UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _____________ to ________________
Commission File Number 0-9147
CANARGO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 91-0881481
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
P.O. BOX 291, ST PETER PORT, GUERNSEY, BRITISH ISLES GY1 3RR
(Address of Principal Executive Offices)
Registrant's telephone number, including area code: (44) 1481 729 980
Securities Registered Pursuant to Section 12(b) of the Act:
NONE
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, PAR VALUE $0.10 PER SHARE
(Title of Class)
Indicate by check mark whether the registrant: (1) filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated herein by reference in Part III of this Form 10-K or any amendment
to this Form 10-K. [X]
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date: Common Stock, $0.10 par value,
105,798,421 shares outstanding as of February 29, 2004.
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). YES [ ] NO [X]
The aggregate market value of the Registrant's common stock held
by-non-affiliates was approximately $16.5 million as of June 30, 2003, based
upon the last reported sales price of such stock on the Over The Counter
Bulletin Board on that date. For this purpose, the Registrant considers Dr.
David Robson and Nils Trulsvik to be its only affiliates.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive Proxy Statement to be issued in
connection with its 2004 Annual Meeting of Shareholders are incorporated by
reference in Part III of this Report. Other documents incorporated by reference
in this Report are listed in the Exhibit Index.
2
CANARGO ENERGY CORPORATION
FORM 10-K
TABLE OF CONTENTS
PAGE
----
PART 1.
Item 1. Business 4
Item 2. Properties 12
Item 3. Legal Proceedings 27
Item 4. Submission of Matters To a Vote of Security Holders 27
PART 2.
Item 5. Market for Common Equity and Related Stockholder Matters 28
Item 6. Selected Financial Data 29
MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 31
Item 7a Quantitative and Qualitative Disclosures about Market Risk 50
Item 8 Financial Statements and Supplementary Data 51
Item 9 Changes and Disagreements with Accountants on Accounting and Financial Disclosure 51
Item 9a Control and Procedures 51
PART III.
Item 10. Directors and Executive Officers of the Registrant 52
Item 11. Executive Compensation 52
Item 12. Security Ownership of Certain Beneficial Owners and Management 52
Item 13. Certain Relationships and Related Transactions 52
Item 14. Principal Accounting Fees and Services 52
PART IV.
Item 15 Exhibits, Financial Statement Schedules, and Reports on Form 8-K 53
3
PART I
QUALIFYING STATEMENT WITH RESPECT TO FORWARD-LOOKING INFORMATION
The United States Private Securities Litigation Reform Act of 1995 provides a
"safe harbour" for certain forward-looking statements. Such forward-looking
statements are based upon the current expectations of CanArgo Energy Corporation
("CanArgo") and speak only as of the date made. These forward-looking statements
involve risks, uncertainties and other factors. The factors discussed in Item 1.
"Business - Risks Associated with CanArgo's Oil and Gas Activities", Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and elsewhere in this Annual Report on Form 10-K are among those
factors that in some cases have affected CanArgo's historic results and could
cause actual results in the future to differ significantly from the results
anticipated in forward-looking statements made in this Annual Report on Form
10-K, future filings by CanArgo with the Securities and Exchange Commission, in
CanArgo's press releases and in oral statements made by authorized officers of
CanArgo. When used in this Annual Report on Form 10-K, the words "estimate,"
"project," "anticipate," "expect," "intend," "believe," "hope," "may" and
similar expressions, as well as "will," "shall" and other indications of future
tense, are intended to identify forward-looking statements.
In this Annual Report, "CanArgo" or the "company", "we", "us" and "our" refer to
CanArgo Energy Corporation and, unless otherwise indicated by the context, our
consolidated subsidiaries.
ITEM 1. BUSINESS
GENERAL DEVELOPMENT OF BUSINESS
We operate as an oil and gas exploration and production company and carry out
our activities through a number of subsidiaries and associated companies. These
companies are generally focused on one of our projects, and this structure
assists in maintaining separate cost centers for these different projects.
Our principal activities are oil and gas exploration, development and production
of oil and gas, principally in the Republic of Georgia, and to a lesser extent
in Kazakhstan and Ukraine although in 2003 we approved a plan to dispose of our
interests in Ukraine. However in late 2000 CanArgo also began to engage in oil
and gas marketing and refining activities in Georgia. In November 2000, CanArgo
acquired a 51% interest in Georgian American Oil Refinery company which owns a
refurbished American refinery with a design capacity of approximately 4,000
barrels per day. Shortly thereafter, in December 2000, CanArgo expanded its
interest in Georgia to include a 50% controlling interest in CanArgo Standard
Oil Products with the objective of developing within Georgia a chain of retail
petrol stations. These have now been sold, conditional upon receiving the agreed
purchase price from the buyer. Regardless of these investments, CanArgo
continues to direct most of its efforts and resources to the development of its
Georgian exploration program and the Ninotsminda Field. In February 2004,
CanArgo disposed of its interest in the Georgian American Oil Refinery.
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
In Georgia our exploration, development and production activities are carried
out under four production sharing contracts ("PSC"), these being:
1. The Ninotsminda, Manavi and West Rustavi Production Sharing
Contract, covering Block XI(E), ("Ninotsminda PSC"), in which
Ninotsminda Oil Company Limited owns a 100% interest.
Ninotsminda Oil Company Limited is a wholly owned subsidiary
of CanArgo. This PSC covers an area of approximately 27,739
acres (113 km(2));
2. The Nazvrevi and Block XIII Production Sharing Contract
("Nazvrevi PSC") in which CanArgo (Nazvrevi) Limited owns a
100% interest. CanArgo (Nazvrevi) Limited is a wholly owned
subsidiary of CanArgo. This PSC covers an area of
approximately acres 388,450 acres (1,572 km(2));
3. The Norio (Block XI(C)) and North Kumisi Production Sharing
Agreement ("Norio PSA") in which CanArgo Norio Limited
currently owns a 100% interest, although this interest will be
reduced to 85% following
4
completion of a farm-in by the state oil company, Georgian
Oil, to the MK72 well, and potentially to 50% if Georgian Oil
exercises its option under that farm-in agreement. CanArgo
Norio Limited is currently 75% owned by CanArgo. This PSA
covers an area of approximately 378,523 acres (1,542 km(2));
and
4. The Block XI(G) and XI(H) Production Sharing Contract
("Tbilisi PSC"), in which CanArgo Norio Limited owns a 100%
interest. CanArgo Norio Limited is currently 75% owned by
CanArgo. This PSC covers an area of approximately 119,843
acres (485 km(2)).
Under production sharing contracts, the contractor party (generally a foreign
investor) assumes the risk and provides investment into the project (in the
above mentioned contracts, CanArgo through its appropriate subsidiary is a
contractor party) and in return is entitled to a share of any petroleum produced
which is split into a cost recovery and profit share element. The remaining
profit petroleum produced from the project is delivered to the State from which
the State will assume, pay and discharge, in the name and on behalf of each
contractor party, the contractor party's profit tax liability and all other host
States taxes, levies and duties. PSCs are a common form of oil and gas
exploration and production contract in many parts of the world.
[MAP]
NINOTSMINDA FIELD
Since completion of the business combination with CanArgo Oil & Gas Inc., our
resources have, through our wholly owned subsidiary Ninotsminda Oil Company,
been focused on the development of the Ninotsminda Field and related exploration
activities. The Ninotsminda Field covers approximately 3,276 acres (13.26 km(2))
and is located approximately 25 miles (40 kms) north east of the Georgian
capital, Tbilisi. It is adjacent to and east of the Samgori Oil Field, which was
Georgia's most productive oil field. The Ninotsminda Field was discovered later
than the Samgori Field and has experienced substantially less development
activity. Georgian Oil and others, including Ninotsminda Oil Company, have
drilled thirty-six wells in the Ninotsminda Field, of which nine are currently
producing.
5
We believe the Ninotsminda PSC area both outside of and beneath the currently
producing reservoirs of the Ninotsminda Field has significant additional
exploration potential and we have invested substantial funds in exploring this
area.
OTHER PROJECTS
We also have additional exploratory and developmental oil and gas properties and
prospects in Georgia and Ukraine and we own interests in other oil and gas
projects in the former Soviet Union. However, during 2003, the company decided
to dispose of its Ukrainian assets in order to focus on its business in Georgia.
At the end of 2003, CanArgo had sold its interest in its west Ukrainian project
and was in negotiations with a buyer for the sale of its interest in the
Bugruvativske Field in eastern Ukraine. Our principal product is crude oil, and
the sale of crude oil and crude oil products is our principal source of revenue.
BUSINESS STRUCTURE
CanArgo and its principal active subsidiaries are as follows:
[FLOW CHART]
CanArgo's activities at the Ninotsminda Field are conducted through Ninotsminda
Oil Company Limited, a Cypriot corporation ("NOC"). Initially CanArgo had a
partner in NOC named JKX Oil & Gas plc ("JKX") however in May 2000, we reached
an agreement with JKX to acquire its final 21.2% interest in NOC for a direct
equity interest in CanArgo. In July 2000, this transaction was completed and NOC
became our wholly owned subsidiary. In November 1999, we increased our
percentage ownership of NOC from 68.5% to 78.8% when JKX chose not to subscribe
for it's pro rata portion of shares being offered to increase NOC capital.
NOC obtained its rights to the Ninotsminda Field, including all existing wells,
one other field and exploration acreage in Block XI(E) under a 1996 production
sharing contract with Georgian Oil and the State of Georgia ("Ninotsminda PSC").
NOC's rights under the contract expire in December 2019, subject to the possible
loss of
6
undeveloped areas prior to that date and a possible extension with regard to
developed areas. Under the Ninotsminda PSC, NOC is required to relinquish at
least half of the area then covered by the production sharing contract, but not
any portions being actively developed, at five-year intervals commencing
December 1999. In 1998, these terms were amended with the initial relinquishment
being due in 2006 and a reduction in the area to be relinquished at each
interval from 50% to 25%.
Under the Ninotsminda PSC, up to 50% of petroleum produced under the contract
("Production") is allocated to NOC for the recovery of the cumulative allowable
capital, operating and other project costs associated with the Ninotsminda Field
and exploration in Block XI(E). NOC pays 100% of the costs incurred in the
project as the sole contractor party under the Ninotsminda PSC. The balance of
Production is allocated on a 70/30 basis between Georgian Oil and NOC
respectively. While NOC continues to have unrecovered costs, it will receive 65%
of Production (profit petroleum). After recovery of its cumulative capital,
operating and other allowable project costs, NOC will receive 30% of Production.
Thus, while NOC is responsible for all of the costs associated with the
Ninotsminda PSC, it is only entitled to receive 30% of Production after cost
recovery. The allocation of a share of Production to Georgian Oil, however,
relieves NOC of all obligations it would otherwise have to pay the Republic of
Georgia for taxes, duties and levies related to activities covered by the
production sharing contract. Georgian Oil and NOC take their respective shares
of oil production in kind, and they market their oil independently, however gas
is marketed jointly.
Until the end of 2001, Georgian Oil had a priority right to receive oil
representing a projection of what the Ninotsminda Field would have yielded based
upon the wells and equipment in use at the time the contract was entered into.
This priority right has now ceased.
Pursuant to the terms of CanArgo's PSCs in Georgia, including the Ninotsminda
PSC, a Georgian not-for-profit company must be appointed as field operator.
Currently there are three such field operating companies, relating to CanArgo's
four PSC's: Georgian British Oil Company Ninotsminda, Georgian British Oil
Company Nazvrevi and Georgian British Oil Company Norio (in respect of both the
Norio PSA and the Tbilisi PSC), each of which is 50% owned by a company within
the CanArgo group with the remainder owned by Georgian Oil, but with CanArgo
having chairmanship of the board and a casting vote. The field operator provides
the operating personnel and is responsible for day-to-day operations. CanArgo or
a company within the CanArgo group pays the operating company's expenses
associated with the development of the fields, and the operating company
performs its services on a non-profit basis. Georgian British Oil Company
Ninotsminda currently has 114 full time employees and substantially all of its
activities relate to the development of the Ninotsminda Field. The use of such
Georgian companies as field operator gives us less control of operations than we
might otherwise have if we were conducting operations directly, although we do
have board control of these field operating companies.
Operations under each of the PSCs are determined by a governing body
("Co-ordinating Committee") composed of members designated by the respective
CanArgo company and Georgian Oil, with the deciding vote on field development
issues allocated to us. If Georgian Oil believes that action proposed by CanArgo
with which Georgian Oil disagrees would result in permanent damage to a field or
reservoir or in a material reduction in production over the life of a field or
reservoir, it may refer the disagreement to a western independent expert for
binding resolution. Since we acquired our interest in the PSCs, there has been
no such disagreement. Georgian regulatory authorities must approve any drilling
sites tentatively selected by us before drilling may commence.
NINOTSMINDA, MANAVI AND WEST RUSTAVI PRODUCTION SHARING CONTRACT
Production from the Ninotsminda Field was minimal when NOC assumed developmental
responsibility for the Field in 1996. We believed that the development and
production obtainable from the Ninotsminda Field had in the past been hampered
by, among other factors, a lack of funding, civil strife and utilization of old
technology and methods.
NOC's initial approach to the Ninotsminda Field development was to produce oil
from one zone or underground formation, the Middle Eocene. This development
included repairing and adding perforations to existing wells, obtaining
additional seismic data and a limited drilling program. The first new well
(named N96) was completed in October 1997 and initially produced at the rate of
400 to 600 barrels of oil per day and has recently been re-
7
completed as a horizontal producer. A second well (N98) was completed in October
1998, and sidetracked as a horizontal producer in 2000 and has produced 279,690
barrels of oil to date.
A third oil well commenced in October 1998 (named N97) but drilling was
suspended in December 1998 at a depth of 3,258 feet (993 meters) as a result of
an undependable supply of electricity. Drilling of this well recommenced in July
2000 as a potential gas condensate exploration well for the deep Cretaceous zone
but in October 2000, we announced that as a result of difficult drilling
conditions, the well could not be completed to the Cretaceous target as
originally planned but rather would be tested in the newly identified shallower
Sarmatian zone. This well tested at rates up to 130 barrels of oil per day, but
production declined quickly, and this zone requires further analysis to assess
its full potential. This well awaits either further completion in the shallow
zones utilizing other completion techniques, or else utilization as a horizontal
producer in the Middle Eocene zone. We undertook further work to assess the
potential of these shallow zones in the Ninotsminda Field, with the sidetracking
of the previously mechanically suspended N78 well (Oligocene formation), and the
recompletion of the N59 well (Upper Eocene formation). N78z initially flowed at
some 660 barrels of oil per day, but has since declined significantly due to a
decrease in reservoir pressure and sand production - similarly N59 has also
declined and is currently shut-in. Further analysis is required to assess the
full potential of these oil bearing upper zones in the Ninotsminda Field, in
particular on completion techniques for these formations. Such studies may,
however, also open up new potential in the upper zones of this and other areas
currently under license in Georgia.
In January 2003, in order to increase production at the Ninotsminda Field and
further improve working capital, drilling of a new horizontal sidetrack well,
N4H, commenced targeting an existing producing reservoir of Middle Eocene age.
The well is a horizontal sidetrack from an existing well bore in the Middle
Eocene reservoir at approximately 2,356 meters. The horizontal production
section extends for a total distance of 400 meters in the west central area of
the Field between the N4 and N9 wells. The well was successfully completed and
originally put on production at over 1,000 barrels of oil per day (bopd) in
April 2003. It was later reduced to approximately 500 bopd to ensure optimal
total production produced from the well on the advice of an independent
petroleum engineering consultant. Drilling commenced on an additional horizontal
sidetrack well, N100H, in August 2003. This well was successfully completed in
September 2003. It was drilled along a similar orientation to the N4H well along
the crestal part of the Ninotsminda Field where the most fracturing is believed
to occur, and into an area of the reservoir that has not yet been drained. The
well tested at rates of over 2,000 bopd but has been put on production at a
lower rate. In December 2003, a third horizontal well, N96H horizontal well
drilled in the west central part of the Field was completed with test flow rates
in excess of 1,200 bopd.
Independent petroleum engineering specialists recommend that the optimal
long-term production rate for horizontal wells be of the order of 500 bopd per
well. In order to maximise productivity and recoverability from the Field, wells
are being choked back to the approximate recommended levels while it is planned
that future horizontal wells should be drilled under-balanced (i.e., producing
while drilling). This requires a specialist unit, and discussions are underway
with several international service companies who supply such equipment.
Once the under-balanced specialist drilling equipment is on the Field, several
additional horizontal well bores will be drilled. These include N22H and N30H,
which were previously planned to be drilled using conventional drilling
techniques. A second horizontal well (N100H2 - east horizontal) will be drilled
from the N100 well bore, and a decision is currently being made as to whether
this will be drilled using conventional techniques (CanArgo Rig#2 is mobilized
to the well), or using under-balanced coiled tubing drilling. The N100H1 (west
horizontal), which is currently producing approximately 500 bopd, was drilled
from the N100 well in 2003. We believe that the planned N100H2 (east horizontal)
will be the first multilateral well to be drilled in the Caucasus. A new well
(N99) is included in the program; this well will be designed so as to have up to
three multilateral horizontal wells drilled from it. These will be drilled into
the eastern part of the Field, an area that is currently largely undeveloped. It
is expected that a suitable under-balanced drilling unit will arrive in Georgia
by August 2004. The advancement of the horizontal program is being rescheduled
until such a unit is in place.
The completion of a dynamic reservoir model during the year and the
implementation of the successful development program based on horizontal
drilling have resulted in a significant increase in recoverable oil reserves at
the Ninotsminda Field. A report prepared by Oilfield Production Consultants, an
independent firm of consulting petroleum engineers dated January 1, 2004 shows
year-end 2003 gross total proved oil reserves at the Ninotsminda
8
Field were 6.762 million barrels (MMbbl) up 63% from 2002's 4.15 MMbbl. Over the
same period, gross total proved natural gas reserves, on an energy equivalent
basis, decreased from 1.34 million barrels of oil equivalent (MMboe) to 0.51
MMboe. See "Properties-Reserves" and "Business - Risks Associated with CanArgo's
Oil and Gas Activities" below for a discussion of the inherent possibility of
imprecision in estimating reserves. The recovery of these reserves is dependent
on application of optimal production levels for the Ninotsminda wells and
further application of horizontal drilling techniques utilizing under-balanced
drilling techniques.
While most of the exploration and development of the Ninotsminda Field prior to
2000 focused on oil, a layer of gas above the oil or gas cap was known to exist
above the principal producing zone. In December 1999, NOC began commercial
production of this gas cap following regulatory approval from the Georgian
government. This production was sold pursuant to a gas contract with AES -
Telasi, a subsidiary of the US based AES Corporation, for delivery to the
Gardabani thermal power plant. Under terms of the gas contract, AES-Telasi had
agreed to purchase all the gas produced from the Ninotsminda Field in priority
to all other suppliers with no maximum or minimum volume. AES continued to
purchase gas from NOC on similar contractual terms during 2000 and into 2001.
With increases in demand for natural gas produced in Georgia, in 2001 NOC
commenced the first and second wells of a planned three-well exploration program
to explore and determine the future development potential of gas condensate
prospects in the Ninotsminda area, particularly focused on the potential in the
deeper Cretaceous sequence.
In 2000, the Cretaceous exploration program was initiated under a Participation
Agreement with AES Gardabani (also a subsidiary of AES Corporation) relating to
the exploration and potential future development of Sub Middle Eocene gas
prospects in parts of the Ninotsminda PSC. Under the Participation Agreement,
AES Gardabani was to earn a 50% interest in identified prospects at the Sub
Middle Eocene stratigraphic level (rocks older than the Middle Eocene sequence
i.e., below the producing horizons of the Ninotsminda Field) by funding two
thirds of the cost of a three-well exploration program. However, prior to
completion of the exploration program as defined in the Participation Agreement,
AES indicated in January 2002 that it wished to withdraw from the Participation
Agreement in order to focus on its core business. In February 2002, the
Participation Agreement with AES was terminated without AES earning any rights
to any of the Ninotsminda Field reservoirs. Under a separate Letter Agreement,
if gas from the Sub Middle Eocene is discovered and produced, AES will be
entitled to recover at the rate of 15% of future gas sales from the Sub Middle
Eocene, net of operating costs, their funding under the Participation Agreement.
AES also has an option to enter into a five year take or pay gas sales agreement
for a quantity up to 200 million cubic meters per year at an initial contract
price of $1.30 per thousand cubic feet ($46.00 per thousand cubic meters).
In January 2002, the first well drilled under the Participation Agreement, N100,
reached a depth of 16,165 feet (4,927 meters) without having reached the
targeted Cretaceous zone. The well was terminated at this depth because of lack
of funding caused by the withdrawal of AES from the project, and for mechanical
reasons, having penetrated a significant thickness of hydrocarbon bearing
sandstones belonging to the Lower Eocene and Palaeocene sequences. Three
formation tests were carried out on these sandstones, these tests recovering
35 degrees API (SG 0.85) oil, but without commercial flow, despite the
installation of a down hole progressive cavity pump. We have concluded that the
reason for the lack of commercial flow was either that the zone was of low
permeability, or that it suffered formation damage due to the mud used to drill
the well. Potential still remains in this sequence but the N100 well was
recompleted in 2003 as a Middle Eocene horizontal oil producer. Future plans are
to drill a further horizontal well in the Middle Eocene from the N100 well bore,
this then becoming the first multi-lateral drilling carried out in Georgia.
Manavi
The second well drilled under the Participation Agreement, Manavi well M11, was
targeting a large Cretaceous prospect in the Manavi area, east of the
Ninotsminda Field, with further potential in the Middle Eocene. This well was
suspended for financial reasons in 2002 at a depth of 4,182 meters, but
re-started following a farm-in by a local oil service company (GBOSC) in
September 2003. This well was drilled to a total depth of 14,765 feet (4,500
meters), and encountered the Cretaceous limestone target at 14,265 feet (4,348
meters). Drilling data and wire line logs indicated the presence of hydrocarbons
in the Cretaceous and a production liner was set for testing. After initially
very encouraging clean-up flows of drilling fluid accompanied by good quality
34.4 degrees API oil, and gas, flow
9
stopped due to a mechanical collapse of the production tubing. This is the first
discovery of oil in the Cretaceous sequence in Georgia, however, this sequence
is a prolific producer in nearby Chechnya and Dagestan. Regional outcrop studies
in east-central Georgia indicate that the Cretaceous reservoir unit to be over
300 meters (~1,000 feet) thick. Although over 490 feet (150 meters) of
hydrocarbons were encountered in the Manavi well, no oil-water contact was
identified on the logs. An earlier well, the Manavi M7 well, drilled to the
south of the M11 location, encountered hydrocarbons in the Cretaceous limestone
sequence over 4,265 feet (1,300 meters) deeper, before this well was abandoned
without testing being completed.
Mapping of the Manavi Cretaceous oil discovery indicates a substantial potential
oilfield might be present. In addition, the shallower Middle Eocene sequence
encountered in the well also had hydrocarbon indications, and awaits testing.
This is approximately 3,280 feet (1,000 meters) deeper than the currently
assumed oil-water contact for eastern Ninotsminda, and may indicate deeper oil
in this area. Following the initial testing of the M11 well, CanArgo and NOC
agreed with its farm-in partner GBOSC, to buy out its 50% interest in the well
by issuing to GBOSC two million shares of CanArgo common stock. As such NOC has
now regained its 100% interest in the well, subject only to the possible gas
sales related arrangements with AES mentioned above.
Work to retrieve the damaged tubing from M11 and continue the testing program
was delayed due to sourcing the necessary equipment from outside Georgia, but we
should be ready to recommence operations shortly. However, it is entirely
possible that the well will need to be sidetracked to complete the evaluation of
the discovery. Regardless of the continuation of the testing on the M11
discovery, we plan to move ahead quickly with appraisal of Manavi. An appraisal
well location has been chosen, and discussions are underway to commence drilling
this appraisal well (M12) in June/July 2004. Some additional seismic is required
to firm up the location for the second appraisal well, but we would hope that
this well could commence before the end of the year, while at the same time
implementing an early production scheme for the field. Although management is
excited about the potential of the Manavi prospect, a fair amount of additional
drilling and analysis is still required before we will be able to fully evaluate
the reserves and productive possibilities of this prospect.
On the Ninotsminda Field, we have not yet fully evaluated the reserves and
economics of production from the upper oil zones, the gas cap or from the
hydrocarbon bearing zones below the Middle Eocene. To fully evaluate these
zones, further seismic, technical interpretation and drilling will be required.
With respect to gas production, only limited short duration gas supply contracts
currently exist for production directly from the gas cap. Gas currently produced
from the Middle Eocene and upper zones is subject to market conditions and
environmental constraints within Georgia and the ability of NOC to arrange
short-term gas supply agreements as required.
West Rustavi and Kumisi
In addition to the Ninotsminda Field and Manavi prospect, under the Ninotsminda
PSC NOC has rights to one other field, West Rustavi and an underlying gas
prospect named Kumisi.
The West Rustavi Field is located approximately 25 miles (40 km) southeast of
the Ninotsminda Field. Prior to NOC gaining the Ninotsminda PSC, Georgian Oil
drilled ten wells in the West Rustavi Field area, two of which produced oil. The
Middle Eocene zone is thinner and less productive in this area than what is
found in the Ninotsminda Field and only limited production has taken place from
the West Rustavi Field. However NOC has carried out only very limited workover
activity on West Rustavi, and potential may yet exist for further oil production
from the Middle Eocene dependant on technical and economic factors. One of the
ten wells drilled in the West Rustavi Field was completed in the deeper
Cretaceous/Paleocene horizon. This well was tested and produced 1 million cubic
feet of gas and 3,500 barrels of water per day, and is interpreted to have
tested the down dip extent of a Cretaceous gas deposit named Kumisi. Additional
seismic data has been acquired by NOC over this structure, but further
geo-technical work is required on this horizon to determine its potential size,
which could be significant. Given a positive outcome from this work, NOC has
potential plans to appraise this discovery dependent on this technical work and
on commercial sales contracts for gas off take.
In addition to the horizons discussed above, seismic and well data are currently
being interpreted to identify further prospects in the Ninotsminda area at
several different stratigraphic levels.
10
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used in
this Form 10-K. All volumes of natural gas referred to herein are stated at the
legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
"Bbl" One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
"Bopd" Barrels of oil produced per day.
"Development drilling" The drilling of a well within the proved area of an oil
or gas reservoir to the depth of a stratigraphic horizon known to be productive.
"Exploration prospects or locations" A location where a well is drilled to find
and produce natural gas or oil reserves not classified as proved, to find a new
reservoir in a field previously found to be productive of oil or gas in another
reservoir or to extend a known reservoir.
"Finding and development costs" Costs associated with acquiring and developing
proved natural gas and oil reserves which are capitalized pursuant to generally
accepted accounting principles, including any capitalized general and
administrative expenses.
"Farm-in or farm-out" An agreement under which the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in
the acreage. The assignor usually retains a royalty or reversionary interest in
the lease. The interest received by an assignee is a "farm-in" while the
interest transferred by the assignor is a "farm-out."
"Gross acreage or gross wells" The total acres or wells, as the case may be, in
which a working interest is owned.
"Mcf" One thousand cubic feet of natural gas.
"MMbbl" One million barrels.
"Net acres or net wells" The sum of the fractional working interests owned in
gross acres or gross wells.
"Producing property" A natural gas and oil property with existing production.
"Proved developed reserves" Proved reserves that can be expected to be recovered
from existing wells with existing equipment and operating methods.
"Proved reserves" The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
"Proved undeveloped reserves" Proved reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units that offset productive units and that
are reasonably certain of production when drilled.
"Recomplete" This term refers to the technique of drilling a separate well bore
from all existing casing in order to reach the same reservoir, or redrilling the
same well-bore to reach a new reservoir after production from the original
reservoir has been abandoned.
11
"Undeveloped acreage" Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of natural gas and oil regardless of whether such acreage contains proved
reserves.
"Working interest" An operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to receive a
share of production.
"Workovers" Operations on a producing well to restore or increase production.
ITEM 2. PROPERTIES
PRODUCTION HISTORY
The Ninotsminda Field was discovered and initial development began in 1979.
Average gross oil production for January and February 2004 was 1,711 barrels of
oil per day. A testing program implemented to test the optimal production level
for individual wells resulted in the temporary shut-in of certain wells thus
negatively affecting the production in February. Current production as of March
18, 2004 was approximately 2,000 bopd. Gross production from the Ninotsminda
Field for the past three years was as follows:
YEAR ENDED
DECEMBER 31, OIL - GROSS BARRELS
------------ -------------------
2003 695,174
2002 292,289
2001 413,724
PRODUCTIVE WELLS AND ACREAGE
The following table summarizes as of December 31, 2003 with respect to
Ninotsminda Oil Company the number of productive oil and gas wells and the total
developed acreage for the Ninotsminda Field. Such information has been presented
on a gross basis, representing our 100% interest in Ninotsminda Oil Company.
GROSS
--------------------------
NUMBER OF WELLS ACREAGE
--------------- -------
Ninotsminda Field 9 3,276
On December 31, 2003, there were no productive wells or developed acreage on any
of our other Georgian properties, except for one gross well on the West Rustavi
Field which was shut-in at that date.
RESERVES
The following table summarizes net hydrocarbon reserves for the Ninotsminda
Field. This information is derived from a report dated as of January 1, 2004
prepared by Oilfield Production Consultants (OPC), independent petroleum
consultants headquartered in London, England. This report is available for
inspection at our principal executive offices during regular business hours. The
reserve information in the table below has also been filed with the Oslo Stock
Exchange.
12
OIL RESERVES - PSC ENTITLEMENT
OIL RESERVES GROSS VOLUMES (1)
-------------- ---------------
(MILLION (MILLION
BARRELS) BARRELS)
-------------- ---------------
Proved Developed 3.593 2.336
Proved Undeveloped 3.169 2.059
----- -----
TOTAL PROVEN 6.762 4.395
===== =====
GAS RESERVES - PSC ENTITLEMENT
GAS RESERVES GROSS VOLUMES (1)
-------------- ---------------
(BILLION CUBIC (BILLION CUBIC
FEET) FEET)
-------------- ---------------
Proved Developed 1.742 1.133
Proved Undeveloped 1.243 0.808
----- -----
TOTAL PROVEN 2.985 1.941
===== =====
(1) PSC Entitlement Volumes attributed to CanArgo are calculated
using the "economic interest method" applied to the terms of
the production sharing contract. PSC Entitlement Volumes are
those produced volumes which, through the production sharing
contract, accrue to the benefit of Ninotsminda Oil Company
after deduction of Georgian Oil's share which includes all
Georgian taxes, levies and duties. As a result of CanArgo's
interest in Ninotsminda Oil Company, these volumes accrue to
the benefit of CanArgo for the recovery of capital, repayment
of operating costs and share of profit.
Proved reserves are those reserves estimated as recoverable under current
technology and existing economic conditions from that portion of a reservoir
which can be reasonably evaluated as economically productive on the basis of
analysis of drilling, geological, geophysical and engineering data, including
the reserves to be obtained by enhanced recovery processes demonstrated to be
economically and technically successful in the subject reservoir. Proved
reserves include proved developed reserves (producing and non-producing
reserves) and proved undeveloped reserves.
Proved developed reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Proved
undeveloped reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage are
limited to those drilling units offsetting productive wells that are reasonably
certain of production when drilled.
Uncertainties exist in the interpretation and extrapolation of existing data for
the purposes of projecting the ultimate production of oil from underground
reservoirs and the corresponding future net cash flows associated with that
production. The estimating process requires educated decisions relating to the
evaluation of all available geological, engineering and economic data for each
reservoir. The amount and timing of cost recovery is a function of oil and gas
prices which can fluctuate significantly over time. The net oil and gas price
used in the report by OPC as of January 1, 2004 were $20.07 per barrel and $1.25
per mcf respectively. Having considered the geological and engineering data in
the interpretation process, the company believes with reasonable certainty that
the stated proven reserves represent the estimated quantities of oil and gas to
be recoverable in future years under existing operating and economic conditions.
No independent reserves have been assessed for the West Rustavi Field.
13
UNDEVELOPED ACREAGE
The following table summarizes the gross and net undeveloped acreage held under
the Ninotsminda, Nazvrevi/Block XIII and Norio/North Kumisi production sharing
contracts as of December 31, 2003. The information regarding net acreage
represents our interest based on our 100% interest in Ninotsminda Oil Company
and the subsidiary holding the Nazvrevi/Block XIII contract and its current 75%
interest in the subsidiary holding the Norio/North Kumisi contract.
GROSS NET
------------------- -------------------
SQUARE SQUARE
PSC ACREAGE KILOMETERS ACREAGE KILOMETERS
------- ---------- ------- ----------
Ninotsminda, Manavi and West 27,739 113 27,739 113
Rustavi covering Block XI(E)
Nazvrevi and Block XIII 388,450 1,572 388,450 1,572
Norio (Block XI(C)) and North Kumisi. 378,523 1,542 283,892 1,157
Block XI(G) and XI(H) 119,843 485 119,843 485
------- ----- ------- -----
Total 914,555 3,712 819,924 3,327
======= ===== ======= =====
We lease office space in London, England; Guernsey, Channel Islands; Calgary,
Alberta; and Tbilisi, Republic of Georgia. The leases have remaining terms
varying from eight months to six years and six months and annual rental charges
ranging from $16,000 to $262,000.
PROCESSING, SALES AND CUSTOMERS
Georgian Oil built a considerable amount of infrastructure in and adjacent to
the Ninotsminda Field prior to entering into the production sharing contract
with Ninotsminda Oil Company. Ninotsminda Oil Company now uses that
infrastructure, including initial processing equipment.
The mixed oil, gas and water fluid produced from the Ninotsminda Field wells
flows into a two-phase separator located at the Ninotsminda Field, where gas
associated with the oil is separated. The oil and water mixture is then
transported eleven kilometers either in a pipeline or by truck to Georgian Oil's
central processing facility at Sartichala for further treatment. The gas is
transported to Sartichala in a separate pipeline where some is used for fuel and
the rest is piped 34 kilometers to Rustavi where it is delivered to the Rustavi
industrial complex for sale to a number of customers.
At Sartichala, the water is separated from the oil. Ninotsminda Oil Company then
sells oil in this state to buyers at Sartichala for local consumption or
transfers it by pipeline 20 kilometers to a railhead at Gatchiani or by road
tanker to Vaziani rail loading terminal primarily for export sales. At the
railheads, the oil is loaded into railcars for transport to the Black Sea port
of Batumi, Georgia, where oil can be loaded onto tankers for international
shipment. Buyers transport the oil at their own risk and cost from the delivery
point at Sartichala.
Ninotsminda Oil Company sells its oil directly to local and international
buyers. In 2003, Ninotsminda Oil Company sold its oil production to eleven
customers. Of these customers, three customers represented sales greater than
10% of oil revenue:
CUSTOMER PERCENT OF OIL REVENUE
-------- ----------------------
Crownhill 42.4%
Baslam 32.3%
Sveti 16.9%
Management believes that the loss of any of the foregoing customers should not
materially adversely affect our production revenues because of the existence of
a ready market for our production and an established export route for crude oil
from the Caspian area via Georgia and its Black Sea ports. However, there can be
no assurance that such substitute purchasers of our production will offer to
purchase our production on the same terms and conditions.
14
In 2002, Ninotsminda Oil Company sold its oil production to eight customers of
which four customers represented sales greater than 10% of oil revenue:
CUSTOMER PERCENT OF OIL REVENUE
--------------- ----------------------
Caspian Trading 28.4%
Sveti 26.4%
Crownhill 20.1%
Trafigura 19.9%
In 2001, Ninotsminda Oil Company sold its oil production to eight customers of
which three customers represented sales greater than 10% of oil revenue:
CUSTOMER PERCENT OF OIL REVENUE
---------------------------------- ----------------------
Caspian Trading 63.8%
Georgian American Oil refinery (1) 23.5%
MS 12.7%
(1) 51% owned by CanArgo effective November 2000
Sales to both the domestic and international markets are based on the average of
a number of quotations for Dated Brent Mediterranean with an appropriate
discount for transportation and other charges. Sales in 2003 were at an average
discount of $7.70 to the price of Brent crude oil as quoted in the Platts Crude
Oil Marketwire for Brent Dated Mediterranean compared to an average discount to
the Brent price of $5.09 and $6.29 for sales in 2002 and 2001, respectively. The
higher discount in 2003 is due to significant upfront security payments being
made by the buyer to Ninotsminda Oil Company in return for the option to lift
oil over a twelve-month period (described more fully under Liquidity and Capital
Resources). For the period of the option, Ninotsminda Oil Company will retain
the security for its own use and account.
Prices for oil and natural gas are subject to wide fluctuations in response to a
number of factors including:
- global and regional changes in the supply and demand for oil and
natural gas;
- actions of the Organization of Petroleum Exporting Countries;
- weather conditions;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political conditions in the Middle East and elsewhere; and
- overall global and regional economic conditions.
OTHER GEORGIAN LICENSES
Nazvrevi and Block XIII Production Sharing Contract ("Nazvrevi PSC")
In February 1998, we entered into a second production sharing contract with
Georgian Oil and the State of Georgia. This contract covers the Nazvrevi and
Block XIII areas of East Georgia, an approximately 492,914 acre (2,008 km(2))
exploration area adjacent to the Ninotsminda and West Rustavi Fields and
containing existing infrastructure ("Nazvrevi PSC"). The agreement extends for
twenty-five years. We are required to relinquish at least half of the area then
covered by the Nazvrevi PSC, but not any portions being actively developed, at
five-year intervals commencing in 2003. The first relinquishment was made in
2003, of the southern part of the area, reducing the area to approximately
388,450 acres (1,572 km(2)).
Under the Nazvrevi PSC, CanArgo pays all operating and capital costs. CanArgo
first recovers its cumulative operating costs from production. After deducting
production attributable to operating costs, 50% of the remaining production
(profit petroleum), considered on an annual basis, is applied to reimburse
CanArgo for its cumulative
15
capital costs. While cumulative capital costs remain unrecovered, the other 50%
of remaining production is allocated on a 50/50 basis between Georgian Oil and
CanArgo. After all cumulative capital costs have been recovered by CanArgo,
remaining production after deduction of operating costs is allocated on a 70/30
basis between Georgian Oil and CanArgo, respectively. Thus, while CanArgo is
responsible for all of the costs associated with the Nazvrevi PSC it is only
entitled to receive 30% of production after cost recovery. The allocation of a
share of production to Georgian Oil, however, relieves CanArgo of all
obligations it would otherwise have to pay the Republic of Georgia for taxes and
similar levies related to activities covered by the production sharing contract.
Both Georgian Oil and CanArgo will take their respective shares of oil
production under the Nazvrevi PSC in kind but will jointly market any available
gas production.
The first phase of the preliminary work program under the Nazvrevi PSC involved
primarily a seismic survey of a portion of the exploration area and the
processing and interpretation of the data collected. The seismic survey has been
completed, and the results of those studies continue to be interpreted, with a
view towards defining possible oil and gas prospects and exploration drilling
locations. The cost of the seismic program was approximately $1.5 million, and
met the minimum obligatory work commitment under the contract. The Department
for Protection of Mineral Resources and Mining has confirmed that we have met
the requirements of the work program defined in the production sharing
agreements. The Kumisi gas discovery may extend into Block XIII, and there are
several identified prospects, however as the Nazvrevi and Block XIII area is an
exploration area and no discoveries have been made to date, it is not possible
to estimate the expenditures needed to discover and if discovered, produce
commercial quantities of oil and gas.
Norio (Block XI(C)) and North Kumisi Production Sharing Agreement ("Norio PSA")
In December 2000, CanArgo, through its then 50% owned subsidiary CanArgo Norio
Limited ("CanArgo Norio"), entered into a third production sharing contract with
the State of Georgia represented by Georgian Oil and the State Agency for
Regulation of Oil and Gas Resources in Georgia. The Norio PSA covers the Norio
and North Kumisi blocks of East Georgia, an exploration area of approximately
378,523 acres (1,542 km(2)) adjacent to the Ninotsminda and Samgori Fields.
There are two existing oil fields on the Norio PSA area, Norio and Satskhenisi
which are old, small, relatively shallow fields and which produce small
quantities of oil. CanArgo Norio has determined production from these fields to
be uneconomic, and the fields are currently being operated by Georgian Oil under
a service agreement with CanArgo Norio, whereby Georgian Oil takes all
production to compensate it for its costs under what is effectively a social
program. If CanArgo Norio wishes, it could take over field operations and
production from these fields forthwith.
The commercial terms of the Norio PSA are similar to those of the Nazvrevi PSC
with the exception that after all cumulative capital costs have been recovered
by CanArgo Norio, remaining production after deduction of operating costs is
allocated on a 60/40 basis between Georgian Oil and CanArgo Norio, respectively.
Thus, while CanArgo Norio is responsible for all of the costs associated with
development of the Norio PSA, it is only entitled to receive 40% of production
after cost recovery. We currently own a 75% controlling interest in CanArgo
Norio with the remainder held by private investors.
The first phase of the preliminary work program under the Norio PSA involved
primarily a seismic survey of a portion of the exploration area and the
processing and interpretation of the data collected. The seismic survey has been
completed, and the results of those studies have and will continue to be
interpreted. In addition to the main target, which is the Middle Eocene, the
potential of the license area to produce from the Miocene, Sarmatian, Upper
Eocene and Cretaceous is being assessed. The cost of the seismic program was
approximately $1.5 million.
The second phase of the preliminary work program under the Norio PSA commenced
in January 2002 with the first exploration well named MK72 drilled on a large
prospect identified at Middle Eocene level which is the productive horizon in
both the Ninotsminda and Samgori Fields to the south and east. The Samgori Oil
Field has produced approximately 180 million barrels of oil to date.
The MK72 well was initially drilled to a depth of 9,620 feet (2,932 meters), at
which depth the well was suspended in August 2002 due to lack of available
funding at that time. Downhole seismic data acquired in the well bore indicated
the target may be at a depth of approximately 13,780 feet (4,200 meters), and
CanArgo Norio did not have
16
sufficient funding to complete the well to that depth. However the State Agency
for the Regulation of Oil and Gas Resources in Georgia confirmed that CanArgo
Norio had satisfied all drilling and work obligations under the terms of the
Norio PSA by the initial phase of drilling of the MK72 well.
In connection with this initial phase of drilling, which cost a total of $4.3
million, CanArgo's partner in CanArgo Norio sought to farm-out to CanArgo and to
third party investors part of its interest in CanArgo Norio to partly fund the
drilling of the MK72 well. One of these third party investors was Provincial
Securities Limited, an investment company to which Mr. Russell Hammond, a
non-executive director of CanArgo, is an Investment Advisor. CanArgo Norio's
total share of these drilling costs was $3.1 million. In November 2002,
shareholders of CanArgo Norio agreed to adjust the ownership of CanArgo Norio to
reflect the funding for the MK72 well, and capitalization of certain loans and
management fees that CanArgo had made to CanArgo Norio. Under this agreement,
CanArgo's interest increased from 50% to 64.2% in CanArgo Norio. CanArgo Norio
then sought a partner to assist with the financing to deepen the MK72 well.
In September 2003, CanArgo Norio signed a farm-in agreement relating to the
Norio PSA with a wholly owned subsidiary of Georgian Oil, the Georgian State Oil
Company. CanArgo Norio had previously been in negotiations with a large third
party energy company to farm-in to the Norio PSA, but Georgian Oil exercised its
pre-emption rights under the Norio PSA. Georgian Oil is already a party to the
Norio PSA as the commercial representative of the State. The farm-in agreement
obligates Georgian Oil to pay up to $2.0 million to deepen, to a planned depth
of 16,400 feet (5,000 meters) the MK-72 well in return for a 15% interest in the
contractor share of the Norio PSA. Georgian Oil also has an option (the
"Option"), exercisable for a limited period after completion of the well, to
increase its interest to 50% of the contractor share of the Norio PSA on payment
to CanArgo Norio of US$ 6.5 million. If Georgian Oil exercises this Option under
the farm-in agreement, it loses its rights to exercise the PSA Option under the
Norio PSA itself.
Co-incident with the Georgian Oil farm-in, CanArgo concluded a deal to purchase
some of the minority interests in CanArgo Norio by a share swap for shares in
CanArgo. Through this exchange CanArgo has acquired an additional 10.8% interest
in CanArgo Norio, giving CanArgo a 75% interest in CanArgo Norio at present.
This approximately maintains CanArgo's effective interest in the Norio PSA after
Georgian Oil has completed the first stage of the farm-in at 63.7%. The purchase
was achieved by issuing 6 million restricted CanArgo common shares to the
minority interest holders in CanArgo Norio. Of the interests in CanArgo Norio,
Provincial Securities Limited owned 4%. In the event that Georgian Oil exercises
the Option and pays the required $6.5 million, CanArgo (which would have
received some $4.8 million of this payment with its previous interest) would
receive a further $1.2 million, resulting in a total payment to CanArgo of
approximately $6 million. If Georgian Oil exercises this Option CanArgo will
issue a further 3 million restricted shares to the minority interest holders.
Drilling at the MK72 well, funded by Georgian Oil, recommenced in December 2003
and by March 16, 2004 total depth had reached approximately 4,200 meters.
This is an important well in management's opinion since several additional high
potential prospects may exist on trend within the licence area.
As the area in which we are currently drilling is an exploration area with no
commercial discoveries (excluding the small shallow fields currently operated by
Georgian Oil), it is not possible to estimate the expenditures needed to
discover and, if discovered, produce commercial quantities of oil and gas.
Block XI(G) and XI(H) Production Sharing Contract ("Tbilisi PSC")
In November 2002, CanArgo's subsidiary, CanArgo Norio, won the tender for the
oil and gas exploration and production rights to the Tbilisi PSC an area of
approximately 119,843 acres (485 km(2)) in eastern Georgia adjacent to the
Norio, Block XIII and West Rustavi areas. In July 2003, it was announced that
CanArgo Norio, had signed a Production Sharing Contract covering these areas.
CanArgo Norio views these blocks as having good potential, being adjacent to
productive acreage and with some existing wells on the blocks. The commercial
terms of the Tbilisi PSC are similar to those of the Norio PSA with the
exception that Georgian Oil does not have an option to acquire an interest in
the contractor party's share following a commercial discovery. CanArgo Norio
will evaluate
17
existing seismic and geological data during the first year and acquire
additional seismic data within four years of the effective date of the Contract
which was set as 29 September 2003. The total commitment over the next four
years is $350,000. The abovementioned Georgian Oil farm-in to the Norio PSA does
not apply to the Tbilisi PSC.
Block XI(B) Production Sharing Contract ("Samgori PSC")
In February 2004 CanArgo announced that it has obtained State regulatory
approval to an agreement to obtain 50% of the Contractor's interest in the
Samgori PSC in Georgia and a 50% interest in the licence holder for Block XIB
covering the Samgori Oil Field. Regulatory approval was a key condition to the
agreement and the other conditions are expected to be satisfied in due course.
This interest is being acquired from Georgian Oil Samgori Limited ("GOSL"), a
company wholly owned by the Georgian Oil. Under the terms of the agreement, up
to 10 horizontal wells will be drilled on the Samgori Field, which is the
largest oilfield discovered to date in Georgia and lies adjacent to CanArgo's
Ninotsminda Field. We have been advised that Samgori has produced over 180
million barrels (MMbbl) of oil to date at rates up to 70,000 barrels of oil per
day (bopd).
The Samgori Field complex was discovered in 1974 and produces from the same
Middle Eocene sequence as the Ninotsminda Field. Recent studies by Georgian Oil
(which have not been independently assessed), based on new seismic data acquired
in 2001, indicate that up to 55 MMbbl of oil could be recovered from the Samgori
complex utilising horizontal drilling techniques. Current production from the
Field is approximately 700 bopd. Under the proposed farm-in, CanArgo will be
entitled to an immediate share of this production upon completion of the farm-in
agreement. In addition, Block XI(B) which covers an area of approximately
169,514 acres (634 km(2)) contains several identified prospects and discoveries
in other horizons, notably the Upper Eocene and Cretaceous.
REFINING AND OTHER ACTIVITIES
CanArgo also engages in oil and gas, refining and other activities in Georgia.
Segment and geographical information including revenue from continuing
operations from external customers, operating profit (loss) from continuing
operations and total assets is incorporated herein by reference from note 18 to
the consolidated financial statements.
Georgian American Oil Refinery
The Georgian American Oil Refinery ("GAOR") remained in a care and maintenance
condition during 2003 and we disposed of our 51% interest in the refinery in
February 2004. During 2003, a debit balance of $1,274,895 in minority interest
was written-off due to a change in the intentions of our minority interest owner
and plan to dispose of the asset. In 2004, CanArgo came to an agreement to sell
the refinery.
Drilling Rigs and Associated Equipment
We own several items of drilling equipment, and other related machinery
primarily for use in our Georgian operations. These include three drilling rigs,
pumping equipment and ancillary machinery. In addition, we have signed an
agreement to sell our mobile 3-megawatt duel fuel power plant for $600,000 and
have received a nonrefundable deposit of $300,000. It is expected that transfer
of title for this equipment and the final payment of $300,000 will take place
during the second quarter 2004. This asset is classified and reflected in our
financial statements in "Assets held for sale" for all periods presented. The
rigs and related equipment are used in our Georgian operations, and from time to
time have also been leased out to other operators on a service basis or used by
the company to perform drilling services for other operators.
In September 2001, we entered into an agreement to provide drilling services to
a third party using one of our rigs. Commercial drilling operations commenced in
October 2001 and continued through February 2002. The company subsequently
established a wholly owned well services subsidiary (Argonaut Well Services
Limited) and at the end of March 2003 concluded a new drilling service contract
with an operating company in Georgia. We will continue to bid in appropriate
tenders for drilling contracts in order to utilise drilling equipment not
otherwise used in our own operations.
18
Potential Caspian Exploration Project
In May 1998, CanArgo led a consortium which submitted a bid in a tender for two
large exploration blocks in the Caspian Sea, located off the shore of the
autonomous Russian Republic of Dagestan. The consortium was the successful
bidder in the tender and was awarded the right to negotiate licenses for the
blocks. Following negotiations, licenses were issued in February 1999 to a
majority-owned subsidiary of CanArgo. During 1999 CanArgo concluded that it did
not have the resources to advance this project. Accordingly, in November 1999,
CanArgo reduced its interest to a 9.5%. Subsequent to this, a restructuring of
interests in the project took place with CanArgo increasing its interest
slightly to 10%, and with Rosneft, the Russian State owned oil company, becoming
the majority owner of the project with 75.1%. Seismic was acquired as part of
this restructuring and future plans include interpretation of this data and
possible drilling. However our small interest in this project, and the lack of
an effective joint operating agreement, means that we have little control of the
operator for the project, and any further investment by CanArgo will take this
into account.
Potential Kazakhstan Project
In December 2003, we announced details of the acquisition of oil and gas
interests in Kazakhstan which were previously owned by the UK public company
Atlantic Caspian Resources plc ("ACR"). We intend to acquire these interests
through a newly established associated company, Tethys Petroleum Investments
Limited ("TPI") which will acquire ACR's 70% interest in BN Munai LLP ("BNM"), a
Kazakh limited liability partnership on certain conditions being satisfied.
BNM's interests center on the Akkulkovsky exploration area and the Kyzyloy Gas
Field, located in western Kazakhstan, just to the west of the Aral Sea.
Registration of TPI's interest in BNM is underway and should be completed in the
near future. Until this registration is completed, TPI rights to BNM are not
finalized. In addition, the license position with regard to the Akkulkovsky
exploration area is currently subject to review by the Kazakh authorities and
further negotiation is required to potentially secure this. The consideration
for the acquisition involved ACR taking a fully paid 10% interest in TPI, but
with no cash consideration from CanArgo. Provincial Securities Limited, an
investment company to which Mr. Russell Hammond, one of our non-executive
directors, is an Investment Advisor, was involved in negotiating the acquisition
and the potential future development of TPI, and as such has a significant
minority shareholding in TPI. We operate TPI under a Management Services
Agreement, however it is intended that the further development of TPI will be
primarily funded by third party investment. We expect to retain a significant
minority shareholding in TPI. Under ACR's ownership BNM has drilled two deep
exploration wells in the Akkulkovsky area over the past three years, both of
these wells being plugged and abandoned with hydrocarbon shows. However, we
believe that the short term potential may lie in the shallower Kyzyloy Gas
Field. This is a discovered shallow gas field, located approximately 35 km from
the main Bukhara - Urals gas pipeline system, and close to the Bazoy gas storage
and compression facility. Additional, shallow gas indicators are apparent on
seismic data, which, if successfully tested, potentially could be added to any
development of the Kyzyloy Field.
DISCONTINUED OPERATIONS
CanArgo Standard Oil Products
In September 2002, CanArgo approved a plan to sell CanArgo Standard Oil Products
to finance Georgian and Ukrainian development projects and in October 2002,
CanArgo agreed to sell its 50% holding to Westrade Alliance LLC, an unaffiliated
company, for $4 million in an arms-length transaction, with legal ownership
being transferred upon receipt of final payment due in August 2003. CanArgo
agreed subsequently to re-schedule this payment in return for, the purchaser
paying some of the funds early and paying interest on the outstanding balance at
a an annual rate of 16% payable monthly. To date a total of $2,200,000 has been
received with a further $1,800,000 to be paid by end of June 2004. Discontinued
Operation activity is incorporated herein by reference from note 17 to the
consolidated financial statements.
CanArgo Standard Oil Products sells several different grades of petrol to a
broad range of corporate and retail customers. No one customer purchases more
than 10% of total sales.
19
GAOR
In 2003, CanArgo approved a plan to dispose of its interest in GAOR as the
refiner had remained closed since 2001 and neither CanArgo nor its partners
could find a commercially viable option to putting the refinery back into
operation. In February 2004, we reach agreement with a local Georgian company to
sell our 51% interest in GAOR for a nominal price of one US dollar and the
assumption of all the obligations and debts of GAOR to the State of Georgia
including deferred tax liabilities of approximately $380,000. In 2003 we
announced publicly that we were re-evaluating our treatment in our 2001 and 2002
financial statements of our minority interest in GAOR. After reviewing the basis
for our accounting for our interest in GAOR and after discussions with our
former auditors we have concluded that our interest was properly accounted for
in those statements.
Bugruvativske Field, Ukraine
In April 2001, we acquired approximately 82% (77% on a fully diluted basis) of
the outstanding common shares of Lateral Vector Resources Inc. ("LVR") pursuant
to an unsolicited offer to purchase all of its outstanding common shares.
According to publicly available information at the time we made our offer in
March 2001, LVR negotiated and concluded with Ukrnafta, the Ukrainian State Oil
Company, a Joint Investment Production Activity ("JIPA") agreement in 1998 to
develop the Bugruvativske Oil Field located in Eastern Ukraine. In July 2001, we
completed the acquisition of the remaining outstanding common shares and LVR
became a wholly owned subsidiary of CanArgo. The appointed operator under the
JIPA agreement and party to the JIPA (0.1%) is IPEC, a local Ukrainian company,
owned 85% by LVR. In July 2002, LVR acquired the remaining 15% in IPEC and IPEC
became a wholly owned subsidiary of LVR.
In September 2002, we agreed terms with Ukrnafta on revisions to the existing
JIPA agreement and reached an agreement with an unaffiliated local Ukrainian oil
and gas company on the terms of a farm-in to the JIPA. The terms of the farm-in,
arrived at in arms-length negotiations, were that the local Ukrainian oil and
gas company through its acquisition of IPEC would invest approximately $3
million in the Bugruvativske Field over the course of 12 months in order to
drill two new wells while bearing the financial risk under the JIPA during this
period. LVR could match up to the amount invested by IPEC prior to December 31,
2003. The revised JIPA provided that (assuming LVR matched IPEC's initial
expenditure) LVR would be entitled to approximately 34.5% of net profits
generated under the JIPA (or a proportionally smaller amount if the amount
invested was less than that invested by IPEC). LVR had no obligation to invest
in the JIPA, however in the event that LVR decided not to invest in the project
by December 31, 2003 and IPEC satisfied the terms of the farm-in, it would still
receive an ongoing project fee of between 3 - 4 % of the net profits generated
under the JIPA in recognition of its earlier involvement in the project.
As of September 30, 2003, IPEC had transferred only $1 million to the JIPA
account and drilling operations under the JIPA had not yet commenced due to
ongoing disagreements that IPEC and LVR have with Ukrnafta where the latter is
conducting independent operations on a well that was to be the subject of joint
activity under the JIPA. At December 31, 2003, the dispute with Ukrnafta
remained unresolved and there are no assurances that the dispute with Ukrnafta
can be resolved to the satisfaction of the company.
Due to the lack of progress with the implementation of the JIPA in 2003, and
failure to reach a negotiated agreement with Ukrnafta, management reached the
decision to dispose of its interest in the Bugruvativske project and withdraw
from Ukraine. The company is currently in negotiations with a potential buyer
for the disposal of its 100% interest in LVR. Consequently, CanArgo recorded in
2003 a write-down in respect to the LVR deal and the acquisition of the
Bugruvativske Field of approximately $4.8 million.
CanArgo has now effectively withdrawn from Ukraine, in order to focus on its
Georgian activities, having disposed of its interest in the Stynawske Field in
Western Ukraine in 2003. In September 2003, CanArgo announced it had reached
conditional agreement to sell its interest in Boryslaw Oil Company ("BOC"), the
joint venture in West Ukraine which operates the Stynawske Field. Fountain Oil
Boryslaw ("FOB"), CanArgo's wholly owned subsidiary which holds its 45% interest
in BOC, was sold for $1,000,000 payable in eight equal tranches. Final payment
was
20
received in November 2003 and ownership in FOB was transferred to the buyer. The
buyer has also acknowledged BOC's debts to CanArgo for earlier loans in the
total amount of $160,000.
3-megawatt duel fuel power generator
In 2003, CanArgo signed a sales agreement disposing of a 3-megawatt duel fuel
power generator for $600,000. Following receipt of a non-refundable deposit of
$300,000, the unit was shipped to the US for testing. The test is due to be
completed in the near future at which time the generator will be delivered to
the buyer following receipt of the final payment.
EMPLOYEES
As of December 31, 2003, CanArgo had 279 full time employees. Of its full time
employees, the entity acting as operator of the Ninotsminda Field for
Ninotsminda Oil Company has 114 full time employees, and substantially all of
that company's activities relate to the production and development of the
Ninotsminda Field. CanArgo Standard Oil Products has 153 full time employees at
its office and petrol stations. We have not experienced any strikes, work
stoppages or other labour disputes and management believes the company's
relations with its employees are satisfactory.
RISKS ASSOCIATED WITH CANARGO'S ACTIVITIES
CanArgo's ability to generate cash flows
Our ability to continue to pursue our principal activities of acquiring
interests in and developing oil and gas fields is dependent upon reducing costs,
generating funds from internal sources including the sale of certain non-core
assets, external sources and, ultimately, maintaining sufficient positive cash
flows from operating activities.
Our financial statements have been prepared on a basis which assumes that
operating cash flows, additional funding and/or proceeds from the sale of
non-core assets received meet our cash flow needs. If these operating cash
flows, additional financings, and in particular the receipt of the final
$1,800,000 payment from the sale of CSOP are not received, adjustments may have
to be made to our business plan which will limit our development and exploration
activities.
Development of the oil and gas properties and ventures in which we have
interests involves multi-year efforts and substantial cash expenditures. Full
development of these properties will require the availability of substantial
funds from internal and/or external sources. We believe that we will be able to
generate funds from quasi-governmental financing agencies, conventional lenders,
equity investors and other oil and gas companies that may desire to participate
in our oil and gas projects. Although funds are not yet available, in February
2004, we announced that we had signed a Standby Equity Distribution Agreement
that allows us, at our option, to issue shares to US-based investment fund
Cornell Capital Partners LP up to a maximum value of $20 million over a period
of up to two years. This facility cannot be exercised until the SEC has declared
a Registration Statement effective (See "Item 7- Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources" for a more detailed discussion).
Current Operations Dependent on Success of the Ninotsminda Field and Georgian
Exploration
We have directed substantially all of our efforts and most of our available
funds to the development of the Ninotsminda Field in the Republic of Georgia,
exploration in that area and some ancillary activities closely related to the
Ninotsminda Field project. This decision is based on management's assessment of
the potential of the Ninotsminda Field area. However, the company's focus on the
Ninotsminda Field has over the past several years resulted in overall losses for
us and we have yet to be profitable. There can be no assurances that the
exploration and development plans for the Ninotsminda Field will be successful.
For example, the Ninotsminda Field may not produce sufficient quantities of oil
and gas to justify the investments made and the planned future investments for
the Field, and we may not be able to produce the oil and gas at a sufficiently
low cost or to market the oil and gas
21
produced at a sufficiently high price to generate a positive cash flow and a
profit. Our Georgian exploration and appraisal program is an important factor
for future success and this program may not be successful, as it carries
substantial technical risk.
Minimum Investment Requirements in the Bugruvativske Field in Ukraine Have Not
Been Met
Under the terms of the farm-in agreement signed in September 2002 with us, a
local Ukrainian oil and gas company was required to invest approximately $3
million in the Bugruvativske Field in Ukraine under the Joint Investment
Production Activity (JIPA) agreement over the course of 12 months in order to
drill two new wells and would bear the financial risk during this period. We
could match up to the amount invested by the farminee, prior to December 31,
2003 in order to be entitled to approximately 34.5% of net profits generated
from the project (or a proportionally smaller amount if the amount invested was
less than that invested by the farminee). In the event that we decided not to
invest in the project by December 31, 2003, we would receive an ongoing project
fee of between 3-4 % of the net profits generated under the JIPA in recognition
of our earlier involvement in the project. At December 31, 2003, neither the
farminee nor we had met their respective investment requirements under the JIPA
due to an ongoing dispute with Ukrnafta, the other participant to the JIPA. At
the present time, there are no assurances that the dispute with Ukrnafta can be
resolved to the satisfaction of the company and consequently hydrocarbon
reserves are classified as unproved until the dispute is resolved and our
investment is made. We are currently trying to sell our interest in this
project.
Write Off of Unsuccessful Properties and Projects
In order to realize the carrying value of our oil and gas properties and
ventures, we must produce oil and gas in sufficient quantities and then sell
such oil and gas at sufficient prices to produce a profit. We have a number of
unevaluated oil and gas properties. The risks associated with successfully
developing unevaluated oil and gas properties are even greater than those
associated with successfully continuing development of producing oil and gas
properties, since the existence and extent of commercial quantities of oil and
gas in unevaluated properties have not been established.
Possible Inability to Finance Present Oil and Gas Projects
Our ability to finance all of our present oil and gas projects and other
ventures according to present plans is dependent upon obtaining additional
funding. An inability to obtain financing could require us to scale back or
abandon part or all of our project development, capital expenditures, production
and other plans. Apart from the evaluation of the economics of specific
investment proposals, the availability of equity or debt financing to us, or to
the entities that are developing projects in which we have interests, is
affected by many factors, including:
- world and regional economic conditions;
- the state of international relations;
- the stability and legal, regulatory, fiscal and tax policies
of various governments in areas in which we have or intend to
have operations;
- fluctuations in the world and regional price of oil and gas
and in interest rates;
- the outlook for the oil and gas industry in general and in
areas in which we have or intend to have operations; and
- competition for funds from possible alternative investment
projects.
Potential investors and lenders will also be influenced by their evaluations of
us and our projects, including their technical difficulty, and the comparison
with available alternative investment opportunities.
Additional Funds Needed For Long-Term Oil and Gas Development Plans
It will take many years and substantial cash expenditures to develop fully our
oil and gas properties. The company generally has the principal responsibility
to provide financing for its oil and gas properties and ventures. Accordingly,
we need to raise additional funds from outside sources in order to pay for
project development costs
22
beyond those currently budgeted through 2004. We may not be able to obtain that
additional financing, or such funds may only be available on commercially
unattractive terms. If, in either such case, adequate funds are not available,
it will be necessary to scale back or even suspend operations. The carrying
value of the Ninotsminda Field may not be realized unless additional capital
expenditures are incurred to develop the Field. Furthermore, additional funds
will be required to pursue exploration activities on our existing undeveloped
properties. While expected to be substantial, without further exploration work
and evaluation the amount of funds needed to fully develop all of our oil and
gas properties cannot at present, be quantified.
Oil and Activities Involve Risks, Many of Which Are Beyond Our Control
Our exploration, appraisal, development and production activities are subject to
a number of factors and risks, many of which may be beyond our control. First,
we must successfully identify commercial quantities of oil and gas. The
exploration and development of an oil and gas deposit can be affected by a
number of factors which are beyond the operator's control, such as:
- unexpected or unusual geological conditions;
- the recoverability of the oil and gas on an economic basis;
- the availability of infrastructure, equipment and personnel to
support operations;
- local and global oil prices; and
- government regulation and legal uncertainties.
The company's activities can also be affected by a number of hazards, such as:
- labour disputes;
- natural phenomena, such as bad weather and earthquakes;
- operating hazards, such as fires, explosions, blow-outs, pipe
failures and casing collapses; and
- environmental hazards, such as oil spills, gas leaks, ruptures
and discharges of toxic gases.
Any of these hazards could result in damage, losses or liability for the
company. There is also an increased risk of some of these hazards in connection
with operations that involve the rehabilitation of fields where less than
optimal practices and technology were employed in the past, as was often the
case in the former Soviet Union. We do not purchase insurance covering all of
the risks and hazards that are involved in oil and gas exploration, development
and production.
Risk of Political Instability with Respect to Foreign Operations
Our principal oil and gas properties and activities are in the Republic of
Georgia, which is located in the former Soviet Union. Operation and development
of these assets is subject to a number of conditions endemic to former Soviet
Union countries, including political instability. The present governmental
arrangements in the former Soviet Union in which CanArgo operates were
established relatively recently, when they replaced Communist regimes. If they
fail to maintain the support of their citizens, other institutions, including a
possible reversion to totalitarian forms of government, could themselves replace
these governments. Our operations typically involve joint ventures or other
participatory arrangements with the national government or state-owned
companies.
The PSC covering the Ninotsminda Field is an example of such an arrangement. As
a result of such dependency on government participants, our operations could be
adversely affected by political instability, changes in government institutions,
personnel, policies or legislation, or shifts in political power. There is also
the risk that governments could seek to nationalize, expropriate or otherwise
take over our oil and gas properties. We are not insured against such political
risks because management deems the premium costs of such insurance to be
currently prohibitively expensive.
Risk of Social, Economic and Legal Instability
23
The political institutions in the countries which comprise the former Soviet
Union have recently become more fragmented, and the economic institutions of
many of these countries have only recently converted to a market economy from a
planned economy. New laws have been introduced, and the legal and regulatory
regimes in such regions are often vague, containing gaps and inconsistencies,
and are constantly subject to amendment. Application and enforceability of these
laws may also vary widely from region to region within these countries. Due to
this instability, former Soviet Union countries are subject to certain
additional risks including the following:
- uncertainty as to the enforceability of contracts;
- sudden or unexpected changes in demand for crude oil and or
natural gas;
- the lack of trained personnel; and
- the lack of equipment and services and the presence of other
factors that could significantly change the economics of
production.
In early 2002, the Georgian government requested assistance from the United
States to combat terrorism in the Pankisi Gorge, a region of Georgia bordering
the separatist Chechnya region of Russia. Social, economic and legal instability
have accompanied these changes due to many factors which include:
- low standards of living;
- high unemployment;
- undeveloped and constantly changing legal and social
institutions; and
- conflicts within and with neighbouring countries.
This instability can make continued operations in affected regions difficult or
impossible.
Inadequate or Deteriorating Infrastructure in the Former Soviet Union
Countries in the former Soviet Union often either have underdeveloped
infrastructures or, as a result of shortages of resources, have permitted
infrastructure improvements to deteriorate. The lack of necessary infrastructure
improvements can adversely affect operations. For example, the lack of a
reliable electrical power supply caused Ninotsminda Oil Company to suspend
drilling of one well and the testing of a second well during the 1998-1999
winter season, although the availability of electrical power supplies has been
more regular since that time.
Currency Risks in the Former Soviet Union
Payment for oil and gas products sold in the former Soviet Union countries may
be in local currencies. Although we currently sell our oil principally for U.S.
dollars, we may not be able to continue to demand payment in hard currencies in
the future. Although most former Soviet Union country currencies are presently
convertible into U.S. dollars, there is no assurance that convertibility will
continue. Even if currencies are convertible, the rate at which they convert
into U.S. dollars is subject to fluctuation. In addition, the ability to
transfer currencies into or out of the former Soviet Union countries may be
restricted or limited in the future.
We may enter into contracts with suppliers in former Soviet Union countries to
purchase goods and services in U.S. dollars. The company may also obtain from
lenders credit facilities or other debt denominated in U.S. dollars. If we
cannot receive payment for oil and oil products in U.S. dollars and the value of
the local currency relative to the U.S. dollar deteriorates, we could face
significant negative changes in working capital.
Tax Risks in the Former Soviet Union
Countries in the former Soviet Union frequently add to or amend existing
taxation policies in reaction to economic conditions including state budgetary
and revenue shortfalls. Since we are dependent on international operations,
specifically those in Georgia, we may be subject to changing taxation policies
including the possible imposition of confiscatory excess profits, production,
remittance, export and other taxes. While we are not aware of any recent or
proposed tax changes which could materially adversely affect our operations,
such changes could occur although we
24
have negotiated economic stabilization clauses in our production sharing
agreements in Georgia and all current taxes are payable from the State's share
of petroleum produced under the production sharing contracts.
Conflicting Interests with our Partners
Joint venture, acquisition, financing and other agreements and arrangements must
be negotiated with independent third parties and, in some cases, must be
approved by governmental agencies. These third parties generally have objectives
and interests that may not coincide with those of the company and may conflict
with our interests. Unless we are able to compromise these conflicting
objectives and interests in a mutually acceptable manner, agreements and
arrangements with these third parties will not be consummated.
We may not have a majority of the equity in the entity that is the licensed
developer of some projects, that we may pursue in the former Soviet Union, even
though we may be the designated operator of the oil or gas field. In such
circumstances, the concurrence of co-ventures may be required for various
actions. Other parties influencing the timing of events may have priorities that
differ from ours, even if they generally share the same objectives. Demands by
or expectations of governments, co-venturers, customers, and others may affect
our strategy regarding the various projects. Failure to meet such demand or
expectations could adversely affect our participation in such projects or its
ability to obtain or maintain necessary licenses and other approvals.
Demands by or expectations of governments, co-venturers, customers and others
may also affect our strategy regarding various projects. Failure to meet such
demands or expectations could adversely affect our participation in such
projects or our ability to obtain or maintain necessary licenses and other
approvals.
Governmental Registration
Operating entities in various foreign jurisdictions must be registered by
governmental agencies, and production licenses for development of oil and gas
fields in various foreign jurisdictions must be granted by governmental
agencies. These governmental agencies generally have broad discretion in
determining whether to take or approve various actions and matters. In addition,
the policies and practices of governmental agencies may be affected or altered
by political, economic and other events occurring either within their own
countries or in a broader international context.
Changes in the Market Price of Oil and Gas
Prices for oil and natural gas and their refined products are subject to wide
fluctuations in response to a number of factors which are beyond CanArgo's
control, including:
- global changes in the supply and demand for oil and natural
gas;
- actions of the Organization of Petroleum Exporting Countries;
- weather conditions;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political conditions in the Middle East and elsewhere; and
- overall global and regional economic conditions.
A reduction in oil prices can affect the economic viability of our operations.
There can be no assurance that oil prices will be at a level that will enable us
to operate at a profit. In 2002, the spot price for Brent crude oil increased
from $19.29 per barrel at December 31, 2001 to $31.98 per barrel at December 31,
2002. We may also not benefit from continued increases in oil prices as have
occurred during 2003 as the market for the levels of crude oil produced in
Georgia by Ninotsminda Oil Company can in such an environment be relatively
inelastic and contract prices are often set at a specified price determined with
reference to Brent oil prices when the contract is entered into or over a short
period when the crude oil is delivered.
25
Oil and Gas Production Could Vary Significantly From Reserve Estimates
Estimates of oil and natural gas reserves and their values determined by
petroleum engineers are inherently uncertain. These estimates are based on
professional judgments about a number of elements:
- the amount of recoverable crude oil and natural gas present in
a reservoir;
- the costs that will be incurred to produce, transport and
market the crude oil and natural gas; and
- the rate at which production will occur.
Reserve estimates are also based on evaluations of geological, engineering,
production and economic data. The data can change over time due to, among other
things:
- additional development activity;
- evolving production history; and
- changes in production costs, market prices and economic
conditions.
As a result, the actual amount, cost and rate of production of oil and gas
reserves and the revenues derived from sale of the oil and gas produced in the
future will vary from those anticipated in the most recent report on our oil and
gas reserves prepared by OPC as of January 1, 2004. The magnitude of those
variations may be material.
The rate of production from crude oil and natural gas properties declines as
reserves are depleted. Except to the extent we acquire additional properties
containing proved reserves, conduct successful exploration and development
activities or, through engineering studies, identify additional productive zones
in existing wells or secondary recovery reserves, our proved reserves will
decline as reserves are produced. Future crude oil and natural gas production is
therefore highly dependent upon our level of success in replacing depleted
reserves.
Oil and Gas Operations are Subject to Extensive Governmental Regulation
Governments at all levels, national, regional and local, regulate oil and gas
activities extensively. We must comply with laws and regulations which govern
many aspects of our oil and gas business, including:
- exploration;
- development;
- production;
- refining;
- marketing;
- transportation;
- occupational health and safety;
- labour standards; and
- environmental matters.
We expect the trend towards more burdensome regulation of our business to result
in increased costs and operational delays. This trend is particularly applicable
in developing economies, such as those in the former Soviet Union where we have
our principal operations. In these countries, the evolution towards a more
developed economy is often accompanied by a move towards the more burdensome
regulations that typically exist in more developed economies.
26
Competition
The oil and gas industry including the refining and marketing of crude oil
products is highly competitive. Our competitors include integrated and
independent oil and gas companies. Many of our competitors are large,
well-established, well-financed companies. Because of our small size and our
lack of financial resources, we may not be able to compete effectively with
these companies.
Operations are Dependent on Chairman of the Board and Chief Executive
Dr. David Robson, the Chairman of the Board and Chief Executive Officer of
CanArgo, is our executive who has the most experience in the oil and gas
industry and who has the most extensive business relationships in the former
Soviet Union. Our business and operations could be significantly harmed if Dr.
Robson were to leave the company or become unavailable because of illness or
death. Dr. Robson through his company, Vazon Energy Limited, has signed a
comprehensive Management Services Agreement with a rolling six-month notice
period and a two-year non-competition clause effective from the date of
termination of the agreement. We do not carry key employee insurance on any of
our employees.
ITEM 3. LEGAL PROCEEDINGS
At December 31, 2003 there were no legal proceedings pending involving CanArgo
which, if adversely decided, would have a material adverse effect on CanArgo's
financial position or business. From time to time we are subject to various
legal proceedings in the ordinary course of our business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of our security holders during the fourth
quarter of the year ended December 31, 2003.
27
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
CanArgo has a primary listing on the Oslo Stock Exchange ("OSE") where our
common stock trades under the symbol "CNR".
Our common stock is also traded on the Over the Counter Bulletin Board ("OTCBB")
under the symbol "GUSH.OB", and as a result of this stockholders may:
- find it more difficult to obtain accurate and timely quotations
regarding the bid and asked prices for common stock;
- experience greater spreads between bid and asked prices;
- be charged relatively higher transactional costs when buying or selling
common stock; and
- encounter more difficulty in effecting sales or purchases of common
stock.
In addition, while securities listed on national securities exchanges and the
NASDAQ National Market System are exempt from the registration requirements of
state securities laws, securities traded on the OTCBB must comply with the
registration requirements of state securities laws, which increases the time and
costs associated with complying with state securities laws when raising capital.
The listing of our common stock on the OSE had until October 2000, been a
secondary listing, with the primary listing being on the NASDAQ Stock Market.
The following table sets forth the high and low sales prices of the common stock
on the OSE, and the high and low bid prices on the OTCBB for the periods
indicated. Average daily trading volume on these markets during these periods is
also provided. OTCBB data is provided by the NASDAQ Trading and Market Services
and/or published financial sources and OSE data is derived from published
financial sources. The over-the-counter quotations reflect inter-dealer prices,
without retail mark-up, markdown or commissions, and may not represent actual
transactions. Sales prices on the OSE were converted from Norwegian kroner into
United States dollars on the basis of the daily exchange rate for buying United
States dollars with Norwegian kroner announced by the central bank of Norway.
Prices in Norwegian kroner are denominated in "NOK". For historical price
verification in Norway please see
http://uk.table.finance.yahoo.com/k?s=cnr.ol&g=d and for exchange rate
conversion $/NOK for the corresponding dates please see
www.oanda.com/convert/fxhistory.
OTCBB OSE
-------------------------- --------------------------
AVERAGE AVERAGE
HIGH LOW DAILY VOLUME HIGH LOW DAILY VOLUME
---- ---- ------------ ---- ---- ------------
FISCAL QUARTER ENDED
March 31, 2002 0.36 0.26 32,697 0.36 0.25 550,687
June 30, 2002 0.38 0.19 3,508 0.32 0.14 250,000
September 30, 2002 0.20 0.05 9,156 0.20 0.05 256,500
December 31, 2002 0.15 0.04 29,404 0.08 0.04 712,500
March 31, 2003 0.11 0.03 35,575 0.06 0.04 273,079
June 30,2003 0.22 0.05 41,739 0.24 0.05 1,127,948
September 30, 2003 0.47 0.10 29,714 0.49 0.16 1,936,776
December 31,2003 0.69 0.26 107,109 0.54 0.27 1,582,019
At February 27, 2004, the closing price of our common stock on the OTCBB and THE
OSE was $ 0.99 and $ 0.95, respectively. On February 27, 2004 one U.S. dollar
equalled 7.0645 Norwegian kroner.
On February 27, 2003 the number of holders of record of our common stock was
approximately 8,000. We have not paid any cash dividends on our common stock. We
currently intend to retain future earnings, if any, for use in our business and,
therefore, do not anticipate paying any cash dividends in the foreseeable
future. The payment of future
28
dividends, if any, will depend, among other things, on our results of operations
and financial condition and on such other factors as our Board of Directors may,
in their discretion, consider relevant.
On September 4, 2003, co-incident with the Georgian Oil farm-in to the Norio
PSA, CanArgo issued 6,000,000 shares of common stock at an imputed price of
$0.19 to buy out certain minority shareholders in CanArgo Norio. Four percent
(4.0%) of these minority interests were owned by Provincial Securities Limited,
a company for which Mr. Russell Hammond, a non-executive director of CanArgo, is
an Investment Advisor. The shares, issued to purchasers previously identified in
a prospectus filed as part of a registration statement on Form S-1 (file no.
333-67814), were issued as restricted securities as that term is defined in Rule
144 under the Securities Act in a transaction intended to qualify for the
exemption from registration afforded by Section 4(2) thereunder and may not be
offered for sale, sold or otherwise transferred except pursuant to an effective
registration statement under the Securities Act or pursuant to an exemption from
registration under the Securities Act.
On December 17, 2003 CanArgo issued 261,782 restricted shares at $0.32 per share
to Cornell Capital as part of the commission for a Standby Equity Distribution
Agreement, which is described in greater detail in the section in Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" entitled "Liquidity and Capital Resources- Cornell Equity Facility".
On February 11, 2004 we issued an additional 163,218 restricted shares of common
stock to Cornell Capital and 30,799 restricted shares of common stock to
Newbridge Securities in connection with entering into a new, expanded equity
facility also described in detail in such section of Item 7. The shares issued
to Cornell Capital were issued as restricted securities as that term is defined
in Rule 144 under the Securities Act in transactions intended to qualify for the
exemption from registration afforded by Section 4(2) thereunder and may not be
offered for sale, sold or otherwise transferred except pursuant to an effective
registration statement under the Securities Act or pursuant to an exemption from
registration under the Securities Act. Pursuant to the Standby Equity
Distribution Agreement we are required to file a registration statement under
the Securities Act registering such shares for resale which must be declared
effective prior to our being able to utilize such facility.
On December 12, 2003, CanArgo issued 2,000,000 restricted shares of common stock
at an imputed price of $0.33 per share to buy out the farm-in partner to the
Manavi M-11 well. The shares were issued as restricted securities as that term
is defined in Rule 144 under the Securities Act in a transaction intended to
qualify for the exemption from registration afforded by Section 4(2) and
Regulation S promulgated thereunder and may not be offered for sale, sold or
otherwise transferred except pursuant to an effective registration statement
under the Securities Act or pursuant to an exemption from registration under the
Securities Act.
We have recently made an application to the American Stock Exchange to list our
shares of common stock for trading. There is no assurance that the Exchange will
approve our listing application.
On March 23, 2004 at a duly convened special meeting of our stockholders held in
Oslo, Norway the requisite majority of our stockholders approved an amendment to
Article 4 of our Certificate of Incorporation to increase the number of shares
of common stock, par value $.10 per share, that we are authorized to issue from
150,000,000 to 300,000,000.
ITEM 6. SELECTED FINANCIAL DATA
Reference is hereby made to the Section entitled "QUALIFYING STATEMENT WITH
RESPECT TO FORWARD-LOOKING INFORMATION" with respect to certain qualifications
regarding the following information.
The following data reflect the historical results of operations and selected
balance sheet items of CanArgo and should be read in conjunction with Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the consolidated financial statements included in Item 8.
"Financial Statements and Supplementary Data" herein.
29
Reported in $000's except for per YEAR ENDED
common share amounts DECEMBER 31,
---------------------------------------------------
2003 2002 2001 2000 1999
---------------------------------------------------
FINANCIAL PERFORMANCE
Operating revenues from 8,105 5,486 4,575 7,010 2,783
continuing operations
Operating loss from (159) (4,902) (11,838) (2,401) (8,119)
continuing operations
Other income (expense) and
Minority Interest in income (597) (576) (525) 258 (354)
(loss) of consolidated subsidiaries
Net loss from continuing
operations (756) (5,478) (11,313) (2,143) (8,473)
Net income (loss) from
discontinued operations, net (6,608) 150 (1,905) (8) --
of taxes and minority interest
(1)
Cumulative effect of change 41 -- -- -- --
in accounting policy
Net loss (7,322) (5,328) (13,218) (2,151) (8,473)
Net loss per common share -
basic and diluted before (0.01) (0.06) (0.14) (0.04) (0.32)
cumulative effect of change
in accounting principle from
continuing operations
Net loss per common share -
basic and diluted before (0.07) (0.00) (0.02) (0.00) --
cumulative effect of change
in accounting principle from discontinued
operations
Net loss per common share -
basic and diluted (0.08) (0.06) (0.16) (0.04) (0.32)
Cash generated by (used in)
operations 4,431 1,635 (6,289) 7,881 (1,210)
Working capital 3,235 10,646 14,590 23,315 2,729
Total assets 74,015 70,736 70,312 82,849 43,948
Minority shareholder
advances -- -- 450 -- --
Stockholders' equity 56,708 62,105 65,800 72,426 37,863
Cash dividends per common
share -- -- -- -- --
(1) In September 2002, CanArgo approved a plan to sell CanArgo Standard Oil
Products to finance its Georgian and Ukrainian development projects and
in October 2002, CanArgo agreed to sell its 50% holding to Westrade
Alliance LLC, an unaffiliated company, for $4 million in an arms-length
transaction, with legal
30
ownership being transferred upon receipt of final payment due in August
2003. The agreed consideration to be exchanged does not result in an
impairment of the carrying value of assets held for sale. The assets and
liabilities of CanArgo Standard Oil Products have been classified as
"Assets held for sale" and "Liabilities for sale" for all periods
presented. The results of operations of CanArgo Standard Oil Products have
been classified as discontinued for all periods presented. The minority
interest related to CanArgo Standard Oil Products has not been
reclassified for any of the periods presented, however net income from
discontinued operations is disclosed net of taxes and minority interest.
CanArgo Standard Oil Products was purchased in 2000 and operations were
developed in 2001, therefore prior to 2000 there is no effect on the
financial statements in respect of discontinued operations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
QUALIFYING STATEMENT WITH RESPECT TO FORWARD-LOOKING INFORMATION AND RISKS
THE FOLLOWING INFORMATION CONTAINS FORWARD-LOOKING INFORMATION. See "Qualifying
Statement With Respect To Forward-Looking Information" above and
"Forward-Looking Statements" below. Our activities and investments in our common
stock involve a high degree of risk. Each of the risks in Item 1 "Business-
Risks Associated with CanArgo's Activities" may have a significant impact on our
future financial condition and results of operations.
GENERAL
We are an independent energy company engaged in operations located primarily in
countries comprising the former Soviet Union involving the acquisition,
exploration, development, production and marketing of crude oil and, to a lesser
extent, natural gas. Our principal means of growth has been through the
acquisition and subsequent development and exploitation of producing oil and gas
properties by means of entering into production sharing arrangements with
governmental or local oil companies. As a result of our historical exploration
and acquisition activities, we believe that we have a substantial inventory of
exploitation and development opportunities, the successful completion of which
is critical to the maintenance and growth of our current production levels. We
have incurred net losses in the last five years, and there can be no assurance
that operating income and net earnings will be achieved in future periods. Our
financial results depend upon many factors, particularly the following factors
which most significantly affect our results of operations:
- the sales prices of crude oil and, to a lesser extent, natural gas;
- the level of total sales volumes of crude oil and, to a lesser
extent, natural gas;
- the availability of, and our ability to raise additional, capital
resources and provide liquidity to meet cash flow needs; and
- the level and success of exploration and development activity.
Reserves and Production Volumes
Year end gross total proved oil reserves at the Ninotsminda Field were 6.762
million barrels (MMbbl) up 63% from 2002's 4.15 MMbbl. Over the same period,
gross total proved natural gas reserves, on an energy equivalent basis,
decreased from 1.34 million barrels of oil equivalent (MMboe) to 0.51 MMboe.
The significant increase in recoverable oil reserves results primarily from the
completion of a dynamic reservoir model during the year and the implementation
of a successful development program based on horizontal drilling. However,
recovery of these reserves is dependent on application of optimal production
levels for the Ninotsminda wells and further application of horizontal drilling
techniques.
31
Because our proved reserves will decline as crude oil, and, to a lesser extent,
natural gas and natural gas liquids are produced (since our natural gas and
natural gas liquid production is currently incidental to our crude oil
production), unless we acquire additional properties containing proved reserves
or conduct successful exploration and development activities, our reserves and
production will decrease. Our ability to acquire or find additional reserves in
the near future will be dependent, in part, upon the amount of available funds
for acquisition, exploitation and development projects. For more information on
the volumes of crude oil, natural gas liquids and natural gas we have produced
during 2001, 2002 and 2003, please refer to the information under the caption
"Results of Operations" below.
Exploitation and Development Activity
During 2003, we continued exploitation activities on our Georgian properties. We
participated in the drilling of 3 successful wells on the Ninotsminda Field. The
Company invested $4.5 million in capital spending on these activities during
2003. In December 2003, as a result of these activities, our average daily
production was approximately 3120bbls, a 372% increase from the daily production
rate at the beginning of the year (excluding production from the property sold
in 2003).
We have budgeted $6.4 million for drilling expenditures in 2004. If crude oil
and, to a lesser extent, natural gas prices return to depressed levels or if our
production levels continue to decrease, our revenues, cash flow from operations
and financial condition will be materially adversely affected. For more
information, see "Liquidity and Capital Resources".
Recent Acquisitions of Interests
In December 2003, CanArgo announced details of the acquisition of oil and gas
interests in Kazakhstan which were previously owned by the UK public company
Atlantic Caspian Resources plc ("ACR"). We intend to acquire these interests
through a newly established associated company, Tethys Petroleum Investments
Limited ("TPI") which will acquire ACR's 70% interest in BN Munai LLP ("BNM"), a
Kazakh limited liability partnership on certain conditions being satisfied.
BNM's interests centre on the Akkulkovsky exploration area and the Kyzyloy Gas
Field, located in western Kazakhstan, just to the west of the Aral Sea.
Registration of the TPI interest in BNM is underway and should be completed in
early 2004. The licence position with regard to the Akkulkovsky exploration area
is currently subject to review by the Kazakh authorities and further negotiation
is required to secure this. The consideration for the acquisition involves ACR
taking a fully paid 10% interest in TPI, but with no cash consideration from
CanArgo. We will operate TPI, however it is intended that the further
development of TPI will be primarily funded by third party investment. We expect
to retain a significant minority shareholding in TPI. Under ACR's ownership BNM
have drilled two deep exploration wells in the Akkulkovsky area over the past
three years, both of these wells being plugged and abandoned with hydrocarbon
shows. However, CanArgo believe that the short term potential may lie in the
shallower Kyzyloy Gas Field. This is a discovered shallow gas field, located
approximately 35 km from the main Bukhara - Urals gas pipeline system, and close
to the Bazoy gas storage and compression facility. Additional shallow gas
indicators are apparent on seismic data, which potentially could be added to any
development of the Kyzyloy Field.
In February 2004, CanArgo announced that it has obtained Georgian State
regulatory approval to an agreement to obtain 50% of the Contractor's interest
in the Samgori PSC in Georgia and a 50% interest in the licence holder for Block
XI(B) covering the Samgori Oil Field. Regulatory approval was a key condition to
the agreement and the other conditions are expected to be satisfied in due
course.
This interest is being acquired from Georgian Oil Samgori Limited ("GOSL"), a
company wholly owned by Georgian Oil. Under the terms of the agreement, up to 10
horizontal wells will be drilled on the Samgori Field, which is the largest
oilfield discovered to date in Georgia and lies adjacent to CanArgo's
Ninotsminda Field. Samgori has produced over 180 million barrels (MMbbl) of oil
to date at rates up to 70,000 barrels of oil per day (bopd).
32
The Samgori Field complex was discovered in 1974 and produces from the same
Middle Eocene sequence as the Ninotsminda Field. Recent studies by Georgian Oil
(which have not been independently assessed), based on new seismic data acquired
in 2001, indicate that up to 55 MMbbl of oil could be recovered from the Samgori
complex utilising horizontal drilling techniques. Current production from the
Field is approximately 700 bopd. We will be entitled to an immediate share of
this production upon completion of the farm-in agreement. In addition, Block
XI(B) which covers an area of approximately 169,514 acres (634 km(2)) contains
several identified prospects and discoveries in other horizons, notably the
Upper Eocene and Cretaceous. As part of the farm-in terms, we will be obliged to
fund 100% of the cost of the first horizontal well section to be drilled on the
Samgori Field, the anticipated cost of this well is $1.2 million. Thereafter, it
is anticipated that up to a further ten horizontal development wells will be
drilled on the Samgori complex over the next three years which will be funded
jointly by CanArgo and GOSL pro rata their interest in the PSC.
While a considerable amount of infrastructure for the Ninotsminda Field has
already been put in place, CanArgo cannot provide assurance that:
- funding of a Field development plan will be timely;
- that the development plan will be successfully completed or will
increase production; or
- that Field operating revenues after completion of the development
plan will exceed operating costs.
To pursue existing projects beyond CanArgo's immediate development plan and to
pursue new opportunities, CanArgo will require additional capital. While
expected to be substantial, without further exploration work and evaluation the
exact amount of funds needed to fully develop all of our oil and gas properties
cannot at present, be quantified. Potential sources of funds include additional
sales of equity securities, project financing, debt financing and the
participation of other oil and gas entities in CanArgo's projects. Based on
CanArgo's past history of raising capital and continuing discussions, management
believes that such required funds may be available. However, there is no
assurance that such funds will be available, and if available, will be offered
on attractive or acceptable terms. Should such funding not be forthcoming and we
are unable to sell some or all of our non-core assets, or, if sold, such sales
realize insufficient proceeds, further cost reductions and additional funding
will be required in order for us to remain a going concern.
Development of the oil and gas properties and ventures in which CanArgo has
interests involves multi-year efforts and substantial cash expenditures. Full
development of CanArgo's oil and gas properties and ventures will require the
availability of substantial additional financing from external sources. CanArgo
may also, where opportunities exist, seek to transfer portions of its interests
in oil and gas properties and ventures to entities in exchange for such
financing. CanArgo generally has the principal responsibility for arranging
financing for the oil and gas properties and ventures in which it has an
interest. There can be no assurance, however, that CanArgo or the entities that
are developing the oil and gas properties and ventures will be able to arrange
the financing necessary to develop the projects being undertaken or to support
the corporate and other activities of CanArgo. There can also be no assurance
that such financing as is available will be on terms that are attractive or
acceptable to or are deemed to be in the best interest of CanArgo, such entities
and their respective stockholders or participants.
Ultimate realization of the carrying value of CanArgo's oil and gas properties
and ventures will require production of oil and gas in sufficient quantities and
marketing such oil and gas at sufficient prices to provide positive cash flow to
CanArgo. Establishment of successful oil and gas operations is dependent upon,
among other factors, the following:
- mobilization of equipment and personnel to implement effectively
drilling, completion and production activities;
- raising of additional capital;
- achieving significant production at costs that provide acceptable
margins;
- reasonable levels of taxation, or economic arrangements in lieu of
taxation in host countries; and
- the ability to market the oil and gas produced at or near world
prices.
33
Subject to our ability to raise additional capital, we have plans to mobilize
resources and achieve levels of production and profits sufficient to recover the
carrying value of our oil and gas properties and ventures. However, if one or
more of the above factors, or other factors, are different than anticipated,
these plans may not be realized, and we may not recover the carrying value of
our oil and gas properties and ventures.
Availability of Capital
As described more fully under "Liquidity and Capital Resources" below, our
sources of capital are primarily cash on hand, cash from operating activities,
project financing, debt financing, the participation of other oil and gas
entities in our projects, funding from the sale of our equity securities under a
Standby Equity Distribution Agreement with Cornell Capital (the "Cornell Equity
Facility") described below, and the proceeds from the sale of certain assets. We
may also attempt to raise additional capital through the issuance of debt or
equity securities although no assurances can be made that we will be successful
in any such efforts.
As of March 23, 2004, the Company had an aggregate of 109,284,724 shares of
common stock outstanding. On March 23, 2004, shareholders approved an increase
in the authorized number of shares of common stock from 150,000,000 to
300,000,000, leaving an aggregate of 165,622,189 of uncommitted shares available
for future issuance by the Company.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
The crude oil and natural gas industry is a highly capital intensive and
cyclical business. Our current capital requirements are driven principally by
our obligations to fund the following costs:
- the development of existing properties, including drilling and
completion costs of wells; and
- acquisition of interests in crude oil and natural gas properties.
The amount of capital available to us will affect our ability to continue to
grow the business through the development of existing properties and the
acquisition of new properties and, possibly, our ability to service any future
debt obligations, if any. Our sources of capital are primarily cash on hand,
cash from operating activities, project financing, debt financing, the
participation of other oil and gas entities in our projects, funding under the
Cornell Equity Facility and the sale of certain assets. Our overall liquidity
depends heavily on the prevailing prices of crude oil and natural gas and our
production volumes of crude oil and natural gas. Significant downturns in
commodity prices, such as that experienced in the last nine months of 2001 and
the first quarter of 2002, can reduce our cash from operating activities. We do
not hedge our crude oil production. Accordingly, future crude oil and, to a
lesser extent, natural gas price declines would have a material adverse effect
on our overall results, and therefore, our liquidity. Low crude oil and natural
gas prices could also negatively affect our ability to raise capital on terms
favorable to us and could also reduce our ability to borrow in the future. If
the volume of crude oil we produce decreases, our cash flow from operations will
decrease. Our production volumes will decline as reserves are produced. We sold
properties in 2003 which reduced potential future reserves and in the future, we
may sell additional properties and other assets, which could further reduce our
production volumes and income from oil well drilling and servicing. To offset
the loss in production volumes resulting from natural field declines and sales
of producing properties, we must conduct successful exploration, exploitation
and development activities, acquire additional producing properties or identify
additional behind-pipe zones or secondary recovery reserves.
As of December 31, 2003, we had working capital of $3,235,000, compared to
working capital of $10,646,000 as of December 31, 2002. The $7,410,000 decrease
in working capital from December 31, 2002 to December 31, 2003 is principally
due to the change in assets and liabilities held for sales resulting from the
impairment of the Bugruvativske field in the period, an increase in loan
facilities undertaken by the retail operation in Georgia and the part receipt of
funds in respect of a farm-in agreement on the Norio project.
34
In May 2003, NOC entered into a new 12-month crude oil sales agreement whereby
the buyer will provide a security payment of $1.75 million in return for the
right to lift up to 5,000 metric tons of oil per month for the 12-month period
commencing August 2003. At the end of the 12 months, the security payment will
be repaid through the delivery of additional crude oil equal to the value of the
security. This agreement replaces an existing crude oil sales agreement, where
the buyer had already provided $1 million security. Following the success of the
N100H well, NOC entered into a further oil sales agreement with the buyer for an
additional monthly quantity of 2,500 metric tons of oil. The agreement runs to
the end of 2004 and as security for payment and for having the option to lift
oil on a monthly basis the buyer will provide additional security in the amount
of $550,000. The security will be repaid in oil at the end of the contract
period.
Certain Asset Sales
In September 2003, CanArgo announced it had reached conditional agreement to
sell its interest in Boryslaw Oil Company ("BOC"), the joint venture in West
Ukraine currently operating the Stynawske Oil Field. Fountain Oil Boryslaw
("FOB"), CanArgo's wholly owned subsidiary which holds its 45% interest in BOC,
was sold for $1,000,000 payable in eight equal tranches. The buyer has also
acknowledged BOC's debts to CanArgo for earlier loans in the total amount of
$160,000. On November 10, 2003 CanArgo announced that the full payment had been
received early and that CanArgo's interest in FOB had been transferred to the
buyer. Management has concluded that the sale of our interest in BOC does not
constitute the disposition of a material asset of the Company.
In 2003, CanArgo signed a sales agreement disposing of a 3-megawatt duel fuel
power generator for $600,000. Following receipt of a non-refundable deposit of
$300,000, the unit was shipped to the US for testing. The test is due to be
completed in the near future at which time the generator will be delivered to
the buyer following receipt of the final payment.
CORNELL EQUITY FACILITY
In December 2003, CanArgo announced that it had signed a Standby Equity
Distribution Agreement that allowed it, at its option, to issue shares to
US-based investment fund Cornell Capital Partners LP ("Cornell Capital") up to a
maximum value of $6 million. Under the terms of the Agreement, CanArgo could, at
its discretion, issue shares to Cornell Capital at any time over the next two
years. The maximum aggregate amount of the equity placements pursuant to the
Agreement was $6 million. Subject to this limitation, CanArgo could draw down up
to $200,000 in any seven-day period (a "Put"). The facility could be used in
whole or in part entirely at CanArgo's discretion, subject to effective
registration of the shares under the Securities Act of 1933, as amended
("Securities Act"). Shares issued to Cornell Capital would be priced at a 3%
discount to the lowest daily Volume Weighted Average Price ('VWAP') of CanArgo
common shares traded on each of the five days following a drawdown notice by
CanArgo. A commission of 5% would apply to each issue of CanArgo shares under
the Agreement and would be payable to Cornell Capital at the time of issue. The
net effect of the 5% commission and the 3% discount is that Cornell Capital
would pay 92.15% of the applicable lowest weighted price for each share of the
company's common stock. The shares to be issued to Cornell Capital would be
"restricted securities" as defined in rule 144 under the Securities Act. We
agreed to prepare and file a registration statement under the Securities Act
registering the shares to be issued under the facility for resale under such
Act. This facility was terminated on February 11, 2004 when we entered into a
further standby equity distribution agreement with Cornell ("New Cornell
Facility"). No funds had been drawn down under the original facility when it was
terminated.
Under the terms of the New Cornell Facility, Cornell Capital will provide us
with an equity line of credit for 24 months. The New Cornell Facility allows us
at our discretion to periodically issue and sell to Cornell Capital up to $20
million of shares of our common stock. The terms of the New Cornell Facility are
materially the same as those for the original facility, with the exception that
the New Cornell Facility has been increased to $20 million and the maximum
amount of each advance is set at $600,000. No exercise of a Put will be made
until the SEC has declared effective a registration statement registering the
issuable shares under the Securities Act for resale. By way of fees and
expenses, we shall issue Cornell Capital a restricted stock certificate
evidencing restricted shares of common stock in an amount equal to 2.07% of the
Commitment Amount ($20,000,000) based upon the Market Price (as defined in the
Agreement) for the common stock. The total amount of shares to be issued to
Cornell Capital was 850,000 shares of which an aggregate of 425,000 shares were
issued upon execution of the original and New Cornell
35
Facilities. Cornell Capital will earn the remaining 425,000 restricted shares of
common stock once the SEC declares the Registration Statement effective.
WORKING CAPITAL
At December 31, 2003, our current assets of approximately $15.6 million exceeded
our current liabilities of $12.4 million resulting in a working capital surplus
of $3.2 million. This compares to a working capital surplus of $10.6 million as
of December 31, 2002. Current liabilities as of December 31, 2003 consisted
approximately of trade payables of $0.5 million, $1.4 million in a partial
receipt of funds from a farm-in partner in respect of an agreement on the Norio
project, $3.2 million in revenues due third parties; advanced proceeds, less
costs of the sale of subsidiary $1.9m; advanced proceeds from the sale of other
assets $0.3m, accrued liabilities $0.3m, income taxes payable $0.1m and loans
payable $0.1m.
CAPITAL EXPENDITURES
Capital expenditures in 2003, 2002 and 2001 were $5.9 million, $10.7 million and
$6.3 million, respectively. The table below sets forth the components of these
capital expenditures for the three years ended December 31, 2003 2002 and 2001.
DECEMBER 31,
EXPENDITURE CATEGORY: 2003 2002 2001
---- ------------ ----
Development $ 5,200,614 $ 543,280 $ 2,054,989
Exploration 324,467 12,167,238 5,851,306
Facilities and other 412,772 (1,975,366) (1,589,908)
Total 5,937,853 10,735,152 6,316,376
The negative expenditures recorded in facilities and other recorded in 2002 and
2001 is principally as a result of expenditures being reclassified to
development and exploration expenditure from facilities and other when actual
work is performed.
During 2003, 2002 and 2001 capital expenditures were primarily for the
development and exploration of existing properties. During 2002, capital
expenditures were primarily related to the exploration activity. We currently
have a contingent planned minimum capital expenditure budget of $10 million
subject to financing being available for 2004, of which all is allocated to
Georgian development and appraisal projects. We plan to participate in the
drilling of at least three horizontal sidetracks from existing wells on the
Ninotsminda Field, complete the testing of the Manavi oil discovery well, M11,
and drill at least one appraisal well on the Manavi structure. Further capital
expenditures may be required following the conclusion of the Samgori farm-in. We
have no material long-term capital commitments and are consequently able to
adjust the level of our expenditures as circumstances dictate. Additionally, the
level of capital expenditures will vary during future periods depending on
market conditions and other related economic factors. Should the prices of crude
oil and natural gas decline from current levels; our cash flows will decrease
which may result in a reduction of the capital expenditures budget. If we
decrease our capital expenditures budget, we may not be able to offset crude oil
and natural gas production volume decreases caused by natural field declines and
sales of producing properties.
36
SOURCES OF CAPITAL
The net funds provided by and/or used in each of the operating, investing and
financing activities are summarized in the following table and discussed in
further detail below:
DECEMBER 31,
2003 2002 2001
----------- --------- ----------
Net cash generated (used in) operating activities $ 4,430,921 1,634,629 (6,287,721)
Net cash used in investing activities (3,883,233) (8,431,282) (12,388,739)
Net cash provided in financing 1,529,791 3,174,870 3,085,563
Net cash flows from assets and liabilities held for sale (190,227) (683,308) (8,215,666)
Total 1,887,252 (4,305,091) (23,806,563)
Operating activities for the year ended December 31, 2003 provided us with $4.4
million of cash. Investing activities used $3.9 million during 2003. Financing
activities provided us $1.5 million during 2003. Most of these funds were used
to continue to fund and develop our Georgian projects. In 2003, cash generated
from operating activities ($4.4m) was principally due to improved production
resulting from our successful horizontal well program on the Ninotsminda Field
in Georgia. In 2003, cash used in investing activities was due to capital
expenditures principally in Georgia ($5.9m) partially offset by the proceeds
from disposals of CanArgo Standard Oil Products ($1.4m), Boryslaw Oil Company
($1.0m) and other assets ($0.3m); and receipts from Georgian Oil in respect of
the Norio farm-in ($1.4m).
FUTURE CAPITAL RESOURCES
We will have five principal sources of liquidity going forward: (i) cash on
hand, (ii) cash from operating activities, (iii) funding under the Cornell
Capital Equity Facility, (iv) industry participation in our projects, and (v)
sales of producing properties. We may also attempt to raise additional capital
through the issuance of additional debt or equity securities in public offerings
or through private placements.
BALANCE SHEET CHANGES
All balances represent results from continuing operations, unless disclosed
otherwise.
Cash and cash equivalents increased $1,887,000 to $3,472,000 at December 31,
2003 from $1,585,000 at December 31, 2002. The increase was primarily due to an
increase in cash generated from operating activities, receipts in respect of the
disposal of CanArgo Standard Oil Products and Boryslaw Oil Company, and receipt
from the farm-in partner in respect of the Norio exploration program, partially
offset by capital expenditures on the Ninotsminda project.
37
Accounts receivable decreased from $251,000 at December 31, 2002 to $162,000 at
December 31, 2003 primarily as a result of an allowance against a number of
historic receivables.
Inventory increased from $159,000 at December 31, 2002 to $469,000 at December
31, 2003 primarily as result of increased production of oil by Ninotsminda Oil
Company. Ninotsminda Oil Company held approximately 97,000 barrels of oil in
storage at December 31, 2003 for sale to the Georgian domestic, regional or
international market.
Prepayments increased from $212,000 at December 31, 2002 to $962,000 at December
31, 2003 as a result of prepayment for materials and services related to
CanArgo's exploration activities to be transferred to capital assets upon
receipt. This increase is included in the statement of cash flows as an
investing activity.
Assets held for sale, consisting of assets of CanArgo Standard Oil Products
operations, a 3-megawatt duel fuel power generator, the assets of the refinery
and the capital assets of the Bugruvativske Field project, decreased by
$2,907,000 to $10,346,000 at December 31, 2003 from $13,253,000 at December 31,
2002 primarily due to a net write-down of $4,126,151 in 2003 of which $4,790,727
represented the write down of unproved oil and gas properties to reflect the
estimated recoverable amount from the disposal of our interest in the
Bugruvativske Field following an approved plan to sell our interest in the
project and $667,576 represented a gain on disposal from the sale of CanArgo's
interest in the Boryslaw Oil Company, the joint venture in West Ukraine
currently operating the Stynawske oilfield. This was partially offset by
activity at CanArgo Standard Oil Products relating to the addition of new petrol
stations in Georgia.
Other currents assets increased from $176,000 at December 31, 2002 to $207,000
at December 31, 2002 as a result of a deposit to secure professional services.
Capital assets, net increased from $54,642,000 at December 31, 2002 to
$58,323,000 at December 31, 2003, primarily as a result of investment of
$5,938,000 in capital assets including oil and gas properties and equipment,
principally related to the Ninotsminda PSC. During 2002, we wrote down our oil
and gas properties in the Ninotsminda Field by an aggregate $1,600,000 on
application of the full cost ceiling test as a result of lower reserve
quantities following production declines in 2002 and reduced development plans.
If oil prices or production levels were to decline in the future, we may
experience an additional impairment of this property.
Investments in and advances to oil and gas and other ventures, net deceased from
$459,000 at December 31, 2002 to $75,000 at December 31, 2003. The decrease
reflects our announcement in 2003, that we had reached conditional agreement to
sell our interest in Boryslaw Oil Company, the joint venture in West Ukraine
currently operating the Stynawske Oil Field. Fountain Oil Boryslaw, CanArgo's
wholly owned subsidiary which holds our 45% interest in Boryslaw Oil Company,
was sold for $1,000,000 payable in eight equal tranches. Payment in full was
received in December 2003.
Accounts payable increased to $483,000 at December 31, 2003 from $405,000 at
December 31, 2002 primarily due to an absolute increase in corporate payables.
Advance from joint venture partner of $1,428,000 at December 31, 2003 relates to
an initial receipt from Georgian Oil in accordance with the Norio farm-in
agreement.
Loans payable of $102,179 at December 31, 2003 relates to a short-term secured
loan facility maturing on February 27, 2004, which a subsidiary of CanArgo
entered into, locally in Georgia, at an annual interest rate of 20% in order to
fund the drilling of a new horizontal well, N4H, at the Ninotsminda Field in
Georgia. No parent company guarantees have been provided by CanArgo with respect
to this loan. The loan matured and was paid off in full in February 2004.
Other Liabilities increased from $1,500,000 at December 31, 2002 to $5,474,000
at December 31, 2003 due to advance proceeds received for the sale of CanArgo
Standard Oil Products in the period, advance proceeds received for the sale of a
3-megawatt duel fuel power generator and security received resulting from an oil
sales agreement entered into during the period whereby the buyer provided a
security payment of $1.75 million in return for the right
38
to lift up to 5,000 metric tons of oil per month for the 12 month period
commencing August 2003 and a further security payment of $550,000 under an
additional oil sales agreement in return for the rights to lift 2,500 metric
tons of oil up to the end of December 2004. Proceeds received in respect of
CanArgo Standard Oil Products sale are $2,000,000 at December 31, 2003.
Income taxes payable increased from $61,000 from at December 31, 2002 to $97,000
at December 31, 2003 due to the final assessment of income tax payable for
Ninotsminda Oil Company Ltd, a CanArgo subsidiary.
Accrued liabilities increased to $349,000 at December 31, 2003 from $204,000 at
December 31, 2002 primarily due to an increase in accrued professional fees.
Liabilities held for sale increased by $1,629,000 from $2,819,000 at December
31, 2002 to $4,448,000 at December 31, 2003 due to liabilities held for sale, in
respect of discontinued operations, that increased by $1,614,000 to $3,774,000
at December 31, 2003 from $2,160,000 at December 31, 2002 primarily due to
additional bank loans drawn by CanArgo Standard Oil Products in Tbilisi at an
effective interest rate of 18% per annum, in order to fund the construction of
new petrol stations in Georgia.
Minority interest in continuing and discontinued subsidiaries increased by
$1,254,000 to $4,773,000 at December 31, 2003 from $3,519,000 at December 31,
2002 due to due to the write down of $1,274,895 of the minority interest share
of losses relating to the refinery, minority interest share of income in the
period, partially offset by CanArgo purchasing some of the minority interests in
CanArgo Norio by a share swap for shares in CanArgo in the period.
The foreign currency translation is due to the Company adopting the
self-sustaining method of accounting for CanArgo Standard Oil Products. The fact
that CanArgo Standard Oil Products was no longer financially and operationally
dependant upon its parent company necessitated the adoption of the
self-sustaining method. Under the self-sustaining method of foreign currency
translation, assets and liabilities are translated into US dollars at period end
exchange rates and income and expenses are translated into US dollars at average
rates in effect during the period. Exchange gains and losses on translation are
reflected as a separate component of shareholders' equity.
On March 23, 2004 at a duly convened special meeting of our stockholders held in
Oslo, Norway the requisite majority of our stockholders approved an amendment to
Article 4 of our Certificate of Incorporation to increase the number of shares
of common stock, par value $.10 per share, that we are authorized to issue from
150,000,000 to 300,000,000.
RESULTS OF CONTINUING OPERATIONS
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
CanArgo recorded operating revenue of $8,105,000 during the year ended December
31, 2003 compared with $5,486,000 for the year ended December 31, 2002. The
increase is primarily attributable to higher oil and gas revenues, being
partially offset by lower other revenue being recorded in the twelve month
period ended December 31, 2003. Other revenue for the twelve month period ended
December 31, 2003 and 2002 represented the provision of drilling services in
Georgia.
Ninotsminda Oil Company generated $7,881,000 of oil and gas revenue in the year
ended December 31, 2003 compared with $4,163,000 for the year ended December 31,
2002 due to higher volume of sales resulting from increased production from the
successful horizontal wells completed in 2003 and a higher average net sales
price achieved in 2003. Its net share of the 695,174 barrels (273 barrels per
day) of gross oil production for sale from the Ninotsminda Field in the period
amounted to 451,863 barrels. In 2003, 64,142 barrels of oil were added to
storage. For the year ended December 31, 2002, Ninotsminda Oil Company's net
share of the 292,289 barrels (801 barrels per day) of gross oil production was
189,988 barrels. The increase in production is due to the successful horizontal
development wells completed at the Ninotsminda Field in 2003.
Ninotsminda Oil Company's entire share of production was sold locally in Georgia
under both national and international contracts. Net sale prices for Ninotsminda
oil sold during 2003 averaged $20.07 per barrel as compared
39
with an average of $17.09 per barrel in 2002. Its net share of the 108,630
thousand cubic feet (mcf) of gas delivered was 82,156 mcf at an average net sale
price of $1.25 per mcf of gas. For the year ended December 31, 2002, Ninotsminda
Oil Company's net share of the 212,499 mcf of gas delivered was 138,124 mcf at
an average net sales price of $1.25 per mcf of gas.
CanArgo had other revenue of $224,000 for the year ended December 31, 2003
compared to other revenue of $1,323,000 for the year ended December 31, 2002. In
2003 and 2002, other revenue consisted of the provision of drilling services. In
September 2001, CanArgo entered into an agreement to provide drilling services
to a third party using one of CanArgo's rigs. Commercial drilling operations
commenced in October 2001 and continued through February 2002. The Company
subsequently established a wholly owned well services subsidiary (Argonaut Well
services Limited) and at the end of March 2003 concluded a new drilling services
contract with an operating company in Georgia. It will continue to bid in
appropriate tenders for drilling contracts in order to utilize drilling
equipment not otherwise used in its own operations.
The operating loss from continuing operations for the year ended December 31,
2003 amounted to $159,000 compared with an operating loss of $4,902,000 for
2002. The decrease in operating loss is attributable primarily to a reduction in
field operating expenses, reduced selling, general and administration expense,
reduced direct project costs in the period, and an impairment of oil and gas
properties in 2002; partially offset by an increase in depletion and
amortization in the period; and stock compensation in expense in 2003.
Field operating expenses decreased to $1,052,000 ($2.59 per BOE) for the year
ended December 31, 2003 as compared to $1,538,000 ($4.69 per BOE) for 2002. The
decrease is primarily a result of a cost reduction program initiated in the last
quarter of 2002 at the Ninotsminda Field and costs relating to increase of oil
storage in the year. Operating costs per BOE decreased as day-to-day field
operations in Georgia include a proportionately higher fixed to variable cost
component combined with a cost reduction program initiated in the last quarter
of 2002 at the Ninotsminda Field and higher production rates.
Direct project costs decreased to $1,029,000 for the year ended December 31,
2003, from $1,429,000 for the year ended December 31, 2002, primarily due to
costs associated with the provision of drilling services in Georgia in 2002.
Selling, general and administrative costs decreased to $3,229,000 for the year
ended December 31, 2003, from $3,494,000 for the year ended December 31, 2002.
The decrease is primarily as a result of a corporate cost reduction program
initiated in the last quarter of 2002.
Non cash stock compensation expense increased to approximately $277,000 for the
year ended December 31, 2003, from nil for the year ended December 31, 2002 due
to the Company, effective January 1, 2003, adopting the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation,"
prospectively to all employee awards granted, modified, or settled after
December 31, 2002.
The increase in depreciation, depletion and amortization expense to $3,294,000
for the year ended December 31, 2003 from $2,317,000 for the year ended December
31, 2002 is attributable principally to higher production resulting from the
successful horizontal wells at the Ninotsminda Field completed in 2003.
We wrote down our oil and gas properties in the Ninotsminda Field by an
aggregate $1,600,000 on application of the full cost ceiling test as a result of
lower reserve quantities following production declines in 2002. The write-down
was a non-cash write-down. If oil prices or production levels declined in the
future, we may experience an additional impairment of this property.
During 2003, CanArgo also announced it had reached conditional agreement to sell
its interest in Boryslaw Oil Company, the joint venture in West Ukraine
currently operating the Stynawske Oil Field. Fountain Oil Boryslaw, CanArgo's
wholly owned subsidiary which holds our 45% interest in Boryslaw Oil Company,
was sold for $1,000,000 and a gain on disposal of $665,000 was also recorded in
gain on disposition of investments during the period.
40
CanArgo recorded net other expenses of $605,000 for the year ended December 31,
2003, as compared to net other expense of $576,000 during the year ended
December 31, 2002. The increase is primarily due to foreign exchange translation
losses during 2003 partially offset by CanArgo's adjusted interest in its share
of the carrying net asset value of its subsidiary CanArgo Norio Limited (Norio)
giving rise to a non-operating loss of $444,000, in accordance with the
application of SAB 51, following agreement with the minority shareholders on the
finalization of respective equity interest in Norio in 2002, and a bad debt
allowance of $275,000 being recorded in 2002.
Equity income from investments decreased to $66,000 for the year ended December
31, 2003 from an equity income of $86,000 for the year ended December 31, 2002
primarily as a result of only nine months of equity income recorded from
production and sales of crude oil by Boryslaw Oil Company prior to its disposal
in the last quarter of 2003.
The net loss from continuing operations of $756,000 or $0.01 per share for the
year ended December 31, 2003 compares to a net loss from continuing operations
of $5,478,000 or $0.06 per share for the year ended December 31, 2002. The
weighted average number of common shares outstanding was higher during the year
ended December 31, 2003 than during the year ended December 31, 2002, due in
large part to share issues in respect of agreements relating to of Norio and
Manavi projects during 2003.
The cumulative effect of change in accounting principle of $41,290 at December
31, 2003 relates to the adoption of FASB Statement No. 143 "Accounting for Asset
Retirement Obligations" ("SFAS 143") on January 1, 2003. SFAS 143 requires
companies to record the discounted fair value of a liability for an asset
retirement obligation in the period in which the liability is incurred
concurrent with an increase in the long-lived assets carrying value. The
increase and subsequent adjustments in the related long-lived assets carrying
value is amortised over its useful life. Upon settlement of the liability a gain
or loss is recorded for the difference between the settled liability and the
recorded amount. The discount associated with the liability is accreted into
income over the related asset's useful life. Upon adoption of this standard an
entity is required to record the fair value of its existing asset retirement
obligations as if the liabilities had been initially accounted for in accordance
with SFAS 143 using assumptions present at the date of adoption. The income
statement effect of the treatment is recorded as a cumulative effect in
accounting principle in the period of adoption, no retroactive restatement is
permitted.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
CanArgo recorded operating revenue of $5,486,000 during the year ended December
31, 2002 compared with $4,575,000 for the year ended December 31, 2001. The
increase is primarily attributable to other revenue, representing provision of
drilling services in Georgia.
Ninotsminda Oil Company generated $4,163,000 of oil and gas revenue in the year
ended December 31, 2002 compared with $3,967,000 for the year ended December 31,
2001 due principally to a lower average net sales price achieved in 2002. Its
net share of the 292,289 barrels (801 barrels per day) of gross oil production
for sale from the Ninotsminda Field in the period amounted to 189,988 barrels.
In 2002, 44,483 barrels of oil were removed from storage and sold. For the year
ended December 31, 2001, Ninotsminda Oil Company's net share of the 413,724
barrels (1,133 barrels per day) of gross oil production was 247,179 barrels. The
decline in production is due to limited workover investment resulting in a
natural reservoir rate of decline.
Ninotsminda Oil Company's entire share of production was sold locally in Georgia
under both national and international contracts. Net sale prices for Ninotsminda
oil sold during 2002 averaged $17.09 per barrel as compared with an average of
$19.43 per barrel in 2001. Its net share of the 212,499 thousand cubic feet
(mcf) of gas delivered was 138,124 mcf at an average net sale price of $1.25 per
mcf of gas. For the year ended December 31, 2001, Ninotsminda Oil Company's net
share of the 1,110,390 mcf of gas delivered was 721,754 mcf at an average net
sales price of $1.14 per mcf of gas. Gas deliveries for the year ended December
31, 2002 declined significantly due to lower oil and gas production and the
temporary shutdown by AES of its thermal power generating station following an
accident at the facility. Although AES has now re-opened, CanArgo has not sold
any further gas to AES since their demand for gas was too great for CanArgo to
meet from production.
41
CanArgo had other revenue of $1,323,000 for the year ended December 31, 2002
compared to other revenue of $608,000 for the year ended December 31, 2002. In
2002 and 2001, all other revenue consisted of the provision of drilling
services. In September 2001, CanArgo entered into an agreement to provide
drilling services to a third party using one of CanArgo's rigs. Commercial
drilling operations commenced in October 2001 and continued through February
2002. No new drilling service contracts have been signed, although the company
has established a well services subsidiary, which will bid in local tenders for
drilling contracts.
The operating loss from continuing operations for the year ended December 31,
2002 amounted to $4,902,000 compared with an operating loss of $11,838,000 for
2001. The decrease in operating loss is attributable primarily to reduced
impairment of oil and gas properties in 2002, profit generated from a drilling
services contract, and a reduced depreciation, and reduced depletion and
amortization in the period.
Field operating expenses decreased to $1,538,000 ($4.69 per BOE) for the year
ended December 31, 2002 as compared to $1,568,000 ($2.62 per BOE) for 2001. The
decrease is primarily a result of decreased activity at the Ninotsminda Field
offset partially by costs relating to sales of oil from storage in the year.
Operating costs per BOE increased as day-to-day field operations in Georgia
include a proportionately higher fixed to variable cost component combined with
lower production rates.
Direct project costs increased to $1,429,000 for the year ended December 31,
2002, from $1,300,000 for the year ended December 31, 2001, reflecting
additional costs associated with the provision of drilling services in Georgia.
Selling, general and administrative costs increased to $3,494,000 for the year
ended December 31, 2002, from $3,483,000 for the year ended December 31, 2001.
The increase was primarily as a result of the impact of increased costs
resulting from business development activity offset partially the impact of a
corporate cost reduction program initiated in the last quarter of 2002.
The decrease in depreciation, depletion and amortization expense to $2,317,000
for the year ended December 31, 2002 from $2,746,000 for the year ended December
31, 2001 is attributable principally to lower production, due to limited
workover investment resulting in a natural reservoir rate of decline.
During 2002, CanArgo wrote down its oil and gas properties in the Ninotsminda
Field by an aggregate $1,600,000 on application of the full cost ceiling test as
a result of lower reserve quantities following production declines in 2002. The
write-down was a non-cash write-down. In 2001, CanArgo wrote down its oil and
gas properties in the Ninotsminda Field by an aggregate $7,300,000 on
application of the full cost ceiling test as a result of a decline in Brent oil
prices at December 31, 2001, lower reserve quantities following production
declines in 2001 and reduced development plans. If oil prices or production
levels decline further, CanArgo may experience additional impairment of this
property.
CanArgo recorded net other expenses of $576,000 for the year ended December 31,
2002, as compared to net other income of $525,000 during the year ended December
31, 2001. This is primarily due to CanArgo's adjusted interest in its share of
the carrying net asset value of its subsidiary CanArgo Norio Limited (Norio)
giving rise to a non-operating loss of $444,000, in accordance with the
application of SAB 51, following agreement with the minority shareholders on the
finalization of respective equity interest in Norio. Additional movements are
explained by lower cash balances in 2002, an allowance for doubtful accounts of
$275,000 from previous gas sales, and a bad debt write-off of $93,000 relating
to the provision of drilling services in Georgia.
Equity income from investments increased to $86,000 for the year ended December
31, 2002 from an equity loss of $160,000 for the year ended December 31, 2001 as
a result of increased equity income from production and sales of crude oil by
Boryslaw Oil Company and 2001 expenses relating to operation by East Georgian
Pipeline Company of the gas pipeline from Ninotsminda to the Gardabani power
station.
The net loss from continuing operations of $5,478,000 or $0.06 per share for the
year ended December 31, 2002 compares to a net loss from continuing operations
of $11,313,000 or $0.16 per share for the year ended December 31, 2001. The
weighted average number of common shares outstanding was substantially higher
during the year
42
ended December 31, 2002 than during the year ended December 31, 2001, due in
large part to private placements in July 2001, February and May 2002.
RESULTS OF DISCONTINUED OPERATIONS
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
The net income from discontinued operations, net of taxes and minority interest
for the year ended December 31, 2003 amounted to $6,608,000 compared with net
income of $150,000 for the corresponding period in 2002. The increase in net
loss from discontinued operations, net of taxes and minority interest relates to
the activities of LVR and GAOR, offset partially by the activities of CanArgo
standard Oil Products. Losses increased at GAOR as there was no income in the
year ended December 31, 2003.
During 2003, CanArgo approved a plan to sell its interest in the Bugruvativske
Field and recorded a write-down of $4,790,727 in 2003 of unproved oil and gas
properties to reflect the estimated recoverable amount from disposal.
An impairment of other assets of $1,355,000 for the year ended December 31,
2003, from nil for the year ended December 31, 2002 was due to a write-down of
the minority interest share of losses relating to GAOR of $1,274,895 and the a
write- down of a generator in the period to its net realizable value by $80,000.
During 2003, a debit balance of $1,274,895 in minority interest was written-off
due to a change in the intentions of our minority interest owner and a plan to
dispose of the asset. In 2004, CanArgo came to an agreement to sell the
refinery.
Increased income at CanArgo standard Oil Products is due to higher sales volume
during 2003 offset partially by more competitive operating margins for the year
ended December 31, 2003 compared with the corresponding period in 2002.
Increased income at LVR related to foreign exchange gains in the period for the
year ended December 31, 2003 compared with the corresponding period in 2002
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
The net income from discontinued operations, net of taxes and minority interest
for the year ended December 31, 2002 increased to $150,000 compared with net
loss of $1,905,000 for the corresponding period in 2001. The increase in net
income from discontinued operations, net of taxes and minority interest relates
mainly to the activities of GAOR and the impairment of a power-generating unit
in 2001, offset partially by the activities of CanArgo standard Oil Products and
LVR.
During 2001, Georgian American Oil Refinery ("GAOR") was producing operating
losses. Only naphtha, diesel and mazut can be produced and of these products, an
excise tax on both naphtha and diesel sales remains in place. In the fourth
quarter 2001, GAOR deemed the production of naphtha as commercially uneconomic
and suspended refining activity. In 2002, GAOR entered into a short-term lease
of the refinery to a third party for nominal revenue. During the lease period,
all operating costs of the refinery were borne by the lessee. This lease expired
in May 2002 and has not been renewed. In 2003, CanArgo approved a plan to
dispose of its interest in GAOR.
In 2001, as a result of both product instability and continued difficulties
addressing excise taxes on refined products, refinery and related equipment was
written-down by $3,360,000 to reflect, under current conditions, the estimated
net recoverable amount of the refinery.
In 2001, CanArgo wrote down other oil and gas related equipment by $500,000
following a decision to dispose of a power-generating unit. In 2002, a plan was
agreed to sell this equipment and it is included in assets held for sale as at
December 31, 2002.
CanArgo standard Oil Products income decreased for the year ended December 31,
2002 due to more competitive operating margins for the year ended December 31,
2002 compared with the corresponding period in 2001 and interest on additional
bank loans drawn by CanArgo Standard Oil Products in Tbilisi at an effective
interest rate of 18% per annum, in order to fund the construction of new petrol
stations in Georgia.
43
LVR corporate costs for the year ended December 31, 2002 were lower than the
corresponding period in 2001 due to less corporate activity.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL TERMS
Our principal business and assets are derived from production sharing contracts
in the Republic of Georgia. The legislative and procedural regimes governing
production sharing contracts and mineral use licenses in Georgia have undergone
a series of changes in recent years resulting in certain legal uncertainties.
Our production sharing contracts and mineral use licenses, entered into prior to
the introduction in 1999 of a new Petroleum Law governing such agreements have
not, as yet, been amended to reflect or ensure compliance with current
legislation. As a result, despite references in the current legislation
grandfathering the terms and conditions of our production sharing contracts,
conflicts between the interpretation of our production sharing contracts and
mineral use licenses and current legislation could arise. Such conflicts, if
they arose, could cause an adverse effect on our rights under the production
sharing contracts. However the Norio PSA and the Tbilisi PSC were concluded
after enactment of the Petroleum Law, and under the terms and conditions of this
legislation.
To confirm that the Ninotsminda production sharing contract and the mineral
usage license issued prior to the introduction in 1999 of the Petroleum Law were
validly issued, in connection with its preparation of the Convertible Loan
Agreement with us, the International Finance Corporation, an affiliate of the
World Bank received in November 1998 confirmation from the State of Georgia,
that among other things:
- The State of Georgia recognizes and confirms the validity and
enforceability of the production sharing contract and the license and all
undertakings the State has covenanted with Ninotsminda Oil Company
thereunder;
- the license was duly authorized and executed by the State at the time of
its issuance and remained in full force and effect throughout its term;
and
- the license constitutes a valid and duly authorized grant by the State,
being and remaining in full force and effect as of the signing of this
confirmation and the benefits of the license fully extend to Ninotsminda
Oil Company by virtue of its interest in the license holder and the
contractual rights under the production sharing contract.
Despite this confirmation and the grandfathering of the terms of existing
production sharing contracts in the Petroleum Law, subsequent legislative or
other governmental changes could conflict with, challenge our rights or
otherwise change current operations under the production sharing contract.
In 2002, the Participation Agreement for the three well exploration program on
the Ninotsminda area with AES was terminated without AES earning any rights to
any of the Ninotsminda area reservoirs. The Company therefore has no present
obligations in respect of AES. However, under a separate Letter of Agreement, if
gas from the Sub Middle Eocene is discovered and produced from the exploration
area covered by the Participation Agreement, AES with be entitled to recover at
the rate of 15% of future gas sales from the Sub Middle Eocene, net of operating
costs, approximately $7.5 million, representing their prior funding under the
Participation Agreement.
CanArgo has contingent obligations and may incur additional obligations,
absolute or contingent, with respect to the acquisition and development of oil
and gas properties and ventures in which it has interests that require or may
require CanArgo to expend funds and to issue shares of its Common Stock.
At December 31, 2003, CanArgo had a contingent obligation to issue 187,500
shares of common stock to Fielden Management Services PTY, Ltd (a third party
management services company) upon satisfaction of conditions relating to the
achievement of specified Stynawske Field project performance standards.
Under the Norio and North Kumisi PSA the shareholders agreement with the other
shareholder of Norio calls for a bonus payment of $800,000 to be paid by CanArgo
should commercial production be obtained from the Middle Eocene or older strata
and a second bonus payment of $800,000 should production from the Block from the
Middle Eocene or older strata exceed 250 tons of oil per day over any 90 day
period.
44
In September 2003, CanArgo Norio signed a farm-in agreement relating to the
Norio Production Sharing Agreement ("Norio PSA") with a wholly owned subsidiary
of Georgian Oil. CanArgo Norio had previously been in negotiations with a large
third party energy company to farm-in to the Norio PSA, but Georgian Oil
exercised its pre-emption rights under the Norio PSA. Georgian Oil is already a
party to the PSA as the commercial representative of the State. The agreement
obligates Georgian Oil to pay up to US$ 2.0 million to complete the MK-72 well
on the Norio prospect in return for a 15% interest in the contractor share of
the Norio PSA. Georgian Oil will also have an option (the "Option") exercisable
for a limited period after completion of the well, to increase its interest to
50% of the contractor share of the Norio PSA on payment to CanArgo Norio of US$
6.5 million. The well was suspended in 2002 due to lack of available funding at
that time. Drilling recommenced on the well in December 2003 and the current
depth is approximately 4,200 meters. It is expected that the well will be
finished within three months.
Co-incident with the Georgian Oil farm-in, CanArgo concluded a deal to purchase
some of the minority interests in CanArgo Norio by a share swap for shares in
CanArgo. Through this CanArgo has acquired an additional 10.8% interest in
CanArgo Norio, giving CanArgo a 75% interest in CanArgo Norio at present. This
approximately maintains CanArgo's effective interest in the Norio PSA after
Georgian Oil has completed the first stage of the farm-in at 63.7%. The purchase
was achieved by issuing 6 million restricted CanArgo shares to the minority
interest holders in CanArgo Norio. 4.0% of these minority interests were owned
by Provincial Securities Limited, a company which J.F. Russell Hammond, a
non-executive director of CanArgo, is an Investment Advisor. In the event that
Georgian Oil exercises the Option and pays the required $6.5 million, CanArgo
(which would have received some $4.8 million of this payment with its previous
interest) would receive a further $1.2 million, resulting in a total payment to
CanArgo of approximately $6 million. If the Option is exercised CanArgo would
issue a further 3 million restricted shares to the minority interest holders.
In May 2003, NOC entered into a new 12-month crude oil sales agreement whereby
the buyer will provide a security payment of $1.75 million in return for the
right to lift up to 5,000 metric tons of oil per month for the 12-month period
commencing August 2003. At the end of the 12 months, the security payment will
be repaid through the delivery of additional crude oil equal to the value of the
security. This agreement replaces an existing crude oil sales agreement, where
the buyer had already provided $1 million security. Following the success of the
N100H well, NOC entered into a further oil sales agreement with the buyer for an
additional monthly quantity of 2,500 metric tons of oil. The agreement runs to
the end of 2004 and as security for payment and for having the option to lift
oil on a monthly basis the buyer will provide additional security in the amount
of $550,000. The security will be repaid in oil at the end of the contract
period. NOC has a total commitment to repay $2.3m arising from security payments
under oil sales agreements signed in May 2003 and October 2003.
On July 2, 2003 CanArgo announced that its subsidiary CanArgo Norio had entered
into a new Production Sharing Contract (PSC) for Blocks XI(G) and XI(H)
(Mtskheta, Tetritskaro and Gardabani areas), named the "Tbilisi PSC" in the
Republic of Georgia. The licence was subsequently issued on 9 July 2003 for a
period of 25 years. These areas are located adjacent to CanArgo's existing
acreage close to Tbilisi and cover in total approximately 119,843 acres (485
km(2)). Under the terms of the Tbilisi PSC, CanArgo Norio will evaluate existing
seismic and geological data during the first year and acquire additional seismic
data within four years of the effective date of the Agreement which is September
29, 2003. The total commitment over the next four years is $350,000. The
commercial terms of the Tbilisi PSC are similar to those governing CanArgo
Norio's other exploration areas.
The following table sets forth information concerning the amounts of payments
due under specified contractual obligations for periods of less than one year,
one to three years, three to five years and more than five years as at December
31, 2003.
DUE IN LESS DUE IN 1 TO 3 DUE IN 3 TO 5 DUE IN MORE
CONTRACTUAL OBLIGATIONS THAN 1 YEAR YEARS YEARS THAN 5 YEARS
----------- ------------- ------------- ------------
Operating lease obligations $261,400 683,183 440,000 220,000
Loans payable 102,179
Other long-term liabilities (1) - - - 152,000
--------------------------------------------------------
$363,579 683,183 440,000 372,000
========================================================
45
(1) Other long-term liabilities represent costs provided for future site
restoration.
(2) CanArgo has no contractual obligations in respect of long-term debt,
capital leases or purchase obligations.
RELATED PARTY TRANSACTIONS
Of the 50% of CanArgo Standard Oil Products not held by CanArgo, 41.65% is held
by Standard Oil Products, an unrelated third party entity, and 8.35% is held by
an individual, Mr Levan Pkhakadze, who is one of the founders of Standard Oil
Products and is an officer and director of CanArgo Standard Oil Products. The
majority of refined product purchased by CanArgo Standard Oil Products for
resale at its petrol stations is purchased from a company controlled by Standard
Oil Products who together with an individual shareholder, own the 50% interest
in CanArgo Standard Oil Products not held by CanArgo. Total product purchases
from the related company in 2003 were $7,229,000 (2002 $5,263,000).
A company owned by significant employees of Georgian British Oil Company
Ninotsminda provides certain equipment to Georgian British Oil Company
Ninotsminda. Total rental payments for this equipment in 2003 were $183,428
($125,729 in 2002). In 2003, the same company provided additional services to
Georgian British Oil Company Ninotsminda in accordance with the farm-in
agreement in respect of the Manavi well for the value of $450,000.
Dr. David Robson, Chief Executive Officer, provides all of his services to
CanArgo through Vazon Energy Limited of which he is the Managing Director.
Mr. Russell Hammond, a non-executive director of CanArgo, is also an Investment
Advisor to Provincial Securities who became a minority shareholder in the Norio
and North Kumisi Production Sharing Agreement through a farm-in agreement to the
Norio MK72 well.
Transactions with affiliates are reviewed and voted on solely by non-interested
directors.
CRITICAL ACCOUNTING POLICIES
NATURAL GAS AND OIL PROPERTIES
We utilize the full cost method of accounting for costs related to our natural
gas and oil properties. We review the carrying value of our natural gas and oil
properties under the full cost accounting rules of the SEC. Under these rules,
all such costs (productive and non-productive) are capitalized and amortized on
an aggregate basis over the estimated lives of the properties using the
units-of-production method. These capitalized costs are subject to a ceiling
test, however, which limits such pooled costs to the aggregate of the present
value of future net revenues attributable to proved gas and oil reserves
discounted at 10 percent plus the lower of cost or market value of unproved
properties. If the net capitalized costs of natural gas and oil properties
exceed the ceiling, we will record a ceiling test write-down to the extent of
such excess. A ceiling test write-down is a non-cash charge to earnings. If
required, it reduces earnings and impacts shareholders' equity in the period of
occurrence and results in lower depreciation, depletion and amortization expense
in future periods. The write-down may not be reversed in future periods, even
though higher natural gas and oil prices may subsequently increase the ceiling.
The risk that we will be required to write-down the carrying value of our
natural gas and oil properties increases when natural gas and oil prices are
depressed or if there are substantial downward revisions in estimated proved
reserves. Application of these rules during periods of relatively low natural
gas or oil prices due to seasonality or other reasons, even if temporary,
increases the probability of a ceiling test write-down. Based on natural gas and
oil prices in effect on December 31, 2003, the unamortized cost of our natural
gas and oil properties did not exceed the ceiling of proved natural gas and oil
reserves. Natural gas pricing has historically been unpredictable and any
significant declines could result in a ceiling test write-down in subsequent
quarterly or annual reporting periods.
46
Natural gas and oil reserves used in the full cost method of accounting cannot
be measured exactly. Our estimate of natural gas and oil reserves requires
extensive judgments of reservoir engineering data and is generally less precise
than other estimates made in connection with financial disclosures. Assigning
monetary values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. The uncertainties inherent in the disclosure
are compounded by applying additional estimates of the rates and timing of
production and the costs that will be incurred in developing and producing the
reserves. We engage the services of an independent petroleum consulting firm to
calculate reserves.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Concentration of Credit Risk
Although CanArgo's cash and temporary investments and accounts receivable are
exposed to potential credit loss, CanArgo does not believe such risk to be
significant. Even though a substantial amount of funds were in accounts at
financial institutions which were not covered under bank guarantees, management
does not believe that maintaining balances in excess of bank guarantees resulted
in a significant risk to the Company.
Foreign Operations
CanArgo's future operations and earnings will depend upon the results of
CanArgo's operations in the Republic of Georgia. There can be no assurance that
CanArgo will be able to successfully conduct such operations, and a failure to
do so would have a material adverse effect on the CanArgo's financial position,
results of operations and cash flows. Also, the success of CanArgo's operations
will be subject to numerous contingencies, some of which are beyond management
control. These contingencies include general and regional economic conditions,
prices for crude oil and natural gas, competition and changes in regulation.
Since CanArgo is dependent on international operations, specifically those in
the Republic of Georgia, CanArgo will be subject to various additional
political, economic and other uncertainties. Among other risks, CanArgo's
operations may be subject to the risks and restrictions on transfer of funds,
import and export duties, quotas and embargoes, domestic and international
customs and tariffs, and changing taxation policies, foreign exchange
restrictions, political conditions and regulations.
NEW ACCOUNTING STANDARDS
In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities, an interpretation of ARB No. 51 ("FIN 46"). In
December 2003, the FASB modified FIN 46 to make certain technical corrections
and address certain implementation issues that had arisen. FIN 46 provides a new
framework for identifying variable interest entities ("VIEs") and determining
when a company should include the assets, liabilities, noncontrolling interests
and results of activities of a VIE in its consolidated financial statements.
In general, a VIE is a corporation, partnership, limited-liability corporation,
trust, or any other legal structure used to conduct activities or hold assets
that either: (1) has an insufficient amount of equity to carry out its principal
activities without additional subordinated financial support; (2) has a group of
equity owners that are unable to make significant decisions about its
activities; or (3) has a group of equity owners that do not have the obligation
to absorb losses or the right to receive returns generated by its operations.
FIN 46 requires a VIE to be consolidated if a party with an ownership,
contractual or other financial interest in the VIE ("a variable interest
holder") is obligated to absorb a majority of the risk of loss from the VIEs
activities, is entitled to receive a majority of the VIEs residual returns (if
no party absorbs a majority of the VIEs losses), or both. A variable interest
holder that consolidates the VIE is called the primary beneficiary. Upon
consolidation, the primary beneficiary generally must initially record all the
VIEs assets, liabilities and noncontrolling interests at fair value and
subsequently account for the VIE as if it were consolidated based on majority
voting interest. FIN 46
47
also requires disclosures about VIEs that the variable interest holder is not
required to consolidate but in which it has a significant variable interest.
On October 9, 2003, the FASB issued Staff Position No. 46-6 which deferred the
effective date for applying the provisions of FIN 46 for interests held by
public entities in variable interest entities or potential variable interest
entities created before February 1, 2003. On December 24, 2003, the FASB issued
a revision to FIN 46. Under the revised interpretation, the effective date was
delayed to periods ending after March 15, 2004 for all variable interest
entities, other than SPEs. The adoption of FIN 46 is not expected to have an
impact on the Company's financial condition, results of operations or cash
flows.
The Company does not have an interest in any special purpose entity that is
required to be consolidated under FIN 46. The Company's is currently evaluating
its involvement in other entities pursuant to the revised guidance; however, the
Company does not anticipate a significant effect as a result of its application.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement No. 133 on
Derivative Instruments and Hedging Activities. This statement amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities. SFAS No. 149 requires that contracts with comparable
characteristics be accounted for similarly. The statement is effective for
contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003. The provisions of SFAS No. 149
generally are to be applied prospectively only. The adoption of SFAS No. 149 did
not have a material impact on the Company's results of operations or financial
position.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150
establishes standards for classification and measurement by an issuer of certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that an issuer classify a financial instrument that is within
its scope as a liability (or asset in some circumstances). Many of those
instruments were previously classified as equity. This Statement also addresses
questions about the classification of certain financial instruments that embody
obligations to issue equity shares. This statement is effective for financial
instruments entered into or modified after May 31, 2003, and otherwise is
effective at the beginning of the first interim period beginning after June 15,
2003, except as it relates to consolidated limited-life subsidiaries. The FASB
indefinitely deferred the effective date of this statement as it relates to
certain mandatory redeemable non-controlling interests in consolidated
limited-life subsidiaries. The adoption of the effective provisions of SFAS No.
150 did not have a material impact on the Company's results of operations or
financial position.
On December 17, 2003, the Staff of the Securities and Exchange Commission (or
SEC) issued Staff Accounting Bulletin No. 104 ("SAB 104"), Revenue Recognition,
which supersedes Staff Accounting Bulletin No. 101, Revenue Recognition in
Financial Statements ("SAB 101"). SAB 104's primary purpose is to rescind the
accounting guidance contained in SAB 101 related to multiple-element revenue
arrangements that was superseded as a result of the issuance of EITF
00-21,Accounting for Revenue Arrangements with Multiple Deliverables.
Additionally, SAB 104 rescinds the SEC's related Revenue Recognition in
Financial Statements Frequently Asked Questions and Answers issued with SAB 101
that had been codified in SEC Topic 13, Revenue Recognition. While the wording
of SAB 104 has changed to reflect the issuance of EITF 00-21, the revenue
recognition principles of SAB 101 remain largely unchanged by the issuance of
SAB 104, which was effective upon issuance. The adoption of SAB 104 did not have
a material effect on the Company's financial position or results of operations.
Management has been made aware of a reporting issue regarding the application of
provisions of SFAS 141, Business Combinations and SFAS No. 142, Goodwill and
Other Intangible Assets (SFAS 142) to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS 142 requires
registrants to reclassify costs associated with mineral rights, including both
proved and unproved leasehold acquisition costs, as intangible assets in the
balance sheet, apart from other capitalized oil and gas property costs.
Historically, the Company's and other oil and gas companies have included the
cost of these oil and gas leasehold interests as part of oil and gas properties
and provided the disclosures required by SFAS No. 69, Disclosures about Oil and
Gas Producing Activities (SFAS 69). Also under consideration is whether SFAS 142
requires registrants to provide the additional disclosures prescribed by SFAS
142 for intangible assets for costs associated with mineral rights.
48
The Emerging Issues Task Force ("EITF") has recently decided to consider this
issue. If the EITF determines that SFAS 142 requires the Company to reclassify
costs associates with mineral rights from property and equipment to intangible
assets, the Company currently believes that its results of operations and
financial condition would not be materially affected, since such intangible
assets would continue to be depleted and assessed for impairment in accordance
with existing full cost accounting rules and impairment standards. In addition,
cost associated with mineral rights would continue to be characterized as oil
and gas property costs in the Company's required disclosures under SFAS 69.
FORWARD-LOOKING STATEMENTS
The forward-looking statements contained in this Item 7 and elsewhere in this
Annual Report on Form 10-K are subject to various risks, uncertainties and other
factors that could cause actual results to differ materially from the results
anticipated in such forward-looking statements. Included among the important
risks, uncertainties and other factors are those hereinafter discussed.
Few of the forward-looking statements in this Annual Report deal with matters
that are within our unilateral control. Joint venture, acquisition, financing
and other agreements and arrangements must be negotiated with independent third
parties and, in some cases, must be approved by governmental agencies. These
third parties generally have objectives and interests that may not coincide with
ours and may conflict with our interests. Unless we are able to compromise these
conflicting objectives and interests in a mutually acceptable manner, agreements
and arrangements with these third parties will not be consummated.
Operating entities in various foreign jurisdictions must be registered by
governmental agencies, and production licenses for development of oil and gas
fields in various foreign jurisdictions must be granted by governmental
agencies. These governmental agencies generally have broad discretion in
determining whether to take or approve various actions and matters. In addition,
the policies and practices of governmental agencies may be affected or altered
by political, economic and other events occurring either within their own
countries or in a broader international context. Finally, due to the developing
nature of the legal regimes in many former Soviet Union countries where we
operate, our contractual rights and remedies may be subject to certain legal
uncertainties.
We do not have a majority of the equity in the entity that is the licensed
developer of some projects, , that we may pursue in the former Soviet Union,
even though we may be the designated operator of the oil or gas field. In these
circumstances, the concurrence of co-venturers may be required for various
actions. Other parties influencing the timing of events may have priorities that
differ from ours, even if they generally share our objectives. As a result of
all of the foregoing, among other matters, any forward-looking statements
regarding the occurrence and timing of future events may well anticipate results
that will not be realized. Demands by or expectations of governments,
co-venturers, customers and others may affect our strategy regarding the various
projects. Failure to meet such demands or expectations could adversely affect
our participation in such projects or our ability to obtain or maintain
necessary licenses and other approvals.
Our ability to finance all of its present oil and gas projects and other
ventures according to present plans is dependent upon obtaining additional
funding. An inability to obtain financing could require us to scale back or
abandon part of all of our project development, capital expenditure, production
and other plans. The availability of equity or debt financing to us or to the
entities that are developing projects in which hawse have interests is affected
by many factors, including:
- world economic conditions;
- the state international relations;
- the stability and policies of various governments located in areas
in which we currently operate or intend to operate;
- fluctuations in the price of oil and gas, the general outlook for
the oil and gas industry and competition for available funds; and
- an evaluation of us and specific projects in which we have an
interest.
49
Rising interest rates might affect the feasibility of debt financing that is
offered. Potential investors and lenders will be influenced by their evaluations
of us and our projects and comparisons with alternative investment
opportunities.
COMMITMENTS
CanArgo has not filed any of its required 2002 or 2003 income tax or information
returns required by various governmental authorities. Failure to file these
returns carries significant penalties. CanArgo is taking steps to rectify the
matter. CanArgo has not accrued for any penalties it may be required to pay.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our principal exposure to market risk is due to changes in oil and gas prices
and currency fluctuations. As indicated elsewhere in this Report, as a producer
of oil and gas we are exposed to changes in oil and gas prices as well as
changes in supply and demand which could affect our revenues. We do not engage
in any commodity hedging activities. Due to the ready market for our production
in the Republic of Georgia, we do not believe that any current exposures from
this risk will materially affect our financial position at this time, but there
can be no assurance that changes in such market will not affect us adversely in
the future.
Also as indicated elsewhere in this Report, because all of our operations are
being conducted in the former Soviet Union, we are potentially exposed to the
market risk of fluctuations in the relative values of the currencies in areas in
which we operate. At present we do not engage in any currency hedging operations
since, to the extent we receive payments for our production and marketing
activities in local currencies, we are utilizing such currencies to pay for our
local operations. In addition, we currently have contracts to sell our
production from the Ninotsminda Field in the Republic of Georgia which provide
for payment in dollars, although we may not always be able to continue to demand
payment in U.S. dollars.
While CanArgo Standard Oil Products marketing revenue was denominated in Lari,
the local Georgian currency, and was used to pay Lari denominated operating
costs, its long term debt was denominated in dollars. As a result, had we
retained our interest in CSOP, changes in the exchange rate could have a
material adverse effect on its ability to pay off non-Lari denominated
indebtedness such as its existing credit facility. However, since we have sold
our interest in CSOP, such changes in exchange rates insofar as their effect on
CSOP will not affect our financial condition in the future.
CanArgo had no material interest in investments subject to market risk during
the period covered by this report.
Because the majority of all revenue to CanArgo is from the sale of production
from the Ninotsminda Field then a change in the price of oil or a change in the
production rates have a substantial effect on this revenue and therefore
profits.
Assuming the same production in 2004 as 2003 but decreasing the net oil price
the Company receives from sales by $5.00 and $10.00 respectively would change
the total annual revenue from oil sales as follows. The total annual revenue
from oil sales for 2003 based on an average net oil price received of $20.07 was
$7,778,356. If the average net oil price received was $5.00 less at $15.05 then
the total annual revenue from oil sales would be reduced by $1,938,605 to
$5,842,955. If the average net oil price received was reduced by $10/barrel then
the total annual revenue from oil sales realised would be reduced by $3,877,210
to $3,904,350, assuming all other factors are constant.
Assuming constant oil prices but a reduction in annual production by 20% and 50%
would have the following effect on total annual revenues. In 2003 the total oil
sales were 387,721 barrels of oil producing revenue of $7,778,356. If this was
reduced by 20% then the annual revenue from oil sales would be reduced to
$6,225,248. If the total annual oil sales were reduced by 50% or 193,861 barrels
then the total annual revenue from oil sales would be $3,883,026. Assuming all
other factors are constant.
50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Financial Statements required to be filed in this Report begin at Page F-1
of this Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
As noted in the Form 8-K filed in July 2003, our Board of Directors engaged the
accounting firm of L.J. Soldinger Associates LLP as our certifying accountant
for the year ended December 31, 2003. The engagement of L J Soldinger Associates
LLC was approved by the Audit Committee of the Board of Directors. The Audit
Committee of the Board of Directors approved the dismissal of
PricewaterhouseCoopers LLP. The reports of PricewaterhouseCoopers LLP ("PwC") on
the Company's financial statements for the two fiscal years ended December 31,
2001 and 2002 did not contain any adverse opinion or disclaimer of opinion and
were not qualified or modified as to uncertainty, audit scope or accounting
principles but PwC's report on the financial statements for the fiscal year
ended December 31, 2002 did contain an explanatory paragraph for an uncertainty
regarding the Company's ability to continue as a going concern. In connection
with the audits of the Company's financial statements for each of the two fiscal
years ended December 31, 2001 and 2002, there were no disagreements with
PricewaterhouseCoopers LLP on any matters of accounting principles, financial
statement disclosure or audit scope and procedures which, if not resolved to the
satisfaction of PricewaterhouseCoopers LLP, would have caused the firm to make
reference to the matter in their report.
ITEM 9A. CONTROLS AND PROCEDURES
Based upon an evaluation within the 90 days prior to the filing date of this
report, our Chief Executive Officer and Chief Financial Officer have each
concluded that our disclosure controls and procedures as defined in Rules 13a-14
and 15d-14 of the Securities Exchange Act of 1934, as amended, are effective, as
of the evaluation date, in timely alerting them to material information relating
to our Company required to be included in our reports filed or submitted under
the Exchange Act. In designing and evaluating the disclosure controls and
procedures, the company's management recognized that any controls and
procedures, no matter how well designed and operated, can provide only
reasonable assurances of achieving the desired control objectives, and
management necessarily was required to apply its judgment in designing and
evaluating the controls and procedures. Since the date of the evaluation, there
have been no significant changes in our internal controls over financial
reporting (as required by the Securities Exchange Act of 1934 Rules 13a-15(e)
and 15d-15(e)) or in other factors that have materially affected, or are
reasonably likely to materially affect such controls, including any corrective
actions with regard to significant deficiencies and material weaknesses.
51
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item is hereby incorporated by reference from
our definitive proxy statement to be mailed to stockholders in connection with
our 2004 annual meeting of stockholders and filed with the SEC within 120 days
after the close of our fiscal year.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is hereby incorporated by reference from
our definitive proxy statement to be mailed to stockholders in connection with
our 2004 annual meeting of stockholders and filed with the SEC within 120 days
after the close of our fiscal year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is hereby incorporated by reference from
our definitive proxy statement to be mailed to stockholders in connection with
our 2004 annual meeting of stockholders and filed with the SEC within 120 days
after the close of our fiscal year.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is hereby incorporated by reference from
our definitive proxy statement to be mailed to stockholders in connection with
our 2004 annual meeting of stockholders and filed with the SEC within 120 days
after the close of our fiscal year.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is hereby incorporated by reference from
our definitive proxy statement to be mailed to stockholders in connection with
our 2004 annual meeting of stockholders and filed with the SEC within 120 days
after the close of our fiscal year.
52
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) FINANCIAL STATEMENTS
The following financial statements and related notes of the Company contained on
pages F-1 through F- 44 are filed as part of this Report:
Reports of Independent Auditors
Consolidated Statements of Operations - Years Ended December 31, 2003, 2002, and
2001.
Consolidated Balance Sheets - December 31, 2003 and 2002.
Consolidated Statements of Cash Flows - Years Ended December 31, 2003, 2002, and
2001.
Consolidated Statements of Stockholders' Equity - Years ended December 31, 2003,
2002 and 2001.
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENTS SCHEDULES
None
All other schedules are omitted because of the absence of conditions under which
they are required or because the required information is included in the
consolidated financial statements or notes thereto.
(b) REPORTS ON FORM 8-K:
The following Current Reports on Form 8-K were filed during the quarter
ended December 31, 2003.
On December 11 2003, CanArgo issued a statement that operations in the
Republic of Georgia are unaffected by the current political changes in the
country.
On December 11 2003, CanArgo announced the initial test results of
horizontal production well N96H, in the Ninotsminda Field, Georgia.
On December 11 2003, CanArgo announced that it had filed its results for
the nine months ended September 30th 2003 on November 14th 2003.
(c) EXHIBITS
Management Contracts, Compensation Plans and Arrangements are
identified by an asterisk (*) Documents filed herewith are
identified by a cross (+).
1(6) Engagement Agreement with Sundal Collier & Co ASA dated August
13, 2001. (Incorporated herein by reference from Post-Effective
Amendment No. 2 to Form S-1 Registration Statement, File No.
333-85116 filed on September 10, 2002).
2(4) Memorandum of Agreement between Fielden Management Services Pty,
Ltd., A.C.N. 005 506 123 and Fountain Oil Incorporated dated May
16, 1995 (Incorporated herein by reference from December 31, 1997
Form 10-K/A).
53
3(1) Registrant's Certificate of Incorporation and amendments thereto
(Incorporated herein by reference from July 15, 1998 Form 8-K).
3(2) Registrant's Bylaws (Incorporated herein by reference from
Post-Effective Amendment No. 1 to Form S-1 Registration
Statement, File No. 333-72295 filed on July 29, 1999).
*10(2) Amended and Restated 1995 Long-Term Incentive Plan (Incorporated
herein by reference from Post-Effective Amendment No. 1 to Form
S-1 Registration Statement, File No. 333-72295 filed on July 29,
1999).
*10(3) Amended and Restated CanArgo Energy Inc. Stock Option Plan
(Incorporated herein by reference from September 30, 1998 Form
10-Q).
10(6) Production Sharing Contract between (1) Georgia and (2) Georgian
Oil and JKX Ninotsminda Ltd. dated February 12, 1996
(Incorporated herein by reference from Form S-1 Registration
Statement, File No. 333-72295 filed on September 7, 1999).
*10(14) Management Services t Agreement between CanArgo Energy
Corporation and Vazon Energy Limited concerning the provision of
services by Dr. David Robson dated June 29, 2000 (Incorporated
herein by reference from September 30, 2000 Form 10-Q).
10(15) Tenancy Agreement between CanArgo Services (UK) Limited and
Grosvenor West End Properties dated September 8, 2000
(Incorporated herein by reference from September 30, 2000 Form
10-Q).
10(19) Production Sharing Contract between (1) Georgia and (2) Georgian
Oil and CanArgo Norio Limited dated December 12, 2000
(Incorporated herein by reference from December 31, 2000 Form
10-K).
*10(22) Employment Agreements between CanArgo Energy Corporation and
Vincent McDonnell dated December 1, 2000 (Incorporated herein by
reference from December 31, 2001 Form 10-K).
10(23) Agreement Number 1 dated March 20, 1998 on Joint Investment
Production Activity for further development and further
exploration of Bugruvativske Field (Incorporated herein by
reference from September 30, 2001 Form 10-Q).
10(25) Covenant on terms and conditions of participation in investment
activity under the Joint Investment Production Activity agreement
dated of March 20, 1998, dated July 23, 2002. (Incorporated
herein by reference from September 30, 2002 Form 10-Q).
10(26) Amendments of and Additions to Joint Investment Production
Activity agreement of March 20, 1998, dated August 8, 2002.
(Incorporated herein by reference from September 30, 2002 Form
10-Q).
10(27) Amendment of Clause 9.3.1 of Amendments of and Additions to the
Joint Investment Production Activity agreement of March 20, 1998,
dated September 17, 2002. (Incorporated herein by reference from
September 30, 2002 Form 10-Q).
10(28) Stock sale purchase contract of IPEC between Lateral Vector
Resources Inc. and Lystopad dated September 24, 2002.
(Incorporated herein by reference from September 30, 2002 Form
10-Q).
54
10(29) Stock sale purchase contract of IPEC between Lateral Vector
Resources Inc. and Lyutyi dated September 24, 2002. (Incorporated
herein by reference from September 30, 2002 Form 10-Q).
10(30) Sale agreement of CanArgo Petroleum Products Limited between
CanArgo Limited and Westrade Alliance LLC dated October 14, 2002.
(Incorporated herein by reference from September 30, 2002 Form
10-Q).
10(31) Crude Oil Sales Agreement dated May 5, 2003 (Incorporated herein
by reference from September 30, 2003 Form 10-Q).
10(32) Farm-in Agreement dated September 4, 2003 relating to the Norio
(Block XI(C)) and North Kumisi Production Sharing Agreement in
the Republic of Georgia with a wholly owned subsidiary of
Georgian Oil, the Georgian State Oil Company (Incorporated herein
by reference from September 30, 2003 Form 10-Q).
10(33) Farm-in Agreement dated September 7, 2003 relating to the M11
well on the Manavi Cretaceous prospect within the Ninotsminda PSC
area between Ninotsminda Oil Company Limited and Georgian British
Oil Services Company Limited (Incorporated herein by reference
from September 30, 2003 Form 10-Q).
10(34) Stock Purchase Agreement dated September 24, 2003 regarding the
sale of all of the issued and outstanding stock of Fountain Oil
Boryslaw (Incorporated herein by reference from September 30,
2003 Form 10-Q).
+10(36) Manavi Termination Agreement dated December 5, 2003.
21 List of Subsidiaries (Incorporated herein by reference from
September 30, 2001 Form 10-Q)
+23(a) Consent of L.F. Soldinger & Associates, LLP, Independent Public
Accountants.
+23(b) Consent of PricewaterhouseCoopers LLP, Independent Public
Accountants.
+31(1) Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
of CanArgo Energy Corporation.
+31(2) Rule 13a-14(c)/15d-14(a) Certification of Chief Financial Officer
of CanArgo Energy Corporation.
+32 Section 1350 Certifications.
55
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CANARGO ENERGY CORPORATION
(Registrant)
By: /s/Vincent McDonnell Date: April 8, 2004
----------------------------------
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
By: /s/David Robson Date: April 8, 2004
----------------------------------
David Robson, Chairman of the
Board and Chief Executive Officer
and Director Principal Executive
Officer
By: /s/Vincent McDonnell Date: April 8,2004
----------------------------------
Vincent McDonnell, Chief Financial
Officer and Director Principal
Accounting Officer
By: /s/Michael Ayre Date: April 8, 2004
----------------------------------
Michael Ayre, Director
By: /s/Russell Hammond Date: April 8, 2004
----------------------------------
Russell Hammond, Director
By: /s/Nils N. Trulsvik Date: April 8, 2004
----------------------------------
Nils N. Trulsvik, Director
56
CANARGO ENERGY CORPORATION
INDEX TO FINANCIAL STATEMENTS
Report on Management's Responsibilities F-2
Independent Auditors' Report F-3
Consolidated Balance Sheets F-4
Consolidated Statements of Operations F-5
Consolidated Statements of Stockholders' Equity F-6
Consolidated Statements of Cash Flows F-7
Notes to Financial Statements F-10
F-1
REPORT ON MANAGEMENT'S RESPONSIBILITIES
To the Stockholders of CanArgo Energy Corporation:
CanArgo's management is responsible for the integrity and objectivity of the
financial information contained in this Annual Report. The financial statements
included in this report have been prepared in accordance with accounting
principles generally accepted in the United States and, where necessary, reflect
the informed judgements and estimates of management.
Management maintains and is responsible for systems of internal accounting
control designed to provide reasonable assurance that all transactions are
properly recorded in the Company's books and records, that procedures and
policies are adhered to, and that assets are safeguarded from unauthorized use.
The financial statements for 2003 have been audited by the independent
accounting firm of L J Soldinger Associates LLC, as indicated in their report.
The financial statements for 2002 and 2001 were audited by the independent
accounting firm of PricewaterhouseCoopers, LLP as indicated in their report.
Management has made available to its outside auditors' all the Company's
financial records and related data and minutes of directors' and audit committee
meetings.
CanArgo's audit committee, consisting solely of directors who are not employees
of CanArgo, is responsible for: reviewing the Company's financial reporting;
reviewing accounting and internal control practices; recommending to the Board
of Directors and shareholders the selection of independent accountants; and
monitoring compliance with applicable laws and company policies. The independent
accountants have full and free access to the audit committee and meet with it,
with and without the presence of management, to discuss all appropriate matters.
On the recommendation of the audit committee, the consolidated financial
statements have been approved by the Board of Directors.
/s/Dr. David Robson /s/Vincent McDonnell
Chief Executive Officer Chief Financial Officer
April 8, 2004
F-2
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareholders
CanArgo Energy Corporation
St Peter Port, Guernsey, British Isles
We have audited the accompanying consolidated balance sheet of CanArgo Energy
Corporation as of December 31, 2003, and the related consolidated statements of
operations, stockholders' equity, and cash flows for the year then ended. 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 audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statements presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of CanArgo Energy
Corporation as of December 31, 2003, and the consolidated results of operations,
changes in stockholders' equity and its cash flows for the year then ended in
conformity with accounting principles generally accepted in the United States of
America.
As discussed in Note 2 to the financial statements, the Company changed its
method of accounting for stock-based compensation. Effective January 1, 2003 the
Company voluntarily commenced recording stock based compensation, on a
prospective basis, using the fair value method as allowed by the provisions of
Statement of Financial Accounting Standards No. 148 "Accounting for Stock-Based
Compensation -- Transition and Disclosure -- an Amendment of FASB Statement No.
123".
Also as discussed in Note 2 to the financial statements, the Company changed
its method of accounting for asset retirement obligations effective January 1,
2003, and implemented the accounting required under the provisions of Statement
of Financial Accounting Standards No. 143 "Accounting for Asset Retirement
Obligations.
L J SOLDINGER ASSOCIATES LLC
Deer Park, Illinois, USA
March 11, 2004
F-3
REPORT OF INDEPENDENT ACCOUNTANTS
To the Directors and Shareholders of CanArgo Energy Corporation:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, stockholders' equity and cash flows
present fairly, in all material respects, the financial position of CanArgo
Energy Corporation and its subsidiaries at 31 December 2002, and the results of
their operations and their cash flows for the each of the two years in the
period ended December 31, 2002 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 of America, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
The accompanying financial statements have been prepared assuming the Group will
continue as a going concern. As discussed in Note 1, Basis of Presentation, to
the consolidated financial statements, the Group is reliant on raising
additional significant financing from external sources in order to recover the
carrying value of its undeveloped and unproved properties and without additional
financing there is substantial doubt about the Group's long term ability to
continue as a going concern. Management's plans in regard to these matters are
described in Note 1, Basis of Presentation. The financial statements do not
include any adjustments that might result from the outcome of this uncertainty.
PricewaterhouseCoopers LLP
London, England
March 24, 2003, except for Note 17 paragraph 7, as to which the date is April 9,
2004
F-4
CANARGO ENERGY CORPORATION
Consolidated Balance Sheets
(Expressed in United States dollars)
December 31,
---------------------------------
2003 2002
------------- -------------
ASSETS
Current assets
Cash and cash equivalents $ 3,472,252 $ 1,585,000
Accounts receivable 161,772 250,603
Inventory 468,793 158,896
Prepayments 961,588 211,623
Assets held for sale 10,346,077 13,252,529
Other current assets 206,532 175,951
------------- -------------
Total current assets 15,617,014 15,634,602
Capital assets, net (including unevaluated amounts of $26,592,260 and
$31,882,906, respectively) 58,322,699 54,642,008
Investments in and advances to oil and gas and other ventures, net 75,000 459,308
------------- -------------
Total assets $ 74,014,713 $ 70,735,918
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable - trade $ 483,282 $ 405,234
Advance from joint venture partner 1,427,612 -
Loans payable 102,179 -
Other liabilities 5,473,823 1,500,000
Income taxes payable 97,500 61,000
Accrued liabilities 349,487 204,045
Liabilities held for sale 4,447,706 2,818,727
------------- -------------
Total current liabilities 12,381,589 4,989,006
Provision for future site restoration 152,000 122,290
Minority interest in subsidiaries 4,772,683 3,519,342
Commitments and contingencies
Stockholders' equity:
Common stock, par value $0.10 ; authorized - 150,000,000 shares; shares
issued and outstanding - 105,617,988 at 2003 and 97,356,206 at 2002 10,561,798 9,735,620
Capital in excess of par value 146,401,804 145,151,475
Accumulated other comprehensive income (deficit) (146,463) 4,668
Accumulated deficit (100,108,698) (92,786,483)
------------- -------------
Total stockholders' equity 56,708,441 62,105,280
------------- -------------
Total liabilities and stockholders' equity $ 74,014,713 $ 70,735,918
============= =============
The accompanying notes are an integral part of the consolidated financial
statements
F-5
CANARGO ENERGY CORPORATION
Consolidated Statements of Operations
(Expressed in United States dollars)
For the Years Ended December 31,
--------------------------------------------------
2003 2002 2001
------------ ------------ ------------
Operating revenues from continuing operations:
Oil and gas sales $ 7,881,172 $ 4,163,201 $ 3,967,078
Other 223,608 1,322,554 608,032
------------ ------------ ------------
8,104,780 5,485,755 4,575,110
------------ ------------ ------------
Operating expenses:
Field operating expenses 1,051,905 1,537,917 1,568,011
Direct project costs 1,028,682 1,428,638 1,300,423
Selling, general and administrative 3,228,982 3,493,828 3,482,574
Non cash stock compensation expense 276,507 - -
Depreciation, depletion and amortization 3,294,086 2,316,774 2,745,934
Impairment of oil and gas properties - 1,600,000 7,300,000
Gain on disposition of investment (664,576) - -
Loss on disposition of assets 47,835 10,725 16,130
------------ ------------ ------------
8,263,421 10,387,882 16.413.072
------------ ------------ ------------
Operating Loss from continuing operations (158,641) (4,902,127) (11,837,962)
Other income (expense)
Interest, net (35,386) 32,413 677,559
Foreign exchange gains (losses) (511,370) 128,579 28,948
Other (123,541) (822,908) (21,646)
Equity income (loss) from investments 65,544 86,059 (160,000)
------------ ------------ ------------
Total other income (expense) (604,753) (575,857) 524,861
------------ ------------ ------------
Loss from continuing operations before minority interest and taxes (763,394) (5,477,984) (11,313,101)
Minority interest in loss of consolidated subsidiaries 7,406 58 -
------------ ------------ ------------
Loss from continuing operation (755,988) (5,477,926) (11,313,101)
Net income (loss) from discontinued operations, net of taxes and
minority interest (6,607,517) 150,225 (1,905,245)
Cumulative effect of change in accounting principle 41,290 - -
------------ ------------ ------------
Net Loss $ (7,322,215) $ (5,327,701) $(13,218,346)
============ ============ ============
Weighted average number of common shares outstanding 99,432,000 96,643,744 83,869,579
------------ ------------ ------------
Net loss per common share - basic and diluted before cumulative
effect of change in accounting principle
From continuing operations $ (0.01) $ (0.06) $ (0.14)
From discontinued operations (0.07) - (0.02)
Cumulative effect of change in accounting principle, net of income
tax - - -
------------ ------------ ------------
Net loss per common share - basic and diluted $ (0.08) $ (0.06) $ (0.16)
============ ============ ============
Other comprehensive income (loss):
Foreign currency translation (151,131) 4,668 -
Net loss (7,322,215) (5,327,701) (13,218,346)
------------ ------------ ------------
Comprehensive loss $ (7,473,346) $ (5,323,033) $(13,218,346)
============ ============ ============
The accompanying notes are an integral part of the consolidated financial
statements
F-6
CANARGO ENERGY CORPORATION
Consolidated Statements of Cash Flows
(Expressed in United States dollars)
For the Years Ended December 31,
--------------------------------------------------
2003 2002 2001
------------ ------------ ------------
Operating activities:
Loss from continued operations $ (755,988) $ (5,477,926) $(11,313,101)
Non-cash stock compensation expense 276,507 - -
Non-cash interest expense 14,000 - -
Depreciation, depletion and amortization 3,294,085 2,316,775 2,745,934
Impairment of oil and gas properties - 1,600,000 7,300,000
Equity income from investments (65,544) (86,059) 160,000
Gain on disposition of investment (664,576) - -
Loss on disposition of assets 47,835 10,725 16,130
Allowance for doubtful accounts 170,000 275,000 200,000
Minority interest in (loss) income of consolidated subsidiaries (7,406) (58) -
Changes in assets and liabilities:
Accounts receivable (81,169) 893,086 (1,035,443)
Inventory (309,897) 214,922 294,519
Prepayments 54,767 29,713 (130,300)
Other current assets (30,581) (13,578) 38,690
Accounts payable 78,047 568,205 (4,343,832)
Deferred revenue 2,228,899 1,500,000 -
Income taxes payable 36,500 - 61,000
Accrued liabilities 145,442 (196,176) (281,318)
------------ ------------ ------------
Net cash generated by operating activities 4,430,921 1,634,629 (6,287,721)
------------ ------------ ------------
Investing activities:
Capital expenditures (5,937,853) (10,735,152) (6,316,387)
Proceeds from disposition of assets - - 19,383
Acquisitions, net of cash acquired - (50,000) (4,044,973)
Proceeds from disposition if investments 1,000,000 13,435 125,000
Repayments from (investments in and advance to) oil and gas and
other ventures 114,428 346,059 (831,403)
Advance proceeds from the sale of CanArgo Standard Oil Products 1,443,729 - -
Advance proceeds from the sale of CanArgo Petroleum Refining
Limited 301,195 - -
Change in non cash working capital items (804,732) 1,994,376 (1,340,359)
------------ ------------ ------------
Net cash used in investing activities (3,883,233) (8,431,282) (12,388,739)
------------ ------------ ------------
Financing activities:
Proceeds from sale of common stock - 1,790,948 7,235,337
Share issuance costs - (162,215) (643,075)
Minority shareholder advances - - 450,000
(Repayment of) Advances from minority interest - 1,546,137 1,931,874
Advances from joint venture partner 1,427,612 - (5,888,573)
Proceeds from loans 380,000 - -
Repayment of loans (277,821) - -
------------ ------------ ------------
Net cash provided by financing activities 1,529,791 3,174,870 3,085,563
------------ ------------ ------------
Net cash flows from assets and liabilities held for sale (190,227) (683,308) (8,215,666)
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents 1,887,252 (4,305,091) (23,806,563)
Cash and cash equivalents, beginning of year 1,585,000 5,890,091 29,696,654
------------ ------------ ------------
Cash and cash equivalents, end of year $ 3,472,252 $ 1,585,000 $ 5,890,091
============ ============ ============
The accompanying notes are an integral part of the consolidated financial
statements
F-7
CANARGO ENERGY CORPORATION Page 1 of 2
Consolidated Statements of Stockholders' Equity
(Expressed in United States dollars)
Common Stock
-------------------------- Accumulated
Number of Additional Other Total
Shares Issued Paid-In Comprehensive Accumulated Stockholders'
and Issuable Par Value Capital Income (Loss) Deficit Equity
------------- ----------- ------------ ------------- -------------- -------------
Balance, December 31, 2000 75,526,890 $ 7,552,690 $138,275,319 $ - $ (74,240,436) $ 71,587,573
---------- ----------- ------------ -------- ------------- ------------
Shares issuable upon exchange
of CanArgo Oil & Gas, Inc.
Exchangeable Shares without
receipt of further
consideration 423,791 42,379 795,712 - - 838,091
---------- ----------- ------------ -------- ------------- ------------
Total, December 31, 2000 75,950,681 7,595,069 139,071,031 - (74,240,436) 72,425,664
---------- ----------- ------------ -------- ------------- ------------
Less shares issuable at
beginning of year (423,791) (42,379) (795,712) - - (838,091)
Issuance of common stock
pursuant to July private
placement 16,057,765 1,605,776 5,629,561 - - 7,235,337
Issuance of common stock upon
exchange of CanArgo Oil &
Gas, Inc. Exchangeable Shares 274,965 27,496 516,276 - - 543,772
Share issuance costs - - (643,075) - - (643,075)
Net loss - - - - (13,218,346) (13,218,346)
---------- ----------- ------------ -------- ------------- ------------
Balance, December 31, 2001 91,859,620 9,185,962 143,778,081 - (87,458,782) 65,505,261
---------- ----------- ------------ -------- ------------- ------------
Shares issuable upon exchange
of CanArgo Oil & Gas, Inc.
Exchangeable Shares without
receipt of further
consideration 148,826 14,883 279,436 - - 294,319
---------- ----------- ------------ -------- ------------- ------------
Total, December 31, 2001 92,008,446 9,200,845 144,057,517 - (87,458,782) 65,799,580
---------- ----------- ------------ -------- ------------- ------------
Less shares issuable at
beginning of year (148,826) (14,883) (279,436) - - (294,319)
Issuance of common stock upon
exchange of CanArgo Oil &
Gas, Inc. Exchangeable Shares 148,826 14,883 279,436 - - 294,319
Shares issued pursuant to
private placement February
2002 5,210,000 521,000 1,241,433 - - 1,762,433
Shares issued pursuant to
private placement May 2002 137,760 13,775 14,740 - - 28,515
Share issuance costs - - (162,215) (162,215)
Current year adjustment - - - 4,668 - 4,668
Net loss - - - - (5,327,701) (5,327,701)
---------- ----------- ------------ -------- ------------- ------------
Total, December 31, 2002 97,356,206 $ 9,735,620 $145,151,475 $ 4,668 $ (92,786,483) $ 62,105,280
---------- ----------- ------------ -------- ------------- ------------
The accompanying notes are an integral part of the consolidated financial
statements
F-8
CANARGO ENERGY CORPORATION Page 2 of 2
Consolidated Statements of Stockholders' Equity
(Expressed in United States dollars)
Common Stock
-------------------------- Accumulated
Number of Additional Other Total
Shares Issued Paid-In Comprehensive Accumulated Stockholders'
and Issuable Par Value Capital Income (Loss) Deficit Equity
------------- ----------- ------------ ------------- ------------- -------------
Total, December 31, 2002 97,356,206 $ 9,735,620 $145,151,475 $ 4,668 $ (92,786,483) $62,105,280
---------- ----------- ------------ ----------- ------------- -----------
Shares issued pursuant to Norio
buy-out September 2003 6,000,000 600,000 540,000 - - 1,140,000
Shares issued pursuant to
Manavi buy-out December
2003 2,000,000 200,000 460,000 - - 660,000
Shares issued pursuant to
Standby Equity Distribution
Agreement 261,782 26,178 (26,178) - - -
Change in accounting policy
pursuant to the Company
electing to utilize the
"prospective" method of
transitioning to fair
value method of accounting
for stock-based
compensation under SFAS
No. 148 - - 276,507 - - 276,507
Current year adjustment - - - (151,131) - (151,131)
Net loss - - - - (7,322,215) (7,322,215)
----------- ----------- ------------ ----------- ------------- -----------
Total, December 31, 2003 105,617,988 $10,561,798 $146,401,804 $ (146,463) $(100,108,698) $56,708,441
=========== =========== ============ =========== ============= ===========
The accompanying notes are an integral part of the consolidated financial
statements
F-9
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 1 - NATURE OF OPERATIONS
CanArgo Energy Corporation, headquartered in Guernsey, British Isles, and its
consolidated subsidiaries (collectively "CanArgo"), is an integrated oil and gas
company operating predominately within the Republic of Georgia. The principal
activity of CanArgo is the acquisition of interests in and development of crude
oil and natural gas fields. In 2002 and 2003, CanArgo approved a plan to sell
CanArgo Standard Oil Products, the Ukrainian development projects, the refinery
and a generating power unit. The corresponding assets and liabilities of these
entities have been classified as "Assets held for sale" and "Liabilities held
for sale" for all periods presented and the results of operations have been
classified as discontinued for all periods presented. The minority interest
related to CanArgo Standard Oil Products and the refinery has not been
reclassified for any of the periods presented, however net income from
discontinued operations is disclosed net of taxes and minority interest.
CanArgo has incurred recurring operating losses, and its operations did not
generate positive cash flows in 2001. Although its operations did generate
positive cash flows in 2002, the ability of CanArgo to continue as a going
concern as at December 31, 2002 and to pursue its principal activities of
acquiring interests in and developing oil and gas fields depended upon CanArgo
reducing costs, generating funds from internal sources including the sale of
certain non-core assets, external sources and, ultimately, achieving sufficient
positive cash flows from operating activities.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The consolidated financial statements and notes thereto are prepared in
accordance with accounting principles generally accepted in the United States.
All amounts are in U.S. dollars.
Consolidation
The consolidated financial statements include the accounts of CanArgo Energy
Corporation and its majority owned subsidiaries. All significant intercompany
transactions and accounts have been eliminated. Investments in less than
majority owned corporations and corporate like entities in which the Company
exercises significant influence are accounted for using the equity method.
Entities in which the Company does not have significant influence are accounted
for using the cost method.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents include all liquid investments with an original
maturity of three months or less to be cash equivalents.
Fair Value of Financial Instruments
The carrying amount of cash and other current assets and liabilities
approximates fair value because of the short term maturity of these items.
CanArgo does not hold or issue financial instruments for trading purposes.
F-10
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Concentration of Credit Risk
Although CanArgo's cash and temporary investments and accounts receivable are
exposed to potential credit loss, CanArgo does not believe such risk to be
significant. Even though a substantial amount of funds were in accounts at
financial institutions which were not covered under bank guarantees, management
does not believe that maintaining balances in excess of bank guarantees resulted
in a significant risk to the Company.
Reclassification
Certain items in the consolidated financial statements have been reclassified to
conform to the current year presentation. There was no effect on reported net
loss as a result of these reclassifications.
Allowance for Doubtful Debts
Accounts receivable are carried at the amount owed by customers, reduced by an
allowance for estimated amounts that may not be collectible in the future. The
allowance for doubtful accounts is estimated based upon historical write-off
percentages, known problem accounts, and current economic conditions. Accounts
are written off against the allowance for doubtful accounts when the Company
determines that amounts are not collectable and recoveries of previously
written-off accounts are recorded when collected.
Inventories
Inventories of crude oil refined products and supplies are valued at the lower
of average cost and net realizable value.
Capital Assets
Capital assets are recorded at cost less accumulated provisions for
depreciation, depletion and amortization unless the carrying amount is viewed as
not recoverable in which case the carrying value of the assets is reduced to the
estimated recoverable amount. See "Impairment of Long-Lived Assets" below.
Expenditures for major renewals and betterments, which extend the original
estimated economic useful lives of applicable assets, are capitalized.
Expenditures for normal repairs and maintenance are charged to expense as
incurred. The cost and related accumulated depreciation of assets sold or
retired are removed from the accounts and any gain or loss thereon is reflected
in operations. Unproved properties are not deemed to be impaired until the right
to drill on those properties is lost and planned development has ceased.
Oil And Gas Properties - CanArgo and the unconsolidated entities (for which it
accounts using the equity method) account for oil and gas properties and
interests under the full cost method. Under this accounting method, costs,
including a portion of internal costs associated with property acquisition and
exploration for and development of oil and gas reserves, are capitalized within
cost centers established on a country-by-country basis. Capitalized costs within
a cost center, as well as the estimated future expenditures to develop proved
reserves and estimated net costs of dismantlement and abandonment, are amortized
using the unit-of-production method based on estimated proved oil and gas
reserves. All costs relating to production activities are charged to expense as
incurred. All other costs directly attributable to a project are expensed as
incurred as direct project costs when such costs are considered recurring in
nature.
Capitalized oil and gas property costs, less accumulated depreciation, depletion
and amortization and related deferred income taxes, are limited to an amount
(the ceiling limitation) equal to (a) the present value (discounted at 10%) of
estimated future net revenues from the projected production of proved oil and
gas reserves, calculated at prices in effect as of the balance sheet date (with
consideration of price changes only to the extent provided by fixed and
determinable contractual arrangements), plus (b) the lower of cost or estimated
fair value of unproved and unevaluated properties, less (c) income tax effects
related to differences in the book and tax basis of the oil and gas properties.
F-11
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Property and Equipment - Depreciation of property and equipment is computed
using the straight-line method over the estimated useful lives of the assets
ranging from three to five years for office furniture and equipment to three to
fifteen years for oil and gas related equipment.
Discontinued Operations - CanArgo Standard Oil Products petrol stations and
additions thereto were depreciated over the estimated useful lives of the assets
ranging from ten to fifteen years until operations were reclassified as
discontinued.
Revenue Recognition
CanArgo recognizes revenues when goods have been delivered, when services have
been performed, or when hydrocarbons have been produced and delivered and
payment is reasonably assured. Where crude oil or natural gas production is sold
to or used for internal consumption by the refinery, on consolidation revenues
from these sales are eliminated from sales and other operating revenues and
operating expenses.
Advances
Advances received by CanArgo from joint venture partners, which are to be spent
by CanArgo on behalf of the joint venture partners, are classified within
finance activities. When the cash advances are spent, the payable is reduced
accordingly. These advances do not contribute to CanArgo's operating profits and
are accounted for/disclosed as balance sheet entries only within cash and
payable to joint venture partner.
Foreign Operations
CanArgo's future operations and earnings will depend upon the results of
CanArgo's operations in the Republic of Georgia. There can be no assurance that
CanArgo will be able to successfully conduct such operations, and a failure to
do so would have a material adverse effect on the CanArgo's financial position,
results of operations and cash flows. Also, the success of CanArgo's operations
will be subject to numerous contingencies, some of which are beyond management
control. These contingencies include general and regional economic conditions,
prices for crude oil and natural gas, competition and changes in regulation.
Since CanArgo is dependent on international operations, specifically those in
the Republic of Georgia, CanArgo will be subject to various additional
political, economic and other uncertainties. Among other risks, CanArgo's
operations may be subject to the risks and restrictions on transfer of funds,
import and export duties, quotas and embargoes, domestic and international
customs and tariffs, and changing taxation policies, foreign exchange
restrictions, political conditions and regulations.
Foreign Currency Translation
The U.S. dollar is the functional currency for CanArgo's upstream and refining
operations and the Lari is the functional currency for marketing operations. All
monetary assets and liabilities denominated in foreign currency are translated
into U.S. dollars at the rate of exchange in effect at the balance sheet date
and the resulting unrealized translation gains or losses are reflected in
operations. Non-monetary assets are translated at historical exchange rates.
Revenue and expense items (excluding depreciation and amortization which are
translated at the same rates as the related assets) are translated at the
average rate of exchange for the year.
Income Taxes
CanArgo recognizes deferred tax liabilities and assets for the expected future
tax consequences of events that have been included in the financial statements
or tax returns. Deferred tax liabilities and assets are determined based on the
difference between the financial statement and the tax bases of assets and
liabilities using enacted rates in effect for the years in which the differences
are expected to reverse. Valuation allowances are established, when appropriate,
to reduce deferred tax assets to the amount expected to be realized.
F-12
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Impairment of Long-Lived Assets
The Company evaluates its long-lived assets for impairment using the guidance of
Statement of Financial Accounting Standard ("SFAS") No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. SFAS No. 144 establishes a single
accounting model for long-lived assets to be disposed of by sale and requires
that those long-lived assets be measured at the lower of carrying amount or fair
value less cost to sell, whether reported in continuing operations or in
discontinued operations.
Asset Retirement Obligations
On January 1, 2003 CanArgo adopted FASB Statement No. 143 "Accounting for Asset
Retirement Obligations" ("SFAS 143"). SFAS 143 requires companies to record the
discounted fair value of a liability for an asset retirement obligation in the
period in which the liability is incurred concurrent with an increase in the
long-lived assets carrying value. The increase and subsequent adjustments in the
related long-lived assets carrying value is amortised over its useful life. Upon
settlement of the liability a gain or loss is recorded for the difference
between the settled liability and the recorded amount. The discount associated
with the liability is accreted into income over the related asset's useful life.
Upon adoption of this standard an entity is required to record the fair value of
its existing asset retirement obligations as if the liabilities had been
initially accounted for in accordance with SFAS 143 using assumptions present at
the date of adoption. The income statement effect of the treatment is recorded
as a cumulative effect in accounting principle in the period of adoption, no
retroactive restatement is permitted. During 2003, CanArgo recorded a credit to
income for the cumulative effect of change in accounting principle of $41,290,
increased long-term liabilities to recognise its total obligation and increased
net capital assets in accordance with the provisions of SFAS No. 143 to the
amount of $82,000. No deferred tax expense has been recognised on the SFAS 143
credit as the group is in a net deferred tax asset position against which full
allowance has been made as it is considered more likely than not that the
deferred tax asset will not be realised. There was no impact on the Company's
cash flows as a result of adopting SFAS No. 143. The pro forma asset retirement
obligation would have been $138,000 at December 31, 2002 had the Company adopted
SFAS No. 143 on January 1, 2002. The asset retirement obligation, which is
included on the Consolidated Balance Sheet in Provision for Future site
restoration, was $152,000 at December 31, 2003. The pro-forma amounts assuming
the new method of determination under SFAS 143 were not materially different to
the amounts shown in the income statement and the balance sheet for the prior
year.
Stock-Based Compensation Plans
In August 2003, the Company adopted SFAS No. 123 Accounting For Stock-Based
Compensation ("SFAS 123"), as amended by SFAS No. 148 Accounting for Stock-Based
Compensation--Transition and Disclosure -- an amendment of FASB Statement No.
123, effective as of January 1, 2003. The Company has elected to utilize the
"prospective" method of transitioning from the intrinsic value to the fair value
method of accounting for stock-based compensation as allowed by SFAS No. 148.
This change is estimated to decrease 2003 net income by approximately $276,507.
Stock based awards in existence prior to 2003 will continue to be accounted for
under APB Opinion No. 25, "Accounting for Stock Issued to Employees," unless
they are re-priced or modified.
Prior to 2003, the Company applied APB Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for stock-based
compensation. Under Opinion No. 25, stock-based employee compensation cost was
not recognized in net income when stock options granted had an exercise price
equal, or greater, to the market value of the underlying common stock on the
date of grant.
The pro forma information regarding net loss and net loss per share is required
by SFAS 123 and has been determined as if CanArgo had accounted for its employee
stock options under the fair value method of that statement. The fair value for
these options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted average assumptions for 2003, 2002 and
2001, respectively; risk free interest rates of 2.91%; dividend yields of 0%;
volatility factors of the expected market price of CanArgo common stock of
80.47; and a weighted-average expected life of the options of four years. The
following table illustrates the pro
F-13
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
forma effect on net loss and net loss per share if the fair value based method
had been applied to all outstanding and unvested awards for the years ended
December 31, 2003, 2002 and 2001:
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
For the Years Ended December 31,
-----------------------------------------------------
2003 2002 2001
------------ ------------ --------------
Net Loss as reported $ (7,322,215) $ (5,327,701) $ (13,218,347)
Add: Stock-based compensation cost, net of related
tax effects, included in the determination of net
income reported 276,507 - -
Less: Stock-based compensation cost, net of related
tax effects, that would have been included in the
determination of net income reported if the fair
value based method had been applied to all awards 786,783 925,339 1,334,339
Pro forma net loss (7,832,491) (6,253,040) (14,552,686)
Loss per share
Basic and diluted - as reported (0.08) (0.06) (0.16)
Basic and diluted - pro forma (0.08) (0.06) (0.17)
Recently Issued Pronouncements
In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities, an interpretation of ARB No. 51 ("FIN 46"). In
December 2003, the FASB modified FIN 46 to make certain technical corrections
and address certain implementation issues that had arisen. FIN 46 provides a new
framework for identifying variable interest entities ("VIEs") and determining
when a company should include the assets, liabilities, noncontrolling interests
and results of activities of a VIE in its consolidated financial statements.
In general, a VIE is a corporation, partnership, limited-liability corporation,
trust, or any other legal structure used to conduct activities or hold assets
that either: (1) has an insufficient amount of equity to carry out its principal
activities without additional subordinated financial support; (2) has a group of
equity owners that are unable to make significant decisions about its
activities; or (3) has a group of equity owners that do not have the obligation
to absorb losses or the right to receive returns generated by its operations.
FIN 46 requires a VIE to be consolidated if a party with an ownership,
contractual or other financial interest in the VIE ("a variable interest
holder") is obligated to absorb a majority of the risk of loss from the VIEs
activities, is entitled to receive a majority of the VIEs residual returns (if
no party absorbs a majority of the VIEs losses), or both. A variable interest
holder that consolidates the VIE is called the primary beneficiary. Upon
consolidation, the primary beneficiary generally must initially record all the
VIEs assets, liabilities and noncontrolling interests at fair value and
subsequently account for the VIE as if it were consolidated based on majority
voting interest. FIN 46 also requires disclosures about VIEs that the variable
interest holder is not required to consolidate but in which it has a significant
variable interest.
On October 9, 2003, the FASB issued Staff Position No. 46-6 which deferred the
effective date for applying the provisions of FIN 46 for interests held by
public entities in variable interest entities or potential variable interest
entities created before February 1, 2003. On December 24, 2003, the FASB issued
a revision to FIN 46. Under the revised interpretation, the effective date was
delayed to periods ending after March 15, 2004 for all variable interest
entities, other than SPEs. The adoption of FIN 46 is not expected to have an
impact on the Company's financial condition, results of operations or cash
flows.
F-14
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
The Company does not have an interest in any special purpose entity that is
required to be consolidated under FIN 46. The Company is currently evaluating
its involvement in other entities pursuant to the revised guidance; however, the
Company does not anticipate a significant effect as a result of its application.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement No. 133 on
Derivative Instruments and Hedging Activities. This statement amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities. SFAS No. 149 requires that contracts with comparable
characteristics be accounted for similarly. The statement is effective for
contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003. The provisions of SFAS No. 149
generally are to be applied prospectively only. The adoption of SFAS No. 149 did
not have a material impact on the Company's results of operations or financial
position.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150
establishes standards for classification and measurement by an issuer of certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that an issuer classify a financial instrument that is within
its scope as a liability (or asset in some circumstances). Many of those
instruments were previously classified as equity. This Statement also addresses
questions about the classification of certain financial instruments that embody
obligations to issue equity shares. This statement is effective for financial
instruments entered into or modified after May 31, 2003, and otherwise is
effective at the beginning of the first interim period beginning after June 15,
2003, except as it relates to consolidated limited-life subsidiaries. The FASB
indefinitely deferred the effective date of this statement as it relates to
certain mandatorily redeemable non-controlling interests in consolidated
limited-life subsidiaries. The adoption of the effective provisions of SFAS No.
150 did not have a material impact on the Company's results of operations or
financial position.
On December 17, 2003, the Staff of the Securities and Exchange Commission (or
SEC) issued Staff Accounting Bulletin No. 104 ("SAB 104"), Revenue Recognition,
which supersedes Staff Accounting Bulletin No. 101, Revenue Recognition in
Financial Statements ("SAB 101"). SAB 104's primary purpose is to rescind the
accounting guidance contained in SAB 101 related to multiple-element revenue
arrangements that was superseded as a result of the issuance of EITF
00-21,Accounting for Revenue Arrangements with Multiple Deliverables.
Additionally, SAB 104 rescinds the SEC's related Revenue Recognition in
Financial Statements Frequently Asked Questions and Answers issued with SAB 101
that had been codified in SEC Topic 13, Revenue Recognition. While the wording
of SAB 104 has changed to reflect the issuance of EITF 00-21, the revenue
recognition principles of SAB 101 remain largely unchanged by the issuance of
SAB 104, which was effective upon issuance. The adoption of SAB 104 did not have
a material effect on the Company's financial position or results of operations.
Other. Management has been made aware of a reporting issue regarding the
application of provisions of SFAS 141, Business Combinations and SFAS No. 142,
Goodwill and Other Intangible Assets ( SFAS 142 ) to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS 142
requires registrants to reclassify costs associated with mineral rights,
including both proved and unproved leasehold acquisition costs, as intangible
assets in the balance sheet, apart from other capitalized oil and gas property
costs. Historically, the Company's and other oil and gas companies have included
the cost of these oil and gas leasehold interests as part of oil and gas
properties and provided the disclosures required by SFAS No. 69, Disclosures
about Oil and Gas Producing Activities ( SFAS 69 ). Also under consideration is
whether SFAS 142 requires registrants to provide the additional disclosures
prescribed by SFAS 142 for intangible assets for costs associated with mineral
rights.
The Emerging Issues Task Force ("EITF") has recently decided to consider this
issue. If the EITF determines that SFAS 142 requires the Company to reclassify
costs associates with mineral rights from property and equipment to intangible
assets, the Company currently believes that its results of operations and
financial condition would not be materially affected, since such intangible
assets would continue to be depleted and assessed for impairment in accordance
with existing full cost accounting rules and impairment standards. In addition,
cost associated with mineral rights would continue to be characterized as oil
and gas property costs in the Company's required disclosures under SFAS 69.
F-15
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 3 - ACCOUNTS RECEIVABLE
Accounts receivable consisted of the following at December 31:
2003 2002
---------- ----------
Accounts Receivable before allowance for doubtful debts $ 983,693 $ 902,524
Allowance for doubtful debts (821,921) (651,921)
---------- ----------
$ 161,772 $ 250,603
========== ==========
Bad debt expense for 2003, 2002 and 2001 was $170,000, $250,000 and $275,000,
respectively, and is reflected under other income in the statement of
operations.
NOTE 4 - INVENTORY
Inventory consisted of the following at December 31:
2003 2002
---------- ----------
Crude oil $ 468,793 $ 158,896
---------- ----------
$ 468,793 $ 158,896
========== ==========
NOTE 5 - CAPITAL ASSETS
Capital assets, net of accumulated depreciation and impairment, include the
following at December 31, 2003:
Accumulated Net
Depreciation Capital
Cost And Impairment Assets
------------ -------------- -------------
Oil and Gas Properties
Proved properties $ 44,327,133 $ (21,084,230) $ 23,242,903
Unproved properties 26,592,260 - 26,592,260
------------ ------------- -------------
70,919,393 (21,084,230) 49,835,163
------------ ------------- -------------
Property and Equipment
Oil and gas related equipment 12,350,840 (4,240,698) 8,110,142
Office furniture, fixtures and
equipment and other 1,235,876 (858,482) 377,394
------------ ------------- -------------
13,586,716 (5,099,180) 8,487,536
------------ ------------- -------------
$ 84,506,109 $ (26,183,410) $ 58,322,699
============ ============= =============
F-16
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 5 - CAPITAL ASSETS (Continued)
Capital assets, net of accumulated depreciation and impairment, include the
following at December 31, 2002:
Accumulated Net
Depreciation Capital
Cost And Impairment Assets
------------ -------------- ------------
Oil and Gas Properties
Proved properties $ 32,443,742 $ (18,422,771) $ 14,020,971
Unproved properties 31,882,908 - 31,882,908
------------ ------------- ------------
64,326,650 (18,422,771) 45,903,879
------------ ------------- ------------
Property and Equipment
Oil and gas related equipment 11,991,991 (3,788,028) 8,203,963
Office furniture, fixtures and
equipment and other 1,187,526 (653,360) 534,166
------------ ------------- ------------
13,179,517 (4,441,388) 8,738,129
------------ ------------- ------------
$ 77,506,167 $ (22,864,159) $ 54,642,008
============ ============= ============
Oil and Gas Properties
Ultimate realization of the carrying value of CanArgo's oil and gas properties
will require production of oil and gas in sufficient quantities and marketing
such oil and gas at sufficient prices to provide positive cash flow to CanArgo,
which is dependent upon, among other factors, achieving significant production
at costs that provide acceptable margins, reasonable levels of taxation from
local authorities, and the ability to market the oil and gas produced at or near
world prices. In addition, CanArgo must mobilize drilling equipment and
personnel to initiate drilling, completion and production activities. If one or
more of the above factors, or other factors, are different than anticipated,
CanArgo may not recover its carrying value.
In the fourth quarter of 2003, CanArgo approved a plan to sell its interest in
the Bugruvativske field and recorded a write-down of $4,790,727 in 2003 of
unproved oil and gas properties to reflect the estimated recoverable amount from
disposal. The asset was subsequently reclassified to assets held for sale. In
the third quarter of 2003, CanArgo announced it had reached conditional
agreement to sell its interest in Boryslaw Oil Company, the joint venture in
West Ukraine currently operating the Stynawske oilfield. Fountain Oil Boryslaw,
CanArgo's wholly owned subsidiary which holds its 45% interest in Boryslaw Oil
Company, was sold for $1,000,000 payable in eight equal tranches. A gain on
disposal of the investment of Boryslaw Oil Company of $664,576 was recorded with
the write down of the Bugruvativske field. The net impairment to oil and gas
properties in 2003 was therefore $4,126,151.
As a result of application of the ceiling test limitation, CanArgo recorded a
write-down in 2002 of oil and gas properties of $1,600,000. In 2003, CanArgo did
not need to write-down oil and gas properties due to the ceiling test.
CanArgo generally has the principal responsibility for arranging financing for
the oil and gas properties and ventures in which it has an interest. There can
be no assurance, however, that CanArgo or the entities that are developing the
oil and gas properties and ventures will be able to arrange the financing
necessary to develop the projects being undertaken or to support the corporate
and other activities of CanArgo or that such financing as is available will be
on terms that are attractive or acceptable to or are deemed to be in the best
interests of CanArgo, such entities or their respective stockholders or
participants.
F-17
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 5 - CAPITAL ASSETS (Continued)
The consolidated financial statements of CanArgo do not give effect to any
additional impairment in the value of CanArgo's investment in oil and gas
properties and ventures or other adjustments that would be necessary if
financing cannot be arranged for the development of such properties and ventures
or if they are unable to achieve profitable operations. Failure to arrange such
financing on reasonable terms or failure of such properties and ventures to
achieve profitability would have a material adverse effect on the financial
position, including realization of assets, results of operations, cash flows and
prospects of CanArgo.
Unproved property additions relate to CanArgo's exploration activity in the
period. Oil and gas related equipment includes new or refurbished drilling rigs
and related equipment, all of which are located in the Republic of Georgia.
Property and Equipment
Oil and gas related equipment includes drilling rigs and related equipment
currently in use by CanArgo in the development of the Ninotsminda field.
NOTE 6 - INVESTMENT IN AND ADVANCES TO OIL AND GAS AND OTHER VENTURES
CanArgo has acquired interests in oil and gas and other ventures through less
than majority interests in corporate and corporate-like entities. A summary of
CanArgo's net investment in and advances to oil and gas and other ventures
consisted of the following at December 31:
2003 2002
-------- ------------
Investments in and Advances to Oil and Gas and Other Ventures
Ukraine - Stynawske Field, Boryslaw
Through 45% ownership of Boryslaw Oil Company $ - $ 6,524,121
Other Investments 75,000 75,000
--------- ------------
Total Investments in and Advances to Oil and Gas
and Other Ventures $ 75,000 $ 6,599,121
--------- ------------
Equity in Profit (Loss) of Oil and Gas and Other Ventures
Ukraine - Stynawske Field, Boryslaw - (680,020)
--------- ------------
Cumulative Equity in Profit (Loss) of Oil and Gas and other ventures - (680,020)
--------- ------------
Impairment - Stynawske Field, Boryslaw - (5,459,793)
Disposition of investment - Stynawske Field, Boryslaw - -
--------- ------------
- (5,459,793)
Total Investments in and Advances to Oil and Gas and Other
Ventures, Net of Equity Loss and Impairment $ 75,000 $ 459,308
========= ============
In September 2003, CanArgo announced it had reached conditional agreement to
sell its interest in Boryslaw Oil Company, the joint venture in West Ukraine
currently operating the Stynawske oilfield. Fountain Oil Boryslaw, CanArgo's
wholly owned subsidiary which holds its 45% interest in Boryslaw Oil Company,
was sold for $1,000,000 payable in eight equal tranches. The buyer has also
acknowledged Boryslaw Oil Company's debts to CanArgo for earlier loans in the
total amount of $160,000. On November 10, 2003 CanArgo announced that the full
F-18
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
payment had been received early and that CanArgo's interest in Fountain Oil
Boryslaw had been transferred to the buyer.
Other investments represent CanArgo's 10% interest in a Caspian Sea exploration
project.
NOTE 7 - ADVANCE FROM JOINT VENTURE PARTNER
In 2003, CanArgo received $1,427,612 from Georgian Oil in accordance with the
Norio farm-in agreement. In the third quarter of 2003, CanArgo Norio signed a
farm-in agreement relating to the Norio Production Sharing Agreement ("Norio
PSA") with a wholly owned subsidiary of Georgian Oil, the Georgian State Oil
Company. The farm-in agreement obligates Georgian Oil to pay up to $2.0 million
to deepen, to a planned depth of 16,400 feet (5,000 metres) the MK-72 well in
return for a 15% interest in the contractor share of the Norio PSA. Georgian Oil
also has an option, exercisable for a limited period after completion of the
well, to increase its interest to 50% of the contractor share of the Norio PSA
on payment to CanArgo Norio of US$ 6.5 million. If Georgian Oil exercises this
Option under the farm-in agreement, it loses its rights to exercise the
Production Sharing Agreement Option under the Norio PSA itself.
NOTE 8 - LOANS PAYABLE
Loans payable of $102,179 at December 31, 2003 relates to a short-term secured
loan facility maturing on February 27, 2004, which a subsidiary of CanArgo
entered into, locally in Georgia, at an annual interest rate of 20% in order to
fund the drilling of a new horizontal well, N4H, at the Ninotsminda Field in
Georgia. No parent company guarantees have been provided by CanArgo with respect
to this loan. The loan matured and was paid off in full in February 2004.
NOTE 9 - OTHER LIABILITIES
Other liabilities consisted of the following at December 31:
2003 2002
---------- ----------
Prepaid sales $3,228,899 $1,000,000
Advanced proceeds, less costs of the sale of subsidiary 1,943,729 500,000
Advanced proceeds from the sale of other assets 301,195 -
---------- ----------
$5,473,823 $1,500,000
========== ==========
See Note 17 for details of the sale of the subsidiary classified as discontinued
operation.
NOTE 10 - ACCRUED LIABILITIES
Accrued liabilities consisted of the following at December 31:
2003 2002
-------- --------
Professional fees $231,396 $105,000
Other 118,091 99,045
-------- --------
$349,487 $204,045
======== ========
F-19
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 11 - MINORITY INTEREST
In November 2002, CanArgo reached agreement with the other shareholder in
CanArgo's subsidiary, CanArgo Norio Limited ("CanArgo Norio"), and with third
party investors on a financing arrangement to enable CanArgo Norio to commence
drilling the MK-72 well on the Norio prospect. This agreement resulted in
CanArgo's interest increasing from 50% to 64.2% in CanArgo Norio and in its
existing Norio PSA in the Republic of Georgia (the "Norio PSA"). As a result of
the finalization of respective equity interest, CanArgo's interest was adjusted
to reflect its share of $6,031,070, the carrying net asset value of CanArgo
Norio. The nominal value of the final shares issued in CanArgo Norio were $1,250
per share which gives a nominal value for CanArgo Norio of $11,328,928 of which
CanArgo's share is $7,269,023 and the minority shareholders share was
$4,059,905.
In September 2003 CanArgo Norio signed a Farm-In agreement (the "Agreement")
relating to the Norio PSA with a wholly owned subsidiary of Georgian Oil, the
Georgian State Oil Company ("Georgian Oil"). CanArgo Norio had previously been
in negotiations with a large third party energy company to farm-in to the Norio
PSA, but Georgian Oil exercised its pre-emption right under the Norio PSA.
Georgian Oil is already a party to the Norio PSA as the commercial
representative of the State.
The Agreement obligates Georgian Oil to pay up to US$2,000,000 to complete the
MK-72 well on the Norio prospect in return for a 15% interest in the contractor
share of the Norio PSA. Georgian Oil will also have an option (the "Option")
exercisable for a limited period after completion of the well, to increase its
interest to 50% of the contractor share of the Norio PSA on payment to CanArgo
Norio of US$6,500,000.
Co-incident with the Georgian Oil farm-in CanArgo concluded a deal to purchase
some of the minority interests in CanArgo Norio by a share swap for shares in
CanArgo. Through this CanArgo has acquired an additional 10.8% interest in
CanArgo Norio, giving CanArgo a 75% interest in CanArgo Norio at present. This
approximately maintains CanArgo's effective interest in the Norio PSA after
Georgian Oil has completed the first stage of the farm-in at 63.7%. The purchase
was achieved by issuing 6,000,000 restricted CanArgo shares to the minority
interest holders in CanArgo Norio. Of the interests in CanArgo Norio, 4% were
owned by Provincial Securities Limited, a company which J.F. Russell Hammond, a
non-executive director of CanArgo, is an investor advisor. Provincial Securities
Limited received 2,273,523 shares of common stock in return for their interest.
In the event that Georgian Oil exercises the Option and pays the required
$6,500,000, CanArgo (which would have received some $4,800,000 of this payment
with its previous interest) would receive a further $1,200,000, resulting in a
total payment to CanArgo of approximately $6,000,000. If the Option is exercised
CanArgo would issue a further 3,000,000 restricted shares to the minority
interest holders. As well as the Norio PSA, CanArgo Norio also owns 100% of the
contractor interest in the recently signed Block XI(G) and XI(H) Production
Sharing Contract ("Tbilisi PSC"). Georgian Oil is not currently farming in to
the Tbilisi PSC, which will remain solely with CanArgo Norio. CanArgo Norio is
consolidated in the accounts of CanArgo.
In September 1998, CanArgo purchased for $1,000,000 a 12.9% equity interest in
GAOR, a company which owns a small refinery located at Sartichala, Georgia. On
November 12, 2000, CanArgo acquired a further 38.1% of the common stock of GAOR
for Common Stock consideration valued at $1,666,575. On completion of the
acquisition, CanArgo held 51% of the common stock of GAOR and GAOR became a
subsidiary of CanArgo. GAOR's results have been included in CanArgo's
consolidated financial statements since the date of acquisition. The refinery
began operations in July 1998 and has a potential design capacity of
approximately 4,000 barrels per day.
Since 2001 the refinery has not been operating. Since its acquisition, sales
from the refinery have been negatively impacted by the imposition of
restrictions and subsequent excise tax on feedstock and refined products.
Currently only naphtha, diesel and mazut can be produced and of these products,
an excise tax on naphtha and diesel sales remain in place. As a result of these
taxes and the local market for naphtha in the Republic of Georgia, GAOR deemed
production of naphtha as commercially uneconomic and suspended refining activity
in the fourth quarter of
F-20
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
2001. In January 2002, GAOR entered into a short-term lease of the refinery to a
third party for nominal revenue. During the lease period, all operating costs of
the refinery were borne by the lessee. This lease expired in May 2002 and has
not been renewed. As a result of the uncertainty as to the ultimate
recoverability of the carrying value of the
NOTE 11 - MINORITY INTEREST (Continued)
refinery, CanArgo recorded in 2001 a write-down of the refinery's property,
plant and equipment of approximately $3.5 million. During 2003, a debit balance
of $1,274,895 in minority interest was written-off due to a change in the
intentions of our minority interest owner and a plan to dispose of the asset. In
2004, CanArgo came to an agreement to sell the refinery.
NOTE 12 - COMMITMENTS AND CONTINGENCIES
CanArgo has not filed any of its required 2002 or 2003 income tax or information
returns required by various governmental authorities. Failure to file these
returns carries significant penalties. CanArgo is taking steps to rectify the
matter. CanArgo has not accrued for any penalties it may be required to pay.
CanArgo has contingent obligations and may incur additional obligations,
absolute or contingent, with respect to the acquisition and development of oil
and gas properties and ventures in which it has interests that require or may
require CanArgo to expend funds and to issue shares of its Common Stock.
At December 31, 2003, CanArgo had a contingent obligation to issue 187,500
shares of common stock to Fielden Management Services PTY, Ltd (a third party
management services company) upon satisfaction of conditions relating to the
achievement of specified Stynawske field project performance standards.
Under the Norio PSA the shareholders agreement with the other shareholder of
Norio calls for a bonus payment of $800,000 to be paid by CanArgo should
commercial production be obtained from the Middle Eocene or older strata and a
second bonus payment of $800,000 should production from the Block from the
Middle Eocene or older strata exceed 250 tons of oil per day over any 90 day
period.
If Georgian Oil exercises the Option available to it under the terms of the
Norio farm-in agreement signed in September 2003, CanArgo would issue a further
3 million restricted shares to the minority interest holders from whom CanArgo
acquired an additional 10.8% interest in CanArgo Norio.
In May 2003, NOC entered into a new 12-month crude oil sales agreement whereby
the buyer will provide a security payment of $1,750,000 in return for the right
to lift up to 5,000 metric tons of oil per month for the 12-month period
commencing August 2003. At the end of the 12 months, the security payment will
be repaid through the delivery of additional crude oil equal to the value of the
security. This agreement replaces an existing crude oil sales agreement, where
the buyer had already provided $1,000,000 security. Following the success of the
N100H well, NOC entered into a further oil sales agreement with the buyer for an
additional monthly quantity of 2,500 metric tons of oil. The agreement runs to
the end of 2004 and as security for payment and for having the option to lift
oil on a monthly basis the buyer will provide additional security in the amount
of $550,000. The security will be repaid in oil at the end of the contract
period. NOC has a total commitment to repay $2,300,000 arising from security
payments under oil sales agreements signed in May 2003 and October 2003.
On July 2, 2003 CanArgo announced that its subsidiary CanArgo Norio had entered
into a new Production Sharing Contract (PSC) for Blocks XI(G) and XI(H)
(Mtskheta, Tetritskaro and Gardabani areas), named the "Tbilisi PSC" in the
Republic of Georgia. The license was subsequently issued on 9 July 2003 for a
period of 25 years. These areas are located adjacent to CanArgo's existing
acreage close to Tbilisi and cover in total some 485 km(2). Under the terms of
the Tbilisi PSC, CanArgo Norio will evaluate existing seismic and geological
data during the first year and acquire additional seismic data within four years
of the effective date of the Agreement which is September 29, 2003. The total
commitment over the next four years is $350,000. The commercial terms of the
Tbilisi PSC are similar to those governing CanArgo Norio's other exploration
areas.
F-21
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 12 - COMMITMENTS AND CONTINGENCIES (Continued)
Lease Commitments - CanArgo leases office space under non-cancelable operating
lease agreements. Rental expense for the years ended December 31, 2003, 2002 and
2001 was $395,355, $327,254 and $353,594 respectively. Future minimum rental
payments over the next five years for the Company's lease obligations as of
December 31, 2003, are as follows:
2004 $ 261,400
2005 240,750
2006 222,243
2007 220,000
2008 220,000
Thereafter 440,000*
----------
$1,604,393
==========
* This represents aggregate payments for 2 years.
No parent company guarantees have been provided by CanArgo with respect to its
contingent obligations and commitments.
NOTE 13 - CONCENTRATIONS OF CREDIT RISK
CanArgo's financial instruments that are exposed to concentrations of credit
risk consist primarily of cash and cash equivalents, accounts receivable and
advances to oil and gas and other ventures. CanArgo places its temporary cash
investments with high credit quality financial institutions. Accounts receivable
relates primarily to entities active in the energy and manufacturing sectors.
The concentration of credit risk associated with accounts receivable is reduced
as CanArgo's debtors are spread across several countries and industries.
NOTE 14 - STOCKHOLDERS' EQUITY
On July 8, 1998, at a Special Meeting of Stockholders, the stockholders of
CanArgo approved the acquisition of all of the common stock of CanArgo Oil and
Gas ("CAOG") for Common Stock of the Company pursuant to the terms of an Amended
and Restated Combination Agreement between those two companies (the "Combination
Agreement"). Upon completion of the acquisition on July 15, 1998, CAOG became a
subsidiary of CanArgo, and each previously outstanding share of CAOG common
stock was converted into the right to receive 0.8 shares (the "Exchangeable
Shares") of CAOG which are exchangeable generally at the option of the holders
for shares of CanArgo's Common Stock on a share-for-share basis.
On January 24, 2002 CanArgo announced that it had established May 24, 2002 as
the redemption date for all of the Exchangeable Shares of CAOG since the number
of outstanding Exchangeable Shares had fallen below the minimum 853,071 share
threshold. Each Exchangeable Share was purchased by CanArgo for shares of
CanArgo Common Stock on a share-for-share basis resulting in the issuance of an
aggregate of 148,826 shares of Common Stock. No cash consideration was issued by
CanArgo and the purchase did not increase the total number of shares of Common
Stock of CanArgo deemed issued and issuable.
The total number of shares of common stock authorized was 150,000,000 for 2003,
2002 and 2001.
F-22
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
As of December 31, 2003, CanArgo had 5,000,000 shares of $0.10 par value
preferred stock authorized, of which none were outstanding. The Board of
Directors may at any time issue additional shares of preferred stock and may
designate the rights and privileges of a series of preferred stock without any
prior approval by the stockholders.
NOTE 14 - STOCKHOLDERS' EQUITY (Continued)
During the years ended December 31, 2003 and 2002, the following transactions
regarding CanArgo's Common Stock were consummated pursuant to authorization by
CanArgo's Board of Directors or duly constituted committees thereof.
Year Ended December 31, 2003
- In September 2003, CanArgo issued 6,000,000 shares at $0.19 per share
for purchase some of an additional 10.8% interest in CanArgo Norio.
- In December 2003, CanArgo issued 2,000,000 shares at $0.33 per share
upon completion of the purchase of the interest of the farm-in partner
in the Minavi well.
- In December 2003, CanArgo issued 261,782 shares at $0.33 per share upon
completion of a Standby Equity Distribution Agreement that allows
CanArgo, at its option, to issue shares to US-based investment fund
Cornell Capital Partners LP up to a maximum value of $6 million. Under
the terms of the Agreement, CanArgo may, at its discretion, issue
shares to Cornell at any time over the next two years. The maximum
aggregate amount of the equity placements pursuant to the Agreement is
$6 million. Subject to this limitation, CanArgo may draw down up to
$200,000 in any seven-day period. The facility may be used in whole or
in part entirely at CanArgo's discretion, subject to an effective
registration. Shares issued to Cornell will be priced at a 3% discount
to the lowest daily Volume Weighted Average Price (`VWAP') of CanArgo
Energy Corporation shares traded on each of the five days following a
drawdown notice by CanArgo. A commission of 5% will apply to each issue
of CanArgo shares under the Agreement and will be payable to Cornell at
the time of issue. The net effect of the 5% commission and the 3%
discount is that Cornell shall pay 92.15% of the applicable lowest
weighted price for each share of the Company's common stock. This
facility was terminated on February 11, 2004 when the Company entered
into a further standby equity distribution agreement with Cornell ("New
Cornell Facility"). No funds had been drawn down under the original
facility when it was terminated.
In terms of the New Cornell Facility, Cornell will provide the CanArgo
with an equity line of credit for 24 months. The New Cornell Facility
allows CanArgo at its discretion to periodically issue and sell to
Cornell up to $20 million of shares of its common stock. The terms of
the New Cornell Facility are materially the same as those for the
original facility, with the exception that the New Cornell Facility has
been extended to $20 million and the maximum amount of each advance is
set at $600,000. No exercise of a Put will be made until the SEC has
declared a Registration Statement effective. By way of fees and
expenses, the Company shall issue Cornell a restricted stock
certificate evidencing restricted shares of Common Stock in an amount
equal to 2.07% of the Commitment Amount ($20,000,000) based upon the
Market Price for the Common Stock. The total amount of shares to be
issued to Cornell is 850,000 of which 425,000 were issued upon
execution of the agreement. Cornell will earn the remaining 425,000 in
restricted shares of Common Stock once the SEC declares the
Registration Statement effective.
Year Ended December 31, 2002
- In February 2002, CanArgo issued 5,210,000 shares at $0.34 per share
upon completion of a private placement.
- In May 2002, CanArgo issued 137,760 shares at $0.21 to David Robson,
CanArgo's Chief Executive Officer, for gross proceeds of approximately
$29,000 upon completion of a private placement.
F-23
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 14 - STOCKHOLDERS' EQUITY (Continued)
- In May, 2002 CanArgo redeemed all of the Exchangeable Shares of CAOG
since the number of outstanding Exchangeable Shares had fallen below
the minimum 853,071 share threshold. Each Exchangeable Share was
purchased by CanArgo for shares of CanArgo Common Stock on a
share-for-share basis resulting in the issuance of an aggregate of
148,826 shares of Common Stock. No cash consideration was issued by
CanArgo and the purchase did not increase the total number of shares of
Common Stock of CanArgo deemed issued and issuable.
Year Ended December 31, 2001
- In 2001, CanArgo issued 274,965 shares upon exchange by holders of
Exchangeable Shares.
- In July 2001, CanArgo issued 16,057,765 shares at $0.41 per share upon
completion of a private placement.
NOTE 15 - NET LOSS PER COMMON SHARE
Basic and diluted net loss per common share for the years ended December 31,
2003, 2002 and 2001 were based on the weighted average number of common shares
outstanding during those periods. The weighted average number of shares used was
99,432,000, 96,643,744 and 83,869,579 respectively. Options to purchase
CanArgo's Common Stock were outstanding during the years ended December 31,
2003, 2002 and 2001 but were not included in the computation of diluted net loss
per common share because the effect of such inclusion would have been
anti-dilutive. The total number of such shares excluded from diluted net loss
per common share were 7,986,167, 6,734,501 and 7,092,001 for each of the years
ended December 31, 2003, 2002 and 2001 respectively.
NOTE 16 - INCOME TAXES
CanArgo and its domestic subsidiaries file U.S. consolidated income tax returns.
No benefit for U.S. income taxes has been recorded in these consolidated
financial statements because of CanArgo's inability to recognize deferred tax
assets under provisions of SFAS 109. Due to the implementation of the
quasi-reorganization as of October 31, 1988, future reductions of the valuation
allowance relating to those deferred tax assets existing at the date of the
quasi-reorganization, if any, will be allocated to capital in excess of par
value. A reconciliation of the differences between income taxes computed at the
U.S. federal statutory rate of 34% and CanArgo's reported provision for income
taxes is as follows:
Year Ended December 31,
-------------------------------------------------
2003 2002 2001
----------- ----------- -----------
Income tax benefit at statutory rate $(2,386,000) $(1,811,418) $(4,494,238)
Benefit of losses not recognized 2,386,000 1,811,418 4,494,238
Other, net - - -
----------- ----------- -----------
Provision for income taxes $ - $ - $ -
=========== =========== ===========
Effective tax rate 0% 0% 0%
=========== =========== ===========
F-24
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 16 - INCOME TAXES (Continued)
The components of deferred tax assets consisted of the following as of December
31:
2003 2002
------------ ------------
Net operating loss carryforwards $ 8,443,000 $ 9,512,000
Foreign net operating loss carryforwards 5,953,000 5,142,000
Net timing differences on impairments and accelerated
capital allowances 9,383,000 8,981,000
------------ ------------
23,779,000 23,635,000
Valuation allowance (23,779,000) (23,635,000)
------------ ------------
Net deferred tax asset recognized in balance sheet $ - $ -
============ ============
On August 1, 1991, August 17, 1994, July 15, 1998 and June 28, 2000 CanArgo
experienced changes in ownership as defined in Section 382 of the Internal
Revenue Code ("IRC"). The effect of these changes in ownership is to limit the
utilization of certain existing net operating loss carryforwards for income tax
purposes to approximately $413,000 per year on a cumulative basis. As of
December 31, 2003, total U.S. net operating loss carryforwards were
approximately $24,833,000. Of that amount, approximately $1,551,000 was incurred
subsequent to the ownership change in 2000, $26,426,000 was incurred prior to
2000 and therefore is subject to the IRC Section 382 limitation. See Note 2 of
Notes to Consolidated Financial Statements.
The net operating loss carryforwards expire from 2004 to 2022 The net operating
loss carryforwards limited under the separate return limitation rules may only
be offset against the separate income of the respective subsidiaries. CanArgo
has also generated approximately $13,628,000 of foreign net operating loss
carryforwards. A significant portion of the foreign net operating loss
carryforwards are subject to limitations similar to IRC Section 382.
CanArgo's available net operating loss carryforwards may be used to offset
future taxable income, if any, prior to their expiration. CanArgo may experience
further limitations on the utilization of net operating loss carryforwards and
other tax benefits as a result of additional changes in ownership.
NOTE 17 - DISCONTINUED OPERATIONS
CanArgo Standard Oil Products
In September 2002, CanArgo approved a plan to sell CanArgo Standard Oil Products
to finance Georgian and Ukrainian development projects and in October 2002,
CanArgo agreed to sell its 50% holding to an unaffiliated company for $4,000,000
in an arms-length transaction, with legal ownership being transferred upon
receipt of final payment due originally in August 2003 and subsequently extended
to June 2004. The agreed consideration to be exchanged does not result in an
impairment of the carrying value of assets held for sale. The assets and
liabilities of CanArgo Standard Oil Products have been classified as "Assets
held for sale" and "Liabilities held for sale" for all periods presented. The
results of operations of CanArgo Standard Oil Products have been classified as
discontinued for all periods presented. The minority interest related to CanArgo
Standard Oil Products has not been reclassified for any of the periods
presented, however net income from discontinued operations is disclosed net of
taxes and minority interest.
F-25
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 17 - DISCONTINUED OPERATIONS (Continued)
The results of discontinued operations in respect of CanArgo Standard Oil
Products consisted of the following for the years ending December 31:
2003 2002 2001
----------- ----------- -----------
Operating Revenues $ 9,837,445 $ 7,390,138 $ 6,607,489
Income Before Income Taxes
and Minority Interest 392,411 366,556 733,335
Income Taxes (25,297) (24,132) (46,203)
Minority Interest in Income (183,557) (171,212) (343,566)
----------- ----------- -----------
Net Income from Discontinued
Operation $ 183,557 $ 171,212 $ 343,566
=========== =========== ===========
Gross consolidated assets and liabilities in respect of CanArgo Standard Oil
Products that are included in "assets and liabilities held for sale" consisted
of the following at December 31:
2003 2002
---------- ----------
Assets held for sale:
Cash and cash equivalents $ 30,236 $ 37,948
Accounts receivable 1,675,317 243,529
Inventory 247,758 224,733
Other current assets 174,049 155,079
Capital assets, net 6,629,450 6,326,478
Investment in other ventures, net 594,484 548,910
---------- ----------
$9,351,294 $7,536,677
========== ==========
Liabilities held for sale:
Accounts payable $ 174,506 $ 143,296
Current portion of long term debt 958,346 1,268,422
Income taxes payable 261 48,880
Long term debt 2,816,065 891,367
---------- ----------
$3,949,178 $2,351,965
========== ==========
Investments in other ventures include three petrol station sites in Tbilisi,
Georgia in which CanArgo has a 50% non-controlling interest. CanArgo accounts
for its interest in the three petrol station sites using the equity method and
consolidates the remaining sites in which it has controlling interest. In 2002,
CanArgo purchased the remaining 50% of Petro-Invest, a petrol station site in
which CanArgo previously held a 50% non-controlling interest. This site is now
consolidated in the results of CanArgo Standard Oil Products, above.
Cash consideration received as of December 31, 2003 in respect of this
transaction was $2,000,000 and has been recorded in other liabilities (see Note
10). The sale will be reflected on payment of the consideration in full plus any
interest due which is now expected to be in June 2004. In any event, ownership
in the asset will only transfer to Westrade Alliance on payment of the
consideration in full.
F-26
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 17 - DISCONTINUED OPERATIONS (Continued)
In 2002, the three petrol station sites that CanArgo has a 50% non-controlling
interest entered into credit facility agreements amounting to $550,000 with a
commercial lender in Georgia. As of December 31, 2003, $261,824 under the
facilities were outstanding. The loans bear interest at 18% per annum and are
secured by the assets of the petrol stations. The full amount of the loans are
to be repaid by June 2005. No company guarantees have been provided by CanArgo
with respect to these loans.
From November 2001 through December 2003, CanArgo Standard Oil Products Limited
entered into eight credit facility agreements totaling $5,640,000 with
commercial lenders in Georgia and Greece to fund expansion of its petrol station
network. As of December 31, 2003, CanArgo had outstanding balances of $3,774,411
related to these credit facilities. The loans bear interest between 13% and 18%
per annum and are secured by the assets of the petrol stations. The full amounts
of the loans are to be repaid by August 2008. No guarantees have been provided
by CanArgo with respect to these loans.
The remaining 50% interest in CanArgo Standard Oil Products is held by Standard
Oil Products of Georgia and an individual, Mr. Levan Pkhakazde, who is one of
the founders of Standard Oil Products and the General Director of CanArgo
Standard Oil Products.
During 2003 CanArgo approved a plan to sell its interest in the Bugruvativske
field and its interest in GAOR. The assets and liabilities of these companies
have been classified as "Assets held for sale" and "Liabilities held for sale"
for all period presented. The results of operations of the companies have been
classified as discontinued operations for all period presented.
Lateral Vector Resources Inc
Lateral Vector Resources Inc. ("LVR"), a wholly-owned subsidiary of CanArgo,
negotiated and concluded with Ukrnafta, the Ukrainian State Oil Company, a Joint
Investment Production Activity ("JIPA") agreement in 1998 to develop the
Bugruvativske Oil Field located in Eastern Ukraine.
In 2003, due to the lack of progress with the implementation of the JIPA, and
failure to reach a negotiated agreement with Ukrnafta, management reached the
decision to dispose of its interest in the Bugruvativske project and withdraw
from Ukraine. The company is currently in negotiations with a potential buyer
for the disposal of its 100% interest in LVR. Consequently, CanArgo recorded in
2003 a write-down in respect to the LVR deal and the acquisition of the
Bugruvativske Field of approximately $4.8 million.
The assets and liabilities of LVR have been classified as "Assets held for sale"
and "Liabilities held for sale" for all periods presented. The results of
operations of LVR have been classified as discontinued for all periods
presented.
The results of discontinued operations in respect of LVR consisted of the
following for the years ending December 31:
2003 2002 2001
----------- ---------- ----------
Income (Loss) Before Income Taxes
and Minority Interest $(4,732,418) $ (12,735) $ (38,792)
Net Income (Loss) from Discontinued
Operation $(4,732,418) $ (12,735) $ (38,792)
=========== ========== ==========
F-27
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 17 - DISCONTINUED OPERATIONS (Continued)
Gross consolidated assets in respect of LVR that are included in "assets held
for sale" consisted of the following at December 31:
2003 2002
---------- -----------
Assets held for sale:
Capital assets, net $ 250,000 $ 4,960,517
---------- -----------
$ 250,000 $ 4,960,517
========== ===========
There were no Gross consolidated liabilities in respect of LVR included in
"liabilities held for sale" at December 31 2003 and 2002.
Georgian American Oil Refinery
In 2003, CanArgo approved a plan to dispose of its interest in GAOR as the
refinery had remained closed since 2001 and neither CanArgo nor its partners
could find a commercially viable option to putting the refinery back into
operation. In February 2004, management reached an agreement with a local
Georgian company to sell CanArgo's 51% interest in GAOR for a nominal price of
one US dollar and the assumption of all the obligations and debts of GAOR to the
State of Georgia including deferred tax liabilities of approximately $380,000.
The assets and liabilities of GAOR have been classified as "Assets held for
sale" and "Liabilities held for sale" for all periods presented. The results of
operations of GAOR have been classified as discontinued for all periods
presented. The minority interest related to GAOR has not been reclassified for
any of the periods presented, however net income from discontinued operations is
disclosed net of taxes and minority interest. During 2003, a debit balance of
$1,274,895 in minority interest was written-off due to a change in the
intentions of our minority interest owner and a plan to dispose of the asset.
The plan to dispose of the asset also led to the write-off of an inter-company
payable relating to oil sales purchased from Ninotsminda Oil Company. These
items have been respectively recorded in impairment of other assets and other
income (expense) components of continuing operations. An impairment to the
assets of GAOR in 2001 has also been recorded in the impairment of other assets
component of continuing operations.
The results of discontinued operations in respect of GAOR consisted of the
following for the years ending December 31:
2003 2002 2001
---------- ----------- -----------
Operating Revenues $ - $ 90,187 $ 2,595,763
Income (Loss) Before Income Taxes
and Minority Interest (1,485,705) (16,180) (3,848,182)
Minority Interest in Loss (492,951) 7,928 2,138,163
----------- ----------- -----------
Net Income from Discontinued
Operation $(1,978,656) $ (8,252) $(1,710,019)
=========== =========== ===========
F-28
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 17 - DISCONTINUED OPERATIONS (Continued)
Gross consolidated assets and liabilities in respect of GAOR that are included
in "assets and liabilities held for sale" consisted of the following at December
31:
2002 2003
---------- ----------
Assets held for sale:
Cash and cash equivalents $ 14,095 $ 13,304
Accounts receivable - 55,733
Inventory 29,482 27,028
Other current assets 13,915 -
Capital assets, net 100,000 100,000
---------- ----------
$ 157,492 $ 196,065
========== ==========
Liabilities held for sale:
Accounts payable $ 498,528 $ 466,762
---------- ----------
$ 498,528 $ 466,762
========== ==========
3-megawatt duel fuel power generator
In 2003, CanArgo signed a sales agreement disposing of a 3-megawatt duel fuel
power generator for $600,000. Following receipt of a non-refundable deposit of
$300,000.
The generator has been classified as "Assets held for sale" for all periods
presented. The generator was impaired in 2003 and 2001 by $80,000 and $500,000
respectively to reflect its fair value less cost to sell. The results for the
generator are the following for the years ending December 31:
2003 2002 2001
---------- ---------- ----------
Income (Loss) Before Income Taxes
and Minority Interest $ (80,000) $ - $ (500,000)
---------- ---------- ----------
Net Income (Loss) from Discontinued
Operation $ (80,000) $ - $ (500,000)
========== ========== ==========
Gross consolidated assets in respect of the generator included in "assets held
for sale" consisted of the following at December 31:
2003 2002
---------- ----------
Assets held for sale:
Capital assets, net $ 587,291 $ 559,270
---------- ----------
$ 587,291 $ 559,270
========== ==========
NOTE 18 - SEGMENT AND GEOGRAPHICAL DATA
During the year ended December 31, 2003 CanArgo's continuing operations operated
through two business segments, oil and gas exploration and refining.
F-29
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 18 - SEGMENT AND GEOGRAPHICAL DATA (Continued)
Operating revenues from continuing operations by business segment and
geographical area were as follows for the years ended December 31:
2003 2002 2001
------------ ------------ ------------
Operating Revenues from
Continuing Operations:
Oil and Gas Exploration,
Development and Production
Eastern Europe $ 7,882,070 $ 4,179,208 $ 4,873,623
Other
Eastern Europe 223,608 1,322,554 608,032
Intersegment Eliminations (898) (16,007) (906,545)
------------ ------------ ------------
Total $ 8,104,780 $ 5,485,755 $ 4,575,110
============ ============ ============
In 2003, the Company sold its oil and gas production in Eastern Europe to thirty
two (2002 - twenty two, 2001 - five) customers. In 2003 sales to three third
party customers represented 42%, 32% and 17% of oil and gas revenue
respectively. In 2002 sales to four third party customers represented 27%, 25%,
19% and 19% of oil and gas revenue respectively. In 2001 sales to three
customers represented 67%, 12% and 12% of oil and gas revenue respectively.
Operating profit (loss) from continuing operations for the business segment and
geographical area were as follows for the years ending December 31:
2003 2002 2001
------------ ------------ ------------
Oil and Gas Exploration,
Development and Production
Eastern Europe $ 4,750,974 $ 581,935 $ (7,037,431)
Corporate and Other Expenses (4,909,615) (5,484,062) (4,800,531)
------------ ------------ ------------
Total $ (158,641) $ (4,902,127) $(11,837,962)
============ ============ ============
In the fourth quarter of 2003, CanArgo approved a plan to sell its interest in
the Bugruvativske field and recorded a write-down of $4,790,727 in 2003 of
unproved oil and gas properties to reflect the estimated recoverable amount from
disposal. The asset was subsequently reclassified to assets held for sale. In
the third quarter of 2003, CanArgo announced it had reached conditional
agreement to sell its interest in Boryslaw Oil Company, the joint venture in
West Ukraine currently operating the Stynawske oilfield. Fountain Oil Boryslaw,
CanArgo's wholly owned subsidiary which holds its 45% interest in Boryslaw Oil
Company, was sold for $1,000,000 payable in eight equal tranches. A gain on
disposal of the investment of Boryslaw Oil Company of $664,576 was recorded with
the write down of the Bugruvativske field. The net impairment to oil and gas
properties in 2003 was therefore $4,126,151.
F-30
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 18 - SEGMENT AND GEOGRAPHICAL DATA (Continued)
As a result of application of the ceiling test limitation, CanArgo recorded a
write-down in 2002 of oil and gas properties of $1,600,000. The write-down of
oil and gas properties and generating equipment was recorded in operating loss
for oil and gas, exploration and production. The write-down of minority interest
share of losses in the refinery was recorded in loss for refining. In 2001, an
impairment of $7,300,000 as a result of application of the ceiling test
limitation was recorded in operating loss for oil and gas, exploration.
In 2003 depreciation, depletion and amortization of $3,087,127 and $205,121 were
recorded in operating loss for oil and gas, exploration and production and
corporate and other expenses respectively. In 2002 depreciation, depletion and
amortization of $2,131,160 and $185,761 were recorded in operating loss for oil
and gas, exploration and production and corporate and other expenses
respectively.
Interest expense of $35,387, interest income of $32,413 and interest income
$642,216 was recorded on corporate and other expenses in 2003, 2002 and 2001.
Identifiable assets by business segment and geographical area were as follows at
December 31:
2003 2002
------------ ------------
Corporate
Eastern Europe $ 5,185,020 $ 107,226
Western Europe (principally cash) 463,312 2,274,847
------------ ------------
Total Corporate 5,648,332 2,382,073
------------ ------------
Oil and Gas Exploration,
Development and Production
Eastern Europe 57,945,304 54,642,008
Assets Held for Sale
Eastern Europe 9,758,156 12,693,259
Western Europe 587,921 559,270
------------ ------------
Total Assets Held for Sale 10,346,077 13,252,529
------------ ------------
Other Energy Projects
Eastern Europe 75,000 459,308
------------ ------------
Total Identifiable Assets $ 74,014,713 $ 70,735,918
============ ============
F-31
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 19 - SUPPLEMENTAL CASH FLOW INFORMATION AND NONMONETARY TRANSACTIONS
Supplemental cash flow information consists of the following for the years ended
December 31:
2003 2002 2001
---------- ---------- ----------
Supplemental schedule of
non-cash activities:
Issuance of common stock in
connection with acquisition of
minority interest shareholders
interest in subsidiary $1,140,000 $ - $ -
Issuance of common stock in
connection with acquisition of
farm-in interest in project 660,000 - -
Corporate and Other Expenses - 29,000 -
---------- ---------- ----------
Total $1,800,000 $ 29,000 $ -
========== ========== ==========
The cash paid for interest expense for the years ended December 31, 2003, 2002
and 2001 was $35,387, $734 and $35,353, respectively. There was no cash paid for
income taxes for the years ended December 31, 2003, 2002 and 2001.
NOTE 20 - STOCK-BASED COMPENSATION PLANS
Pursuant to the 1995 Long-Term Incentive Plan (the "1995 Plan") adopted by
CanArgo in February 1996, 7,500,000 shares of the CanArgo's common stock have
been authorized for possible issuance under the 1995 Plan. Stock options granted
under the 1995 Plan may be either incentive stock options or non-qualified stock
options. Options expire on such date as is determined by the committee
administering the 1995 Plan, except that incentive stock options may expire no
later than 10 years from the date of grant. Pursuant to the 1995 Plan, a
specified number of stock options exercisable at the then market price are
granted annually to non-employee directors of CanArgo, which become 100% vested
six months from the date of grant. Stock appreciation rights entitle the holder
to receive payment in cash or common stock equal in value to the excess of the
fair market value of a specified number of shares of common stock on the date of
exercise over the exercise price of the stock appreciation right. No stock
appreciation rights have been granted through December 31, 2003. The exercise
price and vesting schedule of stock appreciation rights are determined at the
date of grant. Under the 1995 Plan, 5,047,167 options were outstanding at
December 31, 2003.
Pursuant to the terms of the Combination Agreement, on July 15, 1998 each stock
option granted under CAOG's existing Stock Option Plan (the "CAOG Plan") to
purchase a CAOG common share was converted into an option to purchase 0.8 shares
of the CanArgo's Common Stock. Pursuant to the CAOG Plan, which has been adopted
by CanArgo, a total of 988,000 shares of CanArgo's Common Stock have been
authorized for issuance. Stock options granted under the CAOG Plan expire on
such date as is determined by the committee administering the CAOG Plan, except
that the term of stock options may not exceed 10 years from the date of grant.
Under the CAOG Plan, 719,000 options were outstanding at December 31, 2003.
In 2000, special stock options and warrants to purchase 2,220,000 shares of
CanArgo's common stock were issued to various individuals who were serving or
were expected in the future to serve CanArgo as officers, directors and
employees. At December 31, 2003, all 2,220,000 special stock options and
warrants remained outstanding.
F-32
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 20 - STOCK-BASED COMPENSATION PLANS (Continued)
In March 2003, CanArgo Energy Corporation resolved to issue 1,589,166 new
options and amend the terms and conditions attaching to 5,117,501 of existing
options. The exercise price for the newly issued options is US $0.10
(approximately NOK 0.71) approximately 2.5 times the trading share price on the
date of grant. All these options vested immediately and expire on March 4, 2008.
With regards to individual officers and directors, details of existing and new
options are as follows:
Amended New
Terms Options Total
---------- ------- ---------
David Robson 2,666,667 333,333 3,000,000
Vincent McDonnell 300,000 300,000 600,000
Russ Hammond 346,250 153,750 500,000
Nils Trulsvik 346,250 153,750 500,000
Liz Landles 172,000 28,000 200,000
The purpose of the Company's stock option plans is to further the interest of
the Company by enabling officers, directors, employees, consultants and advisors
of the Company to acquire an interest in the Company by ownership of its stock
through the exercise of stock options and stock appreciation rights granted
under its various stock option plans.
F-33
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 20 - STOCK-BASED COMPENSATION PLANS (Continued)
A summary of the status of stock options granted under the 1995 Plan, CAOG Plan
and special stock options and warrants is as follows:
Shares Issuable Weighted
Shares Under Average
Available for Outstanding Exercise
Issue Options Price
------------- --------------- ----------
BALANCE, DECEMBER 31, 2000 468,000 5,235,336 $ 1.02
Options (1995 Plan):
Increase in shares available for issue 3,500,000 -
Granted at market (1,795,000) 1,795,000 0.68
Exercised - -
Expired 123,335 (123,335) 1.44
CAOG Plan Authorization:
Granted at market (185,000) 185,000 1.02
Exercised - -
Expired - -
---------- ---------- ----------
BALANCE, DECEMBER 31, 2001 2,111,335 7,092,001 0.92
Options (1995 Plan):
Increase in shares available for issue
Granted at market (130,000) 130,000 0.14
Exercised - -
Expired 307,500 (307,500) 0.25
CAOG Plan Authorization:
Granted at market - -
Exercised - -
Expired 180,000 (180,000) 1.11
---------- ---------- ----------
BALANCE, DECEMBER 31, 2002 2,468,835 6,734,501 0.93
Options (1995 Plan):
Increase in shares available for issue
Granted at market (1,291,833) 1,291,833 0.10
Exercised - -
Expired 132,500 (132,500) 1.35
CAOG Plan Authorization:
Granted at market (297,333) 297,333 0.10
Exercised - -
Expired 205,000 (205,000) 1.19
---------- ---------- ----------
BALANCE, DECEMBER 31, 2003 1,217,169 7,986,167 $ 0.26
========== ========== ==========
F-34
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 20 - STOCK-BASED COMPENSATION PLANS (Continued)
Shares issuable upon exercise of vested options and the corresponding weighted
average exercise price are as follows:
Shares Issuable Weighted
Under Exercisable Average
Options Exercise Price
----------------- --------------
December 31, 2001 3,452,831 $ 0.91
December 31, 2002 5,114,834 $ 0.93
December 31, 2003 7,337,167 $ 0.23
The weighted average fair value of options granted during the year was $0.10,
$0.14 and $0.71 for the years ended December 31, 2003, 2002 and 2001
respectively.
The following table summarizes information about stock options outstanding at
December 31, 2003:
Options Outstanding Options Exercisable
------------------------------------------------------------------------------------
Number Number
of Shares Weighted Weighted Of Shares Weighted
Outstanding at Average Average Exercisable at Average
Range of Exercise December 31, Remaining Exercise December 31, Exercise
Prices 2003 Term Price 2003 Price
----------------- -------------- --------- -------- -------------- --------
$0.10 to $0.14 6,736,667 4.23 0.10 6,411,667 0.10
$0.15 to $0.69 364,500 1.06 0.46 340,500 0.44
$0.70 to $1.44 885,000 1.69 1.44 625,000 1.44
--------- --------- -------- --------- --------
$0.10 to $1.44 7,986,167 3.78 0.26 7,377,167 0.23
========= ========= ======== ========= ========
As discussed in Note 1, Summary of Significant Accounting Policies, in August
2003, the Company adopted SFAS No. 123 Accounting For Stock-Based Compensation,
as amended by SFAS No. 148 Accounting for Stock-Based Compensation--Transition
and Disclosure--an amendment of FASB Statement No. 123, effective as of January
1, 2003. The Company has elected to utilize the "prospective" method of
transitioning from the intrinsic value to the fair value method of accounting
for stock-based compensation as allowed by SFAS No. 148. This change decreased
2003 net income by approximately $276,507. Stock based awards in existence prior
to 2003 will continue to be accounted for under APB Opinion No. 25, "Accounting
for Stock Issued to Employees," unless they are re-priced or modified.
Prior to 2003, the Company applied APB Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for stock-based
compensation. Under Opinion No. 25, stock-based employee compensation cost was
not recognized in net income when stock options granted had an exercise price
equal, or greater, to the market value of the underlying common stock on the
date of grant.
F-35
CANARGO ENERGY CORPORATION
Notes to Consolidated Financial Statements
NOTE 21 - RELATED PARTY TRANSACTIONS
Of the 50% of CanArgo Standard Oil Products not held by CanArgo, 41.65% is held
by Standard Oil Products, an unrelated third party entity, and 8.35% is held by
an individual, Mr Levan Pkhakadze, who is one of the founders of Standard Oil
Products and is an officer and director of CanArgo Standard Oil Products. The
majority of refined product purchased by CanArgo Standard Oil Products for
resale at its petrol stations is purchased from a company controlled by Standard
Oil Products who together with and an individual shareholder, own the 50%
interest in CanArgo Standard Oil Products not held by CanArgo. Total product
purchases from the related company in 2003 were $7,229,000 ($5,263,000 in 2002).
Certain equipment is provided to Georgian British Oil Company Ninotsminda by a
company owned by significant employees of Georgian British Oil Company
Ninotsminda. Total rental payments for this equipment in 2003 were $183,428 and
$125,729 in 2002. In 2003, the same company provided additional services to
Georgian British Oil Company Ninotsminda in accordance with the farm-in
agreement in respect of the Manavi well for the value of $450,000.
Vazon Energy is a company solely owned by Dr. Robson. A management services
agreement exists between CanArgo Energy Corporation and Vazon Energy whereby the
services of Dr. Robson, Mrs. Landles and Mr. Maroney are provided to CanArgo.
J.F. Russell Hammond, a non-executive director of CanArgo, is also an investment
advisor to Provincial Securities who became a minority shareholder in the Norio
PSA through a farm-in agreement to the Norio MK72 well. On September 4, 2003,
co-incident with the Georgian Oil farm-in to the Norio PSA, Provincial
Securities was given 2,273,523 shares of CanArgo common stock in exchange for
his interest in the Norio PSA (see Note 11).
Transactions with affiliates are reviewed and voted on solely by non-interested
directors.
F-36
CANARGO ENERGY CORPORATION
Supplemental Financial Information
Quarterly Results of Operations - Unaudited
2003
----------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER YEAR
----------- ----------- ----------- ----------- -----------
Operating revenue from
continuing operations $ 1,141,458 $ 1,859,995 $ 2,494,029 $ 2,609,298 $ 8,104,780
Operating income (Loss) from
continuing operations (965,818) (165,838) 273,044 699,971 (158,641)
Net income (loss) from
continuing operations (939,218) (155,942) 281,551 57,621 (755,988)
Net income (loss) from
discontinued operations,
net of taxes and minority
interest (9,142) 52,214 32,167 (6,682,756) 6,607,517
Cumulative effect of change in
accounting policy 41,290 - - - 41,290
Net income (loss) (907,070) (103,728) 313,718 (6,625,135) (7,322,215)
Comprehensive income (loss) (876,905) (157,974) 325,529 (6,763,996) (7,473,346)
Net loss per common share -
basic and diluted from
continuing operations (0.01) - - - (0.01)
Net loss per common share -
basic and diluted from
discontinued operations - - - (0.07) (0.07)
Net loss per common share -
basic and diluted (0.01) - - (0.07) (0.08)
2002
----------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER YEAR
----------- ----------- ----------- ----------- -----------
Operating revenue from
continuing operations $ 2,881,434 $ 980,163 $ 696,406 $ 927,752 $ 5,485,755
Operating income (loss) from
continuing operations 135,062 (1,719,662) (462,237) (2,855,290) (4,902,127)
Net income (loss) from
continuing operations (18,976) (1,321,902) (1,264,453) (2,872,595) (5,477,926)
Net income (loss) from
discontinued operations,
net of taxes and minority
interest 106,019 30,763 36,608 (23,165) 150,225
Cumulative effect of change in
accounting policy - - - -
Net income (loss) 87,043 (1,291,139) (1,227,845) (2,895,760) (5,327,701)
Comprehensive income (loss) 87,043 (1,342,396) (1,078,650) (2,989,030) (5,323,033)
Net loss per common share -
basic and diluted from
continuing operations (0.01) (0.01) (0.03) (0.06)
Net loss per common share -
basic and diluted from
discontinued operations - - - -
Net loss per common share -
basic and diluted (0.01) (0.01) (0.03) (0.06)
F-37
CANARGO ENERGY CORPORATION
Supplemental Financial Information
Supplemental Oil and Gas Disclosure - Unaudited
ESTIMATED NET QUANTITIES OF OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs with existing
equipment under existing economic and operating conditions.
Proved developed reserves are proved reserves that can be expected to be
recovered through existing wells with existing equipment and under existing
economic and operating conditions.
No major discovery or other favorable or adverse event subsequent to December
31, 2003 is believed to have caused a material change in the estimates of proved
or proved developed reserves as of that date.
The following tables sets forth the Company's net proved oil and gas reserves,
including the changes therein, and net proved developed reserves at December 31,
2003, as estimated by the independent petroleum engineering firm, Oilfield
Production Consultants Limited:
Net Proved Developed and Undeveloped Reserves - Oil (In Thousands of Barrels) -
Republic of Georgia
2003 2002 2001
------ ------ ------
January 1 2,901 3,729 9,665
Purchase of properties - - -
Revisions of previous estimates 1,951 (630) (5,689)
Extension, discoveries, other additions - - -
Production (457) (198) (247)
Disposition of properties - - -
------ ------ ------
December 31 4,395 2,901 3,729
====== ====== ======
Net Proved Developed Oil Reserves -
December 31, 2003 2,336
======
F-38
CANARGO ENERGY CORPORATION
Supplemental Financial Information
Supplemental Oil and Gas Disclosure - Unaudited
Net Proved Developed and Undeveloped Reserves - Gas (In Million Cubic Feet) -
Republic of Georgia
2003 2002 2001
-------- -------- --------
January 1 2,414 5,025 13,500
Purchase of properties - - -
Revisions of previous estimates (197) (2,265) (7,365)
Extension, discoveries, other additions - - -
Production (276) (346) (1,110)
Disposition of properties - - -
-------- -------- --------
December 31 1,941 2,414 5,025
======== ======== ========
Net Proved Developed Oil Reserves -
December 31, 2003 1,133
========
Net proved oil reserves in the Republic of Georgia consisted of the following at
December 31:
2003 2002
----------------------------- ---------------------------
PSC PSC
Oil Reserves Entitlement Oil Reserves Entitlement
Gross Volumes Gross Volumes
(MSTB) (MSTB) (1) (MSTB) (MSTB) (1)
------------- ------------ ------------ -----------
Proved Developed Producing 3,593 2,336 4,016 2,811
Proved Undeveloped 3,169 2,059 134 90
------------- ------------ ------------ -----------
Total Proven 6,762 4,395 4,150 2,901
============= ============ ============ ===========
Net proved gas reserves in the Republic of Georgia consisted of the following at
December 31:
2003 2002
----------------------------- ----------------------------
PSC PSC
Gas Reserves Entitlement Gas Reserves Entitlement
Gross Volumes Gross Volumes
(MMCF) (MMCF) (1) (MMCF) (MMCF) (1)
------------- ------------ ------------ -----------
Proved Developed Producing 1,742 1,133 7,952 2,385
Proved Undeveloped 1,243 808 96 29
------------- ------------ ------------ -----------
Total Proven 2,985 1,941 8,048 2,414
============= ============ ============ ===========
(1) PSC Entitlement Volumes attributed to CanArgo are calculated using the
"economic interest method" applied to the terms of the production
sharing contract. PSC Entitlement Volumes are those produced volumes
which, through the production sharing contract, accrue to the benefit
of Ninotsminda Oil Company after deduction of Georgian Oil's share
which includes all Georgian taxes, levies and duties. As a result of
CanArgo's interest in Ninotsminda Oil Company, these volumes accrue to
the benefit of CanArgo for the recovery of capital, repayment of
operating costs and share of profit.
F-39
CANARGO ENERGY CORPORATION
Supplemental Financial Information
Supplemental Oil and Gas Disclosure - Unaudited
Results of operations for oil and gas producing activities for 2003, 2002 and
2001 are as follows:
Republic of
Year Ended December 31, 2003 Georgia
------------
Revenues $ 7,882,870
Operating expenses 1,051,905
Depreciation, depletion and amortization 2,634,459
------------
Operating Income (Loss) 4,196,506
Income tax provision -
------------
Results of Operations for Oil and Gas Producing Activities $ 4,196,506
============
Republic of
Year Ended December 31, 2002 Georgia
------------
Revenues $ 4,179,208
Operating expenses 1,537,917
Depreciation, depletion and amortization 3,353,266
------------
Operating Income (Loss) (711,975)
Income tax provision -
------------
Results of Operations for Oil and Gas Producing Activities $ (711,975)
============
Republic of
Year Ended December 31, 2001 Georgia
------------
Revenues $ 4,873,623
Operating expenses 1,568,011
Depreciation, depletion and amortization 10,167,368
------------
Operating Income (Loss) (6,861,756)
Income tax provision -
------------
Results of Operations for Oil and Gas Producing Activities $ (6,861,756)
============
Costs incurred for oil and gas property acquisition, exploration and development
activities for 2003, 2002 and 2001 are as follows:
Year Ended December 31, 2003 Eastern Europe
--------------
Property Acquisition
Unproved * $ -
Proved -
Exploration 324,467
Development 5,200,614
------------
Total costs incurred $ 5,525,081
============
F-40
CANARGO ENERGY CORPORATION
Supplemental Financial Information
Supplemental Oil and Gas Disclosure - Unaudited
Year Ended December 31, 2002 Eastern Europe
--------------
Property Acquisition
Unproved * $ -
Proved -
Exploration 12,167,238
Development 543,280
------------
Total costs incurred $ 12,710,518
============
Year Ended December 31, 2001 Eastern Europe
--------------
Property Acquisition
Unproved * $ 5,186,002
Proved -
Exploration 5,851,306
Development 2,054,989
------------
Total costs incurred $ 13,092,297
============
* These amounts represent costs incurred by CanArgo and excluded from the
amortization base until proved reserves are established or impairment is
determined.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following information has been developed utilizing procedures prescribed by
SFAS No. 69 Disclosure about Oil and Gas Producing Activities ("SFAS 69") and
based on crude oil reserve and production volumes estimated by the Company's
engineering staff. It may be useful for certain comparative purposes, but should
not be solely relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as
representative of realistic assessments of future cash flows, nor should the
Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the Company.
CanArgo believes that the following factors should be taken into account in
reviewing the following information: (1) future costs and selling prices will
probably differ from those required to be used in these calculations; (2) actual
rates of production achieved in future years may vary significantly from the
rate of production assumed in the calculations; (3) selection of a 10% discount
rate is arbitrary and may not be reasonable as a measure of the relative risk
inherent in realizing future net oil and gas revenues; and (4) future net
revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying
period-end oil prices adjusted for fixed and determinable escalations to the
estimated future production of period-end proven reserves. Future cash inflows
were reduced by estimated future development, abandonment and production costs
based on period-end costs in order to arrive at net cash flow before tax. Future
income tax expenses has been computed by applying period-end statutory tax rates
to aggregate future pre-tax net cash flows, reduced by the tax basis of the
properties involved and tax carryforwards. Use of a 10% discount rate is
required by SFAS No. 69.
F-41
CANARGO ENERGY CORPORATION
Supplemental Financial Information
Supplemental Oil and Gas Disclosure - Unaudited
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proven reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved
oil and gas reserves is as follows:
Republic of
DECEMBER 31, 2003 (IN THOUSANDS) Georgia
-----------
Future cash inflows $ 90,674
Less related future:
Production cots 24,621
Development and abandonment costs 6,407
--------
Future net cash flows before income taxes 59,646
Future income taxes (1) (1,596)
--------
Future net cash flows 58,050
10% annual discount for estimating timing of cash flows 20,520
--------
Standardized measure of discounted future net cash flows $ 37,530
========
Republic of
DECEMBER 31, 2002 (IN THOUSANDS) Georgia
-----------
Future cash inflows $ 54,761
Less related future:
Production cots 17,959
Development and abandonment costs 7,500
--------
Future net cash flows before income taxes 29,302
Future income taxes (1) (600)
--------
Future net cash flows 28,702
10% annual discount for estimating timing of cash flows 14,595
--------
Standardized measure of discounted future net cash flows $ 14,107
========
(1) Future cash flows are based on PSC Entitlement Volumes attributed to CanArgo
using the "economic interest method" applied to the terms of the production
sharing contract. PSC Entitlement Volumes are those produced volumes which,
through the production sharing contract, accrue to the benefit of
Ninotsminda Oil Company after deduction of Georgian Oil's share which
includes all Georgian taxes, levies and duties. As a result of CanArgo's
interest in Ninotsminda Oil Company, these volumes accrue to the benefit of
CanArgo for the recovery of capital, repayment of operating costs and share
of profit.
F-42
CANARGO ENERGY CORPORATION
Supplemental Financial Information
Supplemental Oil and Gas Disclosure - Unaudited
A summary of the changes in the standardized measure of discounted future net
cash flows applicable to proved oil and gas reserves is as follows:
December 31, 2003
--------------------------------
In Thousands 2003 2002 2001
-------- -------- --------
Beginning of year $ 14,107 $ 16,695 $ 62,966
Purchase (sale) of reserves in place - - -
Revisions of previous estimates 24,576 (6,978) (36,196)
Development costs incurred during the period 324 543 2,055
Additions to proved reserves resulting from
extensions, discoveries and improved
recovery - - -
Accretion of discount - - -
Sales of oil and gas, net of production costs (6,829) (2,625) (2,327)
Net change in sales prices, net of
production costs 8,317 4,990 (12,865)
Changes in production rates (timing) and other (2,965) 1,482 3,062
-------- -------- --------
Net increase (decrease) 23,423 (2,588) (46,271)
-------- -------- --------
End of year $ 37,530 $ 14,107 $ 16,695
======== ======== ========
F-43