amortization. Amortization is
calculated on a straight-line basis over the estimated useful lives of the
related assets, with a maximum life of 10 years.
Asset Recoverability.
The Company's management evaluates the recorded balances of its property
and equipment, goodwill and other long-term assets for impairment whenever
events or changes in circumstances indicate that the carrying amounts may not be
appropriate. This evaluation is based on a comparison of the expected
undiscounted cash flows associated with the assets to the carrying amounts of
the assets. Any impairment loss is recorded as the difference between the
assets' carrying amounts and fair values. Except as discussed in Note 21,
management believes that there have been no events or circumstances that warrant
revision to the remaining useful lives or that affect the recoverability of the
Company's assets.
UK Leases.
The Company periodically executes leasing arrangements in the United
Kingdom ("UK leases") relating to certain seismic and FPSO vessels and/or
equipment, whereby the Company sells the applicable assets to a UK financial
institution and leases the assets under a long-term charter at the end of which
the Company has an option to purchase the assets for a de minimis amount. The
Company uses a portion of the sales proceeds to legally defease the present
value of the future charter obligations with a third-party investment trustee.
These UK leases provide the financial institutions with the tax depreciation
rights to the assets and, therefore, the ability to utilize the related tax
benefits. Under its UK leases, the Company has indemnified the financial
institutions against certain future events that could reduce the expected tax
benefits to these institutions. These events include potential changes in UK tax
laws and interpretations,
F-8
<PAGE> 53
depreciation rates or interest rates. At the date that the Company executes any
UK lease, the Company treats the excess of the sales proceeds received over the
amount required to be deposited with the third-party trustee as a deferred gain,
due to the indemnification contingencies. The deferred gain is recognizable as
other income once the Company has determined that the possibility of the
indemnification contingencies' being realized is remote.
Derivative Financial Instruments.
Derivative financial instruments are used periodically by the Company in
the management of its interest and foreign currency exchange rate exposures. The
Company does not engage in derivative financial instrument transactions for
speculative purposes. The derivative instruments used are interest rate
contracts and foreign currency exchange contracts. The derivative contracts are
entered into with major international financial institutions utilizing
over-the-counter instruments. The likelihood of non-performance by the Company's
counterparties under these contracts is considered to be remote.
Interest Rate Contracts -- Amounts to be settled under interest rate hedge
contracts and interest rate swap contracts designated as hedges are recognized
over the life of the contracts as adjustments to interest expense of the
underlying debt. Gains and losses on termination of interest rate contracts or
through debt retirement are recognized as adjustments to interest expense.
Foreign Currency Exchange Contracts -- Gains and losses attributable to
forward foreign currency exchange contracts and option contracts, including tax
equalization contracts, which are designated as hedges are deferred and included
in the measurement of the related foreign currency transaction. Gains and losses
attributable to forward foreign exchange contracts and option contracts which
are not hedges are recognized in other income as they arise.
Revenue Recognition.
Revenue from the acquisition of non-cancelable exclusive seismic surveys
and from the pre-funded portion of non-exclusive seismic surveys is recognized
in accordance with the percentage-of-completion method of accounting, based upon
survey costs incurred to date as a percentage of total estimated survey costs.
Revenue from cancelable exclusive seismic surveys is recognized as data are
acquired and become chargeable to the customer.
Revenue from the licensing of finished non-exclusive seismic surveys and
software products is recognized when the Company obtains a non-cancelable
commitment from the customer.
Revenue from the Company's other geophysical services is recognized as the
services are performed.
Tariff revenue from the Company's floating production services is
recognized as production occurs, while day-rate revenue is recognized over the
passage of time. Production management services revenue is recognized as the
services are performed.
Income Taxes.
The Company provides for all current taxes payable and for deferred taxes
arising from temporary differences between the tax bases of assets and
liabilities and their reported amounts in the financial statements, based on
enacted tax rates and laws in effect for the years in which differences are
expected to reverse. Income tax benefits and liabilities arising from
tax-deductible share issue costs and long-term intercompany foreign currency
exchange gains and losses are recorded directly to shareholders' equity. Except
where required by law, Norwegian income taxes are not accrued for unremitted
earnings of international operations that have been, or are intended to be,
reinvested indefinitely.
New Accounting Standards.
Effective January 1, 1999, the Company adopted Statement of Position
("SOP") 98-5, "Reporting on the Costs of Start-up Activities." Accordingly, the
Company expensed as a cumulative effect of an
F-9
<PAGE> 54
accounting change all previously capitalized start-up costs. The $20.0 million
in expensed costs, net of income tax benefits of $8.1 million, included costs
related to the start-up of the PGS floating production business, the reservoir
monitoring business and the multi-component, vertical cable and land seismic
businesses, as well as costs related to the opening of various worldwide
offices. Subsequent to adoption, all start-up costs are expensed as incurred.
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative financial
instrument be recorded in the balance sheet as either an asset or a liability
measured at its fair value, with certain changes in fair value recognized
currently in earnings. In June 1999, the FASB amended SFAS No. 133, delaying the
Company's adoption date to January 1, 2001. The Company will adopt this standard
through a cumulative effect of an accounting change, but has not yet determined
the impact of adoption.
NOTE 2 -- ACQUISITIONS
On May 19, 1998, the Company consummated the acquisition of the FPSO
operations of Awilco ASA ("Awilco"). Consideration paid for the net assets
acquired consisted of approximately $428.0 million in equity issued (in the form
of 12,638,080 shares) to the former owners and the assumption of approximately
$440.0 million in liabilities. The transaction was treated as a purchase for
accounting purposes, with the assets acquired and the liabilities assumed
recorded at their fair values. Goodwill of $234.0 million recorded in the
acquisition is being amortized on the straight-line method over 40 years.
On August 31, 1998, the Company consummated the acquisition of Atlantic
Power Group ("Atlantic Power"), an oil and gas production management specialist.
Consideration paid for the net assets acquired consisted of approximately $38.4
million in equity issued (in the form of 3,248,309 shares) to the former owners
and the assumption of approximately $6.8 million in liabilities. The transaction
was treated as a purchase for accounting purposes, with the assets acquired and
the liabilities assumed recorded at their fair values. Goodwill of $31.6 million
recorded in the acquisition is being amortized on the straight-line method over
40 years.
The unaudited pro forma results of operations for the Company as if these
acquisitions had occurred as of January 1, 1997 are summarized as follows:
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
--------------------------
1998 1997
----------- -----------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C>
Revenue..................................................... $918,051 $744,018
Income before extraordinary charge.......................... 116,898 44,924
Net income.................................................. 116,898 41,477
Basic earnings per share:
Before extraordinary charge............................... $ 1.31 $ 0.56
After extraordinary charge................................ 1.31 0.52
Diluted earnings per share:
Before extraordinary charge............................... $ 1.27 $ 0.54
After extraordinary charge................................ 1.27 0.50
</TABLE>
On July 21, 1998, the Company acquired Acadian, a provider of 3D seismic
acquisition services in transition-zone and shallow-water areas. Consideration
for the acquisition consisted of 1,138,350 shares of the Company issued to the
former owners of Acadian in exchange for all of the outstanding shares of
Acadian. The acquisition was accounted for as a pooling of interests.
Accordingly, the financial statements have been prepared as if the Company and
Acadian were combined as of the inception date of Acadian operations, which was
January 22, 1997. All costs of the acquisition, approximately $3.0 million, were
F-10
<PAGE> 55
expensed. No adjustments of net assets or income were required to conform the
accounting practices of the Company and Acadian.
NOTE 3 -- ACCOUNTS RECEIVABLE
The Company has recorded allowances for doubtful accounts of $7.5 million
and $3.7 million at December 31, 1999 and 1998, respectively. Accounts
receivable include $121.2 million and $116.7 million of unbilled receivables at
December 31, 1999 and 1998, respectively; these receivables relate to revenue
that has been recognized under the percentage-of-completion method but is not
yet billable under the specific broker or customer agreements. Of these unbilled
receivables, $22.6 million and $27.6 million were long-term receivables at
December 31, 1999 and 1998, respectively.
NOTE 4 -- MULTI-CLIENT LIBRARY
The components of the multi-client library, net of accumulated
amortization, are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998
----------- -----------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C>
Multi-client seismic surveys, finished...................... $484,341 $198,850
Multi-client seismic surveys, work in progress.............. 332,082 354,565
-------- --------
Total............................................. $816,423 $553,415
======== ========
</TABLE>
Amortization expense was $137.5 million, $193.6 million and $135.7 million
for the years ended December 31, 1999, 1998 and 1997, respectively. Interest
capitalized into the multi-client library was $26.6 million, $14.6 million and
$6.9 million for the years ended December 31, 1999, 1998 and 1997, respectively.
NOTE 5 -- OTHER CURRENT ASSETS AND ACCRUED EXPENSES
Other current assets at December 31, 1999 include $26.7 million in prepaid
expenses; other current assets at December 31, 1998 include $28.2 million in
prepaid expenses, $24.1 million in consumables and supplies, and $33 million in
subsea equipment reimbursables related to the Ramform Banff. Accrued expenses at
December 31, 1999 include $18.9 million in deferred revenue, $18.5 million in
accrued interest expense, $17.3 million in accrued restructuring costs (Note 21)
and $34.2 million in accrued vessel operating costs; accrued expenses at
December 31, 1998 include $36.5 million in accrued vessel operating costs.
F-11
<PAGE> 56
NOTE 6 -- PROPERTY AND EQUIPMENT
The components of property and equipment are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1999 1998
----------- -----------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C>
FPSO vessels and equipment.................................. $1,590,506 $ 673,212
Seismic vessels, including leasehold improvements........... 488,734 346,114
Seismic and operations computer equipment................... 591,751 592,723
Buildings, including leasehold improvements, and other...... 95,824 57,661
Fixtures, furniture and fittings............................ 68,685 79,052
Construction in progress.................................... 4,563 510,735
---------- ----------
2,840,063 2,259,497
Accumulated depreciation.................................... (410,215) (310,862)
---------- ----------
Total............................................. $2,429,848 $1,948,635
========== ==========
</TABLE>
The gross cost of property and equipment includes $89.8 million and $128.6
million (primarily seismic and computer equipment) relating to capital leases
(Note 10) as of December 31, 1999 and 1998, respectively. Accumulated
depreciation of property and equipment includes $63.1 million and $76.9 million
relating to capital leases as of December 31, 1999 and 1998, respectively. Net
depreciation expense was $86.8 million, $65.6 million and $49.3 million for the
years ended December 31, 1999, 1998 and 1997, respectively. Interest capitalized
into property and equipment was $13.5 million, $29.3 million and $8.3 million
for the years ended December 31, 1999, 1998 and 1997, respectively. Property and
equipment balances at December 31, 1999 reflect the significant restructuring
activities undertaken by the Company in 1999 (Note 21).
NOTE 7 -- UK LEASES
The Company had $1.5 billion and $1.3 billion in property and equipment
under UK leases at December 31, 1999 and December 31, 1998, respectively.
In January and April 1999, the Company executed UK leases on the Ramform
Victory and the Ramform Vanguard (upon delivery of the seismic vessels). During
the respective quarters, the Company recognized the related UK lease gains, with
$9.4 million recorded in the first quarter and $9.7 million recorded in the
second quarter. During the fourth quarter of 1998, the Company recognized $32.5
million in UK lease gains related to UK leases executed in 1998 and 1996.
As of the date of the Awilco acquisition (Note 2), Awilco had $51.0 million
in indemnification contingencies recorded for a UK lease on the Petrojarl
Foinaven. During 1998, the Company was able to remove certain of the
indemnification contingencies and, as a result, reversed approximately $25.0
million of the deferred UK lease gain against goodwill recorded in the
acquisition.
F-12
<PAGE> 57
NOTE 8 -- DEBT
Long-Term Debt, Excluding Revolving Bank Credit Facilities.
Long-term debt, excluding revolving bank credit facilities, consists of the
following:
<TABLE>
<CAPTION>
YEAR-END YEAR-END
WEIGHTED WEIGHTED
AVERAGE DECEMBER 31, AVERAGE DECEMBER 31,
INTEREST RATE 1999 INTEREST RATE 1998
------------- ------------ ------------- ------------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Bank loans/public notes:
Secured.............................. 8.1% $ 146,825 8.0% $ 167,414
Unsecured............................ 7.1% 1,453,901 7.0% 1,255,324
Other loans:
Secured.............................. 7.5% 294 --% --
Unsecured............................ 7.0% 24 7.6% 8,884
---------- ----------
1,601,044 1,431,622
Current portion........................ (14,901) (28,927)
---------- ----------
Long-term portion............ $1,586,143 $1,402,695
========== ==========
</TABLE>
In July 1999, the Company entered into a $350.0 million unsecured bridge
facility in order to finance the acquisition of the Petrojarl Varg FPSO. The
Company then issued $200.0 million of senior unsecured notes for net proceeds of
$195.7 million. The net proceeds on these notes, together with the net proceeds
from the Company's ADS/share offering (Note 13), were used to repay the $350.0
million bank bridge loan facility as well as indebtedness outstanding under the
Company's revolving bank credit facility. The notes carry an interest rate of
8.2%, with interest payable semi-annually, and mature in July 2029. These notes
can be redeemed at the Company's option, in whole or in part, at any time,
subject to an early redemption premium.
In November 1998, the Company issued $250.0 million of senior unsecured
notes. The notes carry an interest rate of 6.3%, with interest payable
semi-annually, and mature in November 2003. These notes can be redeemed at the
Company's option, in whole or in part, at any time, subject to an early
redemption premium. The net proceeds from this issuance were used to repay
indebtedness outstanding under the Company's revolving bank credit facilities.
The notes were issued in a Rule 144A offering; in early 1999, they were
registered under an exchange offering with no change in terms from the initial
offering.
In April 1998, the Company issued $450.0 million and $200.0 million of
senior unsecured notes. The notes carry interest rates of 7.1% and 6.6%,
respectively, with interest payable semi-annually, and mature in March 2028 and
March 2008, respectively. These notes can be redeemed at the Company's option,
in whole or in part, at any time, subject to an early redemption premium. The
net proceeds from this issuance were primarily used to repay indebtedness and
certain other obligations that were assumed in the Awilco acquisition (Note 2)
as well as certain indebtedness outstanding under the Company's revolving bank
credit facilities.
In April 1997, the Company purchased all of the capital stock of a company
that indirectly owns the Ramform Explorer and the Ramform Challenger seismic
vessels. This company has outstanding registered mortgage notes, in an original
principal amount of $165.7 million, secured by the Ramform Explorer and the
Ramform Challenger. The notes carry an interest rate of 8.3%, with interest
payable semi-annually, and mature in June 2011. The notes are subject to
mandatory redemption through semi-annual sinking fund payments. The notes can be
redeemed at the holder's option on any sinking fund payment date on or after
June 2006, in whole but not in part, subject to an early redemption premium.
In March 1997, the Company issued $360.0 million of senior unsecured notes.
The notes carry an interest rate of 7.5%, with interest payable semi-annually,
and mature in March 2007. These notes can be redeemed at the Company's option,
in whole or in part, at any time, subject to an early redemption premium. The
net proceeds from this issuance were used, in part, to redeem $125.0 million of
private
F-13
<PAGE> 58
placement senior notes which were scheduled to begin amortizing in 2001. As a
result of the aforementioned redemption, the Company incurred an extraordinary
charge of $3.4 million, net of income tax benefits of $1.3 million, for the year
ended December 31, 1997 for the write-off of associated debt issuance costs and
the early redemption premium.
The Company's remaining secured loans have varying structures, with final
maturities ranging from 2000 to 2006. US dollar-denominated indebtedness, at
outstanding principal amounts of $5.0 million and $15.1 million at December 31,
1999 and 1998, respectively, carried year-end weighted average interest rates of
7.6% and 7.8%, respectively. Norwegian kroner-denominated indebtedness, at
outstanding US dollar principal amounts of $9.3 million and $13.1 million at
December 31, 1999 and 1998, respectively, carried year-end weighted average
interest rates of 5.3%.
Aggregate maturities of the Company's long-term debt as of December 31,
1999 are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------ (IN THOUSANDS OF DOLLARS)
<S> <C>
2000.................................................... $ 14,901
2001.................................................... 11,524
2002.................................................... 11,966
2003.................................................... 258,600
2004.................................................... 10,283
Thereafter.............................................. 1,293,770
----------
Total......................................... $1,601,044
==========
</TABLE>
Revolving Bank Credit Facilities.
In September 1998, the Company entered into an unsecured five-year $430.0
million revolving bank credit facility with a syndicate of international banks.
The facility bears interest at a LIBOR-based rate, plus a margin of either 0.35%
or 0.40% depending on the Company's level of indebtedness, and carries quarterly
commitment fees on any available revolver at 0.2%. The $430.0 million facility
replaced an unsecured $150.0 million revolving bank credit facility previously
used by the Company. In June 1999, the Company canceled its unsecured $35.0
million revolving bank credit facility, which was set to expire in August 1999.
During 1999, the Company borrowed an aggregate of $410.0 million under the
$430.0 million revolving bank credit facility, with average and maximum
borrowings outstanding of $299.2 million and $400.0 million, and weighted
average interest rates of 5.6% and 6.4% over the year and at December 31, 1999.
At December 31, 1999, the Company had $30.0 million of available committed
revolving bank credit facility.
The Company had $365.0 million of available committed revolving bank credit
facilities at December 31, 1998. During 1998, the Company borrowed an aggregate
of $515.0 million under its revolving bank credit facilities, with average and
maximum borrowings outstanding of $87.1 million and $165.0 million, and weighted
average interest rates of 5.8% and 6.3% over the year and at December 31, 1998.
Short-Term Debt.
Based on working capital requirements, the Company draws short-term debt
with various international banks. Short-term debt was $0.7 million and $17.3
million at December 31, 1999 and 1998, respectively. Average and maximum
short-term debt balances for the year ended December 31, 1999 were $30.7 million
and $120.8 million, and for 1998 were $37.1 million and $110.1 million. The
weighted average interest rates as of and for the year ended December 31, 1999
were 6.5% and 6.1%, and for 1998 were 7.0% and 6.7%.
Covenants.
In addition to customary representations and warranties, certain of the
Company's debt agreements and UK lease agreements (Note 7) include covenants
relating to the maintenance of minimum net worth
F-14
<PAGE> 59
levels, interest coverage ratios and debt leverage ratios. Additionally, certain
covenants restrict additional and subsidiary indebtedness, liens on assets, cash
dividends and sale/leaseback transactions. The Company was in compliance with
all such covenants at December 31, 1999.
Pledged Assets.
Seismic vessels and related equipment carrying a book value of $165.0
million and $218.5 million at December 31, 1999 and 1998, respectively, are
pledged as security on certain of the Company's indebtedness, as described
above.
Letters Of Credit And Guarantees.
The Company had aggregate outstanding letters of credit and related types
of guarantees, not reflected in the accompanying consolidated financial
statements, of $61.3 million and $38.6 million at December 31, 1999 and 1998,
respectively.
Subsequent Event.
In March 2000, the Company issued $225.0 million of senior unsecured notes.
The notes carry a floating interest rate equal to 0.7% over the three-month
LIBOR rate for US dollar deposits, subject to quarterly adjustment, with
interest payable quarterly. The notes mature in March 2002, but can be redeemed
at the Company's option, in whole or in part, on any interest payment date
beginning March 2001 at par plus accrued and unpaid interest. The net proceeds
from this issuance were primarily used to repay indebtedness outstanding under
the Company's revolving bank credit facility.
NOTE 9 -- TRUST PREFERRED SECURITIES
In June 1999, the Company entered into a transaction with PGS Trust I (the
"Trust"), a newly formed Delaware statutory business trust and wholly owned
finance subsidiary of the Company, whereby the Trust issued $4.4 million of
common securities to a U.S. subsidiary of the Company, issued $143.8 million of
trust preferred securities to the public and used the proceeds to purchase
$148.2 million of junior subordinated debt securities (the "junior debt
securities") from the Company. The Company used the $138.9 million in net
proceeds received to repay indebtedness outstanding under its revolving bank
credit facility.
The trust preferred securities consist of 5,750,000 securities which carry
a $25 per security liquidation value and mature on June 30, 2039. The trust
preferred securities represent undivided beneficial interests in the assets of
the Trust, but do not carry general voting rights. The trust preferred
securities carry a 9.625% distribution rate, payable quarterly. The Company's
junior debt securities bear an interest rate of 9.625%, payable quarterly, and
mature on June 30, 2039. Absent any event of default, the Company can defer
interest payments throughout the life of the junior debt securities for up to 20
consecutive quarterly periods, subject to the maturity date and limitations on
certain other transactions during any interest deferral period. In the event
that the Company defers its interest payments on the junior debt securities, the
Trust will defer its distributions on the trust preferred securities.
The Company may redeem the junior debt securities, in whole or in part, at
any time on or after June 2004. Prior to this time, the Company may redeem all
junior debt securities in the event of certain changes in tax or investment
company law. In the event that the Company redeems any of its junior debt
securities prior to maturity, the Trust must use the redemption proceeds to
redeem, on a pro rata basis, an equivalent amount of its trust preferred
securities and common securities.
The Company has guaranteed, on a subordinated basis, the trust preferred
securities' distributions to the extent that the Trust has cash available for
those distributions. In the event that the Trust does not have such cash,
holders of the trust preferred securities may directly sue the Company or seek
other remedies against the Company. When considered together, the declaration of
trust of the Trust, the junior debt securities, the indenture under which the
junior debt securities were issued and the Company's guarantee related to the
trust preferred securities constitute a full and unconditional guarantee by the
Company of the Trust's obligations under the trust preferred securities.
Since a U.S. subsidiary of the Company holds all of the Trust's common
securities, the Company consolidates the Trust. The Trust serves solely as a
finance subsidiary, having no independent assets or
F-15
<PAGE> 60
operations. The sole assets of the Trust are the junior debt securities issued
by the Company. The Trust held the full $148.2 million issue of the junior debt
securities at December 31, 1999. The $139.2 million carrying value of the trust
preferred securities at December 31, 1999 reflects issuance costs; the carrying
value will accrete to the $143.8 million redemption value by the first date at
which the Company can redeem the trust preferred securities. During 1999, the
Company recorded $7.7 million in financial expense for the minority interest in
income of subsidiaries due on the trust preferred securities.
NOTE 10 -- COMMITMENTS AND CONTINGENCIES
Leases.
The Company has operating lease commitments expiring at various dates
through 2014. The Company also has capital lease commitments for seismic vessels
and equipment expiring at various dates through 2004. Future minimum payments
related to non-cancelable operating and capital leases, with lease terms in
excess of one year, existing at December 31, 1999 are as follows:
<TABLE>
<CAPTION>
OPERATING CAPITAL
DECEMBER 31, LEASES LEASES
------------ ------------ ----------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C>
2000........................................................ $124,282 $ 8,007
2001........................................................ 98,860 6,509
2002........................................................ 74,362 4,542
2003........................................................ 37,132 1,970
2004........................................................ 14,931 247
Thereafter.................................................. 44,310 --
-------- -------
Total............................................. 393,877 21,275
========
Imputed interest.......................................... (2,045)
-------
Net present value........................................... 19,230
Current portion........................................... (6,843)
-------
Long-term portion................................. $12,387
=======
</TABLE>
The future minimum payments under the Company's operating leases relate to
the Company's operations as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------
(IN THOUSANDS OF DOLLARS)
<S> <C>
Seismic and support vessels................................ $ 92,068
FPSO shuttle tankers....................................... 121,018
Operations computer equipment.............................. 66,861
Buildings.................................................. 93,896
Fixtures, furniture and fittings........................... 20,034
--------
Total............................................ $393,877
========
</TABLE>
Rental expense for operating leases, including leases with terms of less
than one year, was $133.3 million, $141.4 million and $74.9 million for the
years ended December 31, 1999, 1998 and 1997, respectively.
Other.
The Company has contingent liabilities resulting from litigation, other
claims and commitments incidental to the ordinary course of business. Management
believes that the probable resolution of such contingencies will not materially
affect the financial position, results of operations or cash flows of the
Company.
F-16
<PAGE> 61
NOTE 11 -- INCOME TAXES
The provision (benefit) for income taxes consists of the following:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1999 1998 1997
-------- ------- -------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Current taxes:
Norwegian............................................ $ -- $15,050 $ 879
Foreign.............................................. 3,492 11,983 7,307
Deferred taxes:
Norwegian............................................ (23,546) 9,025 14,561
Foreign.............................................. (29,925) (4,108) 4,118
-------- ------- -------
Total........................................ $(49,979) $31,950 $26,865
======== ======= =======
</TABLE>
The benefit for the year ended December 31, 1999 includes $15.3 million
related to the resolution of certain tax issues.
The provision (benefit) for income taxes differs from the amounts computed
when applying the Norwegian statutory tax rate to income (loss) before income
taxes (inclusive of gross extraordinary charge and cumulative effect of
accounting change) as a result of the following:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Income (loss) before income taxes:
Norwegian.......................................... $(19,693) $ 35,472 $ 60,084
Foreign............................................ (46,554) 108,075 40,918
-------- -------- --------
Total...................................... (66,247) 143,547 101,002
Norwegian statutory rate............................. 28% 28% 28%
-------- -------- --------
Provision (benefit) for income taxes at the statutory
rate............................................... (18,549) 40,193 28,281
Increase (reduction) in income taxes from:
Different income taxes in foreign jurisdictions.... (34,503) (7,774) (1,617)
Prior year tax assessment.......................... -- -- (150)
Permanent items.................................... 3,907 -- --
Other.............................................. (834) (469) 351
-------- -------- --------
Provision (benefit) for income taxes....... $(49,979) $ 31,950 $ 26,865
======== ======== ========
</TABLE>
F-17
<PAGE> 62
The temporary differences which generate the Company's deferred tax assets
and liabilities are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1999 1998
-------- -------
(IN THOUSANDS OF
DOLLARS)
<S> <C> <C>
Property and equipment and long-term assets................. $ 65,987 $22,824
Tax losses carried forward.................................. (58,714) (7,213)
Deferred gains.............................................. (702) (1,399)
Tax and book revenue and cost of sales...................... 13,865 58,708
Tax credits................................................. (3,986) (2,942)
Other temporary differences................................. (837) (4,288)
-------- -------
Total............................................. 15,613 65,690
-------- -------
Deferred tax liability -- Norwegian......................... 34,809 52,572
Deferred tax (asset) liability -- Foreign................... (19,196) 13,118
-------- -------
Total............................................. $ 15,613 $65,690
======== =======
</TABLE>
Norwegian tax losses of $117.5 million expire at various dates beginning in
2003. Tax losses in the UK, Singapore and Australia totaling $31.6 million carry
forward indefinitely. US tax losses of $58.8 million expire in 2019. US minimum
tax credits of $4.0 million carry forward indefinitely.
Unremitted earnings of certain international operations included in
retained earnings total $115.3 million at December 31, 1999. It is the Company's
current policy that these earnings, which reflect full provision for
non-Norwegian income taxes, have no additional provision for Norwegian taxes, as
these earnings are expected to be reinvested indefinitely.
The tax effect of deductible share issue costs, which have been credited
directly to shareholders' equity, was approximately $0.7 million, $0.7 million
and $3.4 million for the years ended December 31, 1999, 1998 and 1997,
respectively.
NOTE 12 -- EARNINGS PER SHARE
Basic earnings per share and diluted earnings per share for 1999 were
equal. The difference between the Company's 1998 and 1997 basic earnings per
share and diluted earnings per share calculations is reconciled as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
-------------------------------------
INCOME WEIGHTED
AVAILABLE TO AVERAGE PER SHARE
SHAREHOLDERS SHARES AMOUNT
------------ ---------- ---------
(IN THOUSANDS OF DOLLARS, EXCEPT
FOR SHARE DATA)
<S> <C> <C> <C>
Basic earnings per share............................ $111,597 82,260,652 $1.36
Share equivalents -- options........................ 2,534,184
----------
Diluted earnings per share.......................... $111,597 84,794,836 $1.32
======== ========== =====
</TABLE>
F-18
<PAGE> 63
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
-------------------------------------
INCOME WEIGHTED
AVAILABLE TO AVERAGE PER SHARE
SHAREHOLDERS SHARES AMOUNT
------------ ---------- ---------
(IN THOUSANDS OF DOLLARS, EXCEPT
FOR SHARE DATA)
<S> <C> <C> <C>
Basic earnings per share before extraordinary
charge............................................ $ 77,584 64,519,503 $1.20
Share equivalents -- options........................ 2,838,501
----------
Diluted earnings per share before extraordinary
charge............................................ $ 77,584 67,358,004 $1.15
======== ========== =====
Basic earnings per share after extraordinary
charge............................................ $ 74,137 64,519,503 $1.15
Share equivalents -- options........................ 2,838,501
----------
Diluted earnings per share after extraordinary
charge............................................ $ 74,137 67,358,004 $1.10
======== ========== =====
</TABLE>
Certain options that would have been anti-dilutive to 1998 and 1997
earnings per share have been excluded from share equivalents in the applicable
quarters.
NOTE 13 -- SHAREHOLDERS' EQUITY
The retained earnings of the Company, together with additional paid-in
capital, constitute the restricted portion of shareholders' equity and are only
distributable subject to shareholder approval. Additionally, the terms of
certain of the Company's debt agreements restrict dividend payments. Dividends,
if declared, are payable in Norwegian kroner. There is no unrestricted
shareholders' equity as of December 31, 1999.
In July and early August 1999, the Company issued an aggregate of
11,159,500 shares and ADSs in an international public offering. Net proceeds of
$214.1 million were used, together with the net proceeds from $200.0 million in
senior notes, to repay the bank bridge loan facility drawn to finance the
Petrojarl Varg acquisition as well as to repay indebtedness outstanding under
the Company's revolving bank credit facility (Note 8).
In June 1998, the Company effected a stock split; all share information has
been restated to reflect this stock split. Concurrent with the stock split, the
par value of the common stock was adjusted to an equivalent nominal value of NOK
5 per share by a transfer from additional paid-in capital.
NOTE 14 -- SHARE-BASED COMPENSATION
At December 31, 1999, the Company had share-based compensation plans for
key employees and directors. The employee and director plans authorize the
Company to award options to purchase shares prior to the years 2002 and 2000,
respectively. As of December 31, 1999, options to purchase 8,993,000 and 395,000
shares, respectively, remain under these authorizations, including outstanding
options. Options granted from the plans' inceptions to December 31, 1999 totaled
12,656,404 and 576,800 shares, respectively, some of which have expired or were
no longer outstanding at December 31, 1999.
Under the plans, the exercise price of each award equals the market price
of the Company's shares on the date of grant. The vesting period for the granted
options ranges from approximately one and one-half years to approximately three
and one-half years, provided that the recipient is still employed by the Company
on the vesting date. Once vested, the recipient generally has two years within
which to exercise the options. Certain option awards are exercisable only on a
specific date. The exercise prices for options granted and outstanding at
December 31, 1999 under both the employee and director option plans range from
NOK75.0 to NOK99.0 for 2,308,000 options and from NOK111.0 to NOK229.5 for
5,383,204 options, with weighted average exercise prices of NOK93 and NOK141 for
these respective ranges. The weighted average remaining contractual lives of
outstanding options approximate 13 months and 35 months, respectively, for the
option ranges described above.
F-19
<PAGE> 64
Awards made under the plans become immediately exercisable upon the
occurrence of a change in control of the Company, generally defined to include
certain changes in the board of directors, the acquisition of a certain
percentage of outstanding shares, certain merger transactions (none of the
acquisitions completed by the Company in 1998 constituted a change in control)
and certain dispositions of all or substantially all of the assets of the
Company.
The Company applies Accounting Principles Board Opinion 25 in accounting
for its share-based compensation plans and has adopted the disclosure-only
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation."
Accordingly, no compensation cost has been recognized under these plans. Had the
compensation cost for the Company's share-based compensation plans been
determined based on the fair values of the options awarded at the grant dates,
consistent with the provisions of SFAS No. 123, the Company's net income (loss)
and earnings (loss) per share would have been reduced to the pro forma amounts
indicated below:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1999 1998 1997
----------- ----------- ----------
(IN THOUSANDS OF DOLLARS, EXCEPT FOR
SHARE DATA)
<S> <C> <C> <C>
Net income (loss):
As reported......................................... $(16,269) $111,597 $74,137
Pro forma........................................... (29,849) 97,829 64,787
Basic earnings (loss) per share:
As reported......................................... $ (0.17) $ 1.36 $ 1.15
Pro forma........................................... (0.31) 1.19 1.00
Diluted earnings (loss) per share:
As reported......................................... $ (0.17) $ 1.32 $ 1.10
Pro forma........................................... (0.31) 1.15 0.96
</TABLE>
The fair value of each option award on the grant date is estimated using
the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 1999, 1998 and 1997, respectively: expected
volatility of 52%, 48% and 47%; risk-free interest rates of 5.8%, 5.1% and 6.3%;
and expected lives of 3.4, 3.5 and 3.9 years. (Dividend yield is zero for all
plan grants.)
The effects of applying the fair market value method of accounting in the
above pro forma disclosure may not be indicative of future amounts since
additional awards in future years are anticipated.
A summary of the status of the Company's share-based compensation plans as
of December 31, 1999, 1998 and 1997, and changes during the years then ended, is
summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------------------
1999 1998 1997
------------------ ------------------ ------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------- -------- ------- -------- ------- --------
(IN THOUSANDS OF OPTIONS)
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year..................... 8,388.0 NOK120 7,060.6 NOK119 4,336.0 NOK 80
Granted.............................................. 335.8 NOK130 2,117.4 NOK123 3,341.0 NOK157
Exercised............................................ (909.6) NOK 68 (477.0) NOK 70 (578.4) NOK 56
Forfeited............................................ (123.0) NOK126 (313.0) NOK172 (38.0) NOK 89
------- ------ ------- ------ ------- ------
Outstanding at end of year........................... 7,691.2 NOK127 8,388.0 NOK120 7,060.6 NOK119
======= ====== ======= ====== ======= ======
Weighted average fair value of options granted during
year............................................... NOK 56 NOK 48 NOK 68
====== ====== ======
</TABLE>
As of December 31, 1999, 2,308,000 of the outstanding options were vested
with a weighted average exercise price of NOK93. Exercisable options at December
31, 1998 and 1997 were 1,789,550 options at a weighted average exercise price of
NOK78 and 156,000 options at a weighted average exercise price of NOK60,
respectively.
F-20
<PAGE> 65
NOTE 15 -- DERIVATIVE FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Notional Amounts And Credit Exposure Of Derivative Financial Instruments.
The notional amounts of the derivative financial instruments summarized
below do not reflect the values exchanged by the parties and, thus, are not a
measure of the Company's exposure. The amounts ultimately exchanged are
calculated on the basis of the notional amounts and the other terms of the
respective derivative financial instruments.
Interest Rate Risk Management.
The Company periodically uses interest rate hedge contracts and interest
rate swap contracts to effectively convert variable rate obligations to fixed
rate obligations in order to reduce the impact of interest rate changes on
future income. The Company did not engage in any interest rate hedge contracts
during 1999. During 1998, prior to the issuance of $650.0 million in unsecured
senior notes (Note 8), the Company entered into an interest rate hedge contract
for a notional amount of $50.0 million which effectively locked into a range the
interest rate risk on the yet-to-be issued notes. This contract expired during
May 1998.
Foreign Currency Exchange Risk Management.
The Company periodically enters into forward exchange contracts and option
contracts to hedge against foreign currency exchange risks associated with
certain firm commitments and transactions related to property and equipment. The
Company is most sensitive to changes in the Norwegian kroner to US dollar
exchange rates. There were no such foreign currency exchange contracts
outstanding at December 31, 1999. At December 31, 1998, the Company had
approximately $121.0 million of forward foreign currency exchange contracts
outstanding as hedges on its construction commitments for the Ramform Victory
and Ramform Vanguard seismic vessels. These vessels were delivered during the
first quarter of 1999, and the hedge contracts expired in the same period. No
new contracts were entered into during 1999.
During 1998, the Company entered into forward foreign currency exchange
contracts known as tax equalization swaps ("TES") related to its $360.0 million
of senior unsecured notes and its mortgage notes (Note 8). During 1999, the
Company entered into additional TES contracts related to its remaining $1.1
billion in unsecured senior notes (Note 8) and its trust preferred securities
(Note 9). These contracts effectively hedge the risk of unrealized exchange rate
fluctuations between the Norwegian kroner and the US dollar related to the
Company's US dollar-denominated debt and trust preferred securities, where such
foreign currency exchange gains and losses are taxable and deductible,
respectively, in each period on a mark-to-market basis for Norwegian statutory
tax purposes. The contracts' aggregate notional values at December 31, 1999 and
1998 were $682.8 million and $190.0 million, respectively. The TES mature at
various dates through December 2003 and provide for interim settlements between
the Company and the counterparty each December 30. At December 31, 1999, the
Company's interim settlement position was an $8.4 million liability to be paid
during 2000.
F-21
<PAGE> 66
Fair Values Of Financial Instruments.
The carrying amounts of cash and cash equivalents, accounts receivable,
other current assets, accounts payable and accrued expenses and other current
liabilities approximate their respective fair values because of the short
maturities of those instruments. The carrying amounts and the estimated fair
values of the Company's other financial instruments are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------
1999 1998
------------------------ ------------------------
CARRYING CARRYING
AMOUNTS FAIR VALUES AMOUNTS FAIR VALUES
---------- ----------- ---------- -----------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Long-term debt, including current
portion............................ $2,001,044 $1,915,521 $1,431,622 $1,426,380
Trust preferred securities........... 139,164 132,969 -- --
Foreign currency exchange
contracts.......................... -- 8,364 -- 3,013
</TABLE>
The following methods and assumptions were used to estimate the fair values
of each class of financial instrument:
Long-term Debt and Trust Preferred Securities -- The carrying amounts of
the Company's variable rate long-term debt instruments approximate their fair
values. The fair values of the Company's other long-term debt instruments and
trust preferred securities are estimated using quotes obtained from dealers in
such financial instruments.
Foreign Currency Exchange Contracts -- The fair values of the Company's
foreign currency exchange contracts, except for its tax equalization contracts,
are estimated based on quotes obtained from brokers and dealers in such
financial instruments. The fair values of the Company's tax equalization
contracts are estimated based on the periodic settlement quotes obtained from
the financial instruments' counterparty.
NOTE 16 -- RETIREMENT PLANS
The Company sponsors defined benefit pension plans for substantially all of
its Norwegian and for certain UK employees, with eligibility determined by
certain period-of-service requirements. These plans are funded through
contributions to insurance companies that assume all liabilities for benefit
payments. It is the Company's practice to fund amounts to these defined benefit
plans which are sufficient to meet the applicable statutory requirements.
F-22
<PAGE> 67
Reconciliations of the plans' aggregate projected benefit obligations and
fair values of assets are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1999 1998
------- -------
(IN THOUSANDS OF
DOLLARS)
<S> <C> <C>
Change in projected benefit obligations:
Projected benefit obligations at beginning of year........ $25,454 $14,616
Service cost.............................................. 6,602 4,875
Interest cost............................................. 1,674 1,245
Employee contributions.................................... 1,066 889
Obligations assumed in Awilco acquisition (Note 2)........ -- 2,435
Amendments................................................ 217 932
Actuarial loss, net....................................... 847 1,451
Benefits paid............................................. (424) (328)
Exchange rate effects..................................... (1,549) (661)
------- -------
Projected benefit obligations at end of year.............. $33,887 $25,454
======= =======
Change in plan assets:
Fair value of plan assets at beginning of year............ $18,249 $11,149
Return on plan assets..................................... 2,453 424
Employer contributions.................................... 4,799 4,353
Employee contributions.................................... 1,066 889
Assets assumed in Awilco acquisition (Note 2)............. -- 2,102
Amendments................................................ 94 154
Benefits paid............................................. (424) (328)
Exchange rate effects..................................... (1,088) (494)
------- -------
Fair value of plan assets at end of year.................. $25,149 $18,249
======= =======
</TABLE>
Plans with accumulated benefit obligations in excess of assets had
aggregate accumulated benefit obligations of $3.1 million and $2.5 million and
aggregate assets of $2.1 million and $2.2 million at December 31, 1999 and 1998,
respectively.
The aggregate funded status of the plans and amounts recognized in the
Company's balance sheets are summarized as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1999 1998
------- -------
(IN THOUSANDS OF
DOLLARS)
<S> <C> <C>
Funded status............................................... $(8,738) $(7,206)
Unrecognized actuarial loss................................. 4,545 5,105
Unrecognized prior service cost............................. 30 34
Unrecognized transition obligation.......................... 181 125
------- -------
Net amount recognized as accrued pension cost............... $(3,982) $(1,942)
======= =======
</TABLE>
The projected benefit obligations have been calculated using the projected
unit credit method. The discount rate used was 7%, the expected return on plan
assets was 8%, and the rate of compensation was estimated at 5% for each of the
three years in the period ended December 31, 1999.
F-23
<PAGE> 68
The aggregate net periodic pension cost for the Company's defined benefit
pension plans is summarized as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1999 1998 1997
------- ------- ------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Components of net periodic pension cost:
Service cost......................................... $ 6,602 $ 4,875 $3,709
Interest cost........................................ 1,674 1,245 788
Expected return on plan assets....................... (1,547) (1,245) (806)
Amortization of actuarial loss....................... 176 78 112
Amortization of prior service cost................... 3 3 3
Amortization of transition obligation................ 17 12 11
------- ------- ------
Net periodic pension cost............................ $ 6,925 $ 4,968 $3,817
======= ======= ======
</TABLE>
Substantially all employees not eligible for coverage under the defined
benefit plans are eligible to participate in pension plans in accordance with
local industrial, tax and social regulations. All of these plans are considered
defined contribution plans. Under the Company's US defined contribution plan,
essentially all US employees are eligible to participate upon completion of
certain period-of-service requirements. The plan allows eligible employees to
contribute up to 15% of compensation, subject to IRS and plan limitations, on a
pre-tax basis. Employee pre-tax contributions are matched by the Company up to
6% of compensation, with a 1999 employee contribution cap of $10,000. All
contributions vest as made. The annual employer matching contribution recognized
by the Company related to the plan was $0.7 million, $1.7 million and $1.1
million for 1999, 1998 and 1997, respectively. Contributions to the plan by
employees for these periods were $2.3 million, $4.0 million and $2.5 million,
respectively. Aggregate 1999 employer and employee contributions under the
Company's other plans totaled $5.9 million and $2.5 million, respectively;
contributions for prior years were not significant.
NOTE 17 -- RELATED PARTY TRANSACTIONS
At December 31, 1999, 1998 and 1997, the Company held 50% of the shares in
K/S Geo Explorer and had chartered a vessel from the company during these years.
The Company also held 50% of the shares in Walther Herwig AS and chartered three
vessels from this company in 1999 and 1998 and two vessels in 1997. Total
charter hire recognized by the Company for 1999, 1998 and 1997 on these vessels
was $13.9 million, $13.3 million and $8.8 million, respectively. Remaining lease
commitments to these investees are reflected in the Company's consolidated lease
commitments (Note 10). On January 1, 1997, a vessel held by Atlantic Explorer
Ltd., a 50% investee of the Company at that date, was purchased by the Company
for $19.7 million; this company, which no longer held significant assets nor had
significant operations, was liquidated in 1998.
At December 31, 1999, 1998 and 1997, the Company held 50% of the shares in
Calibre Seismic Company ("CSC"), one of the companies through which the Company
markets its seismic data. The Company had $15.2 million in investment in CSC at
both December 31, 1999 and 1998, representing Company-funded costs of seismic
data acquisition projects performed for CSC from 1991 to 1995.
NOTE 18 -- SEGMENT AND GEOGRAPHIC INFORMATION
The Company's services are provided by various separately managed business
units. These business units have been aggregated into two reportable segments,
geophysical services and production services, based on shared economic
characteristics and similar long-term performance. The Company believes that the
business units within each reportable segment are strategically and/or
operationally interrelated and provide similar services to the same customer
base. The Company's chief operating officer regularly reviews the operating
results of these two reportable segments in resource allocation decisions and
F-24
<PAGE> 69
performance assessment. The geophysical services segment primarily acquires,
processes, manages and markets 3D, 4D and multi-component marine and onshore
seismic data; provides 4D and multi-component reservoir interpretation,
characterization and monitoring services; and provides data management services
and software. The production services segment owns and/or operates FPSOs and
other offshore production facilities and provides production management services
for oil and gas companies. The principal markets for the Company's production
services segment are the UK and Norway, while the geophysical services segment
serves a worldwide market. Customers for both segments are primarily composed of
major multi-national, independent and national or state-owned oil companies. The
accounting policies for the segments are the same as those described in Note 1.
The Company's corporate overhead has been allocated to the segments based on
percentage of revenue. Affiliated sales are made at prices that approximate
market value. Prior period segment information has been restated to conform to
organizational changes which re-aligned 1999 segment composition.
Information by segment is summarized as follows:
<TABLE>
<CAPTION>
ELIMINATION
OF
GEOPHYSICAL PRODUCTION AFFILIATED
YEARS ENDED DECEMBER 31, SERVICES SERVICES SALES TOTAL
------------------------ ----------- ---------- ----------- -------------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Revenue, unaffiliated companies:
1999......................................... $ 419,854 $ 368,306 $ -- $ 788,160
1998......................................... 622,232 139,530 -- 761,762
1997......................................... 539,381 -- -- 539,381
Revenue, includes affiliates:
1999......................................... $ 426,363 $ 369,166 $ (7,369) $ 788,160
1998......................................... 639,134 139,559 (16,931) 761,762
1997......................................... 541,913 451 (2,983) 539,381
Operating profit:
1999......................................... $ (23,396) $ 62,468 $ -- $ 39,072
1998......................................... 119,723 24,245 -- 143,968
1997......................................... 129,367 (3,011) -- 126,356
Assets:
1999......................................... $2,220,271 $1,956,380 $ -- $4,176,651
1998......................................... 1,847,534 1,577,571 -- 3,425,105
Depreciation and amortization:
1999......................................... $ 189,335 $ 49,241 $ -- $ 238,576
1998......................................... 254,027 19,772 -- 273,799
1997......................................... 191,022 671 -- 191,693
Unusual items:
1999......................................... $ 82,855 $ 7,000 $ 89,855
1998......................................... 18,397 7,340 25,737
1997......................................... -- -- --
Interest expense, net:
1999......................................... $ 40,622 $ 47,636 $ -- $ 88,258
1998......................................... 28,670 11,571 -- 40,241
1997......................................... 24,665 -- -- 24,665
Additions to long-lived tangible assets:
1999......................................... $ 554,972 $ 451,615 $ -- $1,006,587
1998......................................... 615,502 294,356 -- 909,858
1997......................................... 457,104 215,035 -- 672,139
Investment in equity method investees:
1999......................................... $ 98,815 $ 10,658 $ -- $ 109,473
1998......................................... 83,022 8,628 $ -- 91,650
</TABLE>
F-25
<PAGE> 70
Since the Company provides services to the oil and gas industry worldwide,
a substantial portion of the Company's property and equipment is mobile, and the
respective locations at the end of the period (as listed in the table below,
together with multi-client library) are not necessarily indicative of the
earnings of the related property and equipment during the period. The geographic
classification of income statement amounts listed below is based upon location
of performance or, in the case of multi-client seismic data sales, the area
where the survey was physically located.
Information by geographic region is summarized as follows:
<TABLE>
<CAPTION>
ELIMINATION
OF
AFFILIATED
YEARS ENDED DECEMBER 31, AMERICAS UK NORWAY ASIA/PACIFIC AFRICA OTHER SALES TOTAL
------------------------ -------- ---------- -------- ------------ -------- ------- ----------- ----------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenue, unaffiliated
companies:
1999.................. $152,088 $ 381,452 $118,788 $ 69,718 $ 61,535 $ 4,579 -- $ 788,160
1998.................. 251,157 232,092 84,908 123,726 42,581 27,298 -- 761,762
1997.................. 208,983 119,295 47,617 88,915 37,711 36,860 -- 539,381
Revenue, includes
affiliates:
1999.................. $168,237 $ 389,407 $138,081 $ 70,942 $ 61,535 $ 8,670 $(48,712) $ 788,160
1998.................. 262,066 243,843 89,064 125,556 42,581 46,022 (47,370) 761,762
1997.................. 211,416 123,378 50,309 90,639 42,702 40,430 (19,493) 539,381
Operating profit:
1999.................. $(33,707) $ 96,098 $ 2,843 $(30,053) $ 4,549 $ (658) -- $ 39,072
1998.................. 25,917 83,705 1,978 26,033 6,881 (546) -- 143,968
1997.................. 56,015 31,247 (1,438) 18,765 9,508 12,259 -- 126,356
Long-lived tangible
assets:
1999.................. $479,725 $2,279,954 $220,205 $120,472 $110,751 $35,164 -- $3,246,271
1998.................. 450,384 1,785,097 157,737 67,236 15,689 25,907 -- 2,502,050
Depreciation and
amortization:
1999.................. $68,530 $ 93,579 $ 30,489 $ 26,331 $ 17,552 $ 2,095 -- $ 238,576
1998.................. 122,282 83,757 17,086 36,576 6,952 7,146 -- 273,799
1997.................. 85,573 40,301 16,724 24,322 11,829 12,944 -- 191,693
</TABLE>
Export sales from Norway to unaffiliated customers did not exceed 10% of
gross revenue for the years ended December 31, 1999, 1998 and 1997.
For the year ended December 31, 1999, the Company's largest customer
accounted for approximately 16% of the Company's revenue, all of which was
production services revenue. For the years ended December 31, 1998 and 1997, no
single customer accounted for more than 10% of the Company's revenue.
F-26
<PAGE> 71
NOTE 19 -- SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the year includes payments for:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Interest, net of capitalized interest................... $83,957 $45,054 $23,643
Income taxes............................................ 7,790 3,084 9,179
</TABLE>
The Company entered into capital lease agreements for new equipment
aggregating $3.5 million, $13.3 million, and $17.7 million in 1999, 1998 and
1997, respectively.
During 1997, Acadian (Note 2) financed the purchase of seismic equipment
through $22.3 million in aggregate secured debt to the supplier. The Company
retired the supplier debt in July 1998, upon consummation of the Acadian
acquisition.
NOTE 20 -- FINANCIAL EXPENSE, NET
Financial expense, net, includes the following:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Interest income...................................... $ 4,494 $ 7,979 $ 8,217
Interest expense..................................... (92,752) (48,220) (32,882)
Minority interest on trust preferred securities
(Note 9)........................................... (7,711) -- --
-------- -------- --------
Financial expense, net.......................... $(95,969) $(40,241) $(24,665)
======== ======== ========
</TABLE>
NOTE 21 -- UNUSUAL ITEMS
During 1999, the Company experienced a significant decrease in the demand
for its geophysical services due to the low price of oil during 1998 and the
first half of 1999. As a result of these reduced activity levels, the Company
implemented certain restructuring efforts and recorded charges during the first
and third quarters related to these efforts as summarized below:
<TABLE>
<CAPTION>
ACCRUED
AMOUNTS BALANCE AT
PAID IN DECEMBER 31,
TOTAL CHARGE 1999 1999
------------ ------- ------------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Cash charges:
Severance for approximately 500 employees................. $12,685 $ 6,063 $ 6,622
Lease termination, derigging and other obligations........ 38,734 28,036 10,698
------- ------- -------
Cash charges........................................... 51,419 34,099 17,320
------- ------- -------
Non-cash charges -- write-off and write-down of property
and equipment............................................. 22,535
-------
Total cash and non-cash charges................... $73,954
=======
</TABLE>
The employees terminated were primarily field and support personnel
associated with marine, transition zone and land seismic operations that were
removed from service, and employees within the Company's data processing
operations. Approximately 400 employees had been terminated as of December 31,
1999. The amount accrued was based upon the positions eliminated, length of
service and any statutory or legal requirements applicable within the country
where the terminations occurred. The Company estimates that all of the accrued
severance at December 31, 1999 will be paid during 2000.
The Company accrued $38.7 million for costs to (1) derig marine vessels
removed from operations, (2) settle contractual obligations associated with
leased vessels and equipment removed from service, and (3) accrue for certain
other incremental costs associated with the Company's restructuring efforts.
F-27
<PAGE> 72
The impairment of property and equipment primarily consisted of the
write-off or write-down of geophysical assets that are either being scrapped,
disposed of or will not benefit future operations, and the write-off of
leasehold improvements associated with leased vessels and equipment removed from
service. The Company also recognized $15.9 million in impairment charges for
certain software, equity investment and other assets.
Impairment charges were based upon a comparison of the assets' carrying
amounts to internal estimates of the realizable fair market values.
During the fourth quarter of 1998, the Company recorded impairment charges
totaling $22.7 million in response to management's assessment of asset values in
light of the general decline in oil and gas market demand. Of the total, $7.8
million in charges related to the multi-client library, $11.5 million related to
certain of the Company's equity investments, and $3.4 million related to
property items associated with the Company's oil and gas interests.
At December 31, 1999, seismic vessels and equipment totaling $101.4 million
in carrying value were temporarily idled.
NOTE 22 -- SUMMARIZED FINANCIAL INFORMATION
PGS EXPLORATION AS
PGS Exploration AS ("PEXAS"), a Norwegian corporation, is a wholly owned
subsidiary of the Company. PEXAS is the largest geophysical services company
within the PGS group of companies. PEXAS is also the charterer of the Ramform
Explorer and the Ramform Challenger. The Company has fully and unconditionally
guaranteed PEXAS charter obligations in connection with certain debt securities
issued in order to finance the purchase of these vessels. Summarized financial
information for PEXAS and its consolidated subsidiaries is presented below. This
information was derived from the financial statements prepared on a stand-alone
basis in conformity with US GAAP. Separate financial statements and other
disclosures with respect to PEXAS are omitted because the information contained
therein, in light of the information contained in the consolidated financial
statements of the Company, would not be material.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
INCOME STATEMENT DATA
Revenue.................................................... $210,459 $138,816 $200,908
Operating profit........................................... (10,924) 3,576 40,983
Net income................................................. (13,151) 9,043 20,249
BALANCE SHEET DATA
Current assets............................................. $100,165 $132,420 $272,984
Noncurrent assets.......................................... 490,663 207,064 206,661
Current liabilities........................................ 61,116 82,338 171,027
Noncurrent liabilities..................................... 425,704 139,988 194,796
Equity..................................................... 104,008 117,158 113,822
</TABLE>
F-28
<PAGE> 73
OSLO EXPLORER PLC AND OSLO CHALLENGER PLC
Both Oslo Explorer PLC ("Explorer") and Oslo Challenger PLC ("Challenger"),
Isle of Man public limited companies, are wholly owned subsidiaries of the
Company, purchased on April 4, 1997 (Note 8). Explorer and Challenger own the
Ramform Explorer and the Ramform Challenger, respectively, and lease these
vessels to PEXAS pursuant to long-term bareboat charters. Explorer and
Challenger are jointly and severally liable under mortgage notes, in an original
principal amount of $165.7 million, which were issued to finance the purchase of
the Ramform Explorer and the Ramform Challenger. Summarized financial
information for each of Explorer and Challenger is presented below. This
information was derived from the financial statements prepared on a stand-alone
basis in conformity with US GAAP. Separate financial statements and other
disclosures with respect to Explorer and Challenger are omitted because the
information, in light of the information contained in the consolidated financial
statements of the Company, would not be material.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------
1999 1998
---------------------- ----------------------
EXPLORER CHALLENGER EXPLORER CHALLENGER
-------- ---------- -------- ----------
(IN THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
INCOME STATEMENT DATA
Revenue............................................. $ 7,560 $ 7,520 $ 7,720 $ 7,679
Net income.......................................... 1,673 1,634 1,572 1,531
BALANCE SHEET DATA
Current assets...................................... $ -- $ -- $ -- $ --
Noncurrent assets................................... 78,394 78,278 80,113 80,037
Current liabilities................................. 4,972 4,972 4,690 4,690
Noncurrent liabilities.............................. 67,626 67,625 71,299 71,299
Equity.............................................. 5,796 5,681 4,124 4,048
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F-29
<PAGE> 74
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
NUMBER
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<C> <S>
1.1 -- Articles of Association, as amended (English translation)
2.1 -- Indenture, dated as of April 1, 1998, between Petroleum
Geo-Services ASA and Chase Bank of Texas, National
Association, as trustee, in respect of senior debt
securities (incorporated by reference to exhibit 2.12 of
the Annual Report of Petroleum Geo-Services ASA on Form
20-F for the year ended December 31, 1997 (SEC File No.
1-14614))
2.2 -- First Supplemental Indenture, dated as of April 1, 1998,
between Petroleum Geo-Services ASA and Chase Bank of
Texas, National Association, as trustee, in respect of
6 5/8% Senior Notes due 2008 and 7 1/8% Senior Notes due
2028 (incorporated by reference to exhibit 2.13 of the
Annual Report of Petroleum Geo-Services ASA on Form 20-F
for the year ended December 31, 1997 (SEC File No.
1-14614))
2.3 -- Revolving Credit Agreement dated as of September 4, 1998
among Petroleum Geo-Services ASA, Chase Manhattan PLC, as
arranger, Chase Manhattan International Limited, as
agent, and the financial institutions listed therein
(incorporated by reference to exhibit 2.5 of the Annual
Report of Petroleum Geo-Services ASA on Form 20-F for the
year ended December 31, 1998 (SEC File No. 1-14614))
Petroleum Geo-Services ASA and its consolidated subsidiaries are party to several
debt instruments under which the total amount of securities authorized does not
exceed 10% of the total assets of Petroleum Geo-Services ASA and its subsidiaries on
a consolidated basis. Pursuant to paragraph A.2(iii) of the instructions to the
exhibits to Form 20-F, Petroleum Geo-Services ASA agrees to furnish a copy of such
instruments to the SEC upon request.
3 -- Upon request of the SEC, Petroleum Geo-Services ASA will
file as an exhibit a list or diagram of all its
subsidiaries
23.1 -- Consent of PricewaterhouseCoopers LLP
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