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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| þ | ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005
OR
| o | TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission
File Number 001-32145
CANARGO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 91-0881481 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
P.O. Box 291, St Peter Port, Guernsey, British Isles GY1 3RR
(Address of principal executive offices)
(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:
Title of each class |
||
Common Stock, par value $0.10 per share
|
Name of each exchange on which registered | |
American Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act:
None
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
YES o NO þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act
YES
o NO þ
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 þ NO o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large
accelerated filer” in Rule 12b-2 of the Exchange Act (check one)
| Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES o NO þ
The aggregate market value of the voting and non voting common equity held by-non-affiliates was approximately $248 million as of 10 March 2006, based upon the last reported sales
price of such stock on The American Stock Exchange on that date. For this purpose, the Registrant considers Dr. David Robson, Vincent McDonnell, Michael Ayre, Russ Hammond and
Nils Trulsvik to be its only affiliates.
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, 224,108,606
shares outstanding as of 10 March, 2006.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive Proxy Statement issued in connection with its 2006 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.
CANARGO ENERGY CORPORATION
FORM 10-K
TABLE OF CONTENTS
FORM 10-K
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PART I
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K, contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 as amended (“Securities Act”) and Section 21E of the
Securities Exchange Act of 1934 as amended (“Exchange Act”). When used in this Report, 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. The forward-looking statements are based on our current
expectations and speak only as of the date made. These forward-looking statements involve risks,
uncertainties and other factors that in some cases have affected our historical results and could
cause actual results in the future to differ significantly from the results anticipated in
forward-looking statements made in this Report. Important factors that could cause such a
difference are discussed in this prospectus, particularly in the sections entitled “Risk Factors”
and “Management’s Discussion and analysis of Financial condition and Results of Operations”. You
are cautioned not to place undue reliance on the forward-looking statements.
Few of the forward-looking statements in this Report, including the documents that are
incorporated by reference, 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 interests that do not
coincide with ours and may conflict with our interests. Unless the third parties and we are able to
compromise their various objectives in a mutually acceptable manner, agreements and arrangements
will not be consummated.
Although we believe our expectations reflected in forward-looking statements are based on
reasonable assumptions, no assurance can be given that these expectations will prove to have been
correct. Important factors that could cause actual results to differ materially from the
expectations reflected in the forward-looking statements include, among others:
| - | the market prices of oil and gas; | ||
| - | uncertainty of drilling results, reserve estimates and reserve replacement; | ||
| - | operating uncertainties and hazards; | ||
| - | economic and competitive conditions; | ||
| - | natural disasters and other changes in business conditions; | ||
| - | inflation rates; | ||
| - | legislative and regulatory changes; | ||
| - | financial market conditions; | ||
| - | accuracy, completeness and veracity of information received from third parties; | ||
| - | wars and acts of terrorism or sabotage; | ||
| - | political and economic uncertainties of foreign governments; and |
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| - | future business decisions. |
In light of these risks, uncertainties and assumptions, the events anticipated by our
forward-looking statements might not occur. We undertake no obligation to update or revise our
forward-looking statements, whether as a result of new information, future events or otherwise.
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.
GLOSSARY OF CERTAIN 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.
“AMEX” The American Stock Exchange, Inc.
“bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to
crude oil or other liquid hydrocarbons.
“boe” Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or natural
gas liquids to six Mcf of gas.
“bopd” Barrels of oil produced per day.
“Brent” means pricing point for selling North Sea crude oil.
“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.
“Km” means kilometer.
“Mcf” One thousand cubic feet of natural gas.
“MCM” One thousand cubic meters of natural gas.
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“mD” Millidarcies.
“MMbbl” One million barrels.
“MMboe” Million barrels of oil equivalent.
“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.
“PSC” or “PSA” means a Production Sharing Contract or Production Sharing Agreement.
“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.
“SEC” means United States Securities and Exchange Commission.
“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.
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ITEM 1. BUSINESS.
General Development of Business
We operate as an oil and gas exploration and production company and as a holding company carry
out our activities through a number of operating subsidiaries and associated or affiliated
companies. These operating companies are generally focused on one of our projects, and this
structure assists in maintaining separate cost centers for these different projects.
The address of the principal and administrative offices of CanArgo is P.O. Box 291, St Peter
Port, Guernsey, British Isles GY1 3RR (Tel. No. (44) 1481 729 980).
We file reports with the Securities and Exchange Commission (the “Commission”). The public may
read and copy any materials that we file with the Commission at the Commission’s Public Reference
Room at 450 Fifth Street, NW, Washington, DC 20549. The public may
obtain information on the operation of the Public Reference Room by
calling the SEC at 1-800-SEC-0303. The SEC maintains an internet site
at www.sec.gov that contains reports, proxy and information
statements and other information regarding issuers that file
electronically with the SEC. We make available free of charge our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports Form 8-K, and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act on our
internet website at www.canargo.com as soon as reasonably practicable after we electronically file
or furnish such material with or to the Commission.
Our principal activities are oil and gas exploration, development and production, principally
in Georgia and the Republic of Kazakhstan. We direct most of our efforts and resources to our
exploration and appraisal program in Georgia, the development of the Ninotsminda Field in Georgia
and to a lesser extent the appraisal and development of our Kyzyloi Field and the exploration of
the Akkulka block in Kazakhstan. Our management and technical staff have substantial experience in
our areas of operation. Currently our principal product is crude oil, and the sale of crude oil is
our principal source of revenue.
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 27,923 acres (113 Km 2 ), this area, excluding any development area, is subject to a voluntary 25% relinquishment in December 2006; | ||
| 2. | The Nazvrevi and Block XIII Production Sharing Contract (“Nazvrevi PSC”), covering Blocks XID and XIII, 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 388,447 acres (1,572 Km2); | ||
| 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 may be reduced to 85% should the state oil company, Georgian Oil, exercise an option available to it under the PSA for a limited period following the submission of a field development plan. As a contractor party, Georgian Oil would be liable for all costs and expenses in relation to any interest it may acquire in the PSA. This PSA covers an area of approximately 381,034 acres (1,542 Km 2 ), however, it is subject to a 25% relinquishment in March 2006; | ||
| 4. | The Block XI G and XI H Production Sharing Contract (“Tbilisi PSC”), in which CanArgo Norio Limited owns a 100% interest. This PSC covers an area of approximately 119,845 acres (485 Km 2 ). |
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| Until February 16, 2006, we held an interest in the Samgori, Block XI B Production Sharing Contract (“Samgori PSC”), in which CanArgo Samgori Limited acquired a 50% interest in 2004 subject to completion of an agreed work program to be completed in part by September 16, 2006 and in full by June 2008. CanArgo Samgori Limited is a wholly owned subsidiary of CanArgo. This PSC covers an area of approximately 156,664 acres (634 Km 2) of which 50%, excluding any development area, was subject to relinquishment by September 2006. |
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 State taxes, levies and duties. PSCs are a common
form of oil and gas exploration and production contract in many parts of the world.
In Kazakhstan our exploration and development activities centre on the Kyzyloi Production
Contract and the Akkulka Exploration Contract. Through our acquisition of 100% of Tethys Petroleum
Investments Limited on June 9, 2005 we increased to 70% our ownership interest in the Kazakhstan
based limited liability partnership, BN Munai LLP which owns 100% of the Kyzyloi and Akkulka and
Greater Akkulka Contracts. The Kyzyloi Gas Field Production Contract covers an area of 70,919
acres (287 Km2) and is surrounded by the 411,922 acres (1,667 Km2) Akkulka
Exploration Contract area. In November 2005, BNM acquired a 100% interest in the Greater Akkulka
Exploration Contract. This contact, which is for a period of 25 years, with an initial six year
exploration period covers an area of approximately 2.75 million acres (11,133Km2)
surrounding the Akkulka area. On the Greater Akkulka Exploration Contract, 20% of the area is to be
relinquished at the end of the second year (November 23, 2007) with 20% annually thereafter up to
the end of the original six year contract.
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Oil and Gas Fields
Since 1997, our resources have, through our wholly owned subsidiary Ninotsminda Oil Company
Limited, been mainly focused on the development of the Ninotsminda Field and related exploration
activities in Georgia, including the Manavi prospect. 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 and in which we acquired an interest in early 2004 (we withdrew
from this interest in February 2006). The Ninotsminda Field was discovered later than the Samgori
Field and has experienced substantially less development activity. The Georgian State oil company,
Georgian Oil and others, including Ninotsminda Oil Company Limited, have drilled 36 wells in the
Ninotsminda Field, of which nine are currently producing. A total of 144 wells have been drilled in
the Samgori Field area which includes a complex of three separate oil accumulations namely Samgori,
South Dome and Patardzeuli.
We believe the Ninotsminda PSC area both outside of and beneath the currently producing
reservoirs of the Field have significant additional exploration potential. To date, we have
invested and continue to invest substantial funds in exploring the Ninotsminda PSC area including
the Manavi prospect.
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In 2003, we acquired interests in certain oil and gas properties in Kazakhstan which included
the Kyzyloi Gas Field. A development program is underway on the Kyzyloi Field with the intention
of developing a shallow (up to 2,000 feet (600 meters)) gas bearing sandstone reservoir which was
discovered, but not developed, during the 1960’s. This Field is located close to the Bukhara-Urals
gas trunkline, and to the south of the Bozoi gas storage facility just to the west of the Aral Sea.
The Kyzyloi Field covers an area of approximately 70,919 gross acres (287 gross Km 2).
Other Projects
We have additional exploratory and developmental oil and gas properties and prospects in
Georgia and Kazakhstan. During 2004, we disposed of our single remaining Ukrainian asset, the
Bugruvativske Field.
Business Structure
CanArgo is a holding company organized under the laws of the State of Delaware. Our principal
product is crude oil, and the sale of crude oil is our principal source of revenue. CanArgo’s
principal active subsidiaries are as follows:
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Background
Ninotsminda PSC
Our activities at the Ninotsminda Field and on the Manavi prospect are conducted through
Ninotsminda Oil Company Limited, a Cypriot corporation (“NOC”) which became a wholly owned
subsidiary of CanArgo in July 2000.
NOC (then named JKX Ninotsminda Limited) obtained its rights to the Ninotsminda Field,
including all existing wells, one other field (West Rustavi) and exploration acreage in Block XI
E under a 1996 production sharing contract with Georgian Oil and the State of Georgia
(“Ninotsminda PSC”) which came into effect in February 1996. NOC’s rights under the contract expire
in December 2019, subject to the possible loss of undeveloped areas prior to that date and a
possible extension with regard to developed areas. As such the initial term of the Ninotsminda PSC
is until 2019, however, in respect of any development area, if commercial production remains
possible beyond 2019 upon giving notice to the State we have an automatic right to extend the
contract in respect of such development area for an additional term of 5 years (until 2024) or, if
earlier, for the producing life of the development area. Under the Ninotsminda PSC, NOC is required
to relinquish at least half of the area then covered by the production sharing contract, but not in
portions being actively developed, at five year intervals commencing December 1999. In 1998,
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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 (cost
recovery petroleum). NOC pays 100% of the costs incurred in the project as the sole contractor
party under the Ninotsminda PSC. The balance of Production (profit petroleum) 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 (cost recovery plus 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 State 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 the intention is to market gas jointly.
Samgori PSC
In April 2004, we acquired a 50% interest in the Samgori PSC in Georgia. This interest was
acquired from Georgian Oil Samgori Limited (“GOSL”), a company wholly owned by Georgian Oil, by one
of our subsidiaries, CanArgo Samgori Limited (“CSL”). Under the terms of the agreement dated
January 8, 2004, up to 10 horizontal wells were to be drilled on the Samgori Field as a result of
GOSL’s earlier acquisition of the contractor’s interest in the PSC. Completion of well S302 in the
autumn of 2004, which was funded 100% by us, satisfied our
commitment to GOSL under the acquisition agreement. The intention was that the remainder of the
drilling program would be funded jointly by CSL and GOSL, the Contractor parties, pro rata their
interest in the Samgori PSC. The total cost to us of participating in the whole program, which was
due to be completed within 36 months of the commencement of the joint work program, was anticipated
to be up to $13,500,000.
The Samgori PSC came into effect on September 1, 2001 and extends for an initial period of
twenty years with the final year of the contract being September 1, 2021 this period may be
extended subject to commercial production being available for up to a further fifteen years until
2036.
The original Contractor party to the Samgori PSC, National Petroleum Limited (“NPL”), had an
option to reacquire its Contractor’s interest in the Samgori PSC and its 50% interest in the
operating company in the event that the agreed work program was not completed in part (which
involves the drilling of two horizontal well sections) by September 16, 2006 and completed in full
by June 2008. NPL has outstanding costs and expenses of $37,528,964 in relation to the Samgori PSC
which are recoverable by NPL receiving 30% of annual net profit from the Field until such costs
have been fully repaid. Under the Samgori PSC, up to 50% of petroleum produced under the contract
is allocated to the Contractor parties for the recovery of the cumulative allowable capital,
operating and other project costs associated with the Samgori Field and exploration in Block XI
B (“Cost Recovery Oil”). The cost recovery pool includes the $37,528,964 costs
previously incurred by NPL. The balance of production (“Profit Oil”) is allocated on a 50/50 basis
between the State and the Contractor parties respectively. While GOSL and CSL continued to have
unrecovered costs, they would have received 75% of total production (net 37.5% to us). After
recovery of their cumulative capital, operating and other allowable project costs including the NPL
costs, the Contractor parties receive 30% of Profit Oil (net 15% to us). The allocation of a share
of production to the State relieves the Contractor parties of all obligations they would otherwise
have to pay the State of Georgia for taxes, duties and levies related to activities covered by the
Samgori PSC. After NPL’s costs were repaid from either Field production or other production in the
PSC (in the event that new fields are developed in areas identified using seismic surveys
originally performed by NPL), NPL were to continue to receive 5% of annual net profit.
Under the Samgori PSC, Georgian Oil as the State representative in the contract is entitled to
receive up to 250,000 tons (approximately 1.6 million barrels) of oil (“Base Level Oil”) from a
maximum of 50% per calendar quarter of production when the value of the cumulative Cost Recovery
Petroleum, cumulative Profit Oil and cumulative Profit Natural Gas delivered to the Contractor
parties exceeds the cumulative allowable capital, operating
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and other project costs including
finance costs associated with the Samgori Field and exploration in Block XI B and the
NPL costs. While Base Level Oil is being delivered to Georgian Oil, the Contractor parties will
continue to be entitled to a maximum of 50% of the remaining Profit Oil. The Base Level Oil is an
estimate of the amount of oil that Georgian Oil would have expected to produce from the contract
area had the State not come to a contractual arrangement with the previous Contractor party in
1996.
On February 17, 2006 we issued a press release announcing that our subsidiary, CSL, was not
proceeding with further investment in the Samgori PSC and associated farm-in, and accordingly we
terminated our interest in the Samgori PSC with effect from February 16, 2006. The decision by CSL
not to proceed with further investment under the current farm-in arrangements was due to the
inability of CSL’s partner in the project, GOSL, to provide its share of funding to further the
development of the Field. We consider that there would have been insufficient time to meet the
commitments under the Agreement with NPL and we were not prepared to fund the project, which is not
without risk, on a 100% basis without different commercial terms and an extension to the commitment
period. It was not possible to negotiate a satisfactory position on
either matter. CSL has now been
informed that, NPL have exercised their right to take
back 100% of the Contractor Share in the Samgori PSC from GOSL and, accordingly, effective February
16, 2006 we have withdrawn from the Samgori PSC.
CanArgo Georgia Limited
Pursuant to the terms of CanArgo’s PSCs in Georgia, a Georgian not-for-profit company must be
appointed as field operator. Until February 2005, there were three such field operating
companies, relating to CanArgo’s PSCs: 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. However, on February 1, 2005 Georgian Oil, the State Agency for Regulation of Oil and Gas
Resources in Georgia and CanArgo reached agreement on restructuring the field operator companies in
our PSCs. A single operator company, CanArgo Georgia Limited, a wholly owned subsidiary company of
CanArgo, was appointed the field operator for the Ninotsminda, Nazvrevi, Norio and Tbilisi PSCs.
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.
Operations under each of the PSCs are determined by a co-ordinating body (“Co-ordinating
Committee”) composed of members designated by the respective CanArgo company and Georgian Oil,
representing the State, with the deciding vote allocated to us. If the State believes that any
action proposed by us with which the State 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
Ninotsminda
The Ninotsminda Field was discovered in 1979, with commercial production from the Middle
Eocene reservoir established in the same year. When NOC assumed developmental responsibility for
the Field in 1996, production was minimal hampered by, we believe, among other factors, a lack of
funding, civil strife and utilization of old technology and methods.
The Ninotsminda Field is the easternmost element of an elongate anticline which includes the
Samgori and Patardzeuli Fields. The Ninotsminda Field is separated from the Patardzeuli Field. The
Ninotsminda Field is separated from Patardzeuli by a saddle and a NW-SE trending cross fault. The
field structure comprises an elongate
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anticline which measures 10 Km (E-W) by 3 Km and has a
maximum structural relief of around 2,493 feet (760 meters). The main reservoir horizon is the
Middle Eocene which consists of well-bedded deep marine sedimentary rocks eroded from volcanoes.
Such rocks typically have low matrix porosity with the gross field wide effective porosity of
around 0.1% and permeability in the range of 0.5-10 mD, however, in the Ninotsminda Field there are
well developed sub-vertical fractures which provide secondary porosity and permeability of up to
100-500mD. The reservoir which in the field area is up to 1,640 feet (500 meters) thick is at a
depth of 8,530 feet (2,600 meters) below surface to 9,843 feet (3,000 meters) below surface.
Production from the Field is facilitated by a strong water drive. The oil accumulation has a gas
cap which together form a maximum hydrocarbon column of 1,060 feet (323 meters) thickness, with the
gas-oil contact at 4,839 feet (1,475 meters) True Vertical Depth Sub Sea (“TVDSS”) and the
oil-water contact at 5,413 feet (1,650 meters) TVDSS. The oil itself is a high quality sweet crude:
41°API, with just 0.24% sulphur, 4.9% paraffin and 8.7% tar and asphaltene.
NOC began an immediate rehabilitation of the Ninotsminda Field in 1996 which 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 a second well (N98) was
completed in October 1998, and sidetracked as a horizontal producer in 2000. The N98H well had
produced approximately 413,000 barrels of oil to the end of January 2006.
As a result of this development work, subsequent drilling and the completion of a dynamic
reservoir model, it
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was suggested that a higher level of production could be achieved from the
Middle Eocene reservoir from
horizontal wells drilled in a preferred orientation so as to intersect the main fracture sets.
In January 2003, a new horizontal sidetrack well (N4H) was successfully completed and originally
put on production at over 1,000 barrels of oil per day (bopd). At the end of January 2006, this
well had produced approximately 403,000 barrels of oil. Two further horizontal sidetrack wells
(N100H and N96H) were successfully completed in September 2003 and in December 2003, respectively.
The N100H well tested at rates of over 2,000 bopd and N96H at rates in excess of 1,200 bopd.
Although all three wells were put on production at lower rates in accordance with the
recommendations of independent petroleum engineering specialists, it has not been possible to
maintain production at these levels due to water incursion resulting from, what we believe to be
coning of water up the fractures, caused to an extent by, reservoir damage caused by conventional
drilling techniques.
In June, 2004 we signed a contract with WEUS Holding Inc., a subsidiary of Weatherford
International Ltd (“Weatherford”), for the supply of Under Balanced Coiled Tubing Drilling
(“UBCTD”) services to our projects in Georgia. Under the terms of the contract, Weatherford were to
supply and operate a UBCTD unit to be used on a program of up to 14 horizontal wellbores on the
Ninotsminda and Samgori Fields. Elsewhere in the oil industry, the use of under balanced drilling
techniques has been shown to result in significantly less formation damage, resulting in higher
sustained production rates and ultimate recovery. At the same time, utilisation of coiled tubing
drilling gives greater flexibility in the drilling process and in the control of the horizontal
section. It was considered that these combined drilling technologies would provide the best way to
develop and produce both the Ninotsminda and Samgori Fields.
We planned to drill at least five under balanced horizontal sidetracks on the Ninotsminda
Field including: N22H: N30H: a second horizontal well, N100H2 – east horizontal, from the N100
well bore (which achieved good rates of production when drilled horizontally with conventional
techniques and which was later the subject of a blow out in September 2004); N49H: N97H, and a new
well (N99) designed so as to have more than one horizontal wells drilled from it. The N99 well was
planned for the eastern part of the Field, an area that is currently largely undeveloped.
UBCTD operations started on the first well in the program, the N22H well, in December 2004.
The well is located in the east part of the Ninotsminda Field where the reservoir is tighter but it
is believed to be relatively un-drained. We prepared the well with our own crew which involved
sidetracking from the existing well-bore at 8,661 feet (2,640 meters) down to 9,193 feet (2,802
meters) and setting a 41/2 inch liner. Weatherford commenced operations in December 2004, however
technical problems with the Weatherford equipment caused a number of delays which resulted in the
under balanced drilling not being completed until late February, 2005 with a much shorter than
planned section being drilled, and the well not achieving its objective, despite flowing gas at
reported high rates through the gas cap section.
Subsequent operations by Weatherford on both N100H2 and N49H wells also proved unsuccessful,
with Weatherford failing to drill any horizontal section in these wells. Progress was hampered by
multiple failures of the downhole motors, other equipment malfunctions and the loss of bottom hole
assemblies in the wells.
Following the failure of Weatherford to successfully complete any horizontal sidetrack
development wells on the Ninotsminda Field using UBCTD technology, Weatherford demobilized its
equipment and left Georgia in July 2005. Despite this lack of success, which we attribute mainly
to multiple equipment failures, we still believe that under-balanced technology is an appropriate
technology for the development of this type of reservoir. In this respect, we continue to
investigate the potential of bringing an alternative supplier of such equipment and services to
Georgia.
In the meantime, we have continued with our jointed pipe drilling operations using our own
rigs and equipment and the directional drilling services of Baker Hughes International to drill
horizontal sidetrack wells on the Ninotsminda Field. On October 27, 2005 we reached total depth
(“TD”) on the first sidetrack, the N100H2 well. The well was completed in the Middle Eocene
reservoir at approximately 8,659 feet (2,640 meters) TVD (True Vertical Depth) having drilled a
horizontal section of 1,667 feet (508 meters). A pre-perforated liner was run over a 1,421 foot
(433 meters) interval in the horizontal section and was tested at a rate of up to 13.07 million
cubic feet
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(370,000 cubic meters) of gas per day plus 301 barrels of condensate per day (a total of 2,480
barrels oil equivalent1) on a 63/64 inch (25 mm) choke with a flowing tubing head
pressure (FTHP) of 70 atmospheres (1,000 psig). The horizontal section is located in the uppermost
part of the oil zone, close to the gas-oil contact, and a permeable interval was encountered in the
build up section within the lower part of the gas cap. It is expected that the proportion of liquid
hydrocarbon production will rise over time. The well is currently choked back as we await
completion of repairs by the state oil company, Georgian Oil, to the 22.4 mile (36 Km) pipeline
which it is planned will deliver the gas from Ninotsminda to the local State-run thermal
electricity generating station at Gardabani. Terms have been agreed with the government for a gas
supply agreement from the Ninotsminda Field and it is expected that an agreement will be signed in
the near future.
In November 2005, we announced that operations had commenced on the next horizontal sidetrack
well on the Ninotsminda Field, N97H. This sidetrack is more complicated than the N100H2 well as it
is located on the northern flank of the field and it was necessary to first sidetrack the well from
a much shallower level towards the crest of the field before the horizontal section could be
drilled through the reservoir in a westerly direction along the crest of the structure. The well
was drilled by us using our own rig and equipment while utilising directional equipment and
services provided by Baker Hughes. The well has now been completed with a 1,725 foot (534 meters)
horizontal section having been drilled through the Middle Eocene reservoir where good mud losses
were observed, this indicating good permeability. A 1,490 foot (454 meters) slotted production
liner has been run in the horizontal section furthest from the original well bore and the well is
currently being tested. Depending on the test results, it is planned to put the well on production
immediately.
Apart from the Middle Eocene sequence on the Ninotsminda Field there are a number of other
reservoirs which contain oil. We have not yet fully evaluated the reserves and economics of
production from these zones which include shallower oil reservoirs, the gas cap on the Ninotsminda
Field itself or from the hydrocarbon bearing zones below the Middle Eocene. To fully evaluate
these zones, further seismic, technical interpretation and drilling will be required.
Manavi & Cretaceous Exploration
The first exploration well drilled on the Manavi structure, a large prospect at Cretaceous
level, within the Ninotsminda PSC area reached total depth in September 2003. This well was the
second well drilled under a Participation Agreement with AES Gardabani (a subsidiary of AES
Corporation who at that time owned part of the Gardabani thermal power plant) (“AES”) relating to
the exploration and potential future development of sub Middle Eocene gas prospects in parts of the
Ninotsminda PSC. 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 primarily for mechanical reasons, having penetrated a significant thickness
of oil bearing sandstones in the Lower Eocene and Palaeocene sequences. Three formation tests were
carried out on these sandstones which recovered 35 o 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 suffered substantial
formation damage due to the high mud weights used to drill the well, which was being drilled for a
potentially high pressure Cretaceous objective, or that it was of low permeability. Potential
still remains in this sequence but the N100 well was re-completed in 2003 as a Middle Eocene
horizontal oil producer on the Ninotsminda Field. Under the Participation Agreement, AES 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 the
completion of the program as defined in the Participation Agreement, AES withdrew from the
Participation Agreement in February 2002 in order to focus on its core business. The Participation
Agreement was terminated without AES earning any rights to any of the Ninotsminda / Manavi area
reservoirs. Under a separate Letter Agreement, if gas from the sub
Middle Eocene is discovered and produced from the Ninotsminda / Manavi area, AES will be entitled to recover at the rate of
15% of future gas sales from the sub Middle Eocene, net of
| 1 | using 6,000 cubic feet of gas = 1 barrel of oil/condensate |
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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). AES has since sold its interest
in the Gardabani power plant and other assets in Georgia.
The 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, following the withdrawal of AES from the Participation Agreement, at a
depth of 13,720 feet (4,182 meters), but re-started following a farm-in by a local oil service
company 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 34.4º API oil, and gas, flow stopped due to a mechanical collapse of the production
tubing. We believe that this is the first test 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 be over 1,000 feet (~300 meters)
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 in Soviet times, 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.
Attempts to recover the damaged tubing from the M11 well were unsuccessful. The well was
prepared subsequently for sidetracking and additional drilling equipment including more powerful
mud pumps and bicentrical drilling bits were added to our rig for this work. Operations recommenced
in December 2004 with CanArgo’s modified Russian UralMash 4E rig and despite our best efforts we
continued to encounter drilling problems due to the extremely over-pressured swelling clays above
the reservoir intervals. After extensive technical analysis and discussions with the international
drilling contractor Saipem S.p.A. (“Saipem”), and Baker-Hughes International (“Baker-Hughes”), a
major drilling mud company, it was decided that the optimum way to sidetrack this well to the top
of the reservoir as planned was to use an oil-based mud system (to control the swelling clays) on
the Sapiem Ideco E-2100Az drilling rig (which is equipped with a top-drive drilling system and can
use an oil-based mud system unlike our current UralMash rig). Service contracts were subsequently
concluded with Saipem to provide a rig and drilling services to the Company and with Baker-Hughes
for the provision of an oil-based mud system.
On August 26, 2005 we announced that the Manavi M11Z well had reached a total depth (TD) of
14,994 feet (4,570 meters) measured depth (MD) in the Cretaceous. The well was completed in the
Cretaceous using slim-hole drilling technology due to the small size of the casing from which the
well was sidetracked. The primary Cretaceous limestone target was encountered at 14,032 feet
(4,277 meters) MD some 230 feet (70 meters) MD higher than in the original M11 well while the
secondary Middle Eocene target zone was penetrated at 13,009 feet (3,965 meters) MD again
significantly higher than in the M11 well. Drilling data and slim hole wireline logs indicated the
presence of hydrocarbons in both the Cretaceous and Middle Eocene target zones.
On October 6, 2005 we announced that we had commenced testing operations on M11Z. A
pre-perforated 27/8 inch (73mm) liner was run in the slim hole, and the Saipem drilling
rig removed from the site while CanArgo Rig #1 was mobilized to the location for testing operations. During initial testing operations it
emerged that the section of the liner adjacent to the Cretaceous limestone interval may have become
differentially stuck probably due to a build up of filter cake on and in the formation during
drilling which is in itself indicative of a permeable zone. Although small amounts of oil and gas
have been recovered from the well, no significant flow was achieved during the initial
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testing.
Despite efforts to wash the mixture of drilling fluid and carbonate from the well bore using coiled
tubing, it was not possible to clean out the formation and it appears that the Cretaceous limestone
formation has been blocked and is not in communication with the wellbore at this time.
Schlumberger well completions experts were consulted who advised that the best techniques with
which to re-establish communication with the formation in the well by removing near-wellbore damage
is through the application of acid using coiled tubing and, if
necessary, perforate. It is now planned to carry out an acid stimulation and complete the well test
using a Schlumberger supplied coiled-tubing unit, pumping equipment and completion fluids. The
delay in testing this well has been due to the difficulty in sourcing a coil tubing unit to
Georgia.
We have identified further appraisal locations on the Manavi structure. Drilling operations
at the first appraisal site, M12 using the Saipem rig commenced on February 9, 2006. 20 inch (508
mm) casing has now been set and the well is currently operating in
the 17 1/2 inch (445 mm) hole section. The well is located approximately 2.5 miles (4 Km) to the west
of the M11 discovery well. CanArgo rig #2 was used to spud the well and drill the surface casing
section to a depth 1,302 feet (397 meters) whilst Saipem completed operations on the Norio MK72
well. M12 has a planned total depth of 15,092 feet (4,600 meters), and is expected to be completed
in the summer of 2006.
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.
West Rustavi and 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. Horizontal drilling may also be appropriate for this
deposit. One of the ten wells drilled in the West Rustavi Field was tested in the deeper
Cretaceous/Paleocene horizon. This well was tested and is reported to
have 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 over this structure
and the presence of a potentially large prospect has been mapped, with the crestal part being in
the Nazvrevi / Block XIII PSC area. This prospect is located approximately 7.5 miles (12 Km)
southeast of Tbilisi and is close to the gas transportation grid (nearest pipeline approximately
2.2 miles (3.5 Km) (500mm, 10-12 Atm pressure) and a pipeline at 10 miles (16 Km) (700mm, 9-10 Atm)
and is approximately 12.5 miles (20 Km) west of the Gardabani thermal power plant.
On March 3, 2006 we announced that our subsidiary, CanArgo (Nazvrevi) Limited (“CNZ”) has
signed a Memorandum of Understanding (“MOU”) which includes the terms of a take-or-pay natural gas
supply contract with the Ministry of Energy of Georgia relating to gas sales from the Kumisi gas
prospect near Tbilisi, Georgia, (“Kumisi”). The MOU will become effective subject to final
regulatory approval. This MOU provides the commercial basis for CNZ to move forward with the
appraisal of Kumisi and, based on this, CNZ plans to spud a well on Kumisi within the Nazvrevi PSC
area between May and December of 2006.
The MOU contains the terms of a take-or-pay gas supply contract with the Georgian State,
secured against appropriate bank guarantees, in which CNZ will supply gas from Kumisi based on a
pricing formula under which gas is initially supplied at a contract price of US$ 1.56 per mcf (US$
55 per MCM), increasing to US$ 2.28 per mcf (US$ 80 per MCM) by the tenth contract year, after
which escalation will be based on European Union heavy fuel oil price changes.
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The gas supply contract is for the entire field life. However, after the tenth year, CNZ has
the option of selling to third parties if the price obtained is 10% above the contract price at
that time.
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.
ITEM 1A. RISK FACTORS
Reference is hereby made to the Section entitled “CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENT” with respect to certain qualifications regarding the following
information. The risks described below are not the only ones facing the Company. Additional risks
not presently known to us or that we currently deem immaterial may also impair our business
operations and adversely affect the price of our shares.
RISKS ASSOCIATED WITH OUR BUSINESS AND BUSINESS OPERATIONS.
WE HAVE EXPERIENCED RECURRING LOSSES.
For the fiscal years ended December 31, 2005, 2004, 2003, 2002, and 2001, we recorded net
losses of $12,335,314, $4,757,000, $7,322,000, $5,328,000, and $13,218,000 respectively, and have
an accumulated deficit of $117,201,506 as at December 31, 2005. No impairment of oil and gas
properties was recorded in 2005 or 2004. The loss in 2003 included a writedown in our carrying
value of the Bugruvativske Field in Ukraine of $4,790,000 to reflect the estimated recoverable
amount from disposal, a write-off of the $1,275,000 debit balance in minority interest in Georgian
American Oil Refinery (“GAOR”) due to a change in the intentions of our minority interest owner and
plan to dispose of the asset, and a generator unit was impaired by $80,000 to reflect its fair
value less cost to sell. Impairments of oil and gas properties, ventures and other assets in prior
years include writedowns of $1,600,000 in 2002 and $11,160,000 in 2001. No assurance can be given,
however, that we will not experience operating losses or additional writedowns in the future.
OUR ABILITY TO PURSUE OUR ACTIVITIES IS DEPENDENT ON OUR 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 generating funds from internal sources, 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 are realized and/or proceeds from
additional financings and/or the sale of non-core assets are received to meet our cash flow needs.
As a result of a private placement of our Senior Secured Notes due July 25, 2009 and our Senior
Subordinated Convertible Guaranteed Notes due September 1, 2009, and based upon the current level
of operations, we believe that, coupled with our cash flow from operations as well as the
possibility, if required, of obtaining third party participation in our projects, we will have
adequate capital to meet our anticipated existing requirements for working capital, capital
expenditures, interest payments and scheduled principal payments for the next twelve months.
However, 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. Furthermore,
unanticipated investment opportunities and operational difficulties may require unscheduled capital
expenditures which may, in turn, require additional fund raising. No assurance can be given that we
will be able to secure such funds or, if available, such funds can be obtained on commercially
reasonable terms.
OUR CURRENT OPERATIONS ARE DEPENDENT ON THE SUCCESS OF OUR GEORGIAN EXPLORATION ACTIVITIES AND
OUR ACTIVITIES ON THE NINOTSMIND AND KYZYLOI FIELDS.
To date we have directed substantially all of our efforts and most of our available funds to
the development of the Ninotsminda Field in the Kura Basin in the eastern part of Georgia,
appraisal of the Manavi oil discovery, and
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exploration in that area and some ancillary activities in the Kura Basin area. This decision is
based on management’s assessment of the promise of the Kura Basin area. More recently we have begun
operations in Kazakhstan, particularly on the Kyzyloi Gas Field. Our focus on the Ninotsminda Field
has over the past several years resulted in overall losses for us. We cannot assure investors that
the exploration and development plans for the Ninotsminda Field or the Kyzyloi Gas Field will be
successful. For example, the Ninotsminda Field may not produce sufficient quantities of oil and gas
and at sufficient rates to justify the investment we have made and are planning to make in 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 produced at a sufficiently high price to generate a positive cash flow and a
profit. Furthermore, the maintenance of production levels from the Ninotsminda Field is subject to
regular workover operations on the wells due to the friable nature of the reservoir and the need to
remove sediment build-up from the production interval. Such operations will add additional costs
and may not always be successful. Our Georgian exploration program, particularly in the Manavi and
Norio areas, is an important factor for future success, and this program may not be successful, as
it carries substantial risk. See “Our oil and gas activities involve risks, many of which are
beyond our control” below for a description of a number of these potential risks and losses. In
accordance with customary industry practices, we maintain insurance against some, but not all, of
such risks and some, but not all, of such losses. The occurrence of an event not fully covered by
insurance could have a material adverse effect on our financial condition and results of
operations.
OUR OPERATION OF THE NINOTSMINDA FIELD IS GOVERNED BY A PRODUCTION SHARING CONTRACT WHICH MAY
BE SUBJECT TO CERTAIN LEGAL UNCERTAINTIES.
Our principal business and assets are derived from production sharing contracts in Georgia.
The legislative and procedural regimes governing production sharing agreements and mineral use
licenses in Georgia have undergone
a series of changes in recent years resulting in certain legal uncertainties. Our production
sharing agreements 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.
WE MAY ENCOUNTER DIFFICULTIES IN ENFORCING OUR TITLE TO OUR PROPERTIES.
Since all of our oil and gas interests are currently held in countries where there is
currently no private ownership of oil and gas in place, good title to our interests is dependent on
the validity and enforceability of the governmental licenses and production sharing contracts and
similar contractual arrangements that we enter into with government entities, either directly or
indirectly. As is customary in such circumstances, we perform a minimal title investigation before
acquiring our interests, which generally consists of conducting due diligence reviews and in
certain circumstances securing written assurances from responsible government authorities or legal
opinions. We believe that we have satisfactory title to such interests in accordance with standards
generally accepted in the crude oil and natural gas industry in the areas in which we operate. Our
interests in properties are subject to royalty interests, liens incident to operating agreements,
liens for current taxes and other burdens, none of which we believe materially interferes with the
use of, or affects the value of, such interests. However, as is discussed elsewhere, there
is no assurance that our title to its interests will be enforceable in all circumstances due to the
uncertain nature and predictability of the legal systems in some of the countries in which we
operate.
WE WILL REQUIRE ADDITIONAL FUNDS TO IMPLEMENT OUR LONG-TERM OIL AND GAS
DEVELOPMENT PLANS.
It will take many years and substantial cash expenditures to develop fully our oil and gas
properties. We generally have the principal responsibility to provide financing for our oil and gas
properties and ventures. Accordingly, we may need to raise additional funds from outside sources in
order to pay for project development costs. We may not be able to obtain that additional financing.
If adequate funds are not available, we will be required to scale back or even suspend our
operations or such funds may only be available on commercially unattractive terms. The carrying
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value of the Ninotsminda Field or the Kyzyloi Gas 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.
WE MAY BE UNABLE TO FINANCE OUR OIL AND GAS PROJECTS.
Our long term ability to finance most 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 in the future could require us to scale back or abandon part or all of our future 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 we have interests is affected by many factors, including:
| - | world and regional economic conditions; | ||
| - | the state of international relations; | ||
| - | the stability and the 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 be influenced by their evaluations of us and our
projects, including their technical difficulty, and comparison with available alternative
investment opportunities. Finally, our ability to secure debt financing is subject to certain
limitations. See “Our Ability To Incur Additional Indebtedness Is Restricted Under The Terms Of The
Senior Secured And Subordinated Notes” below.
OUR OPERATIONS MAY BE SUBJECT TO THE RISK OF POLITICAL INSTABILITY, CIVIL
DISTURBANCE AND TERRORISM.
Our principal oil and gas properties and activities are in Georgia and in Kazakhstan, both of
which are, located in the former Soviet Union. Operation and development of our assets are subject
to a number of conditions endemic to former Soviet Union countries, including political
instability. The present governmental arrangements in
countries of the former Soviet Union in which we operate 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 replace
these governments. As recent developments in Georgia have illustrated, the national governments in
these countries often must deal, from time to time, with civil disturbances and unrest which may be
based on religious, tribal and local and regional separatist considerations. Our operations
typically involve joint ventures or other participatory arrangements with the national government
or state-owned companies. The production sharing contract 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, terrorism, 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 either directly or through the enactment of laws and regulations which have an
economically confiscatory result. We are not insured against political or terrorism risks because
management deems the premium costs of such insurance to be currently prohibitively expensive.
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WE FACE THE RISK OF SOCIAL, ECONOMIC AND LEGAL INSTABILITY IN THE COUNTRIES IN
WHICH WE OPERATE.
The political institutions of the countries that were a part of the former Soviet Union have
recently become more fragmented, and the economic institutions of these countries have recently
converted to a market economy from a planned economy. New laws have recently been introduced, and
the legal and regulatory regimes in such regions may be vague, containing gaps and inconsistencies,
and are 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 uncertainty as to the
enforceability of contracts. Social, economic and legal instability have accompanied these changes
due to many factors which include:
| - | low standards of living; | ||
| - | high unemployment; | ||
| - | under-developed and changing legal and social institutions; and | ||
| - | conflicts within and with neighbouring countries. |
This instability could make continued operations difficult or impossible. Georgia has
democratically elected a new President following a popular revolt against the previous
administration in November 2003 and has successfully quelled a potential separatist uprising in one
of its regions. Although the new Georgian administration has made public statements supporting
foreign investment in Georgia, and specific written support for our activities, there can be no
guarantee that this will continue, or that these changes will not have an adverse affect on our
operations. There are also some separatist areas within Georgia that may cause instability and
potentially affect our activities.
WE FACE AN INADEQUATE OR DETERIORATING INFRASTRUCTURE IN THE COUNTRIES IN
WHICH WE OPERATE.
Countries in the former Soviet Union may 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, we
have, in the past, suspended drilling and testing procedures due to the lack of a reliable power
supply in Georgia.
WE MAY ENCOUNTER CURRENCY RISKS IN THE COUNTRIES IN WHICH WE OPERATE.
Payment for oil and gas products sold in 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. Most former Soviet Union country
currencies are presently convertible into U.S. dollars, but there is no assurance that such
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 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. We 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.
WE MAY ENCOUNTER TAX RISKS IN THE COUNTRIES IN WHICH WE OPERATE.
Countries may 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
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and in Kazakhstan, 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 have negotiated
economic stabilization clauses in our production sharing contracts in Georgia and all current taxes
are payable from the State’s share of petroleum produced under the production sharing contracts.
WE HAVE IDENTIFIED MATERIAL WEAKNESSES IN OUR INTERNAL CONTROLS OVER FINANCIAL REPORTING
WHICH, IF NOT REMEDIATED, MAY ADVERSELY AFFECT OUR ABILITY TO TIMELY AND ACCURATELY MEET OUR
FINANCIAL REPORTING RESPONSIBILITIES.
We have identified a number of material weakness in our evaluation of the effectiveness of our
internal control over financial reporting as of December 31, 2005 (see Part II, Item 9A Control and
Procedures). We plan to undertake a process to remediate the identified material weaknesses;
however our failure to complete this remediation process may adversely affect our ability to
accurately report our financial results in a timely manner.
We also believe that our disclosure controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934) were ineffective as of December 31, 2005. We
believe that the material weaknesses identified in our evaluation of the effectiveness of our
internal control over financial reporting as of December 31, 2005 mean that we cannot fully ensure
that the information required to be disclosed by us in the reports we file or submit under the
Exchange Act with the Commission (1) is recorded, processed, summarized and processed within the
time period specified in the Commission’s rules and forms and (2) is accumulated and communicated
to the management, including principal executives and principal financial officers, as appropriate
to allow timely decisions regarding required disclosure.
OUR ABILITY TO INCUR ADDITIONAL INDEBTEDNESS IS RESTRICTED UNDER THE TERMS OF THE SENIOR SECURED
AND SUBORDINATED NOTES.
Pursuant to the terms of (i) the Note Purchase Agreement dated July, 25, 2005 entered into by
and between CanArgo and the purchasers of the Senior Secured Notes due July, 25, 2009 (“Senior
Secured Notes”) and (ii) the Note and Warrant Purchase Agreement dated March 3, 2006 entered into
by and between CanArgo and the purchasers of the Senior Subordinated Convertible Guaranteed Notes
due September 1, 2009 (“Subordinated Notes”), we may not incur future indebtedness or issue
additional senior or pari passu indebtedness, except with the prior consent of the beneficial
holders of at least 51% of the outstanding principal amount of the Senior Secured Notes and 50% of
the outstanding principal amount of the Subordinated Notes, or in limited permitted
circumstances. The definition of indebtedness in the Note Purchase Agreement and Note and Warrant
Purchase Agreement encompasses all customary forms of indebtedness, including, without limitation,
liabilities for deferred consideration, liabilities for borrowed money secured by any lien or other
specified security interest (except permitted liens), liabilities in respect of letters of credit
or similar instruments (excluding letters of credit which are 100% cash collateralized) and
guarantees in relation to such forms of indebtedness (excluding parent company guarantees provided
by CanArgo in respect of the indebtedness or obligations of any of our subsidiaries under any Basic
Documents, as defined in the Note and Note and Warrant Purchase Agreements).
RISKS ASSOCIATED WITH OUR INDUSTRY.
WE MAY BE REQUIRED TO WRITE-OFF 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
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been
established. We could be required in the future to write-off our investments in additional
projects, including the Ninotsminda Field project, if such projects prove to be unsuccessful.
OUR OIL AND GAS ACTIVITIES INVOLVE RISKS, MANY OF WHICH ARE BEYOND OUR
CONTROL.
Our exploration, development and production activities are subject to a number of factors and
risks, many of which may be beyond our control. We must first successfully identify commercial
quantities of oil and gas, which is inherently subject to many uncertainties. Thereafter, the
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 and personnel to support operations; | ||
| - | labour disputes; | ||
| - | local and global oil prices; and | ||
| - | government regulation and legal and political uncertainties. | ||
| Our activities can also be affected by a number of hazards, including, without limitation: | |||
| - | natural phenomena, such as bad weather; | ||
| - | 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 factors or hazards could result in damage, losses or liability for us. 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 countries that were part of the former Soviet Union. Risks
associated with bad weather apply in particular to the Kyzyloi and Akkulka areas in
Kazakhstan which has extremes of winter and summer temperatures and where extremely low winter
temperatures and snow may hamper and delay operations and potentially affect production. This
particular risk applies to a lesser extent in Georgia, but we have experienced delays due to
extreme snowfall and winter conditions and earthquakes. We do not purchase insurance covering all
of the risks and hazards or all of our potential liability that are involved in oil and gas
exploration, development and production.
WE MAY HAVE 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 ours and may
conflict with our interests. This would apply to our projects both in Georgia and in Kazakhstan.
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 countries that were a part of 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
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for various actions. Other parties influencing the timing of events
may have priorities that differ from ours, even if they generally share our objectives. 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 OPERATING DIRECT AND INDIRECT SUBSIDIARIES AND JOINT VENTURES REQUIRE
GOVERNMENTAL REGISTRATION.
Operating entities in various foreign jurisdictions must be registered by governmental
agencies, and production licenses and contracts for the 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.
WE ARE AFFECTED BY 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 our control, 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 and terrorist activity in the Middle East, Caucasus, Central Asia 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. We may
also not benefit from rapid increases in oil prices as the market for the levels of crude oil
produced in Georgia by NOC can in such an environment be relatively inelastic. Contract prices are
often set at a specified price determined with reference to world market prices (often based on the
average of a number of quotations for “marker” crude including Dated Brent Mediterranean or Urals
Mediterranean at the time of sale) subject to appropriate discounts for transportation and other
charges which can vary from contract to contract.
OUR ACTUAL OIL AND GAS PRODUCTION COULD VARY SIGNIFICANTLY FROM RESERVE
ESTIMATES.
Estimates of oil and natural gas reserves and their values 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 the crude oil and natural gas; |
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| 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 reports on the oil and gas reserves prepared by independent petroleum
consultants at any given point in time. 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.
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.
OUR 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 countries that were a part of 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.
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WE FACE SIGNIFICANT COMPETITION.
The oil and gas industry is highly competitive. Our competitors include integrated oil and gas
companies, government owned oil companies, independent oil and gas companies, drilling and income
programs, and wealthy individuals. Many of our competitors are large, well-established,
well-financed companies. Because of our small size and lack of financial resources, we may not be
able to compete effectively with these companies.
OUR PROFITABILITY MAY BE SUBJECT TO CHANGES IN INTEREST RATES.
Our profitability may also be adversely affected during any period of unexpected or rapid
increase in interest rates. While our current long term debt has fixed interest rates, increases in
interest rates may adversely affect our ability to raise debt capital to the extent that our income
from operations will be insufficient to cover debt service.
RISKS ASSOCIATED WITH OUR STOCK.
LIMITED TRADING VOLUME IN OUR COMMON STOCK MAY CONTRIBUTE TO PRICE VOLATILITY.
Our common stock is listed for trading on the Oslo Stock Exchange (“OSE”) in Norway, and on
The American Stock Exchange (“AMEX”) in New York. Prior to the listing on the AMEX, our stock was
traded on the Over the Counter Bulletin Board in the United States and on the OSE. During the 12
months ended December 31, 2005, the average daily trading volume for our common stock on the OSE
was 3,726,418 shares and 1,723,540 shares on the AMEX both as reported by Yahoo and the closing
price of our stock during such period ranged from a low of NOK 4.45 and $0.66 to a high of NOK
14.10 and $2.25 on the OSE and AMEX, respectively, as reported by Yahoo. As a relatively small
company with a limited market capitalization, even if our shares are more widely disseminated,
we are uncertain as to whether a more active trading market in our common stock will develop. As a
result, relatively small trades may have a significant impact on the price of our common stock.
THE PRICE OF OUR COMMON STOCK MAY BE SUBJECT TO WIDE FLUCTUATIONS.
The market price of our common stock could be subject to wide fluctuations in response to
quarterly variations in our results of operations, changes in earnings estimates by analysts,
changing conditions in the oil and gas industry or changes in general market, economic or political
conditions.
WE DO NOT ANTICIPATE PAYING CASH DIVIDENDS IN THE FORESEEABLE FUTURE.
We have not paid any cash dividends to date on the common stock and there are no plans for
such dividend payments in the foreseeable future.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not applicable.
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ITEM 2. PROPERTIES.
Production History
Ninotsminda
The Ninotsminda Field was discovered and initial development began in 1979. Current gross
field production as of the end of January, 2006 was approximately 510 bopd. Gross and net
production from the Ninotsminda Field for the past three years was as follows:
| Oil (Barrels) | Gas (mcf) | |||||||||||||||
| Year Ended | Net | Net | ||||||||||||||
| December 31, | Gross | (PSC Entitlement)1 | Gross | (PSC Entitlement)1 | ||||||||||||
2005 |
184,952 | 120,219 | 71,241 | 46,307 | ||||||||||||
2004 |
370,176 | 241,131 | 65,066 | 42,293 | ||||||||||||
2003 |
695,174 | 451,863 | 108,630 | 70,610 | ||||||||||||
| (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 the contractor party after deduction of Georgian Oil’s share which includes all Georgian taxes, levies and duties. NOC owns 100% of the contractor’s interest in the PSC. As a result of CanArgo’s interest in NOC, these volumes accrue to the benefit of CanArgo for the recovery of capital, repayment of operating costs and share of profit. |
Samgori
In April 2004, we announced that we had completed our acquisition of a 50% interest in the
Samgori (Block XI B) Production Sharing Contract (“Samgori PSC”) in Georgia in which we
have since terminated our interest with effect from February 16, 2006. The gross field production
as of end of January 2006 was approximately 380 bopd. The gross and net production for the past
year and the nine month period ending December 31, 2005 was as follows:
| Oil (Barrels) | ||||||||||||
| Year Ended | Net (PSC | |||||||||||
| December 31, | Gross | Entitlement)2 | CSL Net Share | |||||||||
2005 |
166,298 | 124,723 | 62,362 | |||||||||
2004 (nine months) |
152,169 | 114,127 | 57,063 | |||||||||
| (2) | 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 the contractor parties after deduction of Georgian Oil’s share which includes all Georgian taxes, levies and duties. CSL owned 50% of the contractor’s interest in the PSC. As a result of CanArgo’s interest in CSL, these volumes accrued to the benefit of CanArgo for the recovery of capital, repayment of operating costs and share of profit. |
We ceased to have an interest in this project on February 16, 2005.
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Productive Wells and Acreage
The following table summarizes as of December 31, 2005, 2004 and 2003 with respect to NOC 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 NOC.
| Gross | ||||||||
| Number of Wells | Acres | |||||||
Ninotsminda Field |
11 | 492 | ||||||
On December 31, 2005, there were no other productive wells or developed acreage within the
Ninotsminda PSC area except for one gross well on the West Rustavi Field which was shut-in at that
date.
The only other productive wells or developed acreage on any of our other Georgian properties
were within the Samgori PSC area. This information below as of December 31, 2005 and 2004 is
presented on a net basis representing our 100% interest in CSL which in turn had a 50% interest in
the Samgori PSC. Our interest in the Samgori PSC was terminated with effect from February 16, 2006.
| Net | ||||||||
| Number of Wells | Acres | |||||||
Samgori
Field Complex |
11.5 | 950 | ||||||
Reserves
Ninotsminda Field, Georgia
The following table summarizes net hydrocarbon reserves for the Ninotsminda Field in Georgia.
This information is derived from a report dated as of January 1, 2006 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.
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Exploration and Deveopment Wells
The following table summarizes as of December 31, the number of exploration and development
oil and gas wells in progress. Such information has been presented on a gross basis,
representing our 100% interest in these wells.
| Exploration | Development | |||||||
Ninotsminda Field |
2 | 1 | ||||||
Norio Field |
1 | — | ||||||
| 3 | 1 | |||||||
The following table summarizes as of December 31 2005, 2004 and 2003, the total number of dry
exploration oil and gas wells drilled. The information has been represented on a gross basis,
representing our 100% interest in this well.
| 2005 | 2004 | 2003 | ||||||||||
Ninotsminda Field |
1 | 1 | 1 | |||||||||
| 1 | 1 | — | ||||||||||
The following table summarizes as of December 31 2005, 2004 and 2003, the total number of dry
development oil and gas wells drilled. The information has been presented on a gross basis
representing our 100% interest in this wells.
| 2005 | 2004 | 2003 | ||||||||||
Samgori Field * |
1 | 1 | — | |||||||||
| 1 | 1 | — | ||||||||||
| * | CSL 100% funded a development well drilled on the Samgori complex in 2004. |
The following table summarizes as of December 31 2005, 2004 and 2003, the total number of
completed wells that flowed commercial quantities of oil and gas. The information has been
represented on a gross basis, representing our 100% interest in these wells.
| 2005 | 2004 | 2003 | ||||||||||
Ninotsminda Field |
8 | 6 | 6 | |||||||||
| 8 | 6 | 6 | ||||||||||
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| Oil Reserves – | PSC Entitlement | |||||||
| Gross | Volumes (1) | |||||||
| (Million | (Million | |||||||
| Oil Reserves | Barrels) | Barrels) | ||||||
Proved Developed |
3.150 | 2.013 | ||||||
Proved Undeveloped |
2.349 | 1.501 | ||||||
Total Proven |
5.499 | 3.514 | ||||||
| Gas Reserves - | PSC Entitlement | |||||||
| Gross | Volumes (1) | |||||||
| (Billion Cubic | (Billion Cubic | |||||||
| Gas Reserves | Feet) | Feet) | ||||||
Proved Developed |
1.343 | 0.858 | ||||||
Proved Undeveloped |
1.159 | 0.741 | ||||||
Total Proven |
2.502 | 1.599 | ||||||
| (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 the respective contractor parties after deduction of Georgian Oil’s share which includes all Georgian taxes, levies and duties. As a result of CanArgo’s interest in NOC, these volumes accrue to the benefit of CanArgo for the recovery of capital, repayment of operating costs and share of profit. |
Kyzyloi and Akkulka Gas Fields in Kazakhstan
The following table summarizes net hydrocarbon reserves for the Kyzyloi and Akkulka Gas Fields
in Kazakhstan. This information is also derived from a report dated as of January 1, 2006 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.
| Gas Reserves - | Gas Reserves - | |||||||
| Gross | Net (1) | |||||||
| (Billion Cubic | (Billion Cubic | |||||||
| Gas Reserves | Feet) | Feet) | ||||||
Proved Undeveloped |
32.694 | 32.694 | ||||||
Total Proven |
32.694 | 32.694 | ||||||
| (1) | Tethys Petroleum Investment Limited (TPI) through its 100% owned Kazakhstan subsidiary TKL (Tethys Kazakhstan Limited), holds 70% ownership rights in BN Munai LLP, a Kazakh registered company that has the 100% rights to the Kyzyloi field. Under a loan agreement with BN Munai LLP, TKL will take 100% of the net cash flow of the Kyzyloi development until its loan is repaid. This loan is currently in excess of net cash flows generated from the production of gross proven reserves. |
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
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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 oil price used in the Ninotsminda Field report by OPC
as of January 1, 2006 was $50.70 per barrel based on the Brent spot price per barrel at year end
less $7.50 per barrel discount, in line with CanArgo’s most recent contractual arrangement. The
net gas price used in the Ninotsminda Field report is $0.71 per mcf in line with CanArgo’s most
recent contractual arrangement. The gas price used in the Kyzyloi and Akkulka Gas Fields report by
OPC as of January 1, 2006 ranged from $0.79 per mcf to $1.08 per mcf in line with the Gas Sales
Contract for the Kyzyloi Field negotiated with the gas buyer in Kazakhstan. 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. Neither had independent
reserves been assessed for the Samgori Field complex. The Company’s interest in the Samgori PSC
terminated with effect from February 16, 2006.
Undeveloped Acreage
The following table summarizes the gross and net undeveloped acreage held under the
Ninotsminda, Nazvrevi/Block XIII, Norio/North Kumisi, Tbilisi and Samgori production sharing
contracts as of December 31, 2005. The information regarding net acreage represents our interest
based on our 100% interest in NOC and the subsidiaries holding the Nazvrevi/Block XIII contract,
the Norio/North Kumisi and the Tbilisi Block XIG and XIH contracts, and our
50% interest in the Samgori Block XIB contract through our wholly owned subsidiary CSL.
Our interest in the Samgori PSC was terminated with effect from February 16, 2006.
| Gross | Net | |||||||||||||||
| Square | Square | |||||||||||||||
| PSC | Acres | Kilometers | Acres | Kilometers | ||||||||||||
Ninotsminda, Manavi and West Rustavi
covering Block XIE |
27,739 | 112 | 27,739 | 112 | ||||||||||||
Nazvrevi and Block XIII |
388,447 | 1,572 | 388,447 | 1,572 | ||||||||||||
Norio (Block XIC) and North
Kumisi |
381,034 | 1,542 | 381,034 | 1,542 | ||||||||||||
Block
XIG and
XIH (1) |
119,845 | 485 | 119,845 | 485 | ||||||||||||
Samgori and Block XIB (2) |
156,664 | 634 | 78,332 | 317 | ||||||||||||
Total |
1,073,729 | 4,345 | 995,397 | 4,028 | ||||||||||||
(1) 25%
relinquishment March 2006
(2) Exited PSC subsequent to year end, in February 2006
(2) Exited PSC subsequent to year end, in February 2006
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The following table summarizes the gross and net undeveloped acreage held under the Kazakhstan
licenses as of December 31, 2005. The information regarding net acreage represents our interest
based on our 70% interest in BN Munai and the subsidiaries holding the licenses through our wholly
owned subsidiary TPI.
| Gross | Net | |||||||||||||||
| Square | Square | |||||||||||||||
| License | Acres | Kilometers | Acres | Kilometers | ||||||||||||
Kyzyloi |
70,919 | 287 | 49,643 | 201 | ||||||||||||
Akkulka |
411,922 | 1,667 | 288,346 | 1,167 | ||||||||||||
Greater Akkulka |
2,751,009 | 11,133 | 1,925,706 | 7,793 | ||||||||||||
Total |
3,233,850 | 13,087 | 2,263,695 | 9,161 | ||||||||||||
Although the Kyzyloi is potentially a productive field, production has not yet commenced and
has been classified as Undeveloped Acreage. A 33 mile (53 Km) pipeline is planned to tie the field
to the main Bukhara-Urals gas trunkline. A long-term gas offtake agreement has already been
concluded with a planned initial plateau rate of 17.7 million cubic feet (500,000 cubic meters) per
day.
Office Space
We lease office space in London, England; Guernsey, Channel Islands; Tbilisi, Georgia; and
Almaty and Aktobe in Kazakhstan. The leases have remaining terms varying from six months to nine
years and nine months and annual rental charges ranging from $5,000 to $300,000.
Processing, Sales and Customers — Georgia
Georgian Oil built a considerable amount of infrastructure in and adjacent to the Samgori and
Ninotsminda Fields prior to entering into the production sharing contracts for these Fields. NOC
now use that infrastructure, including initial processing equipment and CSL used it during the term
of the Samgori PSC.
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 approximately seven miles (11 Km) either
in a pipeline or by truck to Georgian Oil’s central processing facility at Sartichala for further treatment. Oil produced from the Samgori Field complex was
also transported to Sartichala for treatment prior to sale.
At Sartichala, the water is separated from the oil. NOC and CSL then sell their share of oil
in this state to buyers at Sartichala for local consumption or transfer it by pipeline
approximately 12 miles (20 Km) to a railhead at Gatchiani or by road tanker to Vaziani rail loading
terminal primarily for export sales. At the railheads, the oil is
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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.
NOC sells its oil directly to local and international buyers. In 2005, NOC sold its oil
production in accordance with the terms of a sales agreement concluded with Primrose Financial
Group (“PFG”) which included the sale of oil to other customers nominated by PFG under this
agreement. During the year, oil was purchased and paid for by a total of 4 customers. Of these
customers, the following two customers represented sales greater than 10% of oil revenue:
| Customer | Percent of Oil Revenue | |||
Interchem Energy |
74.5 | % | ||
Gero |
15.8 | % | ||
Management believes that the loss of PFG or any of its nominated 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.
In 2004, NOC sold its oil production to 14 customers of which the following four customers
represented sales greater than 10% of oil revenue:
| Customer | Percent of Oil Revenue | |||
Crownhill |
27.5 | % | ||
Gero |
21.9 | % | ||
Interchem Energy |
20.7 | % | ||
Viva |
11.6 | % | ||
In 2003, NOC sold its oil production to 11 customers of which the following three customers
represented sales greater than 10% of oil revenue:
| Customer | Percent of Oil Revenue | |||
Crownhill |
42.4 | % | ||
Baslam |
32.3 | % | ||
Sveti |
16.9 | % | ||
For NOC, sales to both the domestic and international markets during 2005 were based on the
average of a number of quotations for Dated Brent Mediterranean as quoted in Platts Crude Oil
Marketwire © with an appropriate discount for transportation and other charges amounting
to $7.50 per barrel. Of the sales in 2004, 43.2 % was sold against a Brent quotation at an average
discount of $7.50 per barrel and 56.8 % against an Urals quotation at an average discount of $7.00
per barrel while the average discounts to the price of Brent crude oil as quoted in Platts Crude
Oil Marketwire © for Brent Dated Mediterranean for all sales in 2003 was $7.70.
The average sales price and the average production cost per unit (excluding depreciation,
depletion and amortization) of oil and gas produced by NOC for each of the last three years was as
follows:
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| Average Sales Price | ||||||||||||
| Year Ended | Oil | Gas | Unit Production Cost | |||||||||
| December 31, | $/boe | $/mcf | $/boe | |||||||||
2005 |
44.78 | 0.53 | 14.83 | |||||||||
2004 |
24.94 | 1.41 | 5.81 | |||||||||
2003 |
20.07 | 1.25 | 2.59 | |||||||||
In 2005, CSL sold its share of production to four customers of which the following one
customer represented sales greater than 10% of oil revenue for the period to December 31, 2005:
| Customer | Percent of Oil Revenue | |||
Interchem Energy |
80.0 | % | ||
Since April 2004, when CSL acquired an interest in the Samgori PSC, to December 31, 2004 the
company sold its share of production to seven customers of which the following four customers
represented sales greater than 10% of oil revenue for the period:
| Customer | Percent of Oil Revenue | |||
Mercury |
34.6 | % | ||
Interchem Energy |
24.0 | % | ||
GanOil |
15.5 | % | ||
Valimpex |
10.9 | % | ||
For CSL, sales to both the domestic and international markets during the twelve month period
to end-December 2005 were based on the average of a number of quotations for Dated Brent
Mediterranean with an appropriate discount for transportation and other charges. The average
discount to the price of Brent crude oil as quoted in Platts Crude Oil Marketwire © for
Brent Dated Mediterranean for all sales in 2005 was $6.16 per barrel. The discount during the nine
months of trading in 2004 was $5.12 per barrel. The higher discount during 2005 is due to generally
smaller quantities of oil being available for sale.
The average sales price and the average production cost per unit of oil and gas produced by
CSL in 2005 and 2004 was as follows:
| Average Sales Price | ||||||||||||
| Year Ended | Oil | Gas | Unit Production Cost | |||||||||
| December 31, | $/boe | $/mcf | $/boe | |||||||||
2005 |
46.12 | 0.00 | 18.79 | |||||||||
2004 |
33.96 | 0.00 | 9.59 | |||||||||
Our interest in the Samgori PSC was terminated with effect from February 16, 2006.
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; |
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| • | 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 Production Sharing Contracts
Nazvrevi and Block XIII Production Sharing Contract (“Nazvrevi PSC”)
In February 1998, our wholly owned subsidiary, CanArgo (Nazvrevi) Limited (“CNZ”) entered into
a second production sharing contract with Georgian Oil and the State of Georgia. This contract
covers the Nazvrevi (Block XID ) and Block XIII areas of East Georgia, an approximately
496,186 acre (2,008 Km 2 ) exploration area adjacent to the Ninotsminda and West
Rustavi Fields and containing existing infrastructure. The agreement came into effect on February
20, 1998 and extends for twenty-five years with the final year of the contract being 2023. 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 388,447 acres (1,572 Km 2).
Under the Nazvrevi PSC, CNZ pays all operating and capital costs. We first recover our
cumulative operating costs from production. After deducting production attributable to operating
costs, 50% of the remaining production (cost recovery petroleum), considered on an annual basis, is
applied to reimburse us for our cumulative capital costs. While cumulative capital costs remain
unrecovered, the other 50% of remaining production (profit petroleum) is allocated on a 50/50 basis
between Georgian Oil and CNZ. After all cumulative capital costs have been recovered by us,
remaining production after deduction of operating costs is allocated on a 70/30 basis between
Georgian Oil and CNZ, respectively. Thus, while we are responsible for all of the costs associated
with the Nazvrevi PSC we are only entitled to receive 30% of production after cost recovery. The
allocation of a share of production to Georgian Oil, however, relieves us of all obligations we
would otherwise have to pay the State of Georgia for taxes and similar levies related to activities
covered by the production sharing contract. Both Georgian Oil and CNZ will take their respective
shares of oil production under the Nazvrevi PSC in kind but the intent is to 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 have been
interpreted, and possible oil and gas prospects and exploration drilling locations are being
identified. The cost of the seismic program was approximately $1.5 million, and met the minimum
obligatory work commitment under the contract. The Department for Protection of Mineral Resources
and Mining has confirmed that CNZ have met the requirements of the work program defined in the
production sharing contract. The Manavi oil discovery may extend into the Nazvrevi PSC area and the
West Rustavi 16 gas discovery may extend into Block XIII (the “Kumisi” prospect), and there are
several identified prospects, however as the Nazvrevi and Block XIII area is an exploration area
and no discoveries have been made to date, it is not possible to estimate the expenditures needed
to discover and if discovered, produce commercial quantities of oil and gas.
On March 3, 2006, we announced that CNZ had signed a Memorandum of Understanding (“MOU”) which
includes the terms of a take-or-pay natural gas supply contract with the Ministry of Energy of
Georgia relating to gas sales from the Kumisi gas prospect. The MOU will become effective subject
to final regulatory approval. The MOU provides the commercial basis for CNZ to move forward with the appraisal of Kumisi and, based
on this, CNZ plans to spud a well on Kumisi between May and December 2006. The MOU contains the
terms of a take-or-pay gas supply contract with the Georgian State, secured against appropriate
bank guarantees, in which CNZ will supply gas from Kumisi based on a pricing formula under which
gas is initially supplied at a Contract Price of US$ 1.56 per thousand cubic feet, increasing to
US$ 2.28 per thousand cubic feet by the tenth contract year, after which escalation will be based
on European Union heavy fuel oil price changes. The gas supply contract is for the entire field
life.
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However, after the tenth year, CNZ has the option of selling to third parties if the price
obtained is 10% above the Contract Price at that time.
The Kumisi prospect is located approximately 9 miles (15 Km) south of Tbilisi. The WR16 well,
drilled in Soviet times, is reported to have tested gas condensate from what is interpreted as the
gas-water contact in the Cretaceous/Palaeocene horizon. This well was tested and produced gas plus
water at a rate of approximately 3,500 barrels per day and is interpreted to have tested the
down-dip extent of the Kumisi gas deposit. Additional seismic data acquired by CNZ over this
structure shows a significant up-dip prospect and the location for the Kumisi #1 well has been
identified. The prospect is potentially of very significant size with the principal risk being
closure on the structure.
Norio (Block XIC) and North Kumisi Production Sharing Agreement (“Norio PSA”)
In December 2000, CanArgo, through its then 50% owned subsidiary CanArgo Norio Limited
(“CNL”), 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
262,919 acres (1,064 Km 2 ), following the first contractual relinquishment, adjacent to
the Ninotsminda and Samgori Fields. The Norio PSA came into effect on April 9, 2001 and extends for
a period of twenty-five years with the final year of the contract being 2026. We are required to
relinquish at least 25% of the original contract area, but not any portions being actively
developed, by the fifth anniversary of the effective date (which has been done) and then 50% of the
remaining area at five-year intervals commencing in 2011 up to 2026. 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. CNL has determined production from these fields to be
uneconomic, and the fields are currently being operated by Georgian Oil under a service agreement
with CNL, whereby Georgian Oil takes all production to compensate it for its costs under what is
effectively a social program. If CNL 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 CNL, remaining production
after deduction of operating costs is allocated on a 60/40 basis between Georgian Oil and CNL,
respectively. Thus, while CNL 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. On September
30, 2004 we announced that we had increased our interest in CNL, by buying out the remaining
minority shareholders who held a 25% interest in that company. CNL is now a wholly owned subsidiary
of CanArgo.
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 analogous to the nearby Samgori Field immediately to the south of the block. It has
been reported that 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. Although, the
primary target of the Middle Eocene had not been encountered, the State Agency for the Regulation
of Oil and Gas Resources in Georgia confirmed that CNL had satisfied all drilling and work
obligations under the terms of the Norio PSA by the initial phase of drilling of the MK72 well.
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In connection with this initial phase of drilling, which cost a total of $4.3 million, our
partner in CNL sought to farm-out to us and to third party investors part of its interest in CNL 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. CNL’s total share of these drilling costs was $3.1 million. In
November 2002, shareholders of CNL agreed to adjust the ownership of CNL to reflect the funding for
the MK72 well, and capitalization of certain loans and management fees that we had made to CNL.
Under this agreement, our interest increased from 50% to 64.2% in CNL. CNL then sought a partner to
assist with the financing to deepen the MK72 well.
In September 2003, CNL signed a farm-in agreement relating to the Norio PSA with a wholly
owned subsidiary of Georgian Oil, the Georgian State Oil Company. CNL 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 obligated Georgian Oil to
pay up to $2.0 million to deepen, to a planned depth of 16,733 feet (5,100 meters) the MK-72 well
in return for a 15% interest in the contractor share of the Norio PSA. Georgian Oil also had 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 CNL of $ 6.5 million
Co-incident with the Georgian Oil farm-in, we concluded a deal to purchase some of the
minority interests in CNL by a share swap for shares in CanArgo. Through this exchange we acquired
an additional 10.8% interest in CNL, thus increasing our interest to 75%. The purchase was achieved
by issuing 6 million restricted CanArgo common shares to the minority interest holders in CNL. Of
the interests in CNL, Provincial Securities Limited owned 4%. On September 30, 2004 we acquired the
remaining minority shareholders who held a 25% interest in CNL. We issued a further 6 million
restricted common shares in connection with this transaction.
In accordance with the terms of the farm-in agreement, Georgian Oil invested $1,758,000 in
deepening the MK72 well. Drilling recommenced in December 2003 and the well was drilled ahead to a
depth of 14,830 feet (4,520 meters). The well was cased, having encountered oil bearing sands in
the Oligocene formation which is a secondary objective for the well. Electric logs run over the
Oligocene sequence indicate over 330 feet (100 meters) of net pay sands with porosities in the
range of 8 to 28%, with an average of 13%. From the oil shows while drilling and log analysis,
these sands appear to be oil bearing. It was planned to test the Oligocene sands once the well has
reached total depth. Data obtained from a vertical seismic profile run in the well at this depth
indicated that there was a seismic reflector at 15,744 feet (4,800 meters) which could be the
Middle Eocene objective. Due to Georgian Oil’s inability to continue to fund the drilling of the
well, operations were subsequently suspended.
On May 9, 2005 we announced that CNL had signed final documentation with Georgian Oil for CNL
to secure 100% of the contractor share in the Norio PSA. On May 20, 2005 we paid Georgian Oil
$1,758,000 to terminate the Agreement and Option and secure a 100% working interest in the Norio
PSA.
In late June, we recommenced drilling operations on the suspended MK72 well and on August 26,
2005 we announced that the Saipem Ideco E-2100Az drilling rig and Baker-Hughes oil-based mud system
was being mobilized to the MK72 Norio exploration well. Our Ural Mash Rig had difficulty drilling
through a highly over-pressured section of swelling clays above the prognosed target zone and as
the Saipem Rig with its oil-based mud system had successfully drilled through a similar section in
the M11Z well, it was considered that this afforded the best option to completing the well. MK72
was sidetracked and successfully drilled through the over-pressured section encountering the top of
the Middle Eocene primary target zone at 15,787 feet (4,812 meters). A 5 inch (127 millimetre)
liner was run to 15,899 feet (4,846 meters) before drilling ahead through the reservoir using slim
hole technology.
On December 29, 2005 we announced that the MK72 well reached a depth of 4,900 meters (16,076
feet) in the Middle Eocene reservoir having encountered very good oil and gas shows. Gas levels up
to 21% were recorded at surface, as well as light oil in the mud and hydrocarbon fluorescence in
the cuttings samples. Inflow was observed and it appeared that the small diameter hole collapsed
around the bit. Although it may have been possible to mill down the BHA and to sidetrack the hole,
the small hole diameter and unstable hole conditions meant that there was a
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high risk that such an
operation would not be successful and could take an indeterminate time. As such it was decided to
plug back the lower part of the hole and to concentrate on testing the oil-bearing Oligocene sands
which were the secondary target for the well. From the data obtained from the Middle Eocene (the
primary target for the well) we believe that an oil discovery has been made at this level, and that
the reservoir has exhibited both permeability and the presence of movable light oil. As such, even
though the Middle Eocene has not been fully evaluated, the MK72 well has encountered the Middle
Eocene reservoir on prognosis, and with hydrocarbons thus achieving many of the objectives of this
wildcat exploration well.
The lower section of the well has now been plugged back and the Saipem rig has been moved to
the M12 appraisal location while the CanArgo rig #2 has been mobilised to the MK72 well location in
preparation for the testing of the Oligocene sand interval. High penetration tubing conveyed and
through tubing perforating guns have been imported from the United States for the test program. Ten
separate zones of interest between 12,057 feet (3,675 meters) MD and 13,337 feet (4,065 meters) MD
have been selected for testing. The lowermost zone, a 10 feet (3 meter) interval below the primary
test zones has now been perforated, primarily to give formation
pressure data for the main tests which are expected to commence
shortly.
Given significant production is tested, the well would be placed on long term test production.
The Norio PSA covers a large exploration area with what management believe to be good oil and
gas potential with the presence of reservoir rocks and moveable hydrocarbons have been confirmed by
drilling. We have mapped several significant prospects at different stratigraphic levels within the
area several of which are on trend with the MK72 well and the structure which is being tested.
Both the Oligocene and Middle Eocene prospects as mapped are potentially large and lie just to the
north west of Georgia’s largest oil field, the Samgori Field which is reported to have produced
over 180 million barrels of oil to date. Following a successful test of the Oligocene interval, it
would be intended to commence an appraisal drilling program later this year or early next year
operations permitting. It is also planned that an appraisal well will be drilled to fully evaluate
the Middle Eocene discovery sometime next year, with the well being designed to enter the Middle
Eocene reservoir with a larger hole size.
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 XIG and XIH Production Sharing Contract (“Tbilisi PSC”)
In November 2002, our subsidiary, CanArgo Norio Limited (“CNL”), won the tender for the oil
and gas exploration and production rights to the Tbilisi PSC, an area of approximately 119,845
acres (485 Km 2) in eastern Georgia adjacent to the Norio, Block XIII and West Rustavi
areas. In July 2003, it was announced that CNL, had signed a Production Sharing Contract covering
these areas. The Tbilisi PSC came into effect on September 29, 2003 and will continue for an
initial period of ten years at which time it will terminate unless we have made a commercial
discovery in which case the PSC will continue in full force and effect until September 29, 2028.
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. CNL will evaluate existing seismic and geological data during the
first year and acquire additional seismic data within three years of the effective date of the PSC
which was set as 29 September 2003. The total commitment over the next seven months is $350,000.
Following our acquisition of the minority shareholding in CNL in September 2004, our interest
in the Tbilisi PSC increased from 75% to 100%.
The Kumisi Cretaceous gas prospect extends into the southern part of Block XIG, and
this prospect will be evaluated by the well which is planned to be drilled on the prospect within
the Nazvrevi PSC just to the south of the block boundary with the Tbilisi PSC in the latter half of
2006.
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Exploration, Appraisal and Development Activities — Kazakhstan
In December 2003, we announced details of the conditional acquisition of certain oil and gas
interests in Kazakhstan which had previously been owned by the UK public company, Atlantic Caspian
Resources plc (“ACR”). This was to be achieved through a newly established company, Tethys
Petroleum Investments Limited (“TPI”) on certain conditions being satisfied. These interests were
represented as including a 70% interest in BN Munai LLP (“BNM”), a Kazakh limited liability
partnership, which was represented as holding certain exploration and production interests in
Kazakhstan including the Akkulka exploration contract and Kyzyloi production contract.
Immediately prior to the agreement between TPI and ACR, and as part of that transaction, we entered
into an agreement allocating a 45% interest in TPI to Provincial Securities Limited (an investment
company to which Mr. Russell Hammond, one of our non-executive directors, is an Investment Advisor)
in consideration for future services of providing advice, help and assistance concerning funding
the development of TPI. This transaction resulted in us holding a 45% non-controlling interest in
TPI with the remaining interest holder in TPI being ACR with a 10% interest. At this time the
licence position with regard to the Akkulka exploration area was subject to review by the Kazakh
authorities and further negotiation was required to secure this. In addition the Kyzyloi
production contract had not been signed and certain clarification was required with regard to
registration of BNM.
TPI and BNM subsequently negotiated a two year extension on the Akkulka Exploration Contract,
and a further two year extension was negotiated last year. On June 8, 2004, we announced that that
deal was finalized with the registration with the Kazakh authorities of TPI’s interest in BNM, and
the Kyzyloi Production Contract was signed in May 2005.
On June 7, 2005, we announced that we had acquired the remaining 55% of TPI by way of a share
exchange with the other owners of TPI and TPI had accordingly become a wholly owned subsidiary of
the CanArgo Group.
On March 3, 2006, we announced the finalisation of a $13 million private placement of Senior
Subordinated Convertible Guaranteed Notes due September 1, 2009 the net proceeds of which are to be
used to fund the development of TPI’s assets in Kazakhstan. The noteholders have the right (as an
alternative to conversion into CanArgo common stock) for a period of one year from closing (or, if
later, until the consent of CanArgo’s Senior Noteholders is obtained), to convert their notes into
up to a 25% equity interest in TPI.
BNM’s interest centers on the Akkulka area, a 411,922 acre (1,667 Km2) exploration
area and the shallow Kyzyloi Gas Field, both located in the North Ustyurt basin in southern
Kazakhstan some 41 miles (65 Kms) to the north of the border with the Karalkalpak region of
Uzbekistan and 34 miles (55 Kms) to the north-west of the Aral Sea. In the four years prior
to our ownership interest, BNM had drilled two deep exploration wells in the Akkulka area, which
they plugged and abandoned with minor hydrocarbon shows. The original term of the Exploration
Contract was until 17 September 2003, but an extension until September 2005 was agreed, and at that
time a further extension until 17 September 2007 was agreed by the Expert Commission, subject to
modification to the Contract.
On the Kyzyloi Gas Field a development program is underway. The Kyzyloi Field Contract covers
a 70,919 acre (287 Km2) area. The original licence was issued in June 1997 to Kazakgas,
as state entity, and acquired by BNM in 2001 with an initial term until June 2007. In January 2005
the Ministry of Energy and Mineral Resources agreed to extend the period of production on Kyzyloi
to June 2014, subject to modification to the Contract, and the Production Contract itself was
signed and registered on May 6, 2005.
The field contains sweet natural gas (97% methane) reservoired in shallow sandstones at a
depth of approximately 1,640 feet (500 meters) which was discovered, but not developed, during the
1960’s. This field is located close to the Bukhara-Urals gas trunkline, and to the south of the Bozoi gas storage
facility. BNM is involved in an extensive workover and testing program of wells on the field, with
the last well in the program, KYZ109 now in the process of being tested. The six wells tested to
date for the initial development have flowed at a cumulative rate of over 24 million cubic feet
(688,000 cubic meters) of gas per day. A 33 mile (53 Km) pipeline will be constructed to connect
the Kyzyloi development to the Bukhara-Urals gas trunkline, with the initial planned production
rate being 17.7 million cubic feet (500,000 cubic meters) per day and with first gas planned for
late
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summer 2006. BNM believes that there is significant additional potential both in the Kyzyloi
Field and in its surrounding Akkulka exploration contract area. As such the pipeline and
associated facilities are being designed such that they could be upgraded to throughput up to 78
million cubic feet (2.2 million cubic meters) per day of gas
production. BNM is currently funded through loan agreements with
TPI’s wholly owned subsidiary, Tethys Kazakhstan Limited.
In January 9, 2005 we announced that BNM had executed a natural gas supply contract with Gaz
Impex S.A. LLP (“Gaz Impex”) relating to gas sales from the Kyzyloi Gas Field. The contract, which
has a term until June 2014, is based on a take-or-pay principle and covers all gas produced from
the Kyzyloi Field Production Contract area. Gas will be supplied to Gaz Impex at a tie in point to
the Bukhara-Urals gas trunkline via the pipeline to be constructed between the field and the
trunkline. The price of gas to be supplied at the tie in point averages $1.13 per thousand cubic
feet ($32 per thousand cubic meters) over the life of the contract, with Gaz Impex providing bank
guarantees against payment. We believe that this is one of the first take-or-pay contracts signed
in Kazakhstan for a dedicated dry gas development. Gaz Impex is one of the leading gas marketing
companies in Kazakhstan, and is currently involved with gas purchase and supply contracts both
within Kazakhstan and in surrounding countries. Previously in October 2005, we announced the
execution of a Memorandum of Understanding covering co-operation in the gas sector in Kazakhstan
with Gaz Impex.
A five well exploration program targeting shallow gas anomalies which may be similar to the
Kyzyloi Field is underway within the Akkulka Licence area with two new discoveries having already
been made. The AKK04 exploration well, located some 12.5 miles (20 Km) east of the Kyzyloi Field,
flowed gas at a stabilized flow rate of 8.8 million cubic feet (250,000 cubic meters) of gas per
day, and AKK05 (now named North-East Kyzyloi), located 4 miles (6.5 Km) north east of the Kyzyloi
Field, flowed gas at a rate of 8.2 million cubic feet (233,000 cubic meters) per day. It is
planned to apply for an extension to the Kyzyloi Field Production Contract to include the AKK05
discovery, and to tie the AKK04 discovery into the Kyzyloi development, initially by way of a long
term extended well test, but then by the application for a separate production contract, once the
AKK04 discovery has been fully evaluated.
In the other two exploration wells which have been drilled to date, AKK02 and AKK03, gas
indications have been observed during drilling and in thin sands on wireline logs. These wells lie
to the south east of the Kyzyloi Field, and may have encountered another gas deposit. It is
planned to test these wells as part of an integrated testing program, but operations have been hampered by weather
conditions. The next exploration well, AKK01 should commence once a rig is available from the
Kyzyloi development program.
Initial work is now completed on a geophysical remapping of the Akkulka exploration block.
This work has confirmed the presence of several potential shallow gas prospects (some of which are
being drilled in the current drilling program), and also some potentially large prospects at
Jurassic/Triassic levels. Regional geological studies suggest that these deeper prospects could
have potential for gas condensate or oil deposits.
In November 23, 2005 we announced that BNM had completed the acquisition of a 100% interest in
the Greater Akulka Exploration Contract. This contract, which is for a period of 25 years from
2005, with an initial six year exploration period, covers an area of approximately 2.75 million
acres (11,133 Km2) surrounding the Akkulka area. BNM considers that this area has
substantial exploration potential, with extensions of the shallow gas exploration targets and
deeper Mesozoic plays. This large area within a proven hydrocarbon system, has potential towards
the south and east (towards the Aral Sea), where the Paleogene sand sequence is thought to become
thicker and of better quality, and towards the west and north where potential may exist for
stratigraphic and pinch-out plays.
Refining and Other Activities
We
also have engaged in other oil and gas activities in Georgia and
elsewhere. Discontinued
Operation activity is incorporated herein by reference from note 20 to the consolidated financial
statements.
Georgian American Oil Refinery
As the Georgian American Oil Refinery (“GAOR”) remained in a care and maintenance condition
during 2003
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with little prospect of the plant being returned to a commercially viable operation, we
came to an agreement to sell the refinery and we disposed of our 51% interest in GAOR 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 our plan to dispose of the asset.
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. This equipment is currently being used by our operator company to drill exploration
wells and provide support to our development work on the Ninotsminda Field and on the Manavi and
Norio discoveries.
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 we concluded that we did not have the resources
to advance this project. Accordingly, in November 1999, we reduced our interest to 9.5%. Subsequent
to this, a restructuring of interests in the project took place with us increasing our 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, due to our small interest in
this project and our inability to secure an effective joint operating agreement, we have had little
or no control over the operator. As management does not contemplate any further investment in this
project, we fully impaired our $75,000 investment in the Caspian exploration project during the
year ended December 31, 2004.
Discontinued Operations
CanArgo Standard Oil Products
In September 2002, we approved a plan to sell our interest in CanArgo Standard Oil Products
Limited (“CSOP”), a petroleum product retail business in Georgia, to finance our Georgian and
Ukrainian development projects. In October 2002, we reached agreement with Westrade Alliance LLC,
an unaffiliated company, to sell our wholly owned subsidiary, CanArgo Petroleum Products Limited
(“CPPL”), which held our 50% interest in CSOP for $4,000,000 in an arms-length transaction, with
legal ownership being transferred upon receipt of final payment due in originally in August 2003
and subsequently extended. The final payment of the consideration was received by us in December
2004 at which time we transferred our ownership in CPPL to Westrade Alliance LLC. Discontinued
Operation activity is incorporated herein by reference from note 20 to the consolidated financial
statements.
GAOR
In 2003, we approved a plan to dispose of our interest in GAOR as the refinery had remained
closed since 2001 and neither we nor our 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
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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
Lateral Vector Resources Inc. (“LVR”), a wholly-owned indirect subsidiary of CanArgo acquired
by us in July 2001, negotiated and concluded with Ukrnafta, the Ukrainian State Oil Company, a
Joint Investment Production Activity (“JIPA”) agreement in 1998 to develop the Bugruvativske 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. Consequently, we recorded in 2003 a
write-down in respect to the LVR deal and the acquisition of the Bugruvativske Field of
approximately $4,790,727.
On May 28, 2004, we announced that pursuant to a signed agreement between CanArgo Acquisition
Corporation, our wholly owned subsidiary, and Stanhope Solutions Ltd., we had completed a
transaction to sell our interest in the Bugruvativske Field through the disposal of LVR for
$2,000,000. We received $250,000 as an initial payment and will receive the remaining $1,750,000
based upon certain production targets being achieved on the project. As of March 14, 2006, we had
not received any further payments.
We have now effectively withdrawn from Ukraine, in order to focus principally on our Georgian
activities, having disposed previously of our interest in the Stynawske Field in Western Ukraine in
2003. Our interest in the Stynawske Field was sold for $1,000,000 and the buyer has also
acknowledged debts of the joint venture company which operates the field to us for earlier loans in
the total amount of $160,000.
3-megawatt duel fuel power generator
In 2003, we signed a sales agreement disposing of a 3-megawatt duel fuel power generator for
$600,000 and have received a non-refundable deposit of approximately $300,000. The unit was shipped
to the United States where it underwent tests in late 2004. On completion of these tests to the
satisfaction of the buyer, we were to transfer title for this equipment and receive the final
payment of $300,000. Although the unit was successfully tested, the buyer failed to meet the sale
contract terms resulting in the loss of its deposit in the third quarter, 2005. We are currently
remarketing the generator.
Employees
As of December 31, 2005, we had 189 full time employees. Of our full time employees, the
entity acting as operator of the Ninotsminda Field for Ninotsminda Oil Company has 143 full time
employees, and substantially all of that company’s activities relate to the production and
development of the Ninotsminda Field. In Kazakhstan our subsidiary BN Munai LLP currently employs
29 full time employees in Almaty and Aktobe principally involved with work on the Kyzyloi Field
development. We have not experienced any strikes, work stoppages or other labour disputes and
management believes the Company’s relations with its employees are satisfactory.
ITEM 3. LEGAL PROCEEDINGS.
On September 12, 2005, WEUS Holding Inc (“WEUS”) a subsidiary of Weatherford International Ltd
lodged a formal Request for Arbitration with the London Court of International Arbitration against
CanArgo Energy Corporation in respect of unpaid invoices for work performed under the Master
Service Contract dated June 1, 2004 between the Company and WEUS for the supply of under-balanced
coil tubing drilling equipment and services during the first and second quarter of 2005. Pursuant
to the Request for Arbitration, WEUS’ demand for relief is $4,931,332. The Company is contesting
the claim and intends to file a counterclaim.
On July 27, 2005, GBOC Ninotsminda, an indirect subsidiary of the Company, received a claim
raised by certain of the Ninotsminda villagers (listed on pages 1 to 76 of the claim) in the
Tbilisi Regional Court in respect of damage
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caused by the blowout of the N100 well on the
Nintosminda Field in Georgia on September 11, 2004. An additional claim was received in December
2005 thus bringing the relief sought pursuant to both claims to the sum of 32.4 million GEL
(approximately $19.0 million at the exchange rate of GEL to US dollars in effect on December 31,
2005). At a hearing in March 2006 the defendants increased the
amount of damages sought to 50,000 GEL (approximately $29,000) per
defendant, which increased the total claim to approximately $182,000,000.
We believe that we have meritorious defenses to both claims and intend to defend them
vigorously.
The
Company has been named in a legal action commenced in Alberta,
Canada, with a group of defendants by former interest holders of the Lelyakov
oil field in the Ukraine. The defendants are seeking damages of
approx 600,000 CDN
(approx $514,000 at December 31 exchange rates). The former
owners of UK-Ran Oil Corporation
disposed of their investment in the field prior to selling the Company to CanArgo.
CanArgo believes the claim against it to be meritless. The Company is unable at this time
to determine a potential outcome.
Other than the foregoing, as at December 31, 2005 there were no legal proceedings pending
involving the Company, which, if adversely decided, would have a material adverse effect on our
financial position or our 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, 2005.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.
CanArgo is listed on the Oslo Stock Exchange in Norway (“OSE”) where our stock trades under
the symbol “CNR“and also on the AMEX where our common stock trades under the symbol “CNR”. Until
April 21, 2004 our common stock traded on the NASDAQ Over The Counter Bulletin Board (“OTCBB”)
under the symbol “GUSH”.
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 and AMEX 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 and AMEX 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 | AMEX | ||||||||||||||||||||||||||||||||||
| Average | Average | Average | ||||||||||||||||||||||||||||||||||
| Daily | Daily | Daily | ||||||||||||||||||||||||||||||||||
| High | Low | Volume | High | Low | Volume | High | Low | Volume | ||||||||||||||||||||||||||||
Fiscal Quarter Ended |
||||||||||||||||||||||||||||||||||||
March 31, 2004 |
1.22 | 0.48 | 719,195 | 1.22 | 0.44 | 6,378,789 | ||||||||||||||||||||||||||||||
June 30, 2004* |
— | — | — | 1.04 | 0.66 | 2,234,149 | 1.08 | 0.60 | 243,473 | |||||||||||||||||||||||||||
September 30, 2004 |
0.71 | 0.43 | 1,260,468 | 0.74 | 0.47 | 308,636 | ||||||||||||||||||||||||||||||
December 31, 2004 |
1.23 | 0.69 | 2,929,357 | 1.32 | 0.67 | 1,120,177 | ||||||||||||||||||||||||||||||
March 31, 2005 |
1.98 | 1.08 | 2,296,436 | 1.94 | 1.06 | 2,396,215 | ||||||||||||||||||||||||||||||
June 30, 2005 |
1.47 | 0.69 | 3,058,647 | 1.48 | 0.66 | 1,589,495 | ||||||||||||||||||||||||||||||
September 30, 2005 |
2.18 | 0.79 | 5,691,163 | 2.25 | 0.69 | 1,645,733 | ||||||||||||||||||||||||||||||
December 31, 2005 |
1.85 | 1.09 | 3,689,260 | 1.86 | 1.15 | 1,287,433 | ||||||||||||||||||||||||||||||
| * | The Common Stock ceased trading on the OTCBB and began trading on the AMEX on April 21, 2004. The amounts reflected for the June 30, 2004 fiscal quarter include the trading results on both the OTCBB and the AMEX for the entire quarterly period. |
At March 10, 2006, the closing price of our common stock on the AMEX and the OSE was $ 1.12
and $ 1.06, respectively. On March 10, 2006 one U.S. dollar equalled 6.73 Norwegian kroner.
On March 10, 2006 the number of holders of record of our common stock was approximately
14,000. 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 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.
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ITEM 6. SELECTED FINANCIAL DATA.
Reference is hereby made to the Section entitled “CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS” 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.
| Year Ended | ||||||||||||||||||||
| Reported in $000’s except for per common share amounts | December 31, | |||||||||||||||||||
| 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
Financial Performance |
||||||||||||||||||||
Operating revenues from continuing operations |
7,582 | 9,574 | 8,105 | 5,486 | 4,575 | |||||||||||||||
Operating loss from continuing operations |
(11,009 | ) | (2,954 | ) | (159 | ) | (4,902 | ) | (11,838 | ) | ||||||||||
Other income (expense) and Minority Interest in
income (loss) of consolidated subsidiaries |
(1,327 | ) | (2,346 | ) | (597 | ) | (576 | ) | 525 | |||||||||||
Net loss from continuing operations |
(12,335 | ) | (5,300 | ) | (756 | ) | (5,478 | ) | (11.313 | ) | ||||||||||
Net income (loss) from discontinued operations,
net of taxes and minority interest (1) |
— | 542 | (6,608 | ) | 150 | (1,905 | ) | |||||||||||||
Cumulative effect of change in accounting policy |
— | — | 41 | — | — | |||||||||||||||
Net loss |
(12,335 | ) | (4,758 | ) | (7,323 | ) | (5,328 | ) | (13,218 | ) | ||||||||||
Net loss per common share – basic and diluted
before cumulative effect of change in
accounting principle from continuing operations |
(0.06 | ) | (0.04 | ) | (0.01 | ) | (0.06 | ) | (0.14 | ) | ||||||||||
Net loss per common share – basic and diluted
before cumulative effect of change in
accounting principle from discontinued
operations |
(0.06 | ) | (0.04 | ) | (0.07 | ) | (0.00 | ) | (0.02 | ) | ||||||||||
Net loss per common share – basic and diluted |
(0.06 | ) | (0.04 | ) | (0.08 | ) | (0.06 | ) | (0.16 | ) | ||||||||||
Cash generated by (used in) operations |
(4,651 | ) | (3,781 | ) | 4,431 | 1,635 | (6,289 | ) | ||||||||||||
Working capital |
15,078 | 23,952 | 3,890 | 10,646 | 14,590 | |||||||||||||||
Total assets |
147,448 | 105,160 | 73,360 | 70,736 | 70,312 | |||||||||||||||
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| Year Ended | ||||||||||||||||||||
| December 31, | ||||||||||||||||||||
| Reported in $000’s except for per common share amounts | 2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||
Minority shareholder advances |
— | — | — | -- 4 | 50 | |||||||||||||||
Stockholders’ equity |
107,849 | 96,821 | 56,708 62, | 105 | 65,800 | |||||||||||||||
Cash dividends per common share |
— | — | — | -- - | — | |||||||||||||||
| (1) | In September 2002, CanArgo approved a plan to sell CSOP 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 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 CSOP have been classified as “Assets held for sale” and “Liabilities for sale” for all periods presented. The results of operations of CSOP have been classified as discontinued for all periods presented. The minority interest related to CSOP has not been reclassified for any of the periods presented, however net income from discontinued operations is disclosed net of taxes and minority interest. |
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 “Caurtionary Statement
Regarding Forward-Looking Statements” 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.A
“Risk Factors” may have a significant impact on our future financial condition and results of
operations. The following should be read in conjunction with the audited financial statements and
the notes thereto included herein.
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 and licence 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 5.499 MMbbl down 12%
from 2004’s 6.271 MMbbl. Over the same period, gross total
proved natural gas reserves
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increased from 2.620 billion cubic feet to 35.196 billion cubic feet, primarily with the addition of
the Kyzyloi Field in Kazakhstan.
Because our proved reserves will decline as crude oil and natural gas and natural gas liquids
are produced 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.
Exploitation and Development Activity
Ninotsminda
In June, 2004 we signed a contract with WEUS Holding Inc., a subsidiary of Weatherford
International Ltd (“Weatherford”), for the supply of Under Balanced Coiled Tubing Drilling
(“UBCTD”) services to our projects in Georgia. Under the terms of the contract, Weatherford were to
supply and operate a UBCTD unit to be used on a program of up to 14 horizontal wellbores on our
Ninotsminda and Samgori Fields. Elsewhere in the oil industry, the use of under balanced drilling
techniques has been shown to result in significantly less formation damage, resulting in higher
sustained production rates and ultimate recovery. At the same time, utilisation of coiled tubing
drilling gives greater flexibility in the drilling process and in the control of the horizontal section. It
was considered that these combined drilling technologies would provide the best way to develop and
produce both the Ninotsminda and Samgori Fields.
We planned to drill at least five under balanced horizontal sidetracks on the Ninotsminda
Field including: N22H: N30H: a second horizontal well, N100H2 – east horizontal, from the N100
well bore (which achieved good rates of production when drilled horizontally with conventional
techniques and which was later the subject of a blow out in September 2004); N49H: N97H, and a new
well (N99) designed so as to have more than one horizontal wells drilled from it. The N99 well was
planned for the eastern part of the Field, an area that is currently largely undeveloped.
UBCTD operations started on the first well in the program, the N22H well, in December 2004.
The well is located in the east part of the Ninotsminda Field where the reservoir is tighter but it
is believed to be relatively un-drained. We prepared the well with our own crew which involved
sidetracking from the existing well-bore at 8,661 feet (2,640 meters) down to 9,193 feet (2,802
meters) and setting a 41/2 inch liner. Weatherford commenced operations in December 2004, however
technical problems with the Weatherford equipment caused a number of delays which resulted in the
under balanced drilling not being completed until late February, 2005 with a much shorter than
planned section being drilled, and the well not achieving its objective, despite flowing gas at
reported high rates through the gas cap section.
Subsequent operations by Weatherford on both N100H2 and N49H wells also proved unsuccessful,
with Weatherford failing to drill any horizontal section in these wells. Progress was hampered by
multiple failures of the downhole motors, other equipment malfunctions and the loss of bottom hole
assemblies in the wells.
Following the failure of Weatherford to successfully complete any horizontal sidetrack
development wells on the Ninotsminda Field using UBCTD technology, Weatherford demobilized its
equipment and left Georgia in July 2005. Despite this lack of success, which we attribute mainly
to multiple equipment failures, we still believe that under-balanced technology is an appropriate
technology for the development of this type of reservoir. In this respect, we continue to
investigate the potential of bringing an alternative supplier of such equipment and services to
Georgia.
In the meantime, we have continued with our jointed pipe drilling operations using our own
rigs and equipment and the directional drilling services of Baker Hughes International to drill
horizontal sidetrack wells on the Ninotsminda Field. On October 27, 2005 we reached total depth
(“TD”) on the first sidetrack, the N100H2 well. The well was completed in the Middle Eocene
reservoir at approximately 8,659 feet (2,640 meters) TVD (True Vertical Depth) having drilled a
horizontal section of 1,667 feet (508 meters). A pre-perforated liner was run over a 1,421 foot
(433 meters) interval in the horizontal section and was tested at a rate of up to 13.07 million
cubic feet
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(370,000 cubic meters) of gas per day plus 301 barrels of condensate per day (a total of
2,480 barrels oil equivalent1) on a 63/64 inch (25 mm) choke with a flowing tubing head
pressure (FTHP) of 70 atmospheres (1,000 psig). The horizontal section is located in the uppermost
part of the oil zone, close to the gas-oil contact, and a permeable interval was encountered in the
build up section within the lower part of the gas cap. It is expected that the proportion of liquid
hydrocarbon production will rise over time. The well is currently choked back as we await
completion of repairs by the state oil company, Georgian Oil, to the 22.4 mile (36 Km) pipeline
which it is planned will deliver the gas from Ninotsminda to the local State-run thermal
electricity generating station at Gardabani. Terms have been agreed with the government for a gas
supply agreement from the Ninotsminda Field and it is expected that an agreement will be signed in
the near future.
In November 2005, we announced that operations had commenced on the next horizontal sidetrack
well on the Ninotsminda Field, N97H. This sidetrack was more complicated than the N100H2 well as it
is located on the northern flank of the field and it was be necessary to first sidetrack the well
from a much shallower level towards the crest of the field before the horizontal section could be
drilled through the reservoir in a westerly direction along the crest of the structure. The well
was drilled by us using our own rig and equipment while utilising directional equipment and
services provided by Baker Hughes. In February 2006 we announced that drilling been completed with
a 1,725 feet (534 meter) horizontal section having been drilled through the Middle Eocene reservoir and a
1,490 feet (454 meter) slotted production liner run. The wall is currently being tested.
In 2006, on completion of the N97H sidetrack, we plan to drill two further horizontal
sidetrack wells from the N49 and N46 wells. We have budgeted approximately $6 million for such
development work on the nInotsminda Field in 2006.
Kyzyloi
On the Kyzyloi Gas Field a development program is underway. BNM is involved in an extensive
workover and testing program of wells on the field, with the last well in the program, KYZ109 now
in the process of being tested. The six wells tested to date for the initial development have
flowed at a cumulative rate of over 24 million cubic feet (688,000 cubic meters) of gas per day. A
33 mile (53 Km) pipeline will be constructed to connect the Kyzyloi development to the
Bukhara-Urals gas trunkline, with the initial planned production rate being 17.7 million cubic feet
(500,000 cubic meters) per day and with first gas planned for late summer 2006. BNM believes that
there is significant additional potential both in the Kyzyloi Field and in its surrounding Akkulka
exploration contract area. As such the pipeline and associated facilities are being designed such
that they could be upgraded to throughput up to 78 million cubic feet (2.2 million cubic meters)
per day of gas production.
Production from the Kyzyloi Field will be delivered under a natural gas supply contract
concluded between BNM and Gaz Impex in January 2006. The contract, which has a term until June
2014, is based on a take-or-pay principle and covers all gas produced from the Kyzyloi Field
Production Contract area. The delivery point under the contract will be the planned tie in point
to the Bukhara-Urals gas trunkline. The price of gas at the delivery point averages $1.13 per mcf
($32 per MCM) over the life of the contract, with Gaz Impex providing bank guarantees against
payment.
BNM plans to invest $10.8 million in the Kyzyloi development in 2006.
If crude oil and, to a lesser extent, natural gas prices return to depressed levels or if our
production from our development program does not deliver a significant production increase, our
revenues, cash flow from operations and financial condition will be materially adversely affected.
For more information, see “Liquidity and Capital Resources”.
| 1 | using 6,000 cubic feet of gas = 1 barrel of oil/condensate |
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Exploration and Appraisal
Manavi
Attempts to recover the damaged tubing from the M11 original oil discovery well on the Manavi
structure were unsuccessful and in late 2004 we commenced a sidetrack to this well. Despite an
upgrade to our drilling equipment which included more powerful mud pumps and bicentrical drilling
bits we continued to encounter drilling problems due to the extremely over-pressured swelling clays
above the reservoir intervals. After extensive technical analysis and discussions with the
international drilling contractor Saipem S.p.A. (“Saipem”), and Baker-Hughes International, a major
drilling mud company, it was decided that the optimum way to sidetrack this well to the top of the
reservoir as planned was to use an oil-based mud system (to control the swelling clays) on the
Sapiem Ideco E-2100Az drilling rig (which is equipped with a top-drive drilling system and can use
an oil-based mud system unlike our current Ural-Mash rig). Service contracts were subsequently
concluded with Saipem to provide a rig and drilling services to the company and with Baker-Hughes
for the provision of an oil-based mud system.
On August 26, 2005 we announced that the Manavi M11Z well had reached a total depth (TD) of
14,994 feet (4,570 meters) measured depth (MD) in the Cretaceous. The well was completed in the
Cretaceous using slim-hole drilling technology due to the small size of the casing from which the
well was sidetracked. The primary Cretaceous limestone target was encountered at 14,032 feet
(4,277 meters) MD some 230 feet (70 meters) MD higher than in the original M11 well while the secondary Middle Eocene target zone was penetrated at 13,009 feet
(3,965 meters) MD again significantly higher than in the M11 well. Drilling data and slim hole
wireline logs indicate the presence of hydrocarbons in both the Cretaceous and Middle Eocene target
zones.
On October 6, 2005 we announced that we had commenced testing operations on M11Z. A
pre-perforated 27/8 inch (73mm) liner was run in the slim hole, and the Saipem drilling
rig removed from the site while CanArgo Rig #1 was mobilized to the location for testing
operations. During initial testing operations it emerged that the section of the liner adjacent to
the cretaceous limestone interval had become differentially stuck probably due to a build up of
filter cake on and in the formation during drilling which is in itself indicative of a permeable
zone. Although small amounts of oil and gas have been recovered from the well, no significant flow
was achieved during the initial testing. Despite efforts to wash the mixture of drilling fluid and
carbonate from the well bore using coiled tubing, it was not possible to clean out the formation
and it appears that the Cretaceous limestone formation has been blocked and is not in communication
with the wellbore at this time.
Schlumberger well completions experts
were consulted who advised that the best techniques with
which to re-establish communication with the formation in the well by removing near-wellbore damage
is through the application of acid using coiled tubing, and if necessary perforate. Currently it is planned
to carry out an acid stimulation and complete the well test
using a Schlumberger supplied coiled-tubing unit, pumping equipment and completion fluids. The
delay in testing this well has been due to the difficulty in sourcing a coil tubing unit to
Georgia. It is expected that testing will re-commence in the M11Z well during April 2006.
We have identified
further appraisal locations on the Manavi structure. Drilling
operations at the first appraisal site, M12 using
the Saipem rig commenced on February 9, 2006. 20 inch (508 mm) casing has now been set and the well is currently
operating in 17 ½ inch (445 mm) hole section. The well is located
approximately 2.5 miles (4 Km) to the west of the M11 discovery well. CanArgo rig #2 was used to
spud the well and drill the surface casing section to a depth 1,302 feet (397 meters) whilst Saipem
completed operations on the MK72 well. M12 has a planned total depth of 15,092 feet (4,600
meters), and is expected to be completed in the summer of 2006.
Given significant production is tested from either the M11Z or the M12 wells, these wells
would be placed on long term test production which would involve putting in place an early
production facility.
Norio
On May 9, 2005 we announced that our subsidiary CNL had signed final documentation with
Georgian Oil for CNL to secure 100% of the contractor share in the Norio PSA. On May 20, 2005 we
paid Georgian Oil $1,758,000 to terminate their farm in agreement to the PSA and secured a 100%
working interest in the Norio PSA and so
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enabled us to move forward with the completion of the MK72
exploration well. Operations had been suspended in 2004 when Georgian Oil were not able to finance
the drilling of the well under their September 2003 farm in obligations.
In late June 2005, we recommenced drilling operations on the suspended MK72 well and on August
26 we announced that the Saipem Ideco E-2100Az drilling rig and Baker-Hughes oil-based mud system
was being mobilized to the MK72 Norio exploration well. Our Ural Mash Rig had difficulty drilling
through a highly over-pressured section of swelling clays above the prognosed target zone and as
the Saipem Rig with its oil-based mud system had successfully drilled through a similar section in
the M11Z well, it was considered that this afforded the best option to completing the well. MK72
was sidetracked and successfully drilled through the over-pressured section encountering the top of
the Middle Eocene primary target zone at 15,787 feet (4,812 meters). A 5 inch (127 millimetre)
liner was run to 15,899 feet (4,846 meters) before drilling ahead through the reservoir using slim
hole technology.
On December 29, 2005 we announced that the MK72 well reached a depth of 4,900 meters (16,076
feet) in the Middle Eocene reservoir having encountered very good oil and gas shows. Gas levels up
to 21% were recorded at surface, as well as light oil in the mud and hydrocarbon fluorescence in
the cuttings samples. Inflow was observed and it appeared that the small diameter hole collapsed
around the bit. Although it may have been possible to mill down the BHA and to sidetrack the hole,
the small hole diameter and unstable hole conditions meant that there was a high risk that such an operation would not be successful and could take an indeterminate time.
As such it was decided to plug back the lower part of the hole and to concentrate on testing the
oil-bearing Oligocene sands which were the secondary target for the well. From the data obtained
from the Middle Eocene (the primary target for the well) we believe that an oil discovery has been
made at this level, and that the reservoir has exhibited both permeability and the presence of
movable light oil. As such, even though the Middle Eocene has not been fully evaluated, the MK72
well has encountered the Middle Eocene reservoir on prognosis, and with hydrocarbons thus achieving
many of the objectives of this wildcat exploration well.
The lower section of the well has now been plugged back and the Saipem rig has been moved to
the M11 appraisal location while the CanArgo rig #2 has been mobilised to the MK72 well location in
preparation for the testing of the Oligocene sand interval. High penetration tubing conveyed and
through tubing perforating guns have been imported from the United States for the test program. Ten
separate zones of interest between 12,057 feet (3,675 meters) MD and 13,337 feet (4,065 meters) MD
have been selected for testing. The lowermost zone, a 10 feet (3 meter) interval below the primary
test zones has now been perforated, primarily to give formation pressure data for the main tests which are expected to commence shortly.
Given significant production is tested, the well would be placed on long term test production.
In 2006, we have budgeted approximately $12.5 million for our exploration and appraisal work in
Georgia, primarily for the appraisal of the Manavi discovery.
Akkulka
A five well exploration program targeting shallow gas anomalies which may be similar to the
Kyzyloi Field is underway within the Akkulka Licence area with two new discoveries having already
been made. The AKK04 exploration well, located some 12.5 miles (20 Km) east of the Kyzyloi Field,
flowed gas at a stabilized flow rate of 8.8 million cubic feet (250,000 cubic meters) of gas per
day, and AKK05 (now named North-East Kyzyloi), located 4 miles (6.5 Km) north east of the Kyzyloi
Field, flowed gas at a rate of 8.2 million cubic feet (233,000 cubic meters) per day. It is
planned to apply for an extension to the Kyzyloi Field Production Contract to include the AKK05
discovery, and to tie the AKK04 discovery into the Kyzyloi development, initially by way of a long
term extended well test, but then by the application for a separate production contract, once the
AKK04 discovery has been fully evaluated.
In the other two exploration wells which have been drilled to date, AKK02 and AKK03, gas
indications have been observed during drilling and in thin sands on wireline logs. These wells lie
to the south east of the Kyzyloi Field, and may have encountered another gas deposit. It is
planned to test these wells as part of an integrated testing program in the near future but
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operations have been hampered by weather
conditions. The next exploration well, AKK01 should commence once a rig is available from the
Kyzyloi development program.
Initial work is now completed on a geophysical remapping of the Akkulka exploration block.
This work has confirmed the presence of several potential shallow gas prospects (some of which are
being drilled in the current drilling program), and also some potentially large prospects at
Jurassic/Triassic levels. Regional geological studies suggest that these deeper prospects could
have potential for gas condensate or oil deposits.
We have budgeted $3.3 million for exploration work in Kazakhstan in 2006, primarily for
exploration drilling on shallow gas targets in the later part of the year.
While a considerable amount of infrastructure for the Ninotsminda Field has already been put
in place, and although tested gas wells exist on the Kyzyloi Field we cannot provide assurance
that:
| • | funding of the development plan for the Fields will be timely; | ||
| • | that the development plan will be successfully completed or will increase production; or | ||
| • | that operating revenues from the Fields after completion of the development plan will exceed operating costs. |
To pursue existing projects beyond our immediate development plan and to pursue new
opportunities, we 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 our projects. Based on our 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; we may
have to delay or abandon such projects.
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 our oil and gas
properties and ventures will require the availability of substantial additional financing from
external sources. We may also, where opportunities exist, seek to transfer portions of our
interests in oil and gas properties and ventures to entities in exchange for such financing. We
generally have the principal responsibility for arranging financing for the oil and gas properties
and ventures in which we have an interest. There can be no assurance, however, that we 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 our corporate and other
activities. 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 our 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 us. 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. |
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,
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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, 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 10, 2006, the Company had an aggregate of 224,108,606 shares of common stock
issued and outstanding and 300,000,000 authorized shares of common stock. During 2005, we issued
27,374,778 shares of which 13,012,945 shares were in connection with the Standby Equity
Distribution agreement with Cornell Capital, 11,000,000 shares were in connection with the Tethys
acquisition, 3,281,833 shares were in connection with exercise of stock options and 80,000 were in
connection with a consultancy agreement related to investor relations services. During 2006, we
have issued 1,521,739 shares of our common stock in connection with the conversion of a Convertible
Loan. As of March 14, 2006, an aggregate of 62,844,598 shares are reserved for issuance under
various stock option plans, warrants and other contractual commitments, including the Senior Secured Notes and the Subordinated
Notes.
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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, 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. 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 and 2004 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 as we did with our acquisition of a 50% interest in the Samgori Field in 2004
or identify additional behind-pipe zones or secondary recovery reserves.
Should our current exploration, exploitation and development wells in Georgia prove
unsuccessful and we were unable to raise additional debt or equity finance, we might have to cut
back on our capital spending plans and or modify our operating plans to conserve cash.
As of December 31, 2005, we had working capital of $15,078,000, compared to working capital of
$23,952,000 as of December 31, 2004. The $8,874,000 decrease in working capital from December 31,
2004 to December 31, 2005 is principally due to expenditures in the period to fund the cost of
preparing wells for our horizontal development program at the Ninotsminda Field, the appraisal of
our Manavi oil discovery in Georgia, further drilling of the Norio exploration well, activities in
Kazakhstan and net cash used by operating activities partially offset by cash received pursuant to
the takedowns under the SEDA and the Senior Secured Notes.
In May 2004, NOC entered into a crude oil sales agreement with Primrose Financial Group
(“PFG”) to sell its monthly share of oil produced under the Ninotsminda production sharing contract
with a total contractual commitment of 84,000 metric tonnes (636,720 bbls) (“Sales Agreement”). As
security for payment and having the right to lift up to 8,400 metric tonnes (approximately 64,000
bbls) of oil per month, the buyer caused to be paid to NOC $2,300,000 (“Security Deposit”) to be
repaid at the end of the contract period either in money or through the delivery of additional
crude oil equal to the value of the security. The Security Deposit replaces the previous security
payments totalling $2,300,000 which had been originally made available under previous oil sales
agreements.
On February 4, 2005, NOC and PFG agreed to the terminate the Sales Agreement and enter into a
new agreement (“New Agreement”) whereby PFG would receive an immediate repayment of its Security
Deposit and obtain an extended term over which it can purchase crude oil produced from the Ninotsminda Field while NOC
receives better commercial terms for the sale of its production. The New Agreement has a minimum
term of 45 months and contains the following principal terms:
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| (i) | NOC will make available to PFG NOC’s entire share of production from the Ninotsminda Field including a minimum total amount of 68,555 metric tonnes (the “Minimum Contract Quantity”). In the event NOC fails to produce the Minimum Contract Quantity it will have no liability to PFG; | ||
| (ii) | The delivery point shall be at Georgian Oil’s storage reservoirs at Samgori (adjacent to the Ninotsminda Field); | ||
| (iii) | The price for the oil will be in US Dollars per net US Barrel equal to the average of the mean of three quotations in Platts Crude Oil Marketwire© for Brent Dated Quotations minus a discount: ranging for sales (a) up to the Minimum Contract Quantity from $6.00 to $7.50 based on Brent prices per barrel ranging from less than $15.00 to greater than $25.01, respectively; and (b) for sales of oil in excess of the Minimum Contract Quantity at the commercial discount in Georgia for oil of similar quality less $0.10 per barrel with the maximum discount being $6.00 per barrel for export sales and $5.50 per barrel for local sales; and | ||
| (iv) | PFG will pay NOC for the monthly quantity of oil in advance of delivery. |
NOC’s obligations are subject to customary Force Majeure provisions, title and risk of loss
pass to buyer at the delivery point, NOC agrees to assist the buyer to sell the oil locally or
export oil in accordance with applicable law and the Agreement is governed by English law.
Certain Asset Sales
In 2003, we signed a sales agreement disposing of a 3-megawatt duel fuel power generator for
$600,000 and have received a non-refundable deposit of approximately $300,000. The unit was shipped
to the United States where it underwent tests in late 2004. On completion of these tests to the
satisfaction of the buyer, we were to transfer title for this equipment and receive the final
payment of $300,000. Although the unit was successfully tested, the buyer failed to meet the sale
contract terms resulting in the loss of its deposit in the third quarter, 2005. We are currently
remarketing the generator.
On May 28, 2004, we announced that pursuant to a signed agreement between CanArgo Acquisition
Corporation, our wholly owned subsidiary, and Stanhope Solutions Ltd., we had completed a
transaction to sell our interest in the Bugruvativske Field in Ukraine through the disposal of our
wholly owned subsidiary, Lateral Vector Resources, for $2,000,000. We received $250,000 as an
initial payment and will receive the remaining $1,750,000 based upon certain production targets
being achieved on the project.
Financing
On February 11, 2004, we entered into a Standby Equity Distribution Agreement (“SEDA”) that
allowed us, at our option, periodically to issue shares of our common stock to US-based investment
fund Cornell Capital Partners, LP (“Cornell Capital”) up to a maximum value of $20,000,000
(“Cornell Facility”). Under the terms of the SEDA, Cornell Capital provided us with an equity line
of credit for 24 months from the Effective Date (as defined in the SEDA). The maximum aggregate
amount of the equity placements pursuant to the SEDA was $20,000,000. Subject to this limitation,
we could draw down up to $600,000 in any seven-day trading period (a “Put”). The Cornell Facility
could be used in whole or in part entirely at our discretion, subject to effective registration of
the shares under the Securities Act. Shares issued to Cornell Capital were priced at a 3% discount
to the lowest daily Volume Weighted Closing Bid Price (“VWAP”) of CanArgo common shares traded on
the Oslo Stock Exchange (“OSE”) for each of the five consecutive trading days immediately following
a draw down notice by CanArgo. For each share of common stock purchased under the SEDA, Cornell
Capital received a substantial discount to the current market price of CanArgo common stock. The
level of the total discount varied depending on the market price of our stock and the amount drawn down under the SEDA. On the basis of the average high and low price for common stock
as reported on the American Stock Exchange on January 27, 2005 of $1.37, Cornell Capital will
received a total discount of 13.87% to the market price of our stock. Such discount comprised (1)
3% discount to, the lowest volume weighted average price of our common stock; (2) 5% of the
proceeds that we received for each advance under the
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SEDA; and (3) a commitment fee of 5.87%. The
commitment fee, which was paid, consisted of $10,000 in cash (paid in two tranches) and 850,000
shares of our common stock (issued in three tranches). The 850,000 shares of common stock issued in
respect of the commitment fee represented nearly 4% of the estimated 23 million shares of common
stock that could have been issued by us under the SEDA. In February 2004, we engaged Newbridge
Securities Corporation, a registered broker dealer, to advise us and to act as our exclusive
placement agent in connection with the Cornell Facility pursuant to the Placement Agent Agreement dated
February 11, 2004. For its services, Newbridge Securities Corporation received 30,799 restricted
shares of our common stock which were included in the Registration Statement on Form S-3 (Reg. No.
333-115261) filed on May 6, 2004. On February 3, 2005, the SEC declared effective the registration
statement on Form S-3 (Reg. No. 333-115261) originally filed by us on May 6, 2004 in respect of the
shares issuable under the Cornell Facility.
On May 19, 2004, we signed a promissory note with Cornell Capital whereby they agreed to
advance us the sum of $1,500,000. This amount was payable on the earlier of 180 days from the date
of the promissory note or within 60 days from the date that the Registration Statement on Form S-3
was declared effective. If the promissory note was not repaid in full when due, interest accrued on
the outstanding principal owing at the rate of twelve per cent (12%) per annum. At Cornell
Capital’s option any such interest due was to originally be paid either in shares of our common
stock or in cash. However, on December 21, 2004 we entered into a letter of amendment with Cornell
Capital which provided that any sums due in respect of interest accrued on the promissory note
would be paid in cash only. We paid Cornell Capital a commitment fee of five per cent (5%) of the
principal amount of the promissory note which was set off against the first $75,000 of fees payable
by us to Cornell Capital under the Cornell Facility. The promissory note was to become immediately
due and payable upon the occurrence of any of the following: (i) failure to pay the amount of any
principal or interest when due under the promissory note or (ii) if any proceedings under any
bankruptcy laws of the United States of America or under any insolvency, reorganisation,
receivership, readjustment of debt, dissolution, liquidation or any similar law or statute of any
jurisdiction are filed by or against us for all or any part of our property. The proceeds of
advances from Cornell Capital was used by us to order long lead items for our drilling program in
Georgia and for working capital purposes.
On February 21, 2005, we sold 380,836 shares of CanArgo common stock at $1.31 per share under
the Cornell Facility. The proceeds of this sale of $500,000 were used to reduce the promissory note
to Cornell Capital from $1,500,000 to $1,000,000.
On February 28, 2005, we sold 335,653 shares of CanArgo common stock at $1.47 per share under
the Cornell Facility. The proceeds of this sale of $500,000 were used to reduce the promissory note
to Cornell Capital from $1,000,000 to $500,000. The proceeds included additional proceeds
attributable to 5,179 shares of CanArgo common stock issued pursuant to the takedown under the
Equity Line completed on February 21, 2005 proceeds of which should have been credited to us under
the February 21, 2005 draw down.
On March 7, 2005, we sold 344,758 shares of CanArgo common stock at $1.54 per share under the
Cornell Facility. The interest owed on the note of $32,548 was included in the proceeds. The
proceeds of this sale of $500,000 were used to reduce the promissory note to Cornell Capital from
$500,000 to $0.
On March 14, 2005, we sold 370,599 shares of CanArgo common stock at $1.67 per share under the
Cornell Facility. This provided net proceeds of $600,000 to CanArgo.
As at March 14, 2005 we had received $2,102,048 pursuant to 4 takedowns under the Cornell
Facility in which we issued a total of 1,431,846 shares of our common stock to Cornell Capital.
On April 26, 2005 we signed a promissory note with Cornell Capital whereby Cornell Capital
agreed to advance us the sum of $15 million (“Promissory Note”). Pursuant to the terms of the
Promissory Note the $15 million and interest at a rate of 7.5% per annum was repayable either in cash or using the net proceeds of drawdowns
under the SEDA, within 270 calendar days from the date of the Promissory Note. Pursuant to the
terms of the Promissory Note, we escrowed 25 requests for advances under the SEDA each in an amount
not less than $600,000 and one advance of $289,726.03 (representing estimated interest) together
with 16,938,558 shares of CanArgo common stock. As at the agreement date, 664,966 shares were
already in escrow.The escrow agent released requests every 7
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calendar days from May 2, 2005
provided we had not previously made a payment to Cornell Capital in cash. We had the ability at our
sole discretion upon 24 hours prior written notice to Cornell Capital to repay all and any amounts
due under the Promissory Note in immediately available funds and withdraw any advance notices yet
to be effected.
On August 1, 2005, we made a payment of $7,422,410.96 being the outstanding principal and
accrued interest amount payable to Cornell Capital under the terms of both the SEDA and the
Promissory Note. Furthermore, all escrowed advances were cancelled and 7,260,647 shares of CanArgo
common stock were returned from escrow and duly cancelled on October 5, 2005. In accordance with
Section 6 of the Promissory Note, upon receipt of such outstanding sums the Promissory Note was
deemed cancelled. On July 25, 2005 notice was given to Cornell Capital to terminate the SEDA with
effect as of August 24, 2005.
We received $12,332,548 proceeds net of $285,749 of discounts (excluding the commitment fee of
$10,000 and 850,000 shares of common stock previously paid to Cornell Capital) pursuant to twenty
one takedowns under the SEDA in which we issued a total of 13,012,945 shares of our common stock to
Cornell Capital at an average price of $0.9477 per share. From these proceeds, $1,532,548 was used
to repay the promissory note of $1,500,000 plus accrued interest on the note of $32,548 to Cornell
Capital and partially repay the promissory note of $15,000,000.
On July 25, 2005, we announced that we had closed the private placement of a $25,000,000 issue
of Senior Secured Notes due July 25, 2009 with a group of investors arranged through Ingalls &
Snyder LLC of New York City. The proceeds of this financing, after the payment of all professional
and placing expenses and fees estimated at $550,000, have been used to redeem short term debt and
accrued interest in the amount of approximately $7,400,000 under the Promissory Note with Cornell
Capital, to fund our projects in Georgia and to a lesser extent in Kazakhstan. In addition, we
terminated the SEDA which we had with Cornell Capital with effect as of August 24, 2005.
In connection with the placement of the Senior Secured Notes we entered into a Note Purchase
Agreement with a group of private investors (the “Purchasers”), all of whom represented that they
qualified as “accredited investors” under Rule 501(a) promulgated under the Securities Act.
Pursuant to the Note Purchase Agreement, we issued a note due July 25, 2009 in the aggregate
principal amount of $25,000,000 to Ingalls & Snyder LLC, as nominee for the Purchasers, in a
transaction intended to qualify for an exemption from registration under the Securities Act
pursuant to Section 4(2) thereof and Regulation D promulgated thereunder. For purposes hereof each
of the Purchasers is deemed a beneficial holder of the Note and such Purchasers may each be
assigned their own Note as provided in the Note Purchase Agreement and, accordingly, all such Notes
are referred to herein collectively as the “Note” and any such Purchaser or its assignee is
referred to herein as a holder of the Note.
On March 3, 2006, we announced that we had entered into a $13,000,000 private placement with a
small group of accredited investors (“Noteholders”) of Senior Subordinated Convertible Guaranteed
Notes due September 1, 2009 (the “Subordinated Notes”) and two year warrants to purchase an
aggregate of 13,000,000 shares of common stock (“Warrants”).
The Subordinated Notes are convertible in whole or in part into CanArgo common stock at a
price of $1.37 per share, subject to certain anti-dilution adjustments, and will mature on
September 1, 2009. Subject to the consent of the Senior Secured Note holders, CanArgo may call the
Subordinated Notes from March 1, 2007 at an initial price of 105% of par, declining 1% every six
months. Interest will be payable in cash at 3% per annum until December 31, 2006, 10% per annum
thereafter. The Subordinated Notes are subordinated to CanArgo’s existing issue of Senior Secured
Notes and guaranteed on a subordinated basis by CanArgo’s material subsidiaries.
The Warrants are exercisable in whole or in part for CanArgo common stock at an exercise price
of $1.37 per share, subject to adjustment. The expiration date of the Warrants may be accelerated
at CanArgo’s option in the event that the Manavi M12 appraisal well in Georgia (which is currently being drilled) indicates, by way
of an independent engineering report, sustainable production potential, if developed, in excess of
7,500 barrels of oil per day.
The proceeds are to be used to fund the development of the Kyzyloi Gas Field in Kazakhstan and
on the commitment exploration programs in Kazakhstan through Tethys Petroleum Investments Limited
(“Tethys”), the wholly owned subsidiary of CanArgo which holds CanArgo’s Kazakhstan assets.
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The Subordinated Note holders will have the right (as an alternative) until March 3, 2007 (or
until 30 days after receipt of the consent of the Senior Secured Note holders is obtained if such
conversion is prevented under the terms of the Senior Secured Notes) into shares of common stock of
Tethys, with a nominal value of £0.10 per share at a conversion price per share based on a formula
determined by dividing the sum of $52 million plus the amount of any unreimbursed amounts advanced
by the Company to Tethys by 100,000 in the Subordinated Note holders’ Relevant Percentages (as
defined in the Note Purchase Agreement). At the time of any Tethys conversion any further advances
(in excess of the $13 million) from CanArgo to Tethys may be, at CanArgo’s discretion, either
repaid, or converted into Tethys equity based on a valuation of $52 million with the Subordinated Note holders having
the ability to maintain their equity position by providing further funding on a pro-rata basis.
Predicted cash flows from our Georgian operations together with the proceeds of the private
placement of a $25,000,000 issue of Senior Secured Notes (detailed above) and proceeds of the
private placement of a $13,000,000 issue of Subordinated Notes
(detailed above) means we believe that we have the
working capital necessary to cover our immediate and near term funding requirements with respect to
our currently planned development activities in Georgia on our Ninotsminda Field and the
currently drilling Manaui appraisal well, and our initial development plans in the
Kazakhstan, absent any unforeseen circumstances including lower than expected production levels or overuns.
Working Capital
At December 31, 2005, our current assets of approximately $28.2 million exceeded our current
liabilities of $13.1 million resulting in a working capital surplus of approximately $15.1 million.
This compares to a working capital surplus of $24.0 million as of December 31, 2004. Current
liabilities as of December 31, 2005 consisted of (in the following approximate amounts) trade
payables of $5.7 million, $1.0 million promissory note, and accrued liabilities of $6.4 million.
Capital Expenditures
Capital expenditures in cash in 2005, 2004 and 2003 were $33.5 million, $11.2 million and $5.3
million, respectively. The table below sets forth the components of these capital expenditures for
the three years ended December 31, 2005 2004 and 2003.
| December 31, | ||||||||||||
| Expenditure category: | 2005 | 2004 | 2003 | |||||||||
Development |
$ | 13,839,580 | $ | 6,588,137 | $ | 5,200,614 | ||||||
Exploration |
15,316,075 | 1,757,010 | (328,998 | ) | ||||||||
Facilities and other |
4,294,928 | 2,845,143 | 411,772 | |||||||||
Total |
33,450,583 | 11,190,290 | 5,283,388 | |||||||||
The negative expenditures recorded in “Exploration” in 2003 is a result of a prior year
reclassification.
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During 2005, 2004 and 2003 capital expenditures were primarily for the development and
exploration of existing properties. We currently have a contingent planned minimum capital
expenditure budget of $33 million subject to financing being
available for 2006, of which $20 million is allocated to our Georgian development and appraisal projects and $13 million is allocated
to our Kazakhstan projects. During 2006, we plan to participate in the drilling of up to three
horizontal wellbores on the Ninotsminda Field, complete the testing of the Manavi appraisal well,
M11Z, drill one appraisal well on the Manavi structure, and test the Oligocene oil
discovery in the Norio MK72 exploration well. 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 the
results of our development and appraisal programs, 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.
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, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Net cash generated (used in)
operating activities |
$ | (8,268,790 | ) | $ | (3,781,078 | ) | $ | 4,430,922 | ||||
Net cash used in investing activities |
(33,696,496 | ) | (9,967,084 | ) | (3,228,768 | ) | ||||||
Net cash provided in financing |
35,888,797 | 34,771,028 | 875,325 | |||||||||
Net cash flows from assets and
liabilities held for sale |
— | 121,929 | (190,227 | ) | ||||||||
Total |
(6,076,489 | ) | 21,144,795 | 1,887,252 | ||||||||
Operating activities for the year ended December 31, 2005 used $8.3 million of cash.
Investing activities used $33.7 million during 2005. Financing activities provided us $35.9
million during 2005. These funds will be used primarily to continue to fund and develop our
Georgian and Kazakhstan projects. In 2005, cash used in operating activities was used principally
for production purposes on the Ninotsminda and Samgori Fields in Georgia and to fund selling,
general and administrative overhead. In 2005, cash used in investing activities was due to capital
expenditures principally in Georgia ($27.8 million), capital expenditures in Kazakhstan ($4.2
million) and prepaid expenditures relating to our Georgian and Kazakhstan projects ($0.9m).
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Future Capital Resources
We will have four principal sources of liquidity going forward: (i) cash on hand, (ii) cash
from operating activities, (iii) industry participation in our projects, and (iv) 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 further private placements,
however, our ability to secure additional debt financing is restricted under the terms of our
Senior Secured and Subordinated Notes.
Balance Sheet Changes
All balances represent results from continuing operations, unless disclosed otherwise.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Cash and cash equivalents decreased $6,076,000 from $24,617,000 at December 31, 2004 to
$18,541,000 at December 31, 2005. The decrease was primarily due to expenditures in the period to
fund the cost of preparing wells for our horizontal development program at the Ninotsminda and
Samgori Fields, the appraisal of our Manavi oil discovery in Georgia, further drilling of the Norio
exploration well, activities in Kazakhstan and net cash used by operating activities partially
offset by cash received pursuant to the takedowns under the SEDA and the Senior Secured Notes.
Restricted cash increased to $3,182,000 at December 31, 2005 from $1,400,000 at December 31,
2004 due to the funding of a certificate of deposit to secure the issuance of letters of credit as
required under the rig rental and drilling contracts we entered into with Saipem, S.p.A. and Baker
Hughes International.
Accounts receivable decreased from $2,526,000 at December 31, 2004 to $415,000 at December 31,
2005 due to the transfer of the amounts due from Georgian Oil Samgori Limited, for their share of
the capital expenditure on the planned horizontal well program at the Samgori field to the Georgian
cost pool, the receipt of $800,000 from our insurers in relation to N100 blow out costs, partially
offset by further refundable blow out costs incurred, and timing issues related to sales of crude
oil at month end.
Inventory increased from $254,000 at December 31, 2004 to $886,000 at December 31, 2005 due to
the accumulation of larger batches of oil for export sales.
Prepayments increased from $1,518,000 at December 31, 2004 to $4,380,000 at December 31, 2005
primarily as a result of prepayments for materials and services related to our Kazakhstan
activities. Upon receipt of the materials and services, those amounts will be transferred to
capital assets. This increase is included in the statement of cash flows as an investing activity.
Assets held for sale of $600,000 at December 31, 2005 and December 31, 2004 consist of a
3-megawatt duel fuel power generator.
Capital assets net, increased to $119,148,000 at December 31, 2005 from $72,996,000 at
December 31, 2004, due to investing in capital assets including oil and gas properties and
equipment, principally related to the Ninotsminda Production Sharing
Contract, the Norio exploration well, the acquisition of
Tethys Petroleum Investments Limited and its 70% interest in the Kazakhstan based company BN Munai
LLP.
Prepaid financing fees decreased to $247,000 at December 31, 2005 from $649,000 at December
31, 2004 due to the offset of commissions and professional fees, relating to the SEDA with Cornell
Capital, against capital proceeds in excess of par value, partially offset by the fees charged by
Cornell Capital in connection with the $15,000,000 Promissory Note and fees and commissions
incurred in connection with the $25,000,000 Senior Secured Notes in the aggregate amount of
$385,000.
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Investments in and advances to oil and gas and other ventures of $479,000 at December 31, 2004
represented advances to our oil and gas interests in Kazakhstan partially offset by the impairment
of our investment in the project as a result of losses incurred. We now own 70% of the Kazakhstan
project, through our ownership of Tethys Petroleum Investments Limited, and our investment is
reflected in capital assets as at December 31, 2005.
Accounts payable increased to $5,755,000 at December 31, 2005 from $2,332,000 at December 31,
2004 primarily due to timing differences in respect of payments to suppliers in connection with our
appraisal activities at the Manavi oil discovery, our horizontal well development program at the
Ninotsminda and Samgori Fields and our Kazakhstan activities.
Short-term loans payable decreased to $964,000 at December 31, 2005 from $1,500,000 at
December 31, 2004 due to the repayment of the $1,500,000 loan at December 31, 2004 by a series of
takedowns in February and March 2005 under the SEDA. The $964,000 loan payable at December 31, 2005
relates to the $1,050,000 convertible loan facility dated August 27, 2004 convertible into common
stock with detachable warrants to purchase 2,000,000 common shares. In accordance with EITF 00-27
“Application of Issue No. 98-5 to Certain Convertible Instruments”, a portion of the proceeds of
debt is accounted for as a discount to the face amount of the notes and is based on the relative
fair value of the loans and the warrant securities and conversion stock at the time of issuance.
At December 31, 2005 the unamortized discount amounted to $86,000. On February 14, 2006 we
exercised the option forcing conversion of the loan into shares of our common stock.
Deposits decreased to $0 at December 31, 2005 from $3,081,000 at December 31, 2004 due to the
repayment in full of an oil sales security deposit in the amount of $2,300,000 and the recording of
the $301,000 non-refundable deposit lost by the proposed buyer of the generator, due to failing to
meet the sale contract terms, as other income.
Accrued liabilities increased from $172,000 at December 31, 2004 to $6,356,000 at December 31,
2005 due primarily to accrued contractor invoices in connection with our Georgian operations of
which approximately $4,931,000 relates to the disputed Weatherford invoices referred to in Note 13
of these financial statements. All disputed amounts are accrued in
full and in the event of a positive settlement for the Company, the
cost pool will be adjusted downward accordingly.
Long term debt represents the issue of the $25,000,000 Senior Secured Notes in July, 2005. The
long-term debt at December 31, 2004 of $832,000 related to the $1,050,000 convertible loan facility
convertible into common stock with detachable warrants to purchase 2,000,000 common shares, is now
recorded in short-term loans payable.
Other non current liabilities of $1,001,000 at December 31, 2005 represents the difference
between the interest computed using the actual interest rate in effect and the effective interest
rate due on the $25,000,000 Senior Convertible Secured Loan Notes.
Provision for future site restoration increased to $523,000 at December 31, 2005 from $422,000
at December 31, 2004 primarily due to provisions for future site restoration in Kazakhstan as a
result of the acquisition of new oil and gas properties.
Options with redemption feature increased to $2,120,000 at December 31, 2005 from $723,000 at
December 31, 2004 primarily due primarily to new share options issued from the 2004 Long Term
Incentive Plan during the period, which gives the ability for option holders to demand a net cash
settlement of options should a change in control of the Company occur.
Deferred compensation expense increased to $2,220,000 at December 31, 2005 from $1,976,000 at
December 31, 2004 due to additional share options issued offset by the amount expensed for prior
issued options during the period.
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Results of Continuing Operations
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
We recorded operating revenue from continuing operations of $7,582,000 during the year ended
December 31, 2005 compared with $9,575,000 for the year ended December 31, 2004. The decrease is
attributable to lower oil and gas revenues being recorded in the year ended December 31, 2005 due
to lower production levels relating to a delay in the UBCTD program on both the Ninotsminda and
Samgori Fields. Ninotsminda Oil Company Limited (“NOC”) and CanArgo Samgori Limited (“CSL”) sold
168,212 barrels of oil for the year ended December 31, 2005 compared to 364,319 barrels of oil for
the year ended December 31, 2004.
NOC generated $5,279,000 of oil and gas revenue in the year ended December 31, 2005 compared
with $7,833,000 for the year ended December 31, 2004 primarily due to lower production achieved in
the year ended December 31, 2005 compared to the year ended December 31, 2004 offset partially by a
higher average net sales price achieved in the year ended December 31, 2005 compared to the year
ended December 31, 2004. Its net share of the 184,952 bbls (507 bopd) of gross oil production for
sale from the Ninotsminda Field in the period amounted to 120,219 bbls. As at December 31, 2005,
10,601 bbls of oil remained in storage. For the year ended December 31, 2004, NOC’s net share of
the 370,176 bbls (1,011 bopd) of gross oil production for sale from the Ninotsminda Field in the
period amounted to 242,131 bbls.
CSL generated $2,303,000 of oil and gas revenue for the year ended December 31, 2005 compared
to $1,742,000 from the April 2004 purchase date to December 31, 2004 primarily due to a higher
average net sales price achieved in the year ended December 31, 2005 compared to the period from
the April 2004 purchase date to December 31, 2004, offset partially by lower production achieved in
the year ended December 31, 2005 compared to the year ended December 31, 2004. Its net share of the
166,298 barrels (456 barrels per day) of gross oil production for sale from the Samgori Field in
the period amounted to 62,362 barrels. As at December 31, 2005, 18,261 bbls of oil remained in
storage. For the year ended December 31, 2004 CSL’s net share of the 152,169 bbls (585 bopd) of
gross oil production for sale from the Samgori Field in the period amounted to 57,063 bbls. On
February 17, 2006 we issued a press release announcing that our subsidiary, CSL, was not proceeding
with further investment in the Samgori PSC and associated farm-in, and accordingly we terminated
our interest in the Samgori PSC with effect from February 16, 2006.
NOC and CSL’s entire share of production was either sold locally in Georgia under both
national and international contracts or added to storage. Net sale prices for Ninotsminda and
Samgori oil sold during 2005 averaged $45.18 per barrel as compared with an average of $26.21 per
barrel in 2004. Its net share of the 71,241 mcf of gas delivered was 46,307 mcf at an average net
sale price of $0.53 per mcf of gas. For the year ended December 31, 2004, NOC’s net share of the
65,066 mcf of gas delivered was 42,293 mcf at an average net sale price of $1.41 per mcf of gas.
The operating loss from continuing operations for the year ended December 31, 2005 amounted to
$11,009,000 compared with an operating loss of $2,954,000 for the year ended December 31, 2004. The
increase in operating loss is attributable to increased direct project costs, increased selling,
general and administration costs, increased non cash stock compensation expense, increased
depreciation, depletion and amortization, reduced oil and gas revenue and a gain generated from the
disposal of GAOR in the year ended December 31, 2004, partially offset by reduced field operating
expenses in the period.
Field operating expenses decreased to $2,281,000 for the year ended December 31, 2005 as
compared to $2,321,000 for the year ended December 31, 2004. The decrease is primarily a result of
decrease in production at the Ninotsminda Field partially offset by increased oil processing fees
in relation to the Samgori field during the period. The reduction in production at the Ninotsminda
Field was a result of the Company continuing to focus on the long-term development of its producing
assets in Georgia through the preparation of wells for the Under Balanced Coiled Tubing Drilling
(“UBCTD”) technology program together with a delay in implementing the program itself due to
mechanical difficulties with the equipment. The preparation work for the UBCTD program necessitated
the shut in of
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producing wells during the period thus resulting in a lower average production for the period.
We have not had a corresponding proportional decrease in our operating cost as the majority of our
operating costs are fixed.
Direct project costs increased to $1,458,000 for the year ended December 31, 2005, from
$1,434,000 for the year ended December 31, 2004 due to the inclusion of Samgori project cost
expenditures resulting from the acquisition of the Samgori (Block XIB) Production
Sharing Contract in Georgia partially offset by decreased costs directly associated with non
operating activity at the Ninotsminda Field.
Selling, general and administrative costs increased to $11,576,000 for the year ended December
31, 2005 from $7,324,000 for the year ended December 31, 2004. The increase is a result of
additional costs incurred in respect of compliance with Section 404 of the Sarbanes-Oxley Act of
2002, increased audit fees, legal fees, higher insurance premiums and a general increase in
corporate activity. Included in selling, general and administrative costs is non cash stock
compensation expense, which increased to $2,375,000 for the year ended December 31, 2005 from
$1,395,000 for the year ended December 31, 2004 due to share options issued expensed during the
period. The Company, effective January 1, 2003, adopted in August 2003, 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 $3,276,000 for the year
ended December 31, 2005 from $2,881,000 for the year ended December 31, 2004 is attributable to
additions to the full cost pool during 2005, partially offset by lower production in 2005 compared
to 2004.
We impaired our Caspian Sea project to zero during the year ended December 31, 2004 with a
write down of $65,000 of oil and gas properties and a $75,000 write down of our investment
Impairment of other assets of $35,000 during the year ended December 31, 2004 relates to repairs to
the held for sale generator which are not recoverable.
The gain on disposal of subsidiaries of $1,606,000 recorded for the year ended December 31,
2004 reflects gains from the disposals of CSOP and of our interest in GAOR.
The decrease in other expense to $1,327,000 for the year ended December 31, 2005 from
$2,346,000 for the year ended December 31, 2004 is primarily a result of favourable exchange rate
movements in 2005, the realization of the advanced proceeds on the sale of the generator that was
abandoned, partially offset by higher interest payable charges due to increased borrowing and
increased levels of bad debts.
The decrease in equity loss from investments for the year ended December 31, 2005 to $155,000
from $205,000 for the year ended December 31, 2004 is a result of acquiring 100% ownership in
Tethys Petroleum Investments Limited in June 2005 and therefore only equity accounting for our
share of the loss for the first six months of 2005.
The loss from continuing operations of $12,335,000 or $0.06 per share for the year ended
December 31, 2005 compares to a net loss from continuing operations of $4,757,000 or $0.04 per
share for the year ended December 31, 2004. The weighted average number of common shares
outstanding was higher during the year ended December 31, 2005 than during the year ended December
31, 2004 principally due to the issue of shares in respect of the Samgori purchase in April 2004,
the issue of shares in respect of a global offering in September 2004, the issue of shares in
respect of the Norio minority interest buyout in September 2004, the issue of shares under the
terms of the SEDA in 2005 to repay the Cornell Capital promissory notes and in connection with
additional takedowns under the SEDA, the exercise of share options in 2005 and the issue of shares
in respect of the Tethys Petroleum Investments Limited buyout.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
In April 2004, we announced that we had completed our acquisition of a 50% interest in the
Samgori (Block XIB) Production Sharing Contract in Georgia.
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We recorded operating revenue from continuing operations of $ 9,574,000 during the year ended
December 31, 2004 compared with $ 8,105,000 for the year ended December 31, 2003. The increase is
attributable to higher oil and gas revenues being recorded in the year ended December 31, 2004. NOC
and CSL sold 364,319 barrels of oil for the year ended December 31, 2004 compared to 387,721
barrels of oil for the year ended December 31, 2003
NOC generated $7,833,000 of oil and gas revenue in the year ended December 31, 2004 compared
with $7,881,000 for the year ended December 31, 2003 due to a higher average net sales price
achieved in the year ended December 31, 2004 compared to the year ended December 31, 2003. Sales
volumes remained constant over the period. Its net share of the 370,176 bbls (1,011 bopd) of gross
oil production for sale from the Ninotsminda Field in the period amounted to 242,131 bbls. In the
period, 71,899 bbls of oil were removed from storage and sold. A further 9,000 bbls were removed
from storage and returned to Georgian Oil in recognition of agreed losses since the inception of
the Production Sharing Contract. For the year ended December 31, 2003, NOC’s net share of the
695,174 bbls (1,906 bopd) of gross oil production was 451,863 bbls.
CSL generated $1,742,000 of oil and gas revenue from the purchase date to December 31, 2004.
Its net share of the 152,169 bbls (2,832 bopd) of gross oil production for sale from the Samgori
Field in the period amounted to 57,063 bbls. As at December 31, 2004, 5,964 bbls of oil remained
in storage.
NOC and CSL’s entire share of production was sold locally in Georgia under both national and
international contracts. Net sale prices for Ninotsminda and Samgori oil sold during 2004 averaged
$26.21 per barrel as compared with an average of $20.07 per barrel in 2003. Its net share of the
65,066 mcf of gas delivered was 42,293 mcf at an average net sale price of $1.41 per mcf of gas.
For the year ended December 31, 2003, NOC’s net share of the 108,630 mcf of gas delivered was
82,156 mcf at an average net sales price of $ 1.25 per mcf of gas. No gas was produced at the
Samgori Field from the acquisition date of the Production Sharing Contract to December 31, 2004.
The operating loss from continuing operations for the year ended December 31, 2004 amounted to
$2,954,000 compared with an operating loss of $159,000 for the year ended December 31, 2003. The
increase in operating loss is attributable a loss from the disposal of Lateral Vector Resources
Inc., increased field operating costs, increased direct project costs, increased selling, general
and administration costs and impairments to our Caspian project, partially offset by increased oil
and gas revenue, a gain generated from the disposal of our interest in GAOR, and reduced
depreciation, depletion and amortization in the period.
Field operating expenses increased to $2,321,000 ($6.33 per boe) for the year ended December
31, 2004 as compared to $1,052,000 ($2.59 per boe) for the year ended December 31, 2003. The
increase is primarily a result of a decrease in production at the Ninotsminda Field during the
period and the inclusion of the Samgori Field expenditures resulting from the acquisition of an
interest in the Samgori (Block XIB) Production Sharing Contract (“Samgori PSC”) in Georgia. The
reduction in production at the Ninotsminda Field was a result of us continuing to focus on the
long-term development of our producing assets in Georgia through the preparation of wells for the
Under Balanced Coiled Tubing Drilling (“UBCTD”) development program. This necessitated the shut in
of producing wells during the period thus resulting in a lower average production for the period.
We have not had a corresponding decrease in our operating cost as the majority of our operating
costs are fixed.
Direct project costs increased to $1,434,000 for the year ended December 31, 2004, from
$1,029,000 for the year ended December 31, 2003, primarily due to costs directly associated with
non operating activity at the Ninotsminda Field and the inclusion of Samgori project cost
expenditures following our acquisition of an interest in the Samgori PSC in Georgia.
Selling, general and administrative costs increased to $7,324,000 for the year ended December
31, 2004, from $3,505,000 for the year ended December 31, 2003. The increase is primarily as a
result of additional internal costs incurred in respect of fund raising activities relating to the
recent public global offering and increased corporate activity over 2003. Included in selling,
general and administrative costs is non cash stock compensation expense of $1,395,000 for the year
ended December 31, 2004 related to additional employee awards granted in the period. During the year ending December 31, 2004 we issued 6,298,000 stock options to directors and employees. On
August 24, 2004, 5,688,000 of these options were issued, all with a two year vesting period from
issue date of the
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option. The remaining 610,000 stock options were issued over various dates and
have varying vesting terms ranging from immediate to two years. We recorded $3,371,000 of deferred
compensation expense as a separate component of equity in respect of these options. Non cash stock
compensation of $277,000 for the year ended December 31, 2003 relates to the Company, effective
January 1, 2003, adopting in August 2003, 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 decrease in depreciation, depletion and amortization expense to $2,881,000 for the year
ended December 31, 2004 from $3,294,000 for the year ended December 31, 2003 is attributable
principally to reductions in production during 2004 as compared to 2003 and from inclusion of the
depletion of estimated reserves at the Samgori Field which had the effect of diluting the depletion
rate per barrel and reduced overall depletion for the year ended December 31, 2004.
We impaired our Caspian Sea project to zero during the year ended December 31, 2004 with a
write down of $65,000 of oil and gas properties and a $75,000 write down of our investment.
Impairment of other assets of $35,000 during the year ended December 31, 2004 relates to
repairs to the held for sale generator which are not recoverable.
During 2003, we also announced 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, our 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.
The gain on disposal of subsidiaries of $1,607,000 recorded for the year ended December 31,
2004 reflects gains from the disposals of CSOP and of our interest in GAOR.
We recorded net other expense of $2,345,000 for the year ended December 31, 2004, as compared
to $605,000 for the year ended December 31, 2003. The increase in net other expense of $1,740,000
is primarily due to an increase in interest expense of $647,000 largely resulting from the
amortization of the discount on debt issued with detachable stock purchase warrants and on
convertible debt incurred during the period in accordance with APB 14 and EITF 00-27; additional
other expenses relating to an extinguished loan of $350,000, foreign exchange losses, and, equity
income from investments.
Equity loss from investments for the year ended December 31, 2003 of $ 205,000 relates to the
loss incurred on the project in Kazakhstan to acquire oil and gas properties. The equity income for
the year ended December 31, 2003 of $66,000 is from the production and sales of crude oil by
Boryslaw Oil Company, subsequently disposed of in the fourth quarter of 2003.
The cumulative effect of the change in accounting principle of $41,000 for the year ended
December 31, 2003 was a result of the adoption of accounting standard FAS 143 relating to the
treatment of asset retirement obligations.
The loss from continuing operations of $5,300,000 or $0.04 per share for the year ended
December 31, 2004 compares to a net loss from continuing operations of $756,000 or $0.01 per share
for the year ended December 31, 2003. The weighted average number of common shares outstanding was
higher during the year ended December 31, 2004 than during the year ended December 31, 2003,
principally due to share issues in respect of the Manavi agreements in fourth quarters of 2003 and
the issue of shares in respect of the Samgori purchase in April 2004, the exercise of share options
in 2004, the issue of shares in respect of a global offering in September 2004 and the issue of
shares in respect of the Norio minority interest buyout in September 2004.
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Results of Discontinued Operations
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
The net income from discontinued operations, net of taxes and minority interest for the year
ended December 31, 2004 amounted to $542,000 related principally to income relating to the refinery
resulting from the disposal of the refinery in the period, partially offset by the activities of
CanArgo Standard Oil Products Limited (“CSOP”), mainly due to interest on additional bank loans
drawn by CSOP in Tbilisi, Georgia. All discontinued operations had been disposed by December 31,
2004.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
The net income from discontinued operations, net of taxes and minority interest for the year
ended December 31, 2004 amounted to $542,210 compared with net loss of $6,607,517 for the
corresponding period in 2003. The increase in net income from discontinued operations, net of
taxes and minority interest relates to the losses resulting from the activities of Lateral Vector
Resources Inc. (“LVR”) and GAOR in 2003, offset partially by income relating to the refinery
resulting from the disposal of the refinery in the period and income from CSOP during the period.
In September 2002, we approved a plan to sell our interest in CSOP, a petroleum product retail
business in Georgia, to finance our Georgian and Ukrainian development projects. In October 2002,
we reached agreement with Westrade Alliance LLC, an unaffiliated company, to sell our wholly owned
subsidiary, CanArgo Petroleum Products Limited (“CPPL”), which held our 50% interest in CSOP for
$4,000,000 in an arms-length transaction, with legal ownership being transferred upon receipt of
final payment due in originally in August 2003 and subsequently extended. The final payment of the
consideration was received by us in December 2004 at which time we transferred our ownership in
CPPL to Westrade Alliance LLC.
In 2003, we approved a plan to dispose of our interest in GAOR as the refinery had remained
closed since 2001 and neither we nor our 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.
Lateral Vector Resources Inc. (“LVR”), a wholly-owned subsidiary of CanArgo acquired by us in
July 2001, negotiated and concluded with Ukrnafta, the Ukrainian State Oil Company, a Joint
Investment Production Activity (“JIPA”) agreement in 1998 to develop the Bugruvativske 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. Consequently, we recorded in 2003 a
write-down in respect to the LVR deal and the acquisition of the Bugruvativske Field of
approximately $4,790,727.
On May 28, 2004, we announced that pursuant to a signed agreement between CanArgo Acquisition
Corporation, our wholly owned subsidiary, and Stanhope Solutions Ltd., we had completed a
transaction to sell our interest in the Bugruvativske Field through the disposal of LVR for
$2,000,000. We received $250,000 as an initial payment and will receive the remaining $1,750,000
based upon certain production targets being achieved on the project. As of March 10, 2006, we had
not received any further payments.
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Contractual Obligations and Commercial Terms
Our principal business and assets are derived from production sharing contracts in 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, the Tbilisi
PSC and the Samgori 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 NOC 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 NOC 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. No challenge has been made to date.
In 2002, the Participation Agreement for the three well exploration program on the Ninotsminda
/ Manavi area with AES was terminated without AES earning any rights to any of the Ninotsminda /
Manavi 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 $7,500,000, representing their prior funding under the Participation Agreement.
Under the Production Sharing Contract for Blocks XI G and XI H (the
“Tbilisi PSC”) in Georgia our subsidiary CanArgo Norio Limited will evaluate existing seismic and
geological data during the first year and acquire additional seismic data within three years of the
effective date of the Agreement which is September 29, 2003. The total commitment over the next
seven months is $350,000.
In April 2004, we acquired a 50% interest in the Samgori (Block XI B ) Production
Sharing Contract (“Samgori PSC”) in Georgia. This interest was acquired from GOSL, a company wholly
owned by Georgian Oil, by one of our subsidiaries, CSL. Under the terms of the agreement dated
January 8, 2004, we are required to participate in the drilling of up to 10 horizontal wells on the
Samgori Field as required under an earlier agreement between GOSL and National Petroleum Limited
(“NPL”) the previous contractor party in the PSC (“Agreed Work Programme”). Completion of well
S302, which was funded 100% by us satisfied our commitment to GOSL under the acquisition agreement,
the remainder of the drilling program was to be funded jointly by CSL and GOSL, the Contractor
parties, pro rata their interest in the Samgori PSC. The total cost to us of participating in the whole
program, which was due to b e completed within 36 months of the work commencement date (“WCD”) was
anticipated to be up to $13,500,000.
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Furthermore, under the assignment agreement NPL had agreed outstanding costs and expenses of
$37,528,964 in relation to the Samgori PSC which were recoverable by NPL receiving 30% of annual
net profit from the Field until such costs had been fully repaid. After NPL’s costs are repaid from
either Field production or other production in the PSC (in the event that new fields are developed
in areas identified using seismic surveys originally performed by NPL), NPL would continue to
receive 5% of annual net profit.
Under the Samgori PSC, up to 50% of petroleum produced under the contract is allocated to the
Contractor parties for the recovery of the cumulative allowable capital, operating and other
project costs associated with the Samgori Field and exploration in Block XI B (“Cost
Recovery Oil”). The cost recovery pool includes the $37,528,964 costs previously incurred by NPL.
The balance of production (“Profit Oil”) is allocated on a 50/50 basis between the State and the
Contractor parties respectively until capital costs are recovered after which they would receive
30% of Profit Oil. Under the Samgori PSC, Georgian Oil as the State representative in the contract
is entitled to receive up to 250,000 tons (approximately 1.6 million barrels) of oil (“Base Level
Oil”) from a maximum of 50% per calendar quarter of production when the value of the cumulative
Cost Recovery Petroleum, cumulative Profit Oil and cumulative Profit Natural Gas delivered to the
Contractor parties exceeds the cumulative allowable capital, operating and other project costs
including finance costs associated with the Samgori Field and exploration in Block XI B
and the NPL costs. While Base Level Oil is being delivered to Georgian Oil, the Contractor
parties will continue to be entitled to a maximum of 50% of the remaining Profit Oil. The Base
Level Oil is an estimate of the amount of oil that Georgian Oil would have expected to produce from
the contract area had the State not come to a contractual arrangement with the previous Contractor
party in 1996.
Under the terms of the acquisition agreement with GOSl, NPL had an option to reacquire its
Contractor’s interest in the Samgori PSC in the event that the agreed work program is not completed
in part (which involves the drilling of two horizontal well sections) by September 16, 2006 and
completed in full by June 2008. The work commencement date was specified as being no later than
March 16, 2005, however GOSL were reluctant to set the work commencement date at that time and
obtained several extensions from NPL to the work commencement date, with the last being until
February 16, 2006. At that time NPL were not prepared to further extend the work commencement
date, and GOSL were unwilling or unable to commit to their 50% share of costs associated with the
agreed work program. CSL considered that there would have been insufficient time to meet the
commitments under the acquisition agreement, and was not prepared to fund the agreed work program,
which was not without risk, on a 100% basis without different commercial terms and an extension to
the commitment period. It was not possible to negotiate a satisfactory position on either matter,
and as such CSL was informed that, given this, NPL intended to exercise their right to take back
100% of the Contractor Share in the Project from GOSL and accordingly we withdrew from the project
effective February 16, 2006.
We have 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 we
have interests that require or may require us to expend funds and to issue shares of our Common
Stock.
Upon completion of the acquisition of an interest in the Samgori PSC we had a contractual
obligation to issue four million shares of CanArgo Common Stock to Europa Oil Services Limited
(“Europa”), an unaffiliated company in connection with a consultancy agreement with Europa in
relation to this acquisition. On April 16, 2004 Europa was issued with four million restricted
shares of CanArgo Common Stock in an arms length transaction. A further 12 million shares of
CanArgo Common Stock are issuable upon certain production targets being met from future
developments under the Samgori PSC. As we have withdrawn from the Samgori PSC effective February
16, 2006, we have no continuing obligation to issue further shares of CanArgo Common Stock to
Europa. On March 14, 2006, we signed an agreement with Europa formally terminating the consultancy
agreement.
At December 31, 2005, we 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,
an oil field in Ukraine in which we had a previous interest.
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In September 2004, a blow-out occurred at the N100 well on the Ninotsminda Field. Our insurers
will cover 80% of the costs associated with the blow out up to a maximum cover of $2,500,000. We
received $800,000 from our insurers in the second quarter of 2005 in respect of costs incurred to
date and as of December 31, 2005 $32,000 was recorded as a receivable.
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, 2005:
| 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 |
$ | 533,479 | 805,815 | 560,092 | 197,183 | |||||||||||
Loans payable (3) |
1,050,000 | |||||||||||||||
Long term debt |
25,000,000 | |||||||||||||||
Other long-term liabilities (1) |
— | — | — | 523,000 | ||||||||||||
| $ | 1,583,479 | 805,815 | 25,560,092 | 720,183 | ||||||||||||
| (1) | Other long-tem liabilities represent costs provided for future site restoration. | |
| (2) | CanArgo has no contractual obligations in respect of capital leases or purchase obligations. | |
| (3) | Subsequent to year end, we forced conversion of the loan to our common stock. |
Related Party Transactions
A company owned by significant employees of Georgian British Oil Company Ninotsminda until
February 2005 and the same employees of CanArgo Georgia Limited from February 1, 2005 provided
certain equipment, office and storage space to Georgian British Oil Company Ninotsminda until
February 2005 and to CanArgo Georgia Limited from February 1, 2005. Total rental payments for this
equipment, office and storage space in 2005 were $281,024 ($107,946 in 2004). In 2004, the same
company provided additional services to Georgian British Oil Company Ninotsminda in accordance with
a farm-in agreement in respect of the Manavi well for the value of $450,000. No additional services
were provided in 2005.
Dr. David Robson, Chief Executive Officer, provides all of his services to CanArgo through
Vazon Energy Limited, a corporation organized under the laws of the Bailiwick of Guernsey, of which
he is the sole owner and Managing Director. In addition a management services agreement exists
between CanArgo and Vazon Energy whereby the services of Dr. Robson, Mrs. Landles (Corporate
Secretary and Executive Vice President) and Mr. Battey (Chief Financial Officer) are provided to
CanArgo.
Mr. Russell Hammond, a non-executive director of CanArgo, is also an Investment Advisor to
Provincial Securities Limited who became a minority shareholder in the Norio and North Kumisi
Production Sharing Agreement through a farm-in agreement to the Norio MK72 well. On September 4,
2003 we concluded a deal to purchase Provincial Securities Limited’s minority interest in CanArgo
Norio Limited by a share swap for shares in CanArgo. Provincial Securities Limited received
2,234,719 shares of CanArgo common stock in relation to the transaction. Provincial Securities
Limited also had an interest in Tethys Petroleum Investments Limited which was sold in June 2005 to
us by a share exchange for shares in CanArgo. Provincial Securities Limited received 5,500,000
shares of CanArgo common stock in relation to the transaction. Mr Hammond did not receive any
compensation in connection with these transactions and disclaims any beneficial ownership of Provincial Securities
Limited or any of the Company’s commons stock owned by Provincial Securities Limited.
Transactions with affiliates or other related parties including management of affiliates are
to be undertaken on the same basis as third party arms-length transactions. Transactions with
affiliates are reviewed and voted on solely by non-interested directors.
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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 and US generally accepted accounting principles. Under these rules, all such costs excluding significant
acquisition, exploration and development costs related to unproved properties, 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, 2005, 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.
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.
Management believes that it is reasonably possible the following material estimates affecting
the financial statements could significantly change in the coming year: (1) estimates of proved
oil and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas
properties, and (3) estimates of future dismantlement and restoration costs.
Concentration of Credit Risk
Although our cash and temporary investments and accounts receivable are exposed to potential
credit loss, we do 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.
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Foreign Operations
Our future operations and earnings will depend upon the results of our operations in Georgia
and Kazakhstan. There can be no assurance that we will be able to successfully conduct such
operations, and a failure to do so would have a material adverse effect on the our financial
position, results of operations and cash flows. Also, the success of our 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 we are dependent on international operations, specifically those in
Georgia and Kazakhstan, we will be subject to various additional political, economic and other
uncertainties. Among other risks, our 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.
Recently Issued Pronouncements
In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset
Retirement Obligations,” which clarifies that an entity is required to recognize a liability for
the fair value of a conditional asset retirement obligation if the fair value can be reasonably
estimated even though uncertainty exists about the timing and (or) method of settlement. The
Company is required to adopt Interpretation No. 47 prior to the end of 2006 and its adoption is not
expected to have a significant effect on the Company’s results of operations or financial
condition.
In November 2004, the FASB issued SFAS No. 151 “Accounting for Inventory Costs” that amends
Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting
for abnormal amounts of idle facility expense, freight, handling costs, and wasted material
(spoilage). SFAS 151 requires that those items be recognized as current-period charges regardless
of whether they meet the criterion of “so abnormal” and requires that allocation of fixed
production overheads to the costs of conversion be based on the normal capacity of the production
facilities. The Company is required to adopt SFAS No. 151 in the beginning of 2006 and its adoption
is not expected to have a significant effect on the Company’s results of operations or financial
condition.
In December 2004, the FASB issued SFAS No. 153 “Exchanges of Nonmonetary Assets” that amends
Accounting Principles Board (APB) Opinion No. 29, ”Accounting for Nonmonetary Transactions” and
Amends FAS 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies”, paragraphs
44 and 47(e). ARB No. 29 is based on the principle that exchanges of nonmonetary assets should be
measured based on the fair value of the assets exchanged and SFAS 153 amended ABP 29 to eliminate
the exception for nonmonetary exchanges of similar productive assets and replaced it with a general
exception for exchanges of nonmonetary assets that do not have commercial substance. The Company is
required to adopt SFAS No. 153 for nonmonetary asset exchanges occurring in the first quarter of
2006 and its adoption is not expected to have a significant effect on the Company’s results of
operations or financial condition.
In May 2005, the FASB issued SFAS No. 154 “Accounting Changes and Error Corrections” to
replace ABP No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim
Financial Statements.” Opinion 20 previously required that most voluntary changes in accounting
principle be recognized by including in net income of the period of the change the cumulative
effect of changing to the new accounting principle. SFAS 154 requires retrospective application to
prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of
the change. When it is impracticable to determine the period-specific effects of an accounting
change on one or more individual prior periods presented, SFAS 154 requires that the new accounting
principle be applied to the balances of assets and liabilities as of the beginning of the earliest
period for which retrospective application is practicable and that a corresponding adjustment be
made to the opening balance of retained earnings (or other appropriate components of equity or net
assets in the statement of financial position) for that period rather than being reported in an
income statement. When it is impracticable to determine the cumulative effect of applying a change
in accounting principle to all prior periods, SFAS 154 requires that the new accounting principle
be applied as if it were adopted
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prospectively from the earliest date practicable. SFAS 154 is
effective for accounting changes and corrections of errors made in fiscal years beginning after
December 15, 2005. The implementation of FAS 154 is not expected to have a significant effect on
the Company’s results of operations or financial condition.
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. |
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.
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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 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, our contracts to sell our production from the Ninotsminda Field in Georgia
is denominated in U. S. dollars with all export contracts providing for payment in dollars,
although we may not always be able to continue to demand payment in U.S. dollars. Production from
the Kyzyloi Field in Kazakhstan will be delivered under a natural gas supply contract concluded
between BNM and Gaz Impex in January 2006 with payment in U. S. dollars.
We had no material interest in investments subject to market risk during the period covered by
this report.
Because the majority of all revenue to us is from the sale of production from the Ninotsminda
Field a change in the price of oil or a change in the production rates could have a substantial
effect on this revenue and therefore profits.
Assuming the same production in 2006 as 2005 but decreasing the net oil price we receive 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 2005 based on an average net oil price
received of $45.18 was $7,599,151. If the average net oil price received was $5.00 less at $40.18
then the total annual revenue from oil sales would be reduced by $840,396 to $6,758,755. If the
average net oil price received was reduced by $10 per barrel then the total annual revenue from oil
sales realised would be reduced by $1,681,455 to $5,917,696, assuming all other factors are
constant.
Assuming constant oil prices a reduction in annual production by 20% and 50% would have the
following effect on total annual revenues. In 2005 total oil sales were 168,212 bbls of oil
producing revenue of $7,599,151. If this was reduced by 20% then the annual revenue from oil sales
would be reduced to $6,079,321. If the total annual oil sales were reduced by 50% or 84,106 bbls
then the total annual revenue from oil sales would be $3,799,576, assuming all other factors are
constant.
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.
None.
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ITEM 9A. CONTROLS AND PROCEDURES.
Management’s Responsibility for Financial Statements
Our management is responsible for the integrity and objectivity of all information presented
in this Annual Report. The consolidated financial statements were prepared in conformity with
accounting principles generally accepted in the United States of America and include amounts based
on management’s best estimates and judgments. Management believes the consolidated financial
statements fairly reflect the form and substance of transactions and that the financial statements
fairly represent the Company’s financial position and results of operations. The Audit Committee of
the Board of Directors, which is composed solely of independent directors, meets regularly with the
independent auditors, L J Soldinger Associates LLC and representatives of management to review
accounting, financial reporting, internal control and audit matters, as well as the nature and
extent of the audit effort. The Audit Committee is responsible for the engagement of the
independent auditors. The independent auditors have free access to the Audit Committee.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting. Internal control over financial reporting, is defined in the rules
promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the
supervision of, the Company’s principal executive and principal financial officers and effected by
the Company’s Board, management and other personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting procedures (“GAAP”) and includes those
policies and procedures that:
| • | pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; | ||
| • | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with US GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and Directors of the Company; and | ||
| • | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. |
A control system, no matter how well conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system are met. Further, the design of a
control system must reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Because of the inherent limitations in all
control systems, no evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within our Company have been detected. These inherent limitations
include the realities that judgments in decision-making can be faulty, and that breakdowns can
occur because of simple error or mistake. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more people, or by management override of
the control. The design of any system of controls also is based in part upon certain assumptions
about the likelihood of future events, and there can be no assurance that any design will succeed
in achieving its stated goals under all potential future conditions; over time, control may become
inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected.
Under the supervision and with the participation of our management, including our principal
executive, financial and accounting officers, we conducted an evaluation of the effectiveness of
our internal control over financial reporting as of December 31, 2005 based on the framework in
“Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
A material weakness is a control deficiency, or combination of control deficiencies, that
results in more than a remote likelihood that a material misstatement of our annual or interim
financial statements would not be prevented or detected. As of December 31, 2005, we have concluded
that our internal control over financial reporting was ineffective as of December 31, 2005 and that
we have material weaknesses in each of the following areas:
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| 1. | Financial Statement Close Process |
The Company’s controls over the financial reporting close process were not consistently
applied. As a result, the Company has a material weakness related to its ability to compile and
review accurate financial statements.
| • | The financial statement close process relies heavily upon manual rather than automated system process controls and places significant reliance on spreadsheets; | ||
| • | Formal policies and procedures in many functions including maintenance of the Chart of Accounts, financial statement close, purchasing, payroll, and cash management operations do not exist; | ||
| • | Preparation and review of account reconciliations, particularly in Georgia and Kazakhstan, are not performed; and | ||
| • | There is no review, reconciliation or approval of various schedules and reconciliations, including the transfer of amounts from subsidiary trial balances to consolidating spreadsheets prepared to support the financial close and disclosure processes |
These material weaknesses related to the financial statement close process affect all of the
Company’s significant accounts and could result in a material misstatement to the Company’s annual
or interim consolidated financial statements that would not be prevented or detected.
| 2. | Disclosure Controls |
The Company’s disclosure controls and procedures were not effective in providing reasonable
assurance that information required to be disclosed in reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported, within the time periods specified in
the SEC’s rules and forms. Inadequate controls include the lack of procedures used for
identifying, determining and calculating required disclosures and other supplementary information
requirements
| 3. | Information Technology |
The Company did not adequately implement certain controls over information technology,
including certain spreadsheets, used in its core business and financial reporting. These
areas included logical access security controls to financial applications, segregation of duties
and backup and recovery procedures. The Company’s controls over the completeness, accuracy,
validity, restricted access, and the review of certain spreadsheets used in the period-end
financial statement preparation and reporting process was not designed appropriately. This
material weakness affects the Company’s ability to prevent improper access and changes to its
accounting records.
| 4. | Production |
The Company did not have effective controls and procedures to ensure that revenues and
associated costs from the sales of its products based on production and transmission records
between the Company and its third party production sharing partner were reconciled or correctly
recognized. Controls associated with the product transmission are performed by the third party
production sharing partner and there is no evidence that these controls have been reviewed by the
Company.
Deficiencies in the Company’s internal controls and procedures relating to the recording of
production do not allow assurance that revenues and costs are recognized in accordance with
generally accepted accounting principles.
| 5. | Inventory Management |
The Company did not maintain a control environment that fully emphasized the establishment of,
adherence to, or adequate communication regarding appropriate internal control for the management
of its inventory, including the lack of documented procedures to update and review the material
master file and valuation table or compare the cost of inventory to net realizable value.
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These weaknesses increased the likelihood of potential material errors in the Company’s
financial reporting.
| 6. | Entity Level Controls |
As evidenced by the material weaknesses described above, entity-level controls related to the
control environment, risk assessment, monitoring function and dissemination of information and
communication activities did not operate effectively. This includes a lack of adequate mechanisms
for anticipating and identifying financial reporting risks and for reacting to changes in the
operating environment that could have a potential effect on financial reporting. Such entity level
controls, and a comprehensive monitoring of internal controls, are part of the framework to ensure
that the designed system of internal control is operating effectively to ensure that significant
transactions are adequately identified, recorded and disclosed.
As a result, misappropriation of assets and misstatements in the financial statements could
occur and not be prevented or detected by the Company’s controls in a timely manner.
In the light of the review Management, in consultation with the Audit Committee, is reviewing the
most cost effective way to address the issues raised. Management considers that remediation
measures will include the appointment of a Group Compliance Officer with responsibility for
ensuring the preparation, review, testing and updating of the appropriate policies, procedures and
standards. Recruitment of a Country Financial Controller in Kazakhstan to strengthen group
reporting is underway.
CEO
and CFO Certifications — The Certifications of our CEO and CFO which are attached as Exhibits 31(1) and 31(2)
to this Report include information about our disclosure controls and procedures and internal control over financial
reporting. These Certifications should be read in conjunction with the information contained in this Item 9A for
a more complete understanding of the matters covered by the Certifications.
Changes
in Internal Control over Financial Reporting
There
were no changes in our internal control in the fourth quarter.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Stockholders of CanArgo Energy Corporation
Stockholders of CanArgo Energy Corporation
We have audited management’s assessment, included in the accompanying Management’s Report on
Internal Control over Financial Reporting, that CanArgo Energy Corporation did not maintain
effective internal control over financial reporting as of 31 December 2005, because of the effect
of the Material Weaknesses Identified in Management’s Assessment, based on criteria established in
Internal Control—Integrated Framework issued by the Committee of Sponsoring Organization of the
Treadway Commission (COSO). CanArgo Energy Corporation’s management is responsible for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express an opinion on
management’s assessment and an opinion on the effectiveness of the company’s internal control over
financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management’s assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
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A material weakness is a control deficiency, or combination of control deficiencies, that results
in more than a remote likelihood that a material misstatement of the annual or interim financial
statements will not be prevented or detected. The following material weaknesses have been
identified and included in management’s assessment.
Information Technology
The Company did not adequately implement certain controls over information technology, including
certain spreadsheets, used in its core business and financial reporting. These areas
included logical access security controls to financial applications, segregation of duties and
backup and recovery procedures. The Company’s controls over the completeness, accuracy, validity,
restricted access, and the review of certain spreadsheets used in the period-end financial
statement preparation and reporting process was not designed appropriately. This material weakness
affects the Company’s ability to prevent improper access and changes to its accounting records.
Financial Reporting Close Process
The Company’s controls over the financial reporting close process were not consistently applied. As
a result, the Company has a material weakness related to its ability to compile and review accurate
financial statements.
| 1. | The financial statement close process relies heavily upon manual rather than automated system process controls and places significant reliance on uncontrolled spreadsheets; | ||
| 2. | Formal policies and procedures in many functions including maintenance of the Chart of Accounts, financial statement close, purchasing, payroll, and cash management operations do not exist; | ||
| 3. | Preparation and review of account reconciliations, particularly in Georgia and Kazakhstan, are not performed; and | ||
| 4. | There is no review, reconciliation or approval of various schedules and reconciliations, including the transfer of amounts from subsidiary trial balances to consolidating spreadsheets prepared to support the financial close and disclosure processes |
These material weaknesses related to the financial statement close process affect all of the
Company’s significant accounts and could result in a material misstatement to the Company’s annual
or interim consolidated financial statements that would not be prevented or detected.
Disclosure
The Company’s disclosure controls and procedures were not effective in providing reasonable
assurance that information required to be disclosed in reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported, within the time periods specified in
the SEC’s rules and forms. Inadequate controls include the lack of procedures used for
identifying, determining and calculating required disclosures and other supplementary information
requirements.
Production
The Company did not have effective controls and procedures to ensure that revenues and associated
costs from the sales of its products based on production and transmission records between the
Company and its third party production sharing partner were reconciled or correctly recognized.
Controls associated with the product transmission are performed by the third party production
sharing partner and there is no evidence that these controls have been reviewed by the Company.
Deficiencies in the Company’s internal controls and procedures relating to the recording of
production do not allow assurance that revenues and costs are recognized in accordance with
generally accepted accounting principles.
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Inventory Management
The Company did not maintain a control environment that fully emphasized the establishment of,
adherence to, or adequate communication regarding appropriate internal control for the management
of its inventory, including the lack of documented procedures to update and review the material
master file and valuation table or compare the cost of inventory to net realizable value.
These weaknesses increased the likelihood of potential material errors in the Company’s financial
reporting.
Entity Level
As evidenced by the material weaknesses described above, entity-level controls related to the
control environment, risk assessment, monitoring function and dissemination of information and
communication activities did not operate effectively. This includes a lack of adequate mechanisms
for anticipating and identifying financial reporting risks and for reacting to changes in the
operating environment that could have a potential effect on financial reporting. Such entity level
controls, and a comprehensive monitoring of internal controls, are part of the framework to ensure
that that the designed system of internal control is operating effectively to ensure that
significant transactions are adequately identified, recorded and disclosed.
As a result, misappropriation of assets and misstatements in the financial statements could occur
and not be prevented or detected by the Company’s controls in a timely manner.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the 2005 consolidated financial statements of CanArgo Energy Corporation and
our report dated 9 March 2006 expressed an unqualified opinion.
These material weaknesses were considered in determining the nature, timing, and extent of audit
tests applied in our audit of the 2005 financial statements, and this report does not affect our
report dated 9 March 2006 on those financial statements.
In our opinion, management’s assessment that CanArgo Energy Corporation did not maintain effective
internal control over financial reporting as of 31 December 2005, is fairly stated, in all material
respects, based on criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion,
because of the effect of the material weakness described above on the achievement of the objectives
of the control criteria, CanArgo Energy Corporation has not maintained effective internal control
over financial reporting as of 31 December 2005, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
L J Soldinger Associates LLC
Deer Park, Illinois USA
March 9, 2006
March 9, 2006
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ITEM 9B. OTHER INFORMATION
On March 14, 2006, we entered into an agreement (“Termination Agreement”) with Europa Oil Services
Limited (“Europa”), an unaffiliated company, formally terminating the consultancy agreement between
CanArgo and Europa dated January 8, 2004. Under the terms of the consultancy agreement, CanArgo
had an outstanding obligation to issue up to 12 million shares of CanArgo common stock to Europa
upon certain production targets being met from future developments under the Samgori PSC. With
effect from February 16, 2006, we have withdrawn from the Samgori PSC. Pursuant to the terms of
the Termination Agreement the parties accordingly agreed that the consultancy agreement had
terminated with effect from February 16, 2006. CanArgo has not incurred any material early
termination penalties as a result of the termination of the consultancy agreement.
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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 2006 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 2006 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 2006 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 2006 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 2006 Annual Meeting of
Stockholders and filed with the SEC within 120 days after the close of our fiscal year.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
The following financial statements and related notes of the Company contained on pages F-1
through F- 61 are filed as part of this Report:
Reports of Independent Auditors
Consolidated Statements of Operations – Years Ended December 31, 2005, 2004, and 2003.
Consolidated Balance Sheets – December 31, 2005 and 2004.
Consolidated Statements of Cash Flows – Years Ended December 31, 2005, 2004, and 2003.
Consolidated Statements of Stockholders’ Equity – Years ended December 31, 2005, 2004 and 2003.
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) Exhibits
| Management Contracts, Compensation Plans and Arrangements are identified by an asterisk (*) Documents filed herewith are identified by a cross (†). | ||
1(1)
|
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). | |
1(2)
|
Placement Agent Agreement dated September 22, 2004 by and between ABG Sundal Collier, Norge ASA and CanArgo Energy Corporation (Incorporated herein by reference from Amendment No 2 to Registration Statement on Form S-3 filed August 31, 2004 (Reg. No. 333-115645)). | |
1(3)
|
Placement Agent Agreement dated September 22, 2004 by and between ABG Sundal Collier Inc. and CanArgo Energy Corporation (Incorporated herein by reference from Amendment No 1 to Registration Statement on Form S-3 filed July 1, 2004 (Reg. No. 333-115645)). | |
1(4)
|
Engagement letter between ABG Sundal Collier Norge ASA and CanArgo Energy Corporation dated March 23, 2004 (Incorporated herein by reference from March 31, 2004 |
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| Form 10-Q). | ||
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). | |
3(1)
|
Registrant’s Certificate of Incorporation and amendments thereto (Incorporated by reference from the Company’s Proxy Statements filed May 10, 1999 and May 9, 2000 and Form 8-K filed July 24, 1998). | |
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). | |
*4(1)
|
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). | |
*4(2)
|
Amended and Restated CanArgo Energy Inc. Stock Option Plan (Incorporated herein by reference from March 31, 1998 Form 10-Q). | |
*4(3)
|
CanArgo Energy Corporation 2004 Long Term Incentive Plan (Incorporated herein by reference from Form 8-K dated May 19, 2004). | |
4(5)
|
Amended and Restated Loan and Warrant Agreement between CanArgo Energy Corporation and Salahi Ozturk dated August 27, 2004 (Incorporated herein by reference from Form 8-K dated August 27, 2004) | |
4(6)
|
Note Purchase Agreement dated July 25, 2005 among CanArgo Energy Corporation and Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K/A dated July 28, 2005). | |
4(7)
|
Registration Rights Agreement dated July 25, 2005 among CanArgo Energy Corporation and Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K dated July 27, 2005). | |
4(8)
|
Note and Warrant Purchase Agreement dated March 3, 2006 among CanArgo Energy Corporation and the Purchasers party thereto (Incorporated herein by reference from Form 8-K dated March 8, 2006). | |
4(9)
|
Registration Rights Agreement dated March 3, 2006 among CanArgo Energy Corporation and the Purchasers party thereto (Incorporated herein by reference from Form 8-K dated March 8, 2006). | |
10(1)
|
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(2)
|
Management Services Agreement between CanArgo Energy Corporation and Vazon Energy Limited relating to the provisions of the services of Dr. David Robson dated June 29, 2000 (Incorporated herein by reference from March 31, 2000 Form 10-Q). As amended by Deed of Variation of Management Services Agreement between CanArgo Energy Corporation and Vazon Energy Limited dated May 2, 2003 (Incorporated herein by |
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| reference to Form 8-K dated May 13, 2003). | ||
10(3)
|
Tenancy Agreement between CanArgo Energy Corporation and Grosvenor West End Properties dated September 8, 2000 (Incorporated herein by reference from March 31, 2000 Form 10-Q). | |
10(4)
|
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(5)
|
Service Agreement between CanArgo Energy Corporation and Vincent McDonnell dated December 1, 2000 (Incorporated herein by reference from December 31, 2001 Form 10-K). | |
10(6)
|
Sale agreement of CanArgo Petroleum Products Limited between CanArgo Limited and Westrade Alliance LLC dated October 14, 2002. (Incorporated herein by reference from March 31, 2002 Form 10-Q) | |
10(7)
|
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 March 31, 2003 Form 10-Q) | |
10(8)
|
Manavi Termination Agreement dated December 5, 2003 (Incorporated herein by reference from December 31, 2004 Form 10-K) | |
10(9)
|
Agreement between CanArgo Samgori Limited and Georgian Oil Samgori Limited dated January 8, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2004 (Reg. No. 333-115261)). | |
10(10)
|
Consultancy Agreement between CanArgo Energy Corporation and Europa Oil Services Limited dated January 8, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2004 (Reg. No. 333-115261)). | |
10(11)
|
Loan Agreement between CanArgo Energy Corporation and C A Fiduciary Services Limited AS dated April 29, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q). | |
10(12)
|
Oil Sales Agreement between CanArgo Energy Corporation and Primrose Financial Group dated May 5, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q). | |
10(13)
|
Oil Sales Agreement between CanArgo Energy Corporation and Sveti Limited dated April 1, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q). | |
10(14)
|
Agreement dated April 25, 2004 between Ninotsminda Oil Company Limited, Sveti Limited and Primrose Financial Group on the termination of the Crude Oil Sales Agreement dated April 1, 2004 between Ninotsminda Oil Company Limited and Sveti Limited and the terms for the conclusion of a new crude oil sales agreement between Ninotsminda Oil Company Limited and Primrose Financial Group (Incorporated herein by reference from March 31, 2004 Form 10-Q). | |
10(15)
|
Agreement dated March 17, 2004 between CanArgo Acquisition Corporation and Stanhope Solutions Ltd for the sale of Lateral Vector Resources Ltd. (Incorporated herein by |
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| reference from Form 8-K dated May 19, 2004). | ||
10(16)
|
Master Service Contract dated June 1, 2004 between CanArgo Energy Corporation and WEUS Holding Inc. (Incorporated herein by reference from Form 8-K dated June 1, 2004). | |
10(17)
|
Agreement number GN-070/RIG/NOC dated 21 June, 2004 between Ninotsminda Oil Company Limited and Great Wall Drilling Company Limited (Incorporated herein by reference from Form 8-K dated June 21, 2004). | |
10(18)
|
Agreement between Ninotsminda Oil Company Limited and Saipem S.p.A. dated January 27, 2005 (Incorporated herein by reference from Form 8-K dated January 27, 2005). | |
10(19)
|
Agreement between Ninotsminda Oil Company Limited and Primrose Financial Group dated February 4, 2005 (Incorporated herein by reference from Form 8-K dated February 4, 2005). | |
10(20)
|
Termination Agreement between Ninotsminda Oil Company Limited and Primrose Financial Group dated February 4, 2005 (Incorporated herein by reference from Form 8-K dated February 4, 2005). | |
10(21)
|
Subsidiary Guaranty dated July 25, 2005 by and among Ninotsminda Oil Company Limited, CanArgo (Nazvrevi) Limited, CanArgo Norio Limited, CanArgo Limited, CanArgo Samgori Limited, Tethys Petroleum Investments Limited and CanArgo Ltd for the benefit of the holders of the Senior Secured Notes (Incorporated herein by reference from Form 8-K dated July 27, 2005). | |
10(22)
|
Security Agreement dated July 25, 2005 among Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K dated July 27, 2005). | |
†*10(23)
|
Form of Management Services Agreement for Richard J. Battey, Chief Financial Officer dated May 10, 2005 | |
10(24)
|
Agreement dated July 25, 2005 among CanArgo Limited and Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K dated July 27, 2005). | |
10(25)
|
Security Interest Agreement (Securities) dated July 25, 205 among CanArgo Ltd, CanArgo Limited, Ingalls & Snyder LLC as Security Agent for the Secured Parties (Incorporated herein by reference from Form 8-K dated July 27, 2005). | |
10(26)
|
Security Interest Agreement (Securities) dated July 25, 2005 among Tethys Petroleum Investments Limited, CanArgo Limited, Ingalls & Snyder LLC, as Security Agent for the Secured Parties and the Secured Parties (Incorporated herein by reference from Form 8-K dated July 27, 2005). | |
10(27)
|
Security Interest Agreement (Bank Account) dated July 25, 2005 by and among CanArgo Energy Corporation, Ingalls & Snyder LLC, as Security Agent for the Secured Parties and the Secured Parties (Incorporated herein by reference from Form 8-K dated July 27, 2005). | |
10(28)
|
Subordinated Subsidiary Guaranty dated March 3, 2006 by and among Ninotsminda Oil Company Limited, CanArgo (Nazvrevi) Limited, CanArgo Norio Limited, CanArgo Limited, Tethys Petroleum Investments Limited, Tethys Kazakhstan Limited and CanArgo Ltd for the benefit of the holders of the Subordinated Notes (Incorporated herein by |
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| reference from Form 8-K dated March 8, 2006). | ||
10(29)
|
Waiver, Consent and Amendment Agreement dated March 3, 2006 by and among CanArgo Energy Corporation and the Purchasers party thereto (Incorporated herein by reference from Form 8-K dated March 8, 2006). | |
10(30)
|
Gas Supply Contract between BN Munai LLP and Gaz Impex S.A. LLP dated January 5, 2006 (Incorporated herein by reference from Form 8-K dated January 5, 2006) | |
10(31)
|
Memorandum of Understanding dated as of March 2, 2006 by and between the Ministry of Energy of Georgia and CanArgo Energy Corporation (Incorporated herein by reference from Form 8-K dated March 8, 2006) | |
†10(32)
|
Form of Management Service Agreement for Elizabeth Landles, Executive Vice President and Corporate Secretary dated February 18, 2004 | |
14
|
Code of Ethics (Incorporated herein by reference from December 31, 2004 Form 10-K). | |
21
|
List of Subsidiaries (Incorporated herein by reference from June 30, 2005 Form 10-Q) | |
†23(a)
|
Consent of L. Soldinger Associates, LLC, Independent Registered Public Accountants | |
†23(c)
|
Consent of Oilfield Production Consultants (OPC) Limited, Independent Petroleum Consultants. | |
†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(1)
|
Section 1350 Certification of Chief Executive Officer. | |
†32(2)
|
Section 1350 Certification of Chief Financial Officer. |
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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)
(Registrant)
By:
|
/s/ Richard Battey | Date: March 16, 2006 | ||||
| Chief Financial Officer | ||||||
| (Principal Financial and Accounting 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: March 16, 2006 | ||||
| David Robson, Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer) | ||||||
By:
|
/s/ Vincent McDonnell | Date: March 16, 2006 | ||||
| Vincent McDonnell, Chief Operating Officer and Director | ||||||
By:
|
/s/ Michael Ayre | Date: March 16, 2006 | ||||
| Michael Ayre, Director | ||||||
By:
|
/s /Russell Hammond | Date: March 16, 2006 | ||||
| Russell Hammond, Director | ||||||
By:
|
/s/ Nils N. Trulsvik | Date: March 16, 2006 | ||||
| Nils N. Trulsvik, Director |
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EXHIBIT INDEX
†*10(23)
|
Form of Management Services Agreement for Richard J. Battey, Chief Financial Officer dated May 10, 2005 | |
†*10(32)
|
Form of Management Services Agreement for Elizabeth Landles, Executive Vice President and Corporate Secretary dated February 18, 2004 | |
†23(a)
|
Consent of LJ Soldinger Associates, LLC, Independent Registered Public Accountants | |
†23(c)
|
Consent of Oilfield Production Consultants (OPC) Limited, Independent Petroleum Consultants. | |
†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(1)
|
Section 1350 Certification of Chief Executive Officer. | |
†32(2)
|
Section 1350 Certification of Chief Financial Officer. |
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CANARGO ENERGY CORPORATION
INDEX TO FINANCIAL STATEMENTS
| F-2 | ||||
| F-3 | ||||
| F-4 | ||||
| F-5 | ||||
| F-6 | ||||
| F-7 | ||||
| F-10 |
F-1
Table of Contents
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 2005 and 2004 have been audited by the independent accounting firm of
L J Soldinger Associates LLC, 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/Richard Battey | |
Chief Executive Officer
|
Chief Financial Officer | |
March 16, 2006 |
F-2
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
CanArgo Energy Corporation
St Peter Port, Guernsey, British Isles
CanArgo Energy Corporation
St Peter Port, Guernsey, British Isles
We have
audited the accompanying consolidated balance sheets of CanArgo Energy Corporation as of
December 31, 2005 and 2004, and the related consolidated statements of operations and comprehensive
income, stockholders’ equity, and cash flows for each of the years in the three-year period ended
December 31, 2005. 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 audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial 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, 2005
and 2004, and its consolidated results of operations, changes in stockholders’ equity and its cash
flows for each of the years in the three-year period ended December 31, 2005 in conformity with
accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of CanArgo Energy Corporation internal control over
financial reporting as of December 31, 2005, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 9, 2005 expressed an unqulaified opinion on
management’s assessment of internal control over financial reporting and an adverse opinion on the
effectiveness of internal control over financial reporting.
L J SOLDINGER ASSOCIATES LLC
Deer Park, Illinois, USA
March 9, 2006
March 9, 2006
F-3
Table of Contents
CANARGO ENERGY CORPORATION
Consolidated Balance Sheets
| December, 31 | ||||||||
| 2005 | 2004 | |||||||
| (Expressed in United States dollars) | ||||||||
ASSETS |
||||||||
Cash and cash equivalents |
$ | 18,540,558 | $ | 24,617,047 | ||||
Restricted cash |
3,181,672 | 1,400,000 | ||||||
Accounts receivable |
414,597 | 2,526,442 | ||||||
Crude oil inventory |
886,250 | 253,858 | ||||||
Prepayments |
4,379,553 | 1,517,836 | ||||||
Assets held for sale |
600,000 | 600,000 | ||||||
Other current assets |
150,712 | 121,610 | ||||||
Total current assets |
$ | 28,153,342 | $ | 31,036,793 | ||||
Capital assets, net (including
unevaluated amounts of
$50,644,999 and
$25,102,945, respectively) |
119,048,049 | 72,995,666 | ||||||
Prepaid financing fees |
246,910 | 648,507 | ||||||
Investments in and advances to
oil and gas and other
ventures — net |
— | 478,632 | ||||||
Total Assets |
$ | 147,448,301 | $ | 105,159,598 | ||||
LIABILITIES AND STOCKHOLDERS’
EQUITY |
||||||||
Accounts payable — trade |
$ | 5,754,882 | $ | 2,331,945 | ||||
Loans payable |
964,142 | 1,500,000 | ||||||
Deposits |
— | 3,080,839 | ||||||
Accrued liabilities |
6,356,623 | 172,117 | ||||||
Total current
liabilities |
$ | 13,075,647 | $ | 7,084,901 | ||||
Long term debt |
25,000,000 | 832,165 | ||||||
Other non current liabilities |
1,001,041 | — | ||||||
Provision for future site
restoration |
523,000 | 422,000 | ||||||
Total Liabilities |
$ | 39,599,688 | $ | 8,339,066 | ||||
Commitments and contingencies |
||||||||
Options with redemption feature |
2,119,530 | 723,280 | ||||||
Stockholders’ equity: |
||||||||
Common stock, par value
$0.10; authorized -
300,000,000 shares;
shares issued, issuable
and outstanding -
222,586,867 at December
31,
2005 and 195,212,089 at
December 31, 2004 |
22,258,685 | 19,521,208 | ||||||
Capital in excess of par
value |
202,892,303 | 183,418,338 | ||||||
Deferred compensation
expense |
(2,220,399 | ) | (1,976,102 | ) | ||||
Accumulated deficit |
(117,201,506 | ) | (104,866,192 | ) | ||||
Total stockholders’
equity |
$ | 105,729,083 | $ | 96,097,252 | ||||
Total Liabilities, Temporary
Equity and Stockholders’ Equity |
$ | 147,448,301 | $ | 105,159,598 | ||||
The accompanying notes are an integral part of the consolidated financial statements
F-4
Table of Contents
CANARGO ENERGY CORPORATION
Consolidated Statements of Operations and Comprehensive Loss
| For Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (Expressed in United States dollars) | ||||||||||||
Operating Revenues from Continuing Operations: |
||||||||||||
Oil and gas sales |
$ | 7,582,375 | $ | 9,574,520 | $ | 7,881,172 | ||||||
Other |
— | — | 223,608 | |||||||||
| 7,582,375 | 9,574,520 | 8,104,780 | ||||||||||
Operating Expenses: |
||||||||||||
Field operating expenses |
2,281,434 | 2,320,756 | 1,051,905 | |||||||||
Direct project costs |
1,458,315 | 1,434,114 | 1,028,682 | |||||||||
Selling, general and administrative |
11,575,826 | 7,324,292 | 3,505,489 | |||||||||
Depreciation, depletion and amortization |
3,275,553 | 2,881,020 | 3,294,086 | |||||||||
Impairment of oil and gas properties, ventures and other assets |
— | 174,812 | — | |||||||||
Income on dispositions |
— | (1,606,274 | ) | (616,741 | ) | |||||||
| 18,591,128 | 12,528,720 | 8,263,421 | ||||||||||
Operating Loss from Continuing Operations |
(11,008,753 | ) | (2,954,200 | ) | (158,641 | ) | ||||||
Other Income (Expense): |
||||||||||||
Interest, net |
(1,069,724 | ) | (902,130 | ) | (35,386 | ) | ||||||
Foreign exchange gains (losses) |
14,450 | (447,455 | ) | (511,370 | ) | |||||||
Other |
(116,271 | ) | (790,689 | ) | (123,541 | ) | ||||||
Equity Loss from investments |
(155,016 | ) | (205,230 | ) | 65,544 | |||||||
Total Other Expense |
(1,326,561 | ) | (2,345,504 | ) | (604,753 | ) | ||||||
Loss from Continuing Operations Before Taxes |
(12,335,314 | ) | (5,299,704 | ) | (763,394 | ) | ||||||
Income taxes |
— | — | — | |||||||||
Minority interest in loss of consolidated subsidiaries |
— | — | 7,406 | |||||||||
Loss from Continuing Operations |
(12,335,314 | ) | (5,299,704 | ) | (755,988 | ) | ||||||
Net Income (Loss) from Discontinued Operations, net of taxes and
minority interest |
— | 542,210 | (6,607,517 | ) | ||||||||
Loss Before Cumulative Effect of Change in Accounting Principle |
(12,335,314 | ) | (4,757,494 | ) | (7,363,505 | ) | ||||||
Cumulative effect of change in accounting principle |
— | — | 41,290 | |||||||||
Net Loss |
$ | (12,335,314 | ) | $ | (4,757,494 | ) | $ | (7,322,215 | ) | |||
Weighted average number of
common shares outstanding |
||||||||||||
- Basic |
211,586,953 | 134,005,490 | 99,432,000 | |||||||||
- Diluted |
211,586,953 | 134,005,490 | 99,432,000 | |||||||||
Basic and Diluted Net Loss Per Common Share |
||||||||||||
- from continuing operations |
$ | (0.06 | ) | $ | (0.04 | ) | $ | (0.01 | ) | |||
- from discontinued operations |
$ | — | $ | — | $ | (0.07 | ) | |||||
- cumulative effect of change in accounting principle, net of Income tax |
$ | — | $ | — | $ | — | ||||||
Basic and Diluted Net Loss Per Common Share After Cumulative Effect
of Change in Accounting Principle |
$ | (0.06 | ) | $ | (0.04 | ) | $ | (0.08 | ) | |||
Other Comprehensive Income (Loss): |
||||||||||||
Foreign currency translation |
— | 146,463 | (151,131 | ) | ||||||||
Comprehensive Loss |
$ | (12,335,314 | ) | $ | (4,611,031 | ) | $ | (7,473,346 | ) | |||
The accompanying notes are an integral part of the consolidated financial statements
F-5
Table of Contents
CANARGO
ENERGY CORPORATION
Consolidated Statements of Cash Flows
Consolidated Statements of Cash Flows
| For Year Ended December 31, | |||||||||||||||||||
| 2005 | 2004 | 2003 | |||||||||||||||||
| (Expressed in United States dollars) | |||||||||||||||||||
Operating activities: |
|||||||||||||||||||
Loss from continuing operations |
(12,335,314 | ) | (5,299,704 | ) | (755,988 | ) | |||||||||||||
Adjustments to reconcile net loss from continuing operations to net
cash generated (used) by operating activities: |
|||||||||||||||||||
Non-cash stock compensation expense |
2,374,578 | 1,395,035 | 276,507 | ||||||||||||||||
Non-cash interest expense and amortization of debt discount |
1,277,878 | 653,313 | 14,000 | ||||||||||||||||
Non-cash reduction in selling, general and administrative expenses |
— | (300,000 | ) | — | |||||||||||||||
Non-cash debt extinguishment expense |
— | 349,923 | — | ||||||||||||||||
Common stock issued for services |
53,600 | 118,400 | — | ||||||||||||||||
Non-cash
miscellaneous expenses |
193,000 | — | |||||||||||||||||
Depreciation, depletion and amortization |
3,275,553 | 2,881,020 | 3,294,086 | ||||||||||||||||
Impairment of oil and gas ventures and other assets |
— | 174,812 | — | ||||||||||||||||
Equity loss (income) from investments |
155,016 | 205,230 | (65,544 | ) | |||||||||||||||
Gain on dispositions |
— | (1,606,274 | ) | (616,741 | ) | ||||||||||||||
Allowance for doubtful accounts |
145,829 | 5,803 | 170,000 | ||||||||||||||||
Minority interest in loss of consolidated subsidiaries |
— | — | (7,406 | ) | |||||||||||||||
Changes in assets and liabilities: |
|||||||||||||||||||
Restricted cash |
(1,781,672 | ) | (1,400,000 | ) | — | ||||||||||||||
Accounts receivable |
2,146,016 | (2,370,473 | ) | (81,169 | ) | ||||||||||||||
Inventory |
(632,392 | ) | 214,935 | (309,897 | ) | ||||||||||||||
Prepayments |
(202,801 | ) | (12,560 | ) | 54,767 | ||||||||||||||
Other current assets |
(29,102 | ) | 84,922 | (30,581 | ) | ||||||||||||||
Accounts payable |
757,401 | 1,848,664 | 78,047 | ||||||||||||||||
Deferred revenue |
(3,080,839 | ) | (449,255 | ) | 2,228,899 | ||||||||||||||
Income taxes payable |
— | (97,500 | ) | 36,500 | |||||||||||||||
Accrued liabilities |
(585,541 | ) | (177,370 | ) | 145,442 | ||||||||||||||
Net cash generated (used) by operating activities |
(8,268,790 | ) | (3,781,078 | ) | 4,430,921 | ||||||||||||||
Investing activities: |
|||||||||||||||||||
Capital expenditures |
(33,450,583 | ) | (11,190,290 | ) | (5,283,388 | ) | |||||||||||||
Proceeds from disposition of investments |
— | — | 1,000,000 | ||||||||||||||||
Proceeds from disposition of subsidiary |
— | 2,107,001 | — | ||||||||||||||||
Acquisitions, net of cash acquired |
609,553 | — | — | ||||||||||||||||
Investments in oil and gas and other ventures |
— | (383,862 | ) | — | |||||||||||||||
Repayments from oil and gas and other ventures |
— | — | 114,428 | ||||||||||||||||
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 |
(855,466 | ) | (499,933 | ) | (804,732 | ) | |||||||||||||
Net cash used in investing activities |
(33,696,496 | ) | (9,967,084 | ) | (3,228,768 | ) | |||||||||||||
Financing activities: |
|||||||||||||||||||
Proceeds from sale of common stock |
4,429,303 | 37,999,516 | — | ||||||||||||||||
Share issue costs |
(191,876 | ) | (4,543,845 | ) | — | ||||||||||||||
Deferred offering costs |
— | (309,318 | ) | — | |||||||||||||||
Advances from joint venture partner |
— | 290,000 | 1,427,612 | ||||||||||||||||
Payments of joint venture obligations |
— | (1,063,146 | ) | (654,466 | ) | ||||||||||||||
Proceeds from loans |
39,237,000 | 3,806,000 | 380,000 | ||||||||||||||||
Repayment of loans |
(7,200,000 | ) | (1,408,179 | ) | (277,821 | ) | |||||||||||||
Deferred loan costs |
(385,630 | ) | — | — | |||||||||||||||
Net cash provided by financing activities |
35,888,797 | 34,771,028 | 875,325 | ||||||||||||||||
Discontinued activities: |
|||||||||||||||||||
Net cash generated (used) by operating activities |
— | — | (1,456,303 | ) | |||||||||||||||
Net cash used in investing activities |
— | 121,929 | (348,546 | ) | |||||||||||||||
Net cash provided by financing activities |
— | — | 1,614,622 | ||||||||||||||||
Net cash flows from assets and liabilities held for sale |
— | 121,929 | (190,227 | ) | |||||||||||||||
Net increase (decrease) in cash and cash equivalents |
(6,076,489 | ) | 21,144,795 | 1,887,252 | |||||||||||||||
Cash and cash equivalents, beginning of period |
24,617,047 | 3,472,252 | 1,585,000 | ||||||||||||||||
Cash and cash equivalents, end of period |
$ | 18,540,558 | $ | 24,617,047 | $ | 3,472,252 | |||||||||||||
The accompanying notes are an integral part of the consolidated financial statements
F-6
Table of Contents
CANARGO ENERGY CORPORATION
Consolidated Statements of Stockholders’ Equity — continued
| Common Stock | ||||||||||||||||||||||||||||
| Number of | ||||||||||||||||||||||||||||
| Shares | Additional | Deferred | Foreign | Total | ||||||||||||||||||||||||
| Issued and | Paid-In | Compensation | Currency | Accumulated | Stcokholders’ | |||||||||||||||||||||||
| Issuable | Par Value | Capital | Expense | Translation | Deficit | Equity | ||||||||||||||||||||||
| Expressed in United States Dollars | ||||||||||||||||||||||||||||
Balance, December 31st 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 Sept 2003 |
6,000,000 | 600,000 | 540,000 | 1,140,000 | ||||||||||||||||||||||||
Shares issued pursuant to
Manavi buy-out Dec 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 | |||||||||||||
Current year adjustment |
146,463 | 146,463 | ||||||||||||||||||||||||||
Exercise of stock options and warrants |
3,815,084 | 381,508 | 118,008 | 499,516 | ||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity
Distribution agreement (Cornell Capital) |
163,218 | 16,322 | 79,446 | 95,768 | ||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity
Distribution agreement (Newbridge Securities) |
||||||||||||||||||||||||||||
| 30,799 | 3,080 | 15,091 | 18,171 | |||||||||||||||||||||||||
Shares Issued pursuant to consultancy
agreement (Europa Oil Services Ltd) |
4,000,000 | 400,000 | 3,480,000 | 3,880,000 | ||||||||||||||||||||||||
Shares Issued pursuant to consultancy
agreement (CEOCast) |
80,000 | 8,000 | 49,600 | 57,600 | ||||||||||||||||||||||||
Issue of Warrants to purchase 1 million shares
pursuant to a loan agreement |
— | — | 754,000 | 754,000 | ||||||||||||||||||||||||
Issue of Warrants to purchase 300,000 shares
pursuant to a Loan agreement |
— | — | 197,040 | 197,040 | ||||||||||||||||||||||||
Stock based compensation under SFAS 148 |
— | — | 2,647,858 | (1,976,102 | ) | 671,756 | ||||||||||||||||||||||
Shares Issued pursuant to Standby Equity
Distribution agreement (Cornell Capital) |
425,000 | 42,500 | 182,750 | 225,250 | ||||||||||||||||||||||||
Issue of Warrants to purchase 1 million shares
pursuant to a Loan agreement |
— | — | 263,786 | 263,786 | ||||||||||||||||||||||||
Shares Issued pursuant to Global public
offering |
75,000,000 | 7,500,000 | 30,000,000 | 37,500,000 | ||||||||||||||||||||||||
Share issue costs |
— | — | (4,543,845 | ) | (4,543,845 | ) | ||||||||||||||||||||||
Shares Issued pursuant to CanArgo Norio
Limited Buy-Out |
6,000,000 | 600,000 | 3,720,000 | 4,320,000 | ||||||||||||||||||||||||
Shares Issueable pursuant to consultancy
agreement (CEOCast) |
80,000 | 8,000 | 52,800 | 60,800 | ||||||||||||||||||||||||
Net Loss |
— | — | — | — | (4,757,494 | ) | (4,757,494 | ) | ||||||||||||||||||||
Total, December 31, 2004 |
195,212,089 | $ | 19,521,208 | $ | 183,418,338 | $ | (1,976,102 | ) | — | $ | (104,866,192 | ) | $ | 96,097,252 | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements
F-7
Table of Contents
CANARGO ENERGY CORPORATION
Consolidated
Statements of Stockholders’ Equity — Continued
| Common Stock | ||||||||||||||||||||||||||||
| Number of | ||||||||||||||||||||||||||||
| Shares | Additional | Deferred | Foreign | Total | ||||||||||||||||||||||||
| Issued and | Paid-In | Compensation | Currency | Accumulated | Stcokholders’ | |||||||||||||||||||||||
| Issuable | Par Value | Capital | Expense | Translation | Deficit | Equity | ||||||||||||||||||||||
| Total, December 31, 2004 | 195,212,089 | $19,521,208 | $183,418,338 | $(1,976,102) | — | $(104,866,192) | $96,097,252 | |||||||||||||||||||||
| Expressed in United States Dollars | ||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
380,836 | 38,084 | 469,514 | 507,598 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
335,653 | 33,565 | 458,837 | 492,402 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Exercise of stock options |
1,067,833 | 106,783 | 255,850 | 362,633 | ||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
344,758 | 34,476 | 498,072 | 532,548 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
370,599 | 37,060 | 562,940 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
381,170 | 38,117 | 561,883 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
495,745 | 49,574 | 550,426 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Exercise of stock options |
1,570,000 | 157,000 | 11,000 | 168,000 | ||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
552,639 | 55,264 | 544,736 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
473,634 | 47,363 | 552,637 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
837,054 | 83,705 | 516,295 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
813,670 | 81,367 | 518,633 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
872,854 | 87,285 | 512,715 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
847,458 | 84,746 | 515,254 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issueable pursuant to consultancy |
80,000 | 8,000 | 45,600 | 53,600 | ||||||||||||||||||||||||
agreement (CEOCast) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
801,068 | 80,107 | 519,893 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
812,348 | 81,235 | 518,765 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Tethys buy-out |
11,000,000 | 1,100,000 | 7,260,000 | 8,360,000 | ||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
639,591 | 63,959 | 536,041 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
596,421 | 59,642 | 540,358 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
613,246 | 61,325 | 538,675 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
630,120 | 63,012 | 536,988 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
669,568 | 66,957 | 533,043 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
761,325 | 76,133 | 523,867 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
Shares Issued pursuant to Standby Equity |
783,188 | 78,319 | 521,681 | 600,000 | ||||||||||||||||||||||||
Distribution agreement (Cornell Capital) |
||||||||||||||||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements
F-8
Table of Contents
CANARGO ENERGY CORPORATION
Consolidated
Statements of Stockholders’ Equity — continued
Exercise of stock options |
360,000 | 36,000 | 481,320 | 517,320 | ||||||||||||||||||||||||
Exercise of stock options |
284,000 | 28,400 | 352,950 | 381,350 | ||||||||||||||||||||||||
Stock based compensation under SFAS 148 |
— | — | 1,222,625 | (244,297 | ) | 978,328 | ||||||||||||||||||||||
Share issue costs |
— | — | (1,186,633 | ) | (1,186,633 | ) | ||||||||||||||||||||||
Net Loss |
— | — | — | (12,335,314 | ) | (12,335,314 | ) | |||||||||||||||||||||
Total, December 31, 2005 |
222,586,867 | $ | 22,258,685 | $ | 202,892,303 | $ | (2,220,399 | ) | — | $ | (117,201,506 | ) | $ | 105,729,083 | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements
F-9
Table of Contents
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”, “we”, “our”, “us”), is an integrated oil and gas company
operating predominately within Georgia and the Republic of Kazakhstan. Our principal activity is
the acquisition of interests in and development of crude oil and natural gas fields.
In 2002 and 2003, we approved a plan to sell CanArgo Standard Oil Products Limited (“CSOP”),
Lateral Vector Resources Inc. (“LVR”), the Georgian American Oil Refinery Limited (“GAOR”) and a
generating power unit. During 2004, CSOP, GAOR and LVR were sold. The results of these operations
have been classified as discontinued for all periods presented. Net income (loss) from discontinued
operations is disclosed net of taxes and minority interest for all periods presented. The
generating power unit has been classified as “Assets held for sale” for all periods presented.
In the years ended December 31, 2005 and 2004 the Company’s revenues from its Georgian operations
did not cover the costs of its operations. At December 31, 2005 the Company had unrestricted cash
and cash equivalents of approximately $18,541,000. In 2005 the Company experienced a net cash
outflow from operations of approximately $8,269,000. In addition, the Company has a planned
capital expenditure budget in 2006 of approximately $20,000,000 in Georgia. In the event that the
exploration and development wells currently undergoing or waiting to undergo production testing in
Georgia fail to produce enough commercially available quantities of oil and or gas, the Company may
not have sufficient working capital and may have to delay or suspend its capital expenditure plans
and possibly make cutbacks in its operations. There are no assurances the Company could raise
additional sources of equity financing and because of the covenants contained in the Senior Secured
Convertible Notes (see Note 11) the Company is restricted from incurring additional debt
obligations unless it receives consent from at least 51% of the noteholders, which cannot be
assured.
In March 2006 with the private placement of the $13,000,000 Senior Subordinated Convertible
Guaranteed Notes we have fully funded the currently planned budget for our operating and
development expenditure in Kazakhstan for 2006.
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.
Certain items for prior years in the consolidated financial statements have been reclassified to
conform to the current year’s presentation. There was no effect on the reported net loss as a
result of these reclassifications.
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 we exercises significant influence are accounted for using the equity method. Entities in
which we do not have significant influence are accounted for using the cost method.
Equity Method
Under the guidance of Emerging Issue Task Force D-46, “Accounting for Limited Partnership
Investments” the Company uses the equity method to account for all of its limited partnership
interests in oil and gas ventures that exceed 5% and is less than 50%. Under the equity method of
accounting, the Company’s proportionate share of the investees’ net income or loss is included in
“Equity Income from Investments” in the consolidated statements of operations. Any excess of the
carrying value of the investment and loan advances over the underlying net equity of the investee
is evaluated each reporting period for impairment.
In accordance with Emerging Issues Task Force (“EITF”) 98-13 “Accounting by an Equity Method
Investor for Investee Losses When the Investor has Loans to and Investments in Other Securities of
the Investee,” and 99-10 “Percentage Used to Determine the Amount of Equity Method Losses,” in the
event that minority interest losses exceed stockholders’ equity for the majority interest, the
excess minority interest loss is recorded against loan advances or other forms of equity invested
in the subsidiary. In accordance with the requirements of EITF 99-10 the Company has chosen to
account for the percentage of losses to be applied to reduce its loan balance based on its
ownership percentage and not on its relative percentage of investment in each security class across
all investors.
F-10
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
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, judgements 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.
Management believes that it is reasonably possible the following material estimates affecting
the financial statements could significantly change in the coming year: (1) estimates of proved oil
and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas
properties, and (3) estimates of future dismantlement and restoration costs.
Cash and Cash Equivalents
Cash and cash equivalents, of which include all liquid investments with an original maturity
of three months or less are considered to be cash equivalents.
Fair Value of Financial Instruments
The carrying amounts reflected in the consolidated balance sheets for cash and equivalents,
short-term receivables and short-term payables approximate their fair value due to the short
maturity of the instruments. The carrying value of the long-term note payable with detachable
warrants reflects a discount for the value of warrants and was $964,142 at December 31, 2005. The
face amount of the note payable is $1,050,000. The carrying value of the short-term debt
approximates fair value as the debt bears interest at a market rate.
Concentration of Credit Risk
Although our cash and temporary investments and accounts receivable are exposed to potential
credit loss, we do 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 us.
As an independent oil and gas producer, our revenue, profitability and future rate of growth
are substantially dependent upon prevailing prices for oil and gas, which are dependent upon
numerous factors beyond our control, such as economic, political and regulatory developments and
competition from other sources of energy. The energy markets have historically been very volatile,
and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in
the future. A substantial or extended decline in oil and gas prices could have a material adverse
effect on our financial position, results of operations, cash flows and our access to capital and
on the quantities of oil and gas reserves that may be economically produced.
We
sold approximately 90%, 82% and 92% of our oil to 2 customers, 4
customers and 3 customers respectively in 2005, 2004 and 2003.
Management believes that due to the global nature of the market for
oil and gas, that the loss of any customer or group of customers
would not have a material effect on its sales.
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.
Accounts Receivable and 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 we determine
that amounts are not collectable and recoveries of previously written-off accounts are recorded
when collected.
F-11
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
Inventories
Inventories of crude oil are valued at the lower of average cost or net realizable value.
Inventory costs include expenditures and other charges (including depreciation, depletion and
amortization) directly and indirectly incurred in bringing the inventory to its existing condition
and location. Selling expenses and general and administrative expenses are reported as period costs
and excluded from inventory cost.
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 the full cost method, all acquisition, exploration and development costs, including certain
directly related employee costs incurred for the purpose of finding oil and gas are capitalized and
accumulated in pools on a country–by–country basis. Capitalized costs include the cost of drilling
and equipping productive wells, including the estimated costs of dismantling and abandoning these
assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical
costs, delay rentals and costs related to such activities. Employee costs associated with
production and other operating activities and general corporate activities are expensed in the
period incurred.
Where proved reserves are established, capitalized costs are limited on a country–by–country
basis (the ceiling test). The ceiling test is calculated as the sum of the present value of future
net cash flows related to estimated production of proved reserves, using end–of–the-current-period
prices, discounted at 10%, and takes into account expected future costs to develop proved reserves,
and operating expenses and income taxes. Under the ceiling test, if the capitalized cost of the
full cost pool exceeds the ceiling limitation, the excess is charged as an impairment expense.
Unit-of-production depreciation is applied to capitalized cost of the full cost pool.
Unit-of-production rates are based on the amount of proved developed reserves of oil, gas and other
minerals that are estimated to be recoverable from existing facilities using current operating
methods.
We utilize a single cost center for each country where we have operations for amortization
purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas
properties with no gain or loss recognized unless the operations are suspended in the entire cost
center or the conveyance is significant in nature.
The costs of investments in unproved properties and portions of costs associated with major
development projects are excluded from the depreciation, depletion and amortization (“DD&A”)
calculation until the project is evaluated.
Unproved property costs include leasehold costs, seismic costs and other costs incurred during
the exploration phase. In areas where proved reserves are established, significant unproved
properties are evaluated periodically, but not less than annually, for impairment. If a reduction
in value has occurred, these property costs are considered impaired and are transferred to the
related full cost pool. Unproved properties whose acquisition costs
F-12
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
are not individually significant are aggregated, and the portion of such costs estimated to be
ultimately nonproductive, based on experience, is amortized to the full cost pool over an average
holding period.
In countries where the existence of proved reserves has not yet been determined, leasehold
costs, seismic costs and other costs incurred during the exploration phase remain capitalized in
unproved property cost centers until proved reserves have been established or until exploration
activities cease or impairment and reduction in value occurs. If exploration activities result in
the establishment of a proved reserve base, amounts in the unproved property cost center are
reclassified as proved properties and become subject to depreciation, depletion and amortization
and the application of the ceiling test. If exploration efforts in a country are unsuccessful in
establishing proved reserves, it may be determined that the value of exploratory costs incurred
there have been permanently diminished in part or in whole. Therefore, based on the impairment
evaluation and future exploration plans, the unproved property cost centers related to the area of
interest could be impaired, and accumulated costs charged against earnings.
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.
Property and Equipment (CanArgo Standard Oil Products) — Depreciation of property and
equipment at 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
Continuing operations — We recognize revenues when hydrocarbons have been produced and
delivered and payment is reasonably assured.
Discontinued operations — We recognize revenues when goods have been delivered, when services
have been performed, or when hydrocarbons have been produced and delivered and payment is
reasonably assured.
Advances
Advances received by CanArgo from joint venture partners, which are to be spent by us on
behalf of the joint venture partners, are classified as payables and reflected in our cash flow
statement within finance activities. When the cash advances are spent, the payable is reduced
accordingly. These advances do not contribute to our operating profits and are accounted
for/disclosed as balance sheet entries only within cash and payable to joint venture partner.
Foreign Operations
Our future operations and earnings will depend upon the results of our operations in the
Georgia. There can be no assurance that we will be able to successfully conduct such operations,
and a failure to do so would have a material adverse effect on our financial position, results of
operations and cash flows. Also, the success of our 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 we are dependent on international operations, specifically those in Georgia, we
will be subject to various additional political, economic and other uncertainties. Among other
risks, our 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.
F-13
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
Foreign Currency Translation
The U.S. dollar is the functional currency for our upstream 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
We recognize 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.
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.
Dismantlement, Restoration and Environmental Costs
We recognize liabilities for asset retirement obligations associated with tangible long-lived
assets, such as producing well sites, with a corresponding increase in the related long-lived
asset. The asset retirement cost is depreciated along with the property and equipment in the full
cost pool. The asset retirement obligation is recorded at fair value and accretion expense,
recognized over the life of the property, increases the liability to its expected settlement value.
If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded
for both the asset retirement obligation and the asset retirement cost. The Company’s asset
retirement obligations consist of costs related to the plugging of wells, the removal of facilities
and equipment, and site restoration on oil and gas properties. Capitalized costs are depleted as a
component of the full cost pool using the units of production method.
Upon adoption of this standard in 2003 we recorded 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 this
treatment was recorded as a cumulative effect in accounting principle in the period of adoption.
During 2003, we recorded a credit to income for the cumulative effect of change in accounting
principle of $41,290, increased long-term liabilities to recognise our total obligation and
increased net capital assets in accordance with the provisions of SFAS No. 143 to the amount of
$82,000. We did not recognise deferred tax expense 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 our cash
flows as a result of adopting SFAS No. 143. The asset retirement obligation, which is included on
the consolidated balance sheet in provision for future site restoration, was $523,000 at December
31, 2005, which includes $58,800 for retirement obligations related to our acquired
Tethys operations.
F-14
Table of Contents
CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| 2005 | 2004 | |||||||
Beginning balance, January 1 |
$ | 422,000 | $ | 151,000 | ||||
Cumulative effect of change in accounting principle |
— | — | ||||||
New obligations incurred in 2005 |
58,800 | 270,000 | ||||||
Liabilities settled in 2005 |
— | — | ||||||
Accretion of expense |
42,200 | 14,000 | ||||||
Revision in estimates, including timing |
— | (13,000 | ) | |||||
Balance at December 31 |
523,000 | 422,000 | ||||||
Stock-Based Compensation Plans
Effective January 1, 2003, we 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. We elected to utilize the “prospective” method
of transitioning from the intrinsic value to the fair value method of accounting for stock-based
compensation. 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.
In accordance with SFAS 123, compensation expense for awards granted on or after January 1, 2003,
have been measured by the fair value of the award at the date of grant and recognized over the
vesting or requisite service period. The fair value of awards in the form of stock options is
estimated using an option-pricing model.
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 we had accounted for our 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; risk free interest rate of 2.91%; dividend yield 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 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 year ended December 31, 2003:
| For the Year Ended December 31, | ||||
| 2003 | ||||
Net Loss as reported |
$ | (7,322,215 | ) | |
Add: Stock-based compensation cost, net of related tax
effects, included in the determination of net income
As 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 | |||
F-15
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| For the Year Ended December 31, | ||||
| 2003 | ||||
Pro forma net loss |
(7,832,491 | ) | ||
Loss per share |
||||
Basic and diluted – as reported |
(0.08 | ) | ||
Basic and diluted – pro forma |
(0.08 | ) | ||
In December 2004, the Financial Accounting Standards Board (FASB) issued a revised
Statement of Financial Accounting Standards No. 123 (FAS 123R), “Share-based Payment”, which will
become effective for the Company as of January 1, 2006. Adoption of FAS 123R will not materially
change the Corporation’s existing accounting practices or the amount of share-based compensation
recognized in earnings. The Company expects that for options issued
in 2005 and 2004 with graded vesting schedules, that each vesting
tranche will remain unexercised until the expiration of the option
and has thus chosen to amortize compensation costs recorded for those
options using the straight line method.
Recently Issued Pronouncements
In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset
Retirement Obligations,” which clarifies that an entity is required to recognize a liability for
the fair value of a conditional asset retirement obligation if the fair value can be reasonably
estimated even though uncertainty exists about the timing and (or) method of settlement. The
Company is required to adopt Interpretation No. 47 prior to the end of 2006 and its adoption is not
expected to have a significant effect on the Company’s results of operations or financial
condition.
In November 2004, the FASB issued SFAS No. 151 “Accounting for Inventory Costs” that amends
Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting
for abnormal amounts of idle facility expense, freight, handling costs, and wasted material
(spoilage). SFAS 151 requires that those items be recognized as current-period charges regardless
of whether they meet the criterion of “so abnormal” and requires that allocation of fixed
production overheads to the costs of conversion be based on the normal capacity of the production
facilities. The Company is required to adopt SFAS No. 151 in the beginning of 2006 and its adoption
is not expected to have a significant effect on the Company’s results of operations or financial
condition.
In December 2004, the FASB issued SFAS No. 153 “Exchanges of Nonmonetary Assets” that amends
Accounting Principles Board (APB) Opinion No. 29, ”Accounting for Nonmonetary Transactions” and
Amends FAS 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies”, paragraphs
44 and 47(e). ARB No. 29 is based on the principle that exchanges of nonmonetary assets should be
measured based on the fair value of the assets exchanged and SFAS 153 amended ABP 29 to eliminate
the exception for nonmonetary exchanges of similar productive assets and replaced it with a general
exception for exchanges of nonmonetary assets that do not have commercial substance. The Company is
required to adopt SFAS No. 153 for nonmonetary asset exchanges occurring in the first quarter of
2006 and its adoption is not expected to have a significant effect on the Company’s results of
operations or financial condition.
In May 2005, the FASB issued SFAS No. 154 “Accounting Changes and Error Corrections” to
replace ABP No. 20 “Accounting Changes” and SFAS No. 3 “Reporting Accounting Changes in Interim
Financial Statements.” Opinion 20 previously required that most voluntary changes in accounting
principle be recognized by including in net income of the period of the change the cumulative
effect of changing to the new accounting principle. SFAS 154 requires retrospective application to
prior periods’ financial statements of changes in accounting principle, unless it is impracticable
to determine either the period-specific effects or the cumulative effect of the change. When it is
impracticable to determine the period-specific effects of an accounting change on
one or more individual prior periods presented, SFAS 154 requires that the new accounting principle
be applied to the balances of assets and liabilities as of the beginning of the earliest period for
which retrospective
F-16
Table of Contents
CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
application is practicable and that a corresponding adjustment be made to the
opening balance of retained earnings (or other appropriate components of equity or net assets in
the statement of financial position) for that period rather than being reported in an income
statement. When it is impracticable to determine the cumulative effect of applying a change in
accounting principle to all prior periods, SFAS 154 requires that the new accounting principle be
applied as if it were adopted prospectively from the earliest date practicable. SFAS 154 is
effective for accounting changes and corrections of errors made in fiscal years beginning after
December 15, 2005. The implementation of FAS 154 is not expected to have a significant effect on
the Company’s results of operations or financial condition.
In November 2005, accounting standards were revised to provide guidance for determining and
measuring other-than-temporary impairments of debt and equity securities. The new guidance is
effective for reporting periods beginning after December 15, 2005. At December 31, 2005,
available-for-sale investments in our marketable securities had unrealized losses totaling
$0.9 million which are recorded in Other Accumulated Comprehensive Income. We do not believe that
the securities with unrealized losses as of December 31, 2005 currently meet the criteria for
recognizing the loss under existing other-than-temporary guidance.
NOTE 3 – BUSINESS COMBINATIONS
Tetrhys Petroleum Investments Limited
On June 7, 2005, CanArgo made an offer to acquire 55% of the ordinary share capital of Tethys
Petroleum Investments Limited (“Tethys”) which was held by Provincial Securities Limited
(“Provincial”) and Vando International Finance Limited (“Vando”) for consideration of 11,000,000
CanArgo common shares. On June 9, 2005 CanArgo issued 5,500,000 shares to Provincial, of which
Russell Hammond (one of our non-executive directors) is Investment Advisor and 5,500,000 shares to
Vando in connection with this transaction. At June 7, 2005, the closing price of CanArgo total
common stock was $0.76 giving the common stock consideration a market value of $8,360,000 for the
11 million shares. On completion of the acquisition, CanArgo held 100% of the ordinary share
capital of Tethys through its subsidiary CanArgo Limited and Tethys became a wholly-owned
subsidiary of the Company. We have recorded our interest as if the acquisition occurred on June 30,
2005. Tethys’ primary asset was its 70% interest in BN Munai, a Kazakhstan limited partnership.
The purchase price was allocated to the net assets of Tethys as follows:
Cash |
$ | 609,553 | ||
Oil and Gas Properties |
6,418,115 | |||
Other Current Assets |
1,688,294 | |||
Current Liabilities |
(297,162 | ) | ||
Provision for future site restoration |
(58,800 | ) | ||
| $ | 8,360,000 | |||
The principal reason for the purchase was to secure Tethys’ current interests in a proven
gas field and significant exploration areas in western Kazakhstan.
The Company has included the results of operations of Tethys in the consolidated financial
statements starting July 1, 2005.
The following pro forma presentation assumes the Company’s acquisition of Tethys took place on
January 1, 2004. The historical column presents the financial information of the Company for the
periods indicated.
F-17
Table of Contents
CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| Pro Forma | ||||||||||||||||
| Twelve Months Ended December 31, 2005 | ||||||||||||||||
| Historical | Tethys | Adjustments | Combined | |||||||||||||
Revenue |
$ | 7,582,375 | $ | 0 | $ | — | $ | 7,582,375 | ||||||||
Loss from continiung operations |
($ | 12,335,314 | ) | ($ | 215,649 | ) | $ | 155,016 | (1) | ($ | 12,395,947 | ) | ||||
Net (loss) |
($ | 12,335,314 | ) | ($ | 215,649 | ) | $ | 155,016 | ($ | 12,395,947 | ) | |||||
| Basic and diluted loss per share | ($ | 0.06 | ) | |||||||||||||
| Basic and diluted weighted average common shares outstanding | 211,586,953 | |||||||||||||||
| (1) | To add back the equity loss on investment recorded during the first six months of 2005 for the Company’s share of losses prior to acquisition of its majority interest. |
F-18
Table of Contents
CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| Pro Forma | ||||||||||||||||
| Twelve Months Ended December 31, 2004 | ||||||||||||||||
| Historical | Tethys | Adjustments | Combined | |||||||||||||
Revenue |
$ | 9,574,520 | $ | 0 | $ | — | $ | 9,574,520 | ||||||||
Loss from continiung operations |
($ | 5,299,704 | ) | $ | 0 | $ | 0 | ($ | 5,299,704 | ) | ||||||
Net (loss) |
($ | 4,757,494 | ) | $ | 0 | $ | 0 | ($ | 4,757,494 | ) | ||||||
Basic and diluted income per share |
($ | 0.04 | ) | |||||||||||||
| Basic and diluted weighted average common shares outstanding | 134,005,390 | |||||||||||||||
| Pro Forma | ||||||||||||||||
| Twelve Months Ended December 31, 2003 | ||||||||||||||||
| Historical | Tethys | Adjustments | Combined | |||||||||||||
Revenue |
$ | 7,881,172 | $ | 0 | $ | — | $ | 7,881,172 | ||||||||
Loss from continiung operations |
($ | 755,988 | ) | $ | 0 | $ | 0 | ($ | 755,988 | ) | ||||||
Net (loss) |
($ | 7,322,215 | ) | $ | 0 | $ | 0 | ($ | 7,322,215 | ) | ||||||
Basic and diluted income per share |
($ | 0.07 | ) | |||||||||||||
| Basic and diluted weighted average common shares outstanding | 99,432,000 | |||||||||||||||
Kul Bas LLP
In November 2005, CanArgo acquired through its subsidiary BN Munai, 100% of the charter
capital of Kul-Bas LLP, a company registered in Kazakhstan, for consideration of $100,000. Kul-Bas
LLP owns an Exploration contract, which is for a period of 25 years, with an initial six year
exploration period, covering an unexplored area of approximately 2.75 million acres (11,133
km2) surrounding the Akkulka area. The purchase price of the company reflected the fair
value of the unevaluated property and was allocated to unevaluated oil and gas properties.
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
NOTE 4
— RESTRICTED CASH
Restricted cash consisted of the following at December 31:
| 2005 | 2004 | |||||||
Restricted Cash — Escrow |
$ | — | $ | 1,400,000 | ||||
Restricted Cash – Secured deposits |
3,181,672 | — | ||||||
| $ | 3,181,672 | $ | 1,400,000 | |||||
In the first quarter of 2005 we funded a certificate of deposit in the amount of
$3,900,000 to secure the issuance of a letter of credit as required under the rig rental and
drilling contract we entered into with Saipem, S.p.A. Under the terms of the letter of credit
$1,100,000 was released and became unrestricted cash in July 2005. The remaining deposit was due
to become unrestricted in January 2006. The letters of credit were extended until June and August
2006 and will become unrestricted then.
In the third quarter of 2005, we deposited approximately $300,000 to secure the issuance of
a letter of credit as required under the drilling contract we entered into with Baker Hughes
International.
Restricted cash of $1,400,000 at December 31, 2004 related to money placed in a third party
escrow account in October 2004, to fund part of the horizontal development program, of which WEUS
Holding Inc., a subsidiary of Weatherford International Limited (“Weatherford”) was the primary
contractor, at the Ninotsminda and Samgori Fields in Georgia. These funds were disbursed to the
contractor in July 2005 in satisfaction of liabilities for drilling services provided to the
Company in 2005 in accordance with the terms of the escrow agreement.
NOTE 5 — ACCOUNTS RECEIVABLE
Accounts receivable consisted of the following at December 31:
| 2005 | 2004 | |||||||
Trade receivables before allowance for doubtful
debts |
$ | 1,021,868 | $ | 1,081,055 | ||||
Allowance for doubtful debts
|
(1,012,068 | ) | (866,239 | ) | ||||
Due from Samgori PSC partner |
— | 1,057,534 | ||||||
Insurance receivable |
31,755 | 1,047,359 | ||||||
Fees due from underwriters |
180,000 | — | ||||||
Other receivables |
193,042 | 206,733 | ||||||
| $ | 414,597 | $ | 2,526,442 | |||||
Bad debt expense for 2005, 2004 and 2003 was $145,829, $5,803 and $170,000
respectively, and is reflected under other income in the statement of operations.
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
In September 2004, a blow-out occurred at the N100 well on the Ninotsminda Field. Our
insurers will cover 80% of the costs associated with the blow out up to a maximum cover of
$2,500,000. We received $800,000 from our insurers in the second quarter of 2005 in respect of
costs incurred to date. As of December 31, 2005 and 2004, $31,755 and $1,047,359 was recorded as
a receivable, respectively.
Included in receivables as of December 31, 2004 was $1,057,534 due from Georgian Oil Samgori
Limited (“GOSL”) for its share of capital expenditure, on the planned horizontal well drilling
program on the Samgori Field. We funded 100% of the costs which were mainly related to mobilizing
Weatherford to Georgia for the commencement of the horizontal well drilling program. Following
the failure of Weatherford to successfully complete any horizontal sidetrack development wells on
the Ninotsminda Field using Under-Balanced Coiled Tubing Drilling technology, Weatherford
demobilised its equipment and left Georgia in July 2005. These costs have now been transferred to
oil and gas properties.
NOTE 6 — INVENTORY
Inventory of crude oil consisted of the following at December 31:
| 2005 | 2004 | |||||||
Crude oil |
$ | 886,250 | $ | 253,858 | ||||
| $ | 886,250 | $ | 253,858 | |||||
NOTE 7
— PREPAYMENTS
Prepayments consisted of the following at December 31:
| 2005 | 2004 | |||||||
Drilling Contractors |
$ | 4,053,471 | $ | 1,324,147 | ||||
Financing Fees |
115,158 | — | ||||||
Other |
210,924 | 193,689 | ||||||
| $ | 4,379,553 | $ | 1,517,836 | |||||
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
NOTE 8 — CAPITAL ASSETS
Capital assets, net of accumulated depletion, depreciation and amortization (“DD&A”) and
impairment, include the following at December 31, 2005:
| Accumulated | Net | |||||||||||
| DD&A | Capital | |||||||||||
| Cost | And Impairment | Assets | ||||||||||
Oil and Gas Properties |
||||||||||||
Proved properties |
$ | 83,451,848 | $ | (26,033,501 | ) | $ | 57,418,347 | |||||
Unproved properties |
50,644,999 | — | 50,644,999 | |||||||||
| 134,096,847 | (26,033,501 | ) | 108,063,346 | |||||||||
Property and Equipment
|
||||||||||||
Oil and gas related
equipment |
15,453,405 | (5,146,040 | ) | 10,307,365 | ||||||||
Office furniture, fixtures
and
equipment and other |
1,135,601 | (458,263 | ) | 677,338 | ||||||||
| 16,589,006 | (5,604,303 | ) | 10,984,703 | |||||||||
| $ | 150,685,853 | $ | (31,637,804 | ) | $ | 119,048,049 | ||||||
Capital assets, net of accumulated depletion, depreciation and amortization and impairment
(“DD&A”), include the following at December 31, 2004:
| Accumulated | Net | |||||||||||
| DD&A | Capital | |||||||||||
| Cost | And Impairment | Assets | ||||||||||
Oil and Gas Properties |
||||||||||||
Proved properties |
$ | 61,458,503 | $ | (23,382,448 | ) | $ | 38,076,055 | |||||
Unproved properties |
25,102,945 | — | 25,102,945 | |||||||||
| 86,561,448 | (23,382,448 | ) | 63,179,000 | |||||||||
Property and Equipment |
||||||||||||
Oil and gas related equipment |
14,119,443 | (4,693,368 | ) | 9,426,075 | ||||||||
Office furniture, fixtures
and
equipment and other |
689,439 | (298,848 | ) | 390,591 | ||||||||
| 14,808,882 | (4,992,216 | ) | 9,816,666 | |||||||||
| $ | 101,370,330 | $ | (28,374,664 | ) | $ | 72,995,666 | ||||||
We expensed $3,275,553, $2,881,020 and $3,294,086 in respect of depletion, depreciation and
amortization for the years ended December 31, 2005, 2004 and 2003, respectively.
Depletion
(and Depletion per Barrel of Oil Equivalent on a Units of Production
basis) was
$2,651,053 ($18.67), $2,298,218 ($8.45) and $2,634,459 ($6.17) for the years ended December 31,
2005, 2004 and 2003, respectively. All production in the periods presented related to Georgia. Production from our Samgori
Field attracted depletion from the date of acquisition in April 2004 to December 31, 2005.
Production from our Ninotsminda Field attracted depletion for all years presented.
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
Oil and Gas Properties
Ultimate realization of the carrying value of our 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, we 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, we may not recover our carrying value.
In 2005, 2004 and 2003, CanArgo did not need to write-down oil and gas properties due to
the ceiling test.
We generally have the principal responsibility for arranging financing for the oil and gas
properties and ventures in which we have an interest. There can be no assurance, however, that we
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 our
corporate and other activities 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 the Company, such
entities or their respective stockholders or participants.
The consolidated financial statements of CanArgo do not give effect to any additional
impairment in the value of our 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 our financial position, including
realization of assets, results of operations, cash flows and prospects.
Unproved property additions relate to our exploration activity in the period.
We plan to test a substantial portion of our unproved properties for oil and gas in 2006. In the event that
we do not find oil and gas, we could incur substantial impairments were the amounts to exceed our ceiling test.
Costs Not Being Amortised
Oil
and gas property costs not being amortized at December 31, 2005,
for both Georgia and Kazakhstan by year that the costs
were incurred are as follows:
| Year Ended December 31: | Exploration | Acquisition | Total Capital |
|||||||||
2005 |
$ | 16,133,409 | $ | 9,408,644 | $ | 25,542,054 | ||||||
2004 |
5,282,204 | — | 5,282,204 | |||||||||
2003 |
1,286,388 | — | 1,286,388 | |||||||||
Prior |
13,816,708 | 4,717,646 | 18,534,353 | |||||||||
| $ | 36,518,709 | $ | 14,126,290 | $ | 50,644,999 | |||||||
Unevaluated costs include $23,703,850 for the Ninotsminda Field. $ 2,000,000 was allocated to the
Cretaceous on acquisition prior to 2003. The structure named Manavi was proved to contain oil and
gas by an original exploration well in 2003. This well was sidetracked in 2005 and now awaits
testing. Another appraisal well is drilling ahead and is expected to be completed within
approximately five months.
Unevaluated costs include $16,304,554 for the Norio Field. An exploration well was completed at
the end of 2005 and is currently being prepared for testing. The results of this test will
determine whether further appraisal or development drilling is required.
Unevaluated
costs include $3,802,151 for the Nazvrevi Field. $2,695,145 was allocated to the Field
on acquisition prior to 2003. It also includes the significant Kumisi Cretaceous gas prospect for
which we recently signed a Memorandum of Understanding (“MOU”) which includes the terms of a
take-or-pay natural gas supply contract with the Ministry of Energy of Georgia. This MOU provides
the commercial basis for CNL to move forward with the appraisal of
Kumisi and, based on this and subject to regulatory approval, CNL
plans to spud a well on Kumisi between May and December of this year.
Unevaluated
costs include $9,529,588 for Tethys. $9,408,644 was allocated to unevaluated areas on
acquisition in 2005. In Kazakhstan, we are in the process of completing a five well exploration
program. A number of new gas discoveries have already been made & current plans are to undertake
further exploration drilling in 2006.
Property and Equipment
“Property and Equipment, Oil and gas related equipment” includes related equipment currently
in use by us in the development of the Ninotsminda Field.
NOTE 9 – PREPAID FINANCING FEES
Prepaid financing fees at December 31:
| 2005 | 2004 | |||||||
Commission and Professional fees |
$ | 246,910 | $ | 648,507 | ||||
| $ | 246,910 | $ | 648,507 | |||||
Prepaid financing fees as at December 31, 2005 are corporate finance fees incurred in respect
of the private placement of a $25,000,000 issue of Senior Convertible Secured Loan Notes due July
25, 2009 (“Senior Secured Notes”) with a group of investors, discussed in Note 12. The Company is
amortizing the professional fees incurred in relation to the Senior Secured Notes over the term of
the Senior Secured Notes.
Professional fees of $42,312 were amortized on a straight-line basis in 2005 in
connection with the Senior Secured Notes.
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
As at December 31, 2004, commissions and professional fees related to the additional
Ozturk Long Term Loan with Detachable Warrants and the Standby Equity Distribution Agreement
(“SEDA”) dated February 11, 2004 between CanArgo and Cornell Capital Partners LP (“Cornell
Capital”) were included in Prepaid financing fees.
Fees of $25,000 and $6,250 were amortized on a straight-line basis in 2005 and 2004
respectively in connection with the Ozturk Long Term Loan with Detachable Warrants.
Commissions and professional fees of $604,757 at December 31, 2004 relating to the SEDA dated
(See note 17) February 11, 2004 between CanArgo and Cornell Capital were offset against equity in
March 2005 after sufficient draw downs under the SEDA.
NOTE 10 — INVESTMENT IN AND ADVANCES TO OIL AND GAS AND OTHER VENTURES
As discussed in Note 3, on June 9, 2005 we acquired 100% ownership of Tethys
Petroleum Investments Limited and this entity is now consolidated in our financial statements.
A summary of our net investment in and advances to oil and gas and other ventures consisted of
the following at December 31, 2005 and December 31, 2004:
| 2005 | 2004 | |||||||
Kazakhstan – Through 45% ownership of Tethys
Petroleum
Investments Limited |
$ | — | $ | 683,862 | ||||
Total Investments in and Advances to Oil and Gas
and Other Ventures |
$ | — | $ | 683,862 | ||||
Equity in Profit (Loss) of Oil and Gas and Other
Ventures
Kazakhstan |
$ | — | $ | (205,230 | ) | |||
Cumulative Equity in Profit (Loss) of Oil and Gas
and other ventures |
— | (205,230 | ) | |||||
Total Investments in and Advances to Oil and Gas
and Other
Ventures, Net of Equity Loss |
$ | — | $ | 478,632 | ||||
In September 2003, together with Atlantic Caspian Resources plc (“ACR”), we formed a
limited partnership, Tethys Petroleum Investments Limited (“TPI”) and its wholly owned subsidiary
Tethys Kazakhstan Ltd (“TKI”). As part of this investment, ACR contributed its 70% ownership
interest in Too BN Munai LLP
(“BNM”) into TKI in exchange for 10% ownership of TPI and we committed to funding the day to day
operations and provide management services until third party financing could be arranged in
exchange for 90% ownership of TPI. BNM’s interest centers on the Akkulka exploration area and the
Kyzyloi Gas Field, located in western Kazakhstan, just to the west of the Aral Sea. In the four
years prior to our ownership interest, ACR drilled two deep exploration wells inthe Akkulka area,
which they plugged and abandoned after demonstrating the presence of hydrocarbons, due to funding
limitations on their part. On the same day that we consummated the transaction to create TPI, we
entered into an agreement to sell half of our ownership interest in TPI to Provincial Securities
Limited, an investment company to which Mr. Russell Hammond, one of our non- executive directors,
is an Investment Advisor, in consideration for future services of providing advice to us concerning
funding the
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
development of TPI as we intend to fund the majority of the development of the Kyzyloi
Gas Field through third party financing.
The following day we entered into a Technical Services Agreement and a Loan Agreement with TPI
in which we agreed to provide our managerial expertise and to provide cash advances to fund and
manage the day to day operations of TPI and to provide funding to secure additional site licences
within the vicinity of the Kyzyloi Gas Field. The advances under the agreement, both cash and the
value of services we perform on behalf of TPI, bear interest at the rate of 10% per annum and are
repayable immediately upon the receipt by TPI of third party financing.
On June 9, 2005 we acquired the remaining 55% ownership of Tethys Petroleum Investments Limited,
by issuing 11,000,000 shares of our common stock, valued at $8,360,000, and this entity
is now consolidated in our financial statements. Prior to the this, we chose to use our equity
ownership percentage as the basis for recording our portion of our investees’ loss and therefore
first reduced our investment of $17,366 to zero and then applied the remaining equity losses of
$187,864 to reduce the carrying value of our advances to $478,632.
In 2005 our total investment and advances amounted to $2,900,886 which consisted of cash
investment and advances of $2,750,886 and $150,000 in non-cash management fees. In addition, we
accrued an additional $128,293 in interest on our advances and fees to TPI during 2005.
In 2004 our total investment and advances amounted to $683,862 which consisted of cash
investment and advances of $383,862 and $300,000 in non-cash management fees. In addition, we
accrued an additional $30,215 in interest on our advances and fees to TPI during 2004.
At December 31, 2004 the carrying value of our investment and advances exceeded the underlying
equity in the net assets of the investee by $190,312.
NOTE 11 — LOANS PAYABLE AND LONG TERM DEBT
Loans payable at December 31 consisted of the following:
| 2005 | 2004 | |||||||
Short term loans payable
Promissory Notes |
$ | — | $ | 1,500,000 | ||||
Loan with detachable warrants |
$ | 1,050,000 | $ | — | ||||
Unamortized debt discount |
(85,858 | ) | — | |||||
Loans payable |
$ | 964,142 | $ | 1,500,000 | ||||
Long term debt |
||||||||
Senior Convertible Secured Loan Notes |
$ | 25,000,000 | $ | — | ||||
Long term loans with detachable warrants |
$ | — | $ | 1,050,000 | ||||
Unamortized debt discount |
$ | — | $ | (217,835 | ) | |||
Long term debt |
$ | 25,000,000 | $ | 832,165 | ||||
F-25
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
On April 26, 2004, we entered into two loan and warrant agreements, one with Salahi Ozturk in
which Mr. Ozturk advanced us $1,000,000 in exchange for which we issued to Mr. Ozturk a promissory
note in the amount of $1,000,000 (“Original Loan”) and the other for $306,000 with CA Fiduciary
Services, Ltd Trustee for the SP525A Settlement (“CA”), for which we issued to CA a promissory note
in the amount of $306,000. The notes to Mr. Ozturk and to CA attracted interest at the rate of
7.5% per annum and had a term of six months. In addition to the promissory notes, we issued Mr.
Ozturk a warrant to subscribe up to 1,000,000 shares of our common stock, with an exercise price of
$1.00 per share and a term of five years from the date of grant and we issued to CA a warrant to
subscribe up to 300,000 shares of our common stock, with an exercise price of $1.05 per share and a
term of five years from the date of grant. In the event that the Company were to raise gross
proceeds of at least $10 million in any future equity offering, these notes would become due and
payable within seven days from the closing of the future equity offering. We granted Mr. Ozturk a
lien covering 50% of the revenues of Ninotsminda Oil Company Limited, our 100% owned subsidiary
company, (or its interest in the oil sales contract) as security for repayment of the note.
Under Accounting Principles Board (APB) 14: “Accounting for Convertible Debt and Debt Issued
with Stock Purchase Warrants” we allocated the proceeds from the issuances of the promissory note
and warrants based on a fair value basis of each item. The fair value of the warrants was
determined to be $754,000 for the 1,000,000 warrants issued to Mr. Ozturk and $197,040 for the
300,000 warrants issued to CA and was recorded as a discount to the value of the promissory note.
We used the following assumptions to determine the fair value of the debt and warrants:
| Ozturk Loan | CA Loan | |||||||
Stock price on date of grant |
$ | 0.87 | $ | 0.78 | ||||
Risk free rate of interest |
1.19 | % | 1.15 | % | ||||
Expected life of warrant — months |
60 | 60 | ||||||
Dividend rate |
— | — | ||||||
Historical volatility |
138 | % | 132 | % | ||||
The discounts were amortized to interest expense over the life of the promissory note using
the effective interest method.
On August 27, 2004, we entered into an amended and restated loan and warrant agreement
(“Amended Agreement”) with Mr. Ozturk, amending the loan and warrant agreement between the parties
dated April 26, 2004. Under the terms of the amended loan and warrant agreement, Mr. Ozturk agreed
to cancel the original warrant agreement and to advance the Company an additional $1,050,000
(“Additional Loan”) and extend the maturity date of the original loan to one year from six months.
The Additional Loan is repayable two years and one day from the date of the Amended Agreement
unless it has previously been converted. Corporate finance fees of $50,000 were paid in respect of
the Additional Loan. Interest is payable on the Additional Loan at a rate of 7.5% per annum. The
first interest payment date was December 31, 2004 and included rolled up interest for the period
from April 26, 2004 until December 31, 2004. The Additional Loan was convertible into shares of
CanArgo Common Stock (“Conversion Stock”) at 15% above a market price of $0.60 in effect when the
agreement was reached, subject to customary anti-dilution adjustments. We had the option to force
conversion of
the Additional Loan if our share price exceeded 160% of $0.60 (or $0.96 per share) for a period of
20 consecutive trading days. No conversion is possible for a period of one year from the date of
the Amended Agreement.
In consideration for advancing funds under the Amended Agreement and the Additional Loan, we
issued to Mr. Ozturk a warrant to subscribe for 2,000,000 shares of our common stock at an exercise
price 5% above the market price of our common stock on the date of grant, subject to customary
anti-dilution adjustments. The new warrant was issued on August 27, 2004 and is exercisable for a
period of four years commencing one year from the date of the Amended Agreement. The warrants are
transferable to non-US persons and may only be exercised outside the US. The Company agreed to
register the shares underlying the convertible note and warrants on a
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
“best efforts” basis and that
there were no penalties included in the agreement for failure to register or to keep registered.
Under the provisions of Emerging Issues Task Force (“EITF”) 96-19 “Debtor’s Accounting for a
Modification or Exchange of Debt Instruments”, the Company has treated the Amended Agreement as
extinguishment of the Original Loan due to its determination that the provisions of the Amended
Agreement represented a substantial modification of terms as defined in the EITF. The result of
the extinguishment was for the Company to record a loss on extinguishment in the amount of
$349,923, which represented the unamortized portion of the discount of the original loan on the
date of the Amended Agreement.
The Company’s stock price at the time of the Amended Agreement was $0.51; consequently,
pursuant to EITF 98-5 “Accounting for Convertible Securities with Beneficial Conversion Features or
Contingently Adjustable Conversion Ratios” and EITF 00-27 “Application of Issue No. 98-5 to Certain
Convertible Instruments”, the issuance of the Additional Loan and detachable warrants resulted in a
discount being recorded in the amount of $263,786, which resulted from the relative fair value of
the warrants, as determined using the black-scholes model, and will be amortized over the term of
the Notes using the effective interest method.
We used the following assumptions to determine the fair value of the debt and warrants:
| Additional Loan | ||||
Stock price on date of grant |
$ | 0.51 | ||
Risk free rate of interest |
2.51 | % | ||
Expected life of warrant — months |
48 | |||
Dividend rate |
— | |||
Historical volatility |
108 | % | ||
The discounts are being amortized to expense interest over the life of the loan using the
effective interest method. The effective interest rate was 18.9%. As of December 31, 2005 and
December 31, 2004 we had amortized $177,928 and $45,951 respectively, of the debt discount as
interest expense.
As a result of our completing an equity offering on September 22, 2004, we repaid both the
Original Loan to Mr. Ozturk and the CA loan on September 30, 2004. The payoff of the CA loan
resulted in our expensing the remaining unamortized debt discount for that loan. On payment of the
Original Loan to Mr. Ozturk, the lien covering 50% of the revenues of Ninotsminda Oil Company
Limited was terminated.
On May 19, 2004, we signed a promissory note with Cornell Capital Partners, L.P. (“Cornell
Capital”) whereby Cornell Capital agreed to advance us the sum of $1,500,000. This amount would be
payable on the earlier of 180 days from the date of the promissory note or within 60 days from the
date that the Registration Statement on Form S-3 filed with the SEC on May 6, 2004 (Reg. No.
333-115261) would be declared effective. If the promissory note was not repaid in full when due,
interest would accrue on the outstanding principal owing at the rate of 12% per annum. We paid to
Cornell Capital a commitment fee of 5% of the principal amount of the promissory note which would
be set-off against the first $75,000 of fees payable by us to Cornell Capital under the Standby
Equity Distribution Agreement dated February 11, 2004. The promissory note would become
immediately due and payable upon the occurrence of any of the following: (i) failure to pay the
amount of any principal or interest when due under the promissory note; (ii) any proceedings under
any bankruptcy laws of the United States of America or under any insolvency, reorganization,
receivership, readjustment of debt, dissolution, liquidation or any similar law or statute of any
jurisdiction filed by or against us for all or any part of our property. The Registration
Statement was declared effective on February 3, 2005, we have repaid the promissory note by making
a series of takedowns in February and March 2005 under the Standby Equity Distribution Agreement.
On April 26, 2005 we signed a promissory note with Cornell Capital whereby Cornell Capital
agreed to advance us the sum of $15 million (“Promissory Note”) under the following terms:
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
This $15 million and interest at a rate of 7.5% per annum was payable either in cash or using
the net proceeds of drawdowns under the SEDA, within 270 calendar days from the date of the
Promissory Note. Pursuant to the terms of the Promissory Note, we escrowed 25 requests for advances
under the SEDA each in an amount not less than $600,000 and one advance of $289,726.03
(representing estimated interest) together with 16,273,592 shares of CanArgo common stock, as at the agreement date, 664,966 shares were already in escrow.
The escrow agent released requests every 7 calendar days from May 2, 2005 provided we had not
previously made a payment to Cornell Capital in cash. We had the ability at our sole discretion
upon 24 hours prior written notice to Cornell Capital to repay all and any amounts due under the
Promissory Note in immediately available funds and withdraw any advance notices yet to be effected.
The Promissory Note was repaid in full in cash on August 1, 2005, all escrowed advances
cancelled and 7,260,647 shares of CanArgo common stock were returned from escrow and duly cancelled
on October 5, 2005. On July 25, 2005 notice was given to Cornell Capital to terminate the SEDA with
effect as of August 24, 2005.
In order to ensure timely procurement of long lead items for our drilling program in Georgia
and for working capital purposes during 2004, we entered into a number of loan agreements of which
those outstanding during 2005 are described below.
Senior Secured Convertible Notes: On July 25, 2005, CanArgo completed a private placement of
$25,000,000 in aggregate principal amount of our Senior Secured Convertible Notes due July 25, 2009
(the “Senior Secured Notes”) with a group of private investors arranged through Ingalls & Snyder
LLC of New York City, as Placement Agent, pursuant to a Note Purchase Agreement of even date (the
“Note Purchase Agreement”).
The Company paid approximately $100,000 of legal fees for the Purchasers and a $250,000
arrangement fee to Orion Securities in connection with the Senior Secured Notes.
The unpaid principal balance under the Senior Secured Notes bears interest (computed on the
basis of a 360-day year of twelve 30-day months) (a) at increasing rates ranging from 3% from the
date of issuance to December 31,2005; 10% from January 1, 2006 until December 31, 2006; and 15%
from January 1, 2007 until final payment, payable semi-annually, on June 30 & December 30,
commencing December 30, 2005, until the principal shall have become due and payable, and (b) at 3%
above the applicable rate on any overdue payments of principal and interest,
Pursuant to the provisions of Emerging Issue Task Force 86-15: “Increasing-Rate Debt”), the
Company recognizes interest expense using the effective interest rate method, which results in the
use of a constant interest rate for the life of the Senior Secured Notes. The effective interest
rate is approximately 12.3% per annum. The difference between the interest computed using the
actual interest rate in effect in 2005 (3% per annum) and the effective interest rate (12.3% per
annum) of $1,001,041 as of December 31, 2005 has been accrued as a non-current liability.
The Senior Secured Notes are convertible any time, in whole or in part, at the option of the
Note holder, into shares of CanArgo common stock (“the Conversion Stock”) at a conversion price per
share of $0.90 (the “Conversion Price”), which is subject to customary anti-dilution adjustments.
We may, at our option, upon at least not less than 90 days and not more than 120 days prior
written notice, prepay at any time and from time to time after July 31, 2006, all or any part of
the Senior Secured Notes, in a principal amount of not less than $100,000 at the following
Redemption Prices (expressed as percentages of the principal amount so prepaid): 105% after July
31, 2006; 104% after January 1, 2007; 103% after July 1, 2007; 102% after January 1, 2008; 101%
after July 1, 2008, and 100% after January 1, 2009, together with all accrued and unpaid interest.
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
The Senior Secured Notes are subject to mandatory prepayment due to a change in control of the
Company, as defined by the Note Purchase Agreement.
In connection with the execution and delivery of the Note Purchase Agreement, CanArgo entered
into a Registration Rights Agreement with the Purchasers pursuant to which it agreed to register
the Conversion Stock for resale under the Securities Act and indemnify the purchasers in connection
with the registration.
The Company agreed to register the shares underlying the convertible note and warrants on a
“best efforts” basis and that there were no penalties included in the agreement for failure to
register or to keep registered.
The Senior Secured Notes are secured by substantially all of the assets of the Company and its
subsidiaries and contain certain negative and affirmative covenants and also restricts the ability
of the Company to pay dividends to its common stockholders until the loan and all accrued interest
have been paid or the noteholders elect to convert their loans to common stock. All of the
outstanding shares of Ninotsminda Oil Company Limited have been put into escrow and pledged. The
Company cannot enter into any new borrowing arrangements without the Consent of the noteholders.
Any new subsidiary created by the Company must also become party to the guarantee agreement that
all material subsidiaries of CanArgo have agreed to. (See page 30 “Liquidity and Capital Resources”
section of Item 2 below for a more detailed discussion of covenants).
NOTE 12 — OTHER LIABILITIES
Other liabilities consisted of the following at December 31:
| 2005 | 2004 | |||||||
Prepaid sales and oil sales security deposit |
$ | — | $ | 2,699,644 | ||||
Prepaid licence fees |
— | 80,000 | ||||||
Advanced proceeds from the sale of other assets |
— | 301,195 | ||||||
| $ | — | $ | 3,080,839 | |||||
As of December 31, 2004 prepaid sales and oil sales security deposit included $2,300,000
arising from security deposit payments under an oil sales agreement with Primrose Financial Group
(“Primrose”) dated May 5, 2004. In February 2005, we cancelled the May 2004 oil sales agreement
with Primrose, repaid the security deposit in full and concluded a new oil sales agreement with
Primrose. (See Note 16)
As of December 31, 2004 advanced proceeds from the sale of other assets referred to the sale
of a generator for which the proposed buyer had paid a non-refundable deposit of $301,195. The
proposed buyer failed to meet the sale contract terms resulting in the loss of its deposit in the
third quarter, 2005. The $301,195 has been credited to Other Income. (See Note 20)
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
NOTE 13 — ACCRUED LIABILITIES
Accrued liabilities consisted of the following at December 31:
| 2005 | 2004 | ||||||||
Drilling contractors |
$ | 4,984,261 | $ | — | |||||
Professional fees |
1,005,000 | 93,001 | |||||||
Other |
367,362 | 79,116 | |||||||
| $ | 6,356,623 | $ | 172,117 | ||||||
Included in the amounts due to drilling contractors at December 31, 2005 are amounts invoiced
by Weatherford of $4,931,332. We have formally notified Weatherford that we dispute the validity of
these billings to the Company for work Weatherford performed in the first and second quarter of
2005. We have recorded all amounts billed by Weatherford as of December 31, 2005 pending the
outcome of the dispute resolution which may require referral to the London Court of International
Arbitration for resolution in accordance with the provisions of the contract.
NOTE 14 — MINORITY INTEREST
Tethys Petroleum Investments Limited
In September 2003, together with Atlantic Caspian Resources plc (“ACR”), we formed a limited
partnership, Tethys Petroleum Investments Limited (“TPI”) and its wholly owned subsidiary Tethys
Kazakhstan Ltd (“TKI”). As part of this investment, ACR contributed its 70% ownership interest in
BN Munai LLP (“BN Munai”) into TKI in exchange for 10% ownership of TPI and we committed to funding
the day to day operations and provide management services until third party financing could be
arranged in exchange for 90% ownership of TPI. BN Munai’s interest centers on the Akkulka
exploration area and the Kyzyloi Gas Field, located in western Kazakhstan, just to the west of the
Aral Sea. In the four years prior to our ownership interest, ACR drilled two deep exploration wells
inthe Akkulka area, which they plugged and abandoned after demonstrating the presence of
hydrocarbons, due to funding limitations on their part. On the same day that we consummated the
transaction to create TPI, we entered into an agreement to sell half of our ownership interest in
TPI to Provincial Securities Limited, an investment company to which Mr. Russell Hammond, one of
our non- executive directors, is an Investment Advisor, in consideration for future services of
providing advice to us concerning funding the development of TPI as we intended to fund the
majority of the development of the Kyzyloi Gas Field through third party financing.
The following day we entered into a Technical Services Agreement and a Loan Agreement with TPI
in which we agreed to provide our managerial expertise and to provide cash advances to fund and
manage the day to day operations of TPI and to provide funding to secure additional site licenses
within the vicinity of the Kyzyloi Gas Field. The advances under the agreement, both cash and the
value of services we perform on behalf of TPI, bear interest at the rate of 10% per annum and are
repayable immediately upon the receipt by TPI of third party financing.
On June 9, 2005, through our acquisition of the remaining 55% of Tethys Petroleum Investments Limited (See
Note 3) we acquired a 70% ownership interest in BN Munai (“BN Munai”). BN Munai has only suffered
losses from
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
inception and currently the Company is the only partner funding the current operating
losses, therefore, no minority interest is recorded at December 31, 2005 for the 30% ownership not
under our control. The Company does not expect the minority partners in BN Munai to contribute
funds to the partnership.
Under a loan agreement with BN Munai, TKL will take 100% of the net cash flow of the Kyzyloi
development until the loan is repaid. The principal loan value of $9,389,162 plus interest of
$805,451 was accrued as of the loan agreement date and was originally assigned to TKL from ACR as
part of its exchange of its 70% ownership interest in BN Munai for 10% ownership of TPI. As at
December 31, 2005 the principal amount of the loan outstanding was $15,518,240 plus accrued
interest of $1,287,095. Interest is recorded in line with the loan agreement using a 3 month LIBOR
rate as at the first business day of each quarter.
The Company has recorded 100% of its losses in BN Munai for 2005 as it is the only funding
partner.
CanArgo Norio Limited
In September 2003, CanArgo Norio Limited (“CNL”) 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”). 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 $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 would 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 CNL of $6,500,000.
Coincident with the Georgian Oil farm-in, we concluded a transaction to purchase some of the
minority interests in CNL by a share swap for shares in CanArgo. Through this exchange we acquired
an additional 10.8% interest in CNL increasing our interest to 75%. This maintains our effective
interest in the Norio PSA after Georgian Oil has completed the first stage of the farm-in at
approximately 63.7%. The purchase was achieved by issuing 6,000,000 restricted CanArgo shares to
the minority interest holders in CNL. Of the interests in CNL, 4% were owned by Provincial
Securities Limited, a company to which Mr. Russell Hammond, a non-executive director of CanArgo, is
a financial 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 to CNL we would be obligated to issue a further 3,000,000 restricted shares to
the minority interest holders.
On September 30, 2004 we announced that we had increased our interest in CNL, by buying out
the remaining minority shareholder in that company, NPET Oil Limited. CNL will now become a wholly
owned subsidiary of CanArgo. Following completion of the Georgian Oil farm-in to the Norio PSA,
CNL will hold an 85% interest in the Norio PSA. CNL also holds 100% of the contractor’s interest
in the Block XIG and XIH Production Sharing Contract (“Tbilisi PSC”). This
transaction has therefore increased our interest in the Norio PSA by 21.25%, and by 25% in the
Tbilisi PSC. We have issued 6,000,000 restricted shares of our common stock valued at $4,320,000
to NPET Oil Limited in connection with this transaction. Upon recording this transaction, minority
interest of $1,351,022 was reduced to $0 and oil and gas properties increased by $2,968,978. At the
same time, our commitment under the Norio PSA and the original shareholders’ agreement for a bonus
payment of $800,000 to be paid by us to the other shareholders should commercial production be
obtained from the Middle Eocene or older strata and a second bonus payment of $800,000 should
production exceed 250 tonnes (approximately 1,900 barrels) of oil per day over any 90 day period
has terminated.
CanArgo Standard Oil Products Limited
In September 2002, we approved a plan to sell our interest in CanArgo Standard Oil Products
Limited (“CSOP”), a petroleum product retail business in Georgia, to finance our Georgian and
Ukrainian development projects. In October 2002, we reached agreement with Westrade Alliance LLC,
an unaffiliated company, to sell our wholly owned subsidiary, CanArgo Petroleum Products Limited
(“CPPL”), which held our 50% interest in
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
CSOP for $4,000,000 in an arms-length transaction, with
legal ownership being transferred upon receipt of final payment dueoriginally in August 2003 and
subsequently extended. The final payment of the consideration was received by us in December 2004
at which time we transferred our ownership in CPPL to Westrade Alliance LLC. The results of CSOP’s
operations have been presented for financial statement purposes as discontinued operations (See
Note 20 — Discontinued Operations).
Georgian American Oil Refinery
In November 2000, we completed the acquisition of a 51% interest in the Georgian American Oil
Refinery (“GAOR”), a company which owns a small refinery located at Sartichala, Georgia. From that
date, GAOR became a subsidiary of CanArgo and its results have been included in our consolidated
financial statements. However, due to operational difficulties and changes to the fiscal system in
Georgia, GAOR ceased to operate during 2001.
As a result of the uncertainty as to the ultimate recoverability of the carrying value of the
refinery, we recorded in 2001 a write-down of the refinery’s property, plant and equipment of
approximately $3,500,000. 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, we came to an agreement to sell our interest in the refinery. Our interest
in the refinery was sold in February 2004.
NOTE 15 — COMMITMENTS AND CONTINGENCIES
We have contingent obligations and may incur additional obligations, absolute and contingent,
with respect to the acquisition and development of oil and gas properties and ventures in which we
have interests that require or may require us to expend funds and to issue shares of our Common
Stock.
At December 31, 2005, we had the contingent obligation to issue an aggregate of 187,500 shares
of our Common Stock to Fielden Management Services PTY, Ltd (a third party management services
company), subject to the satisfaction of conditions related to the achievement of specified
performance standards by the Stynawske Field project, an oil field in Ukraine in which we had a
previous interest.
Under the Production Sharing Contract for Blocks XIG and XIH (the
“Tbilisi PSC”) in Georgia our subsidiary CanArgo Norio Limited will acquire additional seismic data
within three years of the effective date of the contract which is September 29, 2003. The total
commitment over the next ten months is $350,000. In the event that no
commercial producing wells are developed, our interest in the PSC
terminates 10 years from commencement in March 2011.
In 2002, the Participation Agreement for the three well exploration program on the Ninotsminda
/Manavi area with AES Gardabani (a subsidiary of AES Corporation) (“AES”) was terminated without
AES earning any rights to any of the Ninotsminda / Manavi area reservoirs. We therefore have 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 will be entitled to recover at the rate of 15% of future gas sales
from the Sub Middle Eocene, net of operating costs, approximately $7,500,000, representing their
prior funding under the Participation Agreement.
In April 2004, we acquired a 50% interest in the Samgori (Block XIB) Production
Sharing Contract (“Samgori PSC”) in Georgia. This interest was acquired from Georgian Oil Samgori
Limited (“GOSL”), a company wholly owned by Georgian Oil, by one of our subsidiaries, CanArgo
Samgori Limited (“CSL”). Under the terms of the agreement dated January 8, 2004, up to 10
horizontal wells will be drilled on the Samgori Field. Completion of well S302, which was funded
100% by us, satisfied our commitment to GOSL under the acquisition agreement. It was planned that
the remainder of the drilling program will be funded jointly by CSL and GOSL, the Contractor
parties, pro rata to their interest in the Samgori PSC. The total cost to us of participating in
the whole program, which was due to be completed by June 2008, was anticipated to be up to
$13,500,000.
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
Furthermore, under the assignment agreement NPL had agreed outstanding costs and expenses of
$37,528,964 in relation to the Samgori PSC which were recoverable by NPL receiving 30% of annual
net profit from the Field until such costs had been fully repaid. After NPL’s costs are repaid from
either Field production or other production in the PSC (in the event that new fields are developed
in areas identified using seismic surveys originally performed by NPL), NPL would continue to
receive 5% of annual net profit.
Under the Samgori PSC, up to 50% of petroleum produced under the contract is allocated to the
Contractor parties for the recovery of the cumulative allowable capital, operating and other
project costs associated with the Samgori Field and exploration in Block XI B (“Cost
Recovery Oil”). The cost recovery pool includes the $37,528,964 costs previously incurred by NPL.
The balance of production (“Profit Oil”) is allocated on a 50/50 basis between the State and the
Contractor parties respectively until capital costs are recovered after which they would receive
30% of Profit Oil. Under the Samgori PSC, Georgian Oil as the State representative in the contract
is entitled to receive up to 250,000 tons (approximately 1.6 million barrels) of oil (“Base Level
Oil”) from a maximum of 50% per calendar quarter of production when the value of the cumulative
Cost Recovery Petroleum, cumulative Profit Oil and cumulative Profit Natural Gas delivered to the
Contractor parties exceeds the cumulative allowable capital, operating and other project costs
including finance costs associated with the Samgori Field and exploration in Block XI B
and the NPL costs. While Base Level Oil is being delivered to Georgian Oil, the Contractor
parties will continue to be entitled to a maximum of 50% of the remaining Profit Oil. The Base
Level Oil is an estimate of the amount of oil that Georgian Oil would have expected to produce from
the contract area had the State not come to a contractual arrangement with the previous Contractor
party in 1996.
Upon completion of the acquisition of an interest in the Samgori PSC we had a contractual
obligation to issue 4,000,000 shares of CanArgo Common Stock to Europa Oil Services Limited
(“Europa”), an unaffiliated company in connection with a consultancy agreement with Europa in
relation to this acquisition. On April 16, 2004 Europa was issued with 4,000,000 restricted shares
of CanArgo Common Stock in an arms length transaction. A further 12,000,000 shares of CanArgo
Common Stock are issuable upon certain production targets being met from future developments under
the Samgori PSC. On March 14, 2006, we signed an agreement with Europa formally terminating the
consultancy agreement.
On February 17, 2006 we issued a press release announcing that our subsidiary, CSL, was not
proceeding with further investment in the Samgori PSC and associated farm-in, and accordingly we
terminated our interest in the Samgori PSC with effect from February 16, 2006. On termination, we
have now been released of all commitments and contingencies that the Company had as at December 31,
2005 in respect of the Samgori PSC.
In May 2004, NOC entered into a crude oil sales agreement with Primrose Financial Group
(“PFG”) to sell its monthly share of oil produced under the Ninotsminda production sharing contract
with a total contractual commitment of 84,000 metric tonnes (636,720 bbls) (“Sales Agreement”). As
security for payment and having the right to lift up to 8,400 metric tonnes (approximately 64,000
bbls) of oil per month, the buyer caused to be paid to NOC $2,300,000 (“Security Deposit”) to be
repaid at the end of the contract period either in money or through the delivery of additional
crude oil equal to the value of the security. The Security Deposit replaces the previous security
payments totalling $2,300,000 which had been originally made available under previous oil sales
agreements.
On February 4, 2005, NOC and PFG agreed to the terminate the Sales Agreement and enter into a
new agreement (“New Agreement”) whereby PFG would receive an immediate repayment of its Security
Deposit and obtain an extended term over which it can purchase crude oil produced from the
Ninotsminda Field while NOC receives better commercial terms for the sale of its production. The
New Agreement has a minimum term of 45 months and contains the following principal terms:
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| (i) | NOC will make available to PFG NOC’s entire share of production from the Ninotsminda Field including a minimum total amount of 68,555 metric tonnes (the “Minimum Contract Quantity”). In the event NOC fails to produce the Minimum Contract Quantity it will have no liability to PFG; | ||
| (ii) | The deliver point shall be at Georgian Oil’s storage reservoirs at Samgori (adjacent to the Ninotsminda Field); | ||
| (iii) | The price for the oil will be in US Dollars per net US Barrel equal to the average of the mean of three quotations in Platts Crude Oil Marketwire© for Brent Dated Quotations minus a discount: ranging for sales (a) up to the Minimum Contract Quantity from $6.00 to $7.50 based on Brent prices per barrel ranging from less than $15.00 to greater than $25.01, respectively; and (b) for sales of oil in excess of the Minimum Contract Quantity at the commercial discount in Georgia for oil of similar quality less $0.10 per barrel with the maximum discount being $6.00 per barrel for export sales and $5.50 per barrel for local sales; and | ||
| (iv) | PFG will pay NOC for the monthly quantity of oil in advance of delivery. |
NOC’s obligations are subject to customary Force Majeure provisions, title and risk of loss
pass to buyer at the delivery point, NOC agrees to assist the buyer to sell the oil locally or
export oil in accordance with applicable law and the Agreement is governed by English law.
In September 2004, a blow-out occurred at the N100 well on the Ninotsminda Field. The Company
currently estimates that the total costs attributable to the blow-out, including compensation and
cleaning of the environment will be $2,000,000. The Company’s insurance policies cover 80% of these
costs up to a maximum of $2,500,000 and the remaining 20% insurance retention being payable by the
Company. On June 3, 2005 we received $800,000, as a first instalment, from our insurance company.
On July 27, 2005, GBOC Ninotsminda, an indirect subsidiary of the Company, received a claim
raised by certain of the Ninotsminda villagers (listed on pages 1 to 76 of the claim) in the
Tbilisi Regional Court in respect of damage caused by the blowout of the N100 well on the
Nintosminda Field in Georgia on September 11, 2004. An additional claim was received in December
2005 thus bringing the relief sought pursuant to both claim to the sum of 32.4 million GEL
(approximately $19.0 million at the exchange rate of GEL to US dollars in effect on December 31,
2005).We believe that we have a meritorious defense to this claim and intend to defend it
vigorously.
On September 12, 2005, WEUS Holding Inc (“WEUS”) a subsidiary of Weatherford International Ltd
lodged a formal Request for Arbitration with the London Court of International Arbitration against
CanArgo Energy Corporation in respect of unpaid invoices for work performed under the Master
Service Contract dated June 1, 2004 between the Company and WEUS for the supply of under-balanced
coil tubing drilling equipment and services during the first and second quarter of 2005. Pursuant
to the Request for Arbitration, WEUS’ demand for relief is $4,931,332.55. Although the Company has
recorded all amounts billed by Weatherford as of December 31, 2005 (see Note 13) the Company is
contesting the claim and intends to file a counterclaim. We believe that we have meritorious
defense to this claim and intend to defend it vigorously.
The
Company has been named in with a group of defendants by former interest holders of the
Lelyakov oil field in the Ukraine. The defendants are seeking damages of approx 600,000 CDN
(approx $514,000 at Dec 31 exchange rates) The former owners of UK-Ran Oil company disposed of
their investment in the field prior to selling the Company to CanArgo. CanArgo believes the claim
against it to be meritless. The Company is unable at this time to determine a potential outcome.
Under the Ninotsminda PSC, Ninotsminda Oil Company Ltd is required to relinquish at least half
of the area then covered by the production sharing contract, but not in 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% whereby the Contractor selects the relinquishment portions.
CanArgo Norio Limited currently owns a 100% interest in the Norio (Block XI C ) and North
Kumisi Production Sharing Agreement (“Norio PSA”), although this interest has
a 25 year term it may be reduced to 85% should the state oil company, Georgian Oil,
exercise an option available to it under
the PSA for a limited period following the
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
submission of a field development plan. As a
contractor party, Georgian Oil would be liable for all costs and expenses in relation to any
interest it may acquire in the PSA. This PSA covers an area of approximately 381,034 acres (1,542
km 2 ), however, it is subject to a 25% relinquishment
every 5 years, commencing in March 2006 whereby the
Contractor selects the relinquishment portions.
Our 2004 Long-Term Stock Incentive Plan (“2004 Plan”) allows for up to 7,500,000 shares of the
Company’s common stock to be issued to officers, directors, employees, consultants and advisors
pursuant to the grant of stock based awards, including qualified and non-qualified stock, options,
restricted stock, stock appreciation rights and other stock based performance awards. Stock
options may be exercised, in whole or in part, by giving written notice of exercise to the
Corporation specifying the number of shares to be purchased. However, in the event of a Change of
Control (as defined in the 2004 Plan) an optionee (other than an optionee who initiated a Change of
Control in a capacity other than as an officer or director of the Corporation) may elect to
surrender all or part of the stock option to the Corporation and to receive in cash an amount equal
to the amount by which the fair market value per share of the Stock on the date of exercise shall
exceed the purchase price per share under the stock option multiplied by the number of shares of
the Stock granted under the stock option as to which the right granted by this proviso shall have
been exercised. As of December 31, 2005, options to acquire an aggregate of 1,454,000 shares of
common stock had been granted under this Plan and were outstanding, 1,214,000 of which are
currently vested.
Lease Commitments — We lease office space under non-cancelable operating lease agreements.
Rental expense for the years ended December 31, 2005, 2004 and 2003 was $456,908, $379,102, and
$395,355 respectively. Future minimum rental payments over the next five years for our lease
obligations as of December 31, 2005, are as follows:
2006 |
$ | 426,604 | ||
2007 |
449,947 | |||
2008 |
355,867 | |||
2009 |
355,867 | |||
2010 |
204,225 | |||
Thereafter |
197,183 | * | ||
| $ | 1,989,693 | |||
| * | This represents payments for 3 years and 9 months after 2010. |
No parent company guarantees have been provided by CanArgo with respect to our contingent
obligations and commitments.
NOTE 16 — OPTIONS WITH REDEMPTION FEATURES
Our 2004 Plan allows for up to 7,500,000 shares of the Company’s common stock to be issued to
officers, directors, employees, consultants and advisors pursuant to the grant of stock based
awards, including qualified and non-qualified stock, options, restricted stock, stock appreciation
rights and other stock based performance awards. Stock options may be exercised, in whole or in
part, by giving written notice of exercise to the Corporation specifying the number of shares to be
purchased. However, in the event of Change of Control (as defined in the 2004 Plan) an optionee
(other than an optionee who initiated a Change of Control in a capacity other than as an officer or
director of the Corporation) may elect to surrender all or part of the stock option to the
Corporation and to receive in cash an amount equal to the amount by which the fair market value per
share of the Stock on the date of exercise shall exceed the purchase price per share under the
stock option multiplied by the number of shares of the Stock granted under the stock option as to
which the right granted by this proviso shall have been exercised.
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
Under SEC Accounting Series Release 268 — Presentation in Financial Statements of “Redeemable
Preferred Stocks”, the Company has calculated and classified the intrinsic value of $2,119,530 as
at December 31, 2005 and $723,280 as at December 31, 2004 to options with redemption features, the vested portion
of issued share options from our 1995 Long-Term Incentive Plan in accordance with the related
guidance.
NOTE 17 — 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 we announced that we 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.
In February 2004, we announced that we had signed a Standby Equity Distribution Agreement that
allowed us, at our option, to issue shares to US-based investment fund Cornell Capital Partners LP
up to a maximum value of $20,000,000 over a period of up to two years from the date on which the
Registration Statement on Form S-3 registering for resale the shares under the Securities Act of
1933, as amended (“Securities Act”) is declared effective. The Registration Statement was declared
effective by the SEC on February 3, 2005
The total number of shares of common stock authorized was 300,000,000 as of December 31, 2005
and 2004 and 150,000,000 for 2003.
As of December 31, 2005 and 2004, we 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.
During the years ended December 31, 2005, 2004 and 2003, 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, 2005
We issued to Cornell Capital Partners, L.P. pursuant
to the Standby Equity Distribution Agreement, the following shares at the dates and prices indicated:
| • | In February 2005, 380,836 shares of our common stock were issued at $1.31 per share. | ||
| • | In February 2005, 335,653 shares of our common stock were issued at $1.47 per share. |
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| • | In March 2005, 344,758 shares of our common stock were issued at $1.54 per share. | ||
| • | In March 2005, 370,599 shares of our common stock were issued at $1.62 per share. | ||
| • | In March 2005, 381,170 shares of our common stock were issued at $1.57 per share. | ||
| • | In March 2005, 495,745 shares of our common stock were issued at $1.21 per share. | ||
| • | In April 2005, 552,639 shares of our common stock were issued at $1.09 per share. | ||
| • | In April 2005, 473,634 shares of our common stock were issued at $1.27 per share. | ||
| • | In May 2005, 837,054 shares of our common stock were issued at $0.72 per share. | ||
| • | In May 2005, 813,670 shares of our common stock were issued at $0.74 per share. | ||
| • | In May 2005, 872,854 shares of our common stock were issued at $0.69 per share. | ||
| • | In May 2005, 847,458 shares of our common stock were issued at $0.71 per share. | ||
| • | In June 2005, 801,068 shares of our common stock were issued at $0.75 per share. |
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| • | In June 2005, 812,348 shares of our common stock were issued at $0.74 per share. | ||
| • | In June 2005, 639,591 shares of our common stock were issued at $0.94 per share. | ||
| • | In June 2005, 596,421 shares of our common stock were issued at $1.00 per share. | ||
| • | In July 2005, 613,246 shares of our common stock were issued at $0.98 per share. | ||
| • | In July 2005, 630,120 shares of our common stock were issued at $0.95 per share. | ||
| • | In July 2005, 669,568 shares of our common stock were issued at $0.90 per share. | ||
| • | In July 2005, 761,325 shares of our common stock were issued at $0.79 per share. | ||
| • | In August 2005, 783,188 shares of our common stock were issued at $0.77 per share. |
Other stock issuances were as follows:
| • | In March 2005, 1,067,833 shares of our common stock were issued at an average of $0.34 per share as a result of employees exercising stock options. | ||
| • | In March 2005, 1,570,000 shares of our common stock were issued at an average of $0.11 per share as a result of employees exercising stock options. | ||
| • | In May 2005, 80,000 shares of CanArgo common stock were issuable to CEOcast Inc. in relation to a consultancy agreement between CanArgo and CEOcast. | ||
| • | In June 2005, 5,500,000 shares of our common stock were issued at $0.76 per share to Provincial, of which Russell Hummond (one of our non-executive directors) is Investment Advisor and 5,500,000 shares of our common stock were issued at $0.76 per share to Vundo, in connection with the Tethys acquisition. | ||
| • | In August 2005, 360,000 shares of our common stock were issued at an average of $1.44 per share as a result of stock options being exercised. | ||
| • | In September 2005, 284,000 shares of our common stock were issued at an average of $1.34 per share as a result of stock options being exercised. |
Year Ended December 31, 2004
| • | In February 2004, 163,218 shares of our common stock were issued at $0.56 per share to Cornell Capital Partners, L.P. as part payment of the commitment fee payable pursuant to the Standby Equity Distribution Agreement between Cornell and the Company (“Equity Line of Credit”). |
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
| • | In February 2004, 30,799 shares of our common stock were issued at $0.33 per share to Newbridge Securities Corporation pursuant to the Placement Agent Agreement among CanArgo Energy Corporation, Newbridge Securities Corporation and Cornell Capital Partners in terms of which Newbridge advised the Company and acted as our exclusive placement agent in respect of the Equity Line of Credit. | ||
| • | In March 2004, 3,815,084 shares of CanArgo common stock were issued at an average of $0.13 per share as a result of employees exercising stock options. | ||
| • | In April, 2004 we issued 4,000,000 shares of CanArgo common stock at $0.94 per share to Europa Oil Services Limited pursuant to a consultancy agreement to acquire an interest in the Samgori PSC. | ||
| • | In July, 2004 we issued 80,000 shares of CanArgo common stock at 0.70 per share to CEOcast Inc in relation to a consultancy agreement between CanArgo and CEOcast Inc dated May 17, 2004. | ||
| • | In July 2004, we issued 425,000 shares of our common stock at $0.50 per share to Cornell Capital Partners, L.P. as part payment of the commitment fee payable pursuant to the Standby Equity Distribution Agreement between Cornell and the Company (“Equity Line of Credit”). | ||
| • | In September 2004, we completed a global public offering (“Global Offering”) of 75 million shares of our common stock at an offering price of $0.50 per share. We raised gross proceeds of $37,500,000 and paid total commissions and expenses related to the Global Offering of $4,543,845 which resulted in net proceeds to the Company of $32,956,155. | ||
| • | In September, 2004 we issued 6,000,000 restricted shares of our common stock at $0.60 per share to NPET Oil Limited to increase our interest in CanArgo Norio Limited, by buying out the remaining minority shareholder in that company, NPET Oil Limited. | ||
| • | In November 2004, 80,000 shares of CanArgo common stock were issueable to CEOcast Inc in relation to a consultancy agreement between CanArgo and CEOcast. |
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 Manavi well. | ||
| • | In December 2003, CanArgo issued 261,782 shares at $0.33 per share upon completion of a Standby Equity Distribution Agreement that allowed CanArgo, at its option, to issue shares to US-based investment fund Cornell Capital Partners LP up to a maximum value of $6 million. This facility was terminated on February 11, 2004 when the Company entered into a further standby equity distribution agreement. |
NOTE 18 — NET LOSS PER COMMON SHARE
Earnings (loss) per share is calculated in accordance with SFAS No. 128, “Earnings Per Share.”
Basic and diluted earnings per share are provided for continuing operations, discontinued
operations, cumulative effect of change of accounting principle and net income (loss). Basic
earnings (loss) per share is computed based upon the
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
weighted average number of shares of common
stock outstanding for the period and excludes any potential dilution. Diluted earnings per share
reflects potential dilution from the exercise of securities (warrants, options and convertible
debt) into common stock. Outstanding options and warrants to purchase common stock are not
included in the computation of diluted loss per share because the effect of these instruments would
be anti-dilutive for the loss periods presented.
Basic and diluted net loss per common share for the years ended December 31, 2005, 2004 and
2003 were based on the weighted average number of common shares outstanding during those periods.
Options and warrants to purchase CanArgo’s Common Stock were outstanding during the years ended
December 31, 2005, 2004 and 2003 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 41,644,516, 14,834,080 and
7,986,167 for each of the years ended December 31, 2005, 2004 and 2003 respectively (See Notes 14
and 24).
NOTE 19 — INCOME TAXES
CanArgo and its U.S. domestic subsidiaries file a U.S. consolidated income tax return. 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, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Income tax benefit at statutory
rate |
$ | (4,194,007 | ) | $ | (1,617,548 | ) | $ | (2,386,000 | ) | |||
Benefit of losses not recognized |
4,194,007 | 1,617,548 | 2,386,000 | |||||||||
Provision for income taxes |
$ | — | $ | — | $ | — | ||||||
Effective tax rate |
0 | % | 0 | % | 0 | % | ||||||
The components of deferred tax assets consisted of the following as of December 31:
| 2005 | 2004 | |||||||
Net operating loss carryforwards |
$ | 7,775,000 | $ | 10,957,000 | ||||
Foreign net operating loss carryforwards |
2,961,000 | 3,573,000 | ||||||
Net timing differences on impairments and accelerated
capital allowances |
9,383,000 | 9,383,000 | ||||||
| 20,119,000 | 23,913,000 | |||||||
Valuation allowance |
(20,119,000 | ) | (23,913,000 | ) | ||||
Net deferred tax asset recognized in balance sheet |
$ | — | $ | — | ||||
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
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 $2,920,000 per year on a cumulative basis.
As of December 31, 2005, total unexpired U.S. net operating loss carryforwards were approximately
$38,242,378. Of that amount, approximately $15,375,000 was incurred prior to the ownership change
in 2000 and is subject to the IRC Section 382 limitation (See Note 2).
The U.S. net operating loss carryforwards expire from 2006 to 2025. CanArgo also has
approximately $8,709,000 of foreign net operating loss carryforwards. A significant portion of the
foreign net operating loss carryforwards may be 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 20 — DISCONTINUED OPERATIONS
CanArgo Standard Oil Products
In September 2002, we approved a plan to sell our interest in CanArgo Standard Oil Products
Limited (“CSOP”), a petroleum product retail business in Georgia, to finance our Georgian and
Ukrainian development projects. In October 2002, we reached agreement with Westrade Alliance LLC,
an unaffiliated company, to sell our wholly owned subsidiary, CanArgo Petroleum Products Limited
(“CPPL”), which held our 50% interest in CSOP 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. The total payment received in 2004 was $1,857,000 with the final payment of
the consideration received by us in December 2004 at which time we transferred our ownership in
CPPL to Westrade Alliance LLC. The gain recorded on disposition of subsidiary was $1,275,351.
The results of discontinued operations in respect of CSOP consisted of the following for the
years ending December 31:
| 2005 | 2004 | 2003 | ||||||||||
Operating Revenues |
$ | — | $ | — | $ | 9,837,445 | ||||||
Income Before Income Taxes
and Minority Interest |
— | 18,242 | 392,411 | |||||||||
Income Taxes |
— | — | (25,297 | ) | ||||||||
Minority Interest in Income |
— | — | (183,557 | ) | ||||||||
Net Income from Discontinued
Operation |
$ | — | $ | 18,242 | $ | 183,557 | ||||||
Lateral Vector Resources Inc
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
Lateral Vector Resources Inc. (“LVR”), a wholly-owned subsidiary of CanArgo acquired by us in
July 2001, negotiated and concluded with Ukrnafta, the Ukrainian State Oil Company, a Joint
Investment Production Activity (“JIPA”) agreement in 1998 to develop the Bugruvativske 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. In negotiations with possible buyers in 2003
the Company believed the realizable value to be approximately $250.000. Consequently, we recorded
in 2003 a write-down in respect to the LVR deal and the acquisition of the Bugruvativske Field of
approximately $4,790,727, which reduced the carrying value of LVR to $250,000 as of December 31,
2003. No gain or loss was recorded in 2004 upon the sale of LVR.
On May 28, 2004, we announced that pursuant to a signed agreement between CanArgo Acquisition
Corporation, our wholly owned subsidiary, and Stanhope Solutions Ltd., we had completed a
transaction to sell our interest in the Bugruvativske Field through the disposal of LVR for
$2,000,000. We received $250,000 as an initial payment and will receive the remaining $1,750,000
based upon certain production targets being achieved on the project. As of March 14, 2005, we had
not received any further payments nor does management expect to receive any further payment.
The results of operations of LVR have been classified as discontinued for the year ended
December 31, 2003.
The results of discontinued operations in respect of LVR consisted of the following for the
years ending December 31:
| 2005 | 2004 | 2003 | ||||||||||
Income (Loss) Before Income Taxes
and Minority Interest |
— | — | (4,849,036 | ) | ||||||||
Net Income (Loss) from Discontinued
Operation |
$ | — | $ | — | $ | (4,849,036 | ) | |||||
Georgian American Oil Refinery
In 2003, we approved a plan to dispose of our interest in the Georgian American Oil Refinery
Limited (“GAOR”) as the refinery had remained closed since 2001 and neither we nor our partners
could find a commercially viable option to putting the refinery back into operation. In February
2004, we reached an agreement with a local Georgian company to sell our 51% interest in GAOR for a
nominal price of one US dollar and the buyers assumption of all the obligations and debts of GAOR
to the State of Georgia including deferred tax liabilities of approximately $380,000. The gain
recorded on disposition of GAOR was $330,923. 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.
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
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
$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 Limited. These items have been respectively recorded
in impairment of other assets and other income (expense) components of continuing operations.
The results of discontinued operations in respect of GAOR consisted of the following for the
years ending December 31:
| 2005 | 2004 | 2003 | ||||||||||
Operating Revenues |
$ | — | $ | — | $ | — | ||||||
Income (Loss) Before Income Taxes
and Minority Interest |
— | — | (1,485,705 | ) | ||||||||
Minority Interest in Loss |
— | (523,968 | ) | (492,592 | ) | |||||||
Net Income (Loss) from Discontinued
Operation |
$ | — | $ | (523,968 | ) | $ | (1,978,297 | ) | ||||
3-megawatt duel fuel power generator
In 2003, we signed a sales agreement disposing of a 3-megawatt duel fuel power generator for
$600,000 and have received a non-refundable deposit of approximately $300,000. The unit was shipped
to the United States where it underwent tests in late 2004. On completion of these tests to the
satisfaction of the buyer, we were to transfer title for this equipment and receive the final
payment of $300,000. Although the unit was successfully tested, the buyer failed to meet the sale
contract terms resulting in the loss of its deposit in the third quarter, 2005. We are currently
remarketing the generator.
The generator has been classified as “Assets held for sale” for all periods presented. The
generator was impaired in 2003 by $80,000 to reflect its fair value less cost to sell. The Company
believes that the fair value established in 2003 is still valid. The Company’s marketing efforts
include a sales price less expected costs of
any future sale to be in line with the fair value established in 2003. The results for the
generator are the following for the years ending December 31:
| 2005 | 2004 | 2003 | ||||||||||
Income (Loss) Before Income Taxes
and Minority Interest |
— | — | (80,000 | ) | ||||||||
Net Income (Loss) from Discontinued
Operation |
$ | — | $ | — | $ | (80,000 | ) | |||||
Gross consolidated assets in respect of the generator included in “assets held for sale”
consisted of the following at December 31:
| 2005 | 2004 | |||||||
Assets held for sale: |
||||||||
Capital assets, net |
600,000 | 600,000 | ||||||
| $ | 600,000 | $ | 600,000 | |||||
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
NOTE 21 — SEGMENT AND GEOGRAPHICAL DATA
During the year ended December 31, 2004 CanArgo disposed of its downstream activities in
Georgia and all operations outside of Georgia.
As of December 31, 2004 Georgia represented the only geographical segment.
During the year ended December 31, 2005 CanArgo’s continuing operations operated through one
business segment, oil and gas exploration.
Operating revenues from continuing operations for the year ended December 31, 2005 by
geographical area were as follows:
| 2005 | ||||
Oil and Gas Exploration, Development And Production |
||||
Georgia |
$ | 7,582,375 | ||
Republic of Kazakhstan |
— | |||
Total |
$ | 7,582,375 | ||
Operating (loss) income from continuing operations for the year ended December 31, 2005 by
geographical area was as follows:
| 2005 | ||||
Oil and Gas Exploration, Development And Production |
||||
Georgia |
$ | 1,168,653 | ||
Republic of Kazakhstan |
(729,179 | ) | ||
Corporate and Other Expenses |
(11,448,227 | ) | ||
Total Operating Loss |
$ | (11,008,753 | ) | |
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
Net (loss) income before minority interest from continuing operations for the year ended
December 31, 2005 by geographical area was as follows:
| 2005 | ||||
Oil and Gas Exploration, Development And Production |
||||
Georgia |
$ | 1,168,653 | ||
Republic of Kazakhstan |
(729,179 | ) | ||
Corporate and Other Expenses |
(12,774,788 | ) | ||
Net (Loss) Income Before Minority Interest |
$ | (12,335,314 | ) | |
The segment and geographical data below is presented as of December 31, 2005.
Identifiable assets of continuing and discontinued operations as of December 31, 2005 by
business segment and geographical area were as follows:
| 2005 | ||||
Corporate |
||||
Georgia |
$ | 785,607 | ||
Republic of Kazakhstan |
— | |||
Western Europe (principally cash) |
27,730,478 | |||
Total Corporate |
28,516,085 | |||
Oil and Gas Exploration,
Development and Production |
||||
Georgia |
106,905,403 | |||
Republic of Kazakhstan |
11,426,813 | |||
Assets Held for Sale
|
||||
Western Europe |
600,000 | |||
Total Identifiable Assets |
$ | 147,448,301 | ||
NOTE 22 – SUPPLEMENTAL CASH FLOW INFORMATION
| 2005 | 2004 | 2003 | ||||||||||
Non-cash transactions: |
||||||||||||
Stock compensation expense |
$ | 2,374,578 | $ | 1,395,035 | $ | 276,507 | ||||||
Interest expense and amortization of debt
discount and loan fees |
1,277,878 | 653,313 | — | |||||||||
Debt Extinguishment expense |
— | 118,400 | — | |||||||||
Non cash miscellaneous expense — Financing
fees |
193,000 | — | — | |||||||||
Issuance of common stock for
services |
53,600 | 56,000 | — | |||||||||
Issuance of common stock for purchase of
farm-in partner of Manavi well |
— | — | 6,600,000 | |||||||||
Issuance of common stock to buy out minority
shareholders in CanArgo Norio |
— | 4,320,000 | 1,140,000 | |||||||||
Issuance of common stock pursuant to SEDA
(1) |
10,327,305 | 331,182 | 86,388 | |||||||||
Issuance of common stock for Consultancy
agreement (Europa Oil Services Ltd) to acquire
interest in Samgori |
— | 3,880,000 | — | |||||||||
Issuance of common stock to acquire 55%
remaining interest in Tethys Petroleum Investments, Ltd. |
8,360,000 | — | — | |||||||||
(1) The amount recorded in 2005 included
the following |
||||||||||||
Repayment of
principal of $1.5 million Cornell
advance from 2004 |
1,500,000 | |||||||||||
Repayment of
principal of $15 million Cornell
promissory note from 2005 |
7,800,000 | |||||||||||
Payment of offering costs with proceeds from
SEDA |
994,757 | |||||||||||
Payment of
interest on the $1.5 million Cornell
advance from 2004 |
32,548 | |||||||||||
| 10,327,305 | ||||||||||||
There was no cash paid for income taxes for the
years ended December 31, 2005, 2004 and 2003. |
||||||||||||
Reclassification temporary temporary
equity |
1,396,250 | 723,200 | — | |||||||||
Cash paid for interest expense |
621,644 | 11,559 | 35,387 | |||||||||
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CanArgo Energy Corporation
Notes to Consolidated Financial Statements — continued
NOTE 23 — STOCK-BASED COMPENSATION PLANS
At December 31, 2005, stock options and warrants had been issued from the following stock
based compensation plans:
| • | 1995 Long-Term Incentive Plan (“1995 Plan”). The 1995 Plan was approved by our stockholders at the annual meeting of stockholders held on February 6, 1996.This Plan allows for up to 7,500,000 shares of the Company’s common stock to be issued to officers, directors, employees, consultants and advisors pursuant to the grant of stock based awards, including qualified and non-qualified stock, options, restricted stock, stock appreciation rights and other stock based performance awards. As of December 31, 2005, options to acquire an aggregate of 1,454,000 shares of common stock had been granted under this Plan and were outstanding, 1,214,000 of which are currently vested. The Plan expired on November 13, 2005. The awards have a term of 5 years from date of issue and vest immediately. |
| • | The Amended and Restated CanArgo Energy Inc. Plan (the “CEI Plan”). The CEI Plan (also known as the CAOG Plan) was adopted by the Company’s Board of Directors on September 29, 1998. All Options outstanding under the Plan as of July 15, 1998 were assumed by the Company pursuant to the terms of an Amended and Restated Combination Agreement between the Company and CanArgo Energy Inc. dated February 2, 1998 which was approved by the Company’s stockholders on July 8, 1998. This Plan allowed for up to 1,250,000 shares (of which only 988,000 shares were registered) of the Company’s common stock to be issued to any director or full-time employee of the Company or a subsidiary of the Company. As of December 31, 2005, five year options to acquire an aggregate of 220,000 shares of common stock had been granted under this Plan and were outstanding, 145,000 of which are currently 100% vested. The awards have a term of 5 years from date of issue, each award having a special vesting provision defined in the award. |
| • | Special Stock Options and Warrants. This plan was created to allow the Company to retain and provide incentives to existing executive officers and directors and to allow retirement of new officers and directors following the Company’s decision to relocate finance and administration functions from Calgary, Canada to London, England. As of December 31, 2005, special stock options and warrants issued under this plan exercisable for an aggregate of 535,000 shares were outstanding, subject to customary anti-dilution adjustments. The awards have term of 5 years from date of issue, each award having a vesting provision defined in the award. |
| • | 2004 Long Term Stock Incentive Plan (“2004 Plan”). The 2004 Plan was approved by our stockholders at the annual meeting of stockholders held on May 18, 2004. This Plan allows for up to 10,000,000 shares of the Company’s common stock to be issued to officers, directors, employees, consultants and advisors pursuant to the grant of stock based awards, including qualified and non-qualified stock options, restricted stock, stock appreciation rights and other stock based performance awards. As of December 31, 2005, seven year options to acquire an aggregate of 7,836,000 shares of common stock had been granted under this Plan and were outstanding, 4,044,000 of which vested at that date. The 2004 Plan will expire on May 17, 2014, although the Board of Directors may terminate the 2004 Plan at any |
F-46