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:
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.
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.
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:
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,
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
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
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
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
(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
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
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.
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.
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
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
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:
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world and regional economic conditions;
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the state of international relations;
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the stability and the legal, regulatory, fiscal and tax policies of various governments in areas in which we have or intend to have
operations;
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fluctuations in the world and regional price of oil and gas and in interest rates;
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the outlook for the oil and gas industry in general and in areas in which we have or intend to have operations; and
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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.
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:
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low standards of living;
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high unemployment;
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under-developed and changing legal and social institutions; and
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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
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
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:
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unexpected or unusual geological conditions;
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the recoverability of the oil and gas on an economic basis;
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the availability of infrastructure and personnel to support operations;
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labour disputes;
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local and global oil prices; and
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government regulation and legal and political uncertainties.
Our activities can also be affected by a number of hazards, including, without limitation:
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natural phenomena, such as bad weather;
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operating hazards, such as fires, explosions, blow-outs, pipe failures and casing collapses; and
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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
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:
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global and regional changes in the supply and demand for oil and natural gas;
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actions of the Organization of Petroleum Exporting Countries;
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weather conditions;
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domestic and foreign governmental regulations;
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the price and availability of alternative fuels;
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political conditions and terrorist activity in the Middle East, Caucasus, Central Asia and elsewhere; and
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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:
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the amount of recoverable crude oil and natural gas present in a reservoir;
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the costs that will be incurred to produce the crude oil and natural gas;
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:
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additional development activity;
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evolving production history; and
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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.
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:
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.
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not applicable.
ITEM 2.
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:
(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:
(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.
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.
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.
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.
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.
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.
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.
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.
(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.
(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
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.
(1) 25% relinquishment March 2006
(2) Exited PSC subsequent to year end, in February 2006
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.
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
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:
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:
In 2003, NOC sold its oil production to 11 customers of which the following three customers represented sales greater than 10% of oil revenue:
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:
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:
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:
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:
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;
•
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.
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.
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
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.
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
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
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
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.
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
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.
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.
PART II
ITEM 5.
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.
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.
ITEM 6.
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.
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
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
(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”.
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
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
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,
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.
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:
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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:
(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
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
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.
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.
The negative expenditures recorded in “Exploration” in 2003 is a result of a prior year reclassification.
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:
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).
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.
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.
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
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.
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
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.
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.
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.
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.
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:
(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.
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.
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
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.
ITEM 7A.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Financial Statements required to be filed in this Report begin at Page of this Report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
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:
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.
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.
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
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.
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.
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
ITEM 9B.
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.
PART III
ITEM 10.
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.
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.
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.
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.
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.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
The following financial statements and related notes of the Company contained on pages 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
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CanArgo Energy Corporation
(Registrant)
By:
/s/ 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
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.
CANARGO ENERGY CORPORATION
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
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
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
CANARGO ENERGY CORPORATION
Consolidated Balance Sheets
The accompanying notes are an integral part of the consolidated financial statements
CANARGO ENERGY CORPORATION
Consolidated Statements of Operations and Comprehensive Loss
The accompanying notes are an integral part of the consolidated financial statements
CANARGO ENERGY CORPORATION
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of the consolidated financial statements
CANARGO ENERGY CORPORATION
Consolidated Statements of Stockholders’ Equity - continued
The accompanying notes are an integral part of the consolidated financial statements
CANARGO ENERGY CORPORATION
Consolidated Statements of Stockholders’ Equity - Continued
The accompanying notes are an integral part of the consolidated financial statements
CANARGO ENERGY CORPORATION
Consolidated Statements of Stockholders’ Equity - continued
The accompanying notes are an integral part of the consolidated financial statements
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.
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.
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
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.
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.
CanArgo Energy Corporation
Notes to Consolidated Financial Statements - continued
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:
CanArgo Energy Corporation
Notes to Consolidated Financial Statements - continued
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
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:
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.
CanArgo Energy Corporation
Notes to Consolidated Financial Statements - continued
(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.
CanArgo Energy Corporation
Notes to Consolidated Financial Statements - continued
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.
CanArgo Energy Corporation
Notes to Consolidated Financial Statements - continued
NOTE 4 - RESTRICTED CASH
Restricted cash consisted of the following at December 31:
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:
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.
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:
NOTE 7 - PREPAYMENTS
Prepayments consisted of the following at December 31:
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:
Capital assets, net of accumulated depletion, depreciation and amortization and impairment (“DD&A”), include the following at December 31, 2004:
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.
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:
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:
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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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:
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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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:
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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:
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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“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:
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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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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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:
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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NOTE 13 - ACCRUED LIABILITIES
Accrued liabilities consisted of the following at December 31:
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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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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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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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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(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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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:
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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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:
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Other stock issuances were as follows:
Year Ended December 31, 2004
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Year Ended December 31, 2003
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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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:
The components of deferred tax assets consisted of the following as of December 31:
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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:
Lateral Vector Resources Inc
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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:
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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$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:
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:
Gross consolidated assets in respect of the generator included in “assets held for sale” consisted of the following at December 31:
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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:
Operating (loss) income from continuing operations for the year ended December 31, 2005 by geographical area was as follows:
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Net (loss) income before minority interest from continuing operations for the year ended December 31, 2005 by geographical area was as follows:
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:
NOTE 22 - SUPPLEMENTAL CASH FLOW INFORMATION
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NOTE 23 - STOCK-BASED COMPENSATION PLANS
At December 31, 2005, stock options and warrants had been issued from the following stock based compensation plans:
•
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.
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time prior to that date. The awards have a term of 7 years from date of issue and vest 1/3 for each year over 3 years beginning immediately.
The purpose of the Company’s stock option plans is to further the interest of the Company by enabling officers, directors, employees, consultants and advisors of the Company to acquire an interest in the Company by ownership of its stock through the exercise of stock options and stock appreciation rights granted under its various stock option plans.
A summary of the status of stock options granted under the 1995 Plan, CAOG Plan and special stock options and warrants is as follows:
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Shares issuable upon exercise of vested options and the corresponding weighted average exercise price are as follows:
The weighted average fair value of options granted during the year was $0.83, $0.53 and $0.10 for the years ended December 31, 2005, 2004 and 2003 respectively.
We used the Black-Scholes option pricing model using the following assumptions to determine the fair value of the options issued under our plans during the following years:
The numbers above reflect the weighted average for the options issued during the year
The following table summarizes information about stock options outstanding at December 31, 2005:
NOTE 24 - 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.
Of the 50% of CanArgo Standard Oil Products Limited not held by CanArgo prior to its disposal in December, 2004, 41.65% was held by Standard Oil Products, an unrelated third party entity, and 8.35% held by an individual, Mr Levan Pkhakadze, who is one of the founders of Standard Oil Products and is an officer and director of CanArgo Standard Oil Products. The majority of refined product purchased by CanArgo Standard Oil Products for resale at its petrol stations is purchased from a company controlled by Standard Oil Products who together with and an individual shareholder, own the 50% interest in CanArgo Standard Oil Products not held by CanArgo.
Dr. David Robson, Chief Executive Officer, provides all of his services to CanArgo through Vazon Energy Limited of which he is the sole owner and Managing Director. In addition management services agreements
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exists between CanArgo and Vazon Energy whereby the services of Dr. Robson, Mrs. Landles (Corporate Secretary & Executive Vice President) and Mr. Battey (Chief Financial Officer), amongst others, are provided to CanArgo. Approximately $930,000 was paid to Vazon in respect of these services.
On June 7, 2005, CanArgo made an offer to acquire 55% of the ordinary share capital of Tethys which was held by Provincial and 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 in connection with this transaction.
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 (see Note 14). 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, 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 members of the board of directors.
NOTE 25 - SUBSEQUENT EVENTS
Loan with Detachable Warrants
On February 14, 2006 we exercised the option forcing conversion of the loan from Salahi Ozturk advanced pursuant to the amended and restated loan and warrant agreement dated August 27, 2004 (“Amended Agreement”) into 1,521,739 shares of our common stock. .
Samgori PSC
On February 17, 2006 we issued a press release announcing that our subsidiary, CanArgo Samgori Limited (“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, Georgian Oil Samgori Ltd, 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 been informed that, given this, NPL have indicated that they now intend to exercise 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. CSL had been sharing in both costs and revenues from ongoing production since April 2004, and had approximately broken-even on a cash basis on the project. In 2005 the Samgori PSC added approximately $0.8 million in net revenues to CanArgo. Since 2004, we have capitalized costs of approximately $1.25 million in relation to the Samgori PSC which are part of our cost pool which will be amortized and depleted in accordance with CanArgo’s usual accounting policies for oil and gas properties.
Financing
On March 3, 2006, we announced that we had entered into a $13,000,000 private placement with a small group of accredited investors (“Note holders”) of senior subordinated convertible guaranteed notes (the
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“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 will be subordinated to CanArgo’s existing issue of Senior Secured Notes and guaranteed on a subordinated basis by CanArgo’s material subsidiaries.
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) to convert their notes into shares of common stock of TPI, 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 TPI by 100,000 in the Subordinated Note holders’ Relevant Percentages (as defined in the Note Purchase Agreement). At the time of any TPI conversion any further advances (in excess of the $13 million) from CanArgo to TPI may be, at CanArgo’s discretion, either repaid, or converted into TPI equity based on a valuation of $52 million [plus the amount of any unreimbursed amounts advanced by the Company to TPI], with the Subordinated Note holders having the ability to maintain their equity position by providing further funding on a pro-rata basis
The Warrants will be 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 the 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 required by the agreement to be used to fund the development of the Kyzyloi Gas Field in the Kazakhstan and on the commitment exploration programs in Kazakhstan through TPI, which holds CanArgo’s Kazakhstan assets and therefore these funds will not be available for the Company for general working capital.
In connection with the offering the Company entered into a registration rights agreement with the note holders and agreed to register the shares of common stock underlying the warrants and the convertible note (in the event that they are converted into shares of the Company’s common stock). The registration rights agreement gives the note holders the right to piggy back or demand registration rights and the Company must use its best efforts to have the registration declared effective within 120 days of any demand by the note holders. In addition, the agreement requires the Company have a registration agreement covering the shares underlying the note and the warrants declared effective no later than December 31, 2006 if not demanded earlier by the note holders. The Company is required under the registration rights agreement to maintain the effectiveness of the registration for a period of the earlier of two years or when the securities are no longer restricted securities. The registration rights agreement does not contain penalty provisions in the event the Company fails to register or maintain an effective registration statement covering the resale of the underlying common stock. The Company is only required to register for resale shares of its common stock, and does not have to register shares of its wholly owned subsidiary, TPI, in the event that the note holders elect to convert into shares of TPI as defined in the agreeemnt.
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
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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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NOTE 25 - QUARTERLY FINANCIAL DATA (Unaudited)
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NOTE 26 - SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
ESTIMATED NET QUANTITIES OF OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs with existing equipment under existing economic and operating conditions.
Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and under existing economic and operating conditions.
No major discovery or other favorable or adverse event subsequent to December 31, 2004 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
Oil and gas reserves
The following tables set forth our net proved oil and gas reserves, including the changes therein, and net proved developed reserves at December 31, 2005, as estimated by the independent petroleum engineering firm, Oilfield Production Consultants Limited for Georgia:
Net Proved Developed and Undeveloped Reserves - Oil (In Thousands of Barrels):
Net Proved Developed and Undeveloped Reserves - Gas (In Million Cubic Feet) - Georgia
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Net proved oil reserves in Georgia consisted of the following at December 31:
Net proved gas reserves in Georgia consisted of the following at December 31:
(1)
PSC Entitlement Volumes attributed to CanArgo are calculated using the “economic interest method” applied to the terms of the production sharing contract. PSC Entitlement Volumes are those produced volumes which, through the production sharing contract, accrue to the benefit of Ninotsminda Oil Company after deduction of Georgian Oil’s share which includes all Georgian taxes, levies and duties. As a result of CanArgo’s interest in Ninotsminda Oil Company, these volumes accrue to the benefit of CanArgo for the recovery of capital, repayment of operating costs and share of profit.
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The following tables set forth our net proved oil and gas reserves, including the changes therein, and net proved developed reserves at December 31, 2005, as estimated by the independent petroleum engineering firm, Oilfield Production Consultants Limited for Kazakhstan:
Republic of Kazakhstan
Net Proved Developed and Undeveloped Reserves - Gas (In Million Cubic Feet) - Kazakhstan
Net proved gas reserves in the Kazakhstan consisted of the following at December 31:
(1)
On June 9, 2005 we acquired 100% ownership of Tethys Petroleum Investments Limited (TPI) and as at 31 December 2005, this entity is now consolidated in our financial statements. 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. Prior to the Company’s 100% ownership, we chose to use our equity ownership percentage as the basis for recording our portion of our investees’ loss. No reserves were assessed before we owned 100% of TPI.
(2)
TPI through its 100% owned Kazakhstan subsidiary TKL, 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.
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Results of operations for oil and gas producing activities
Results of operations for oil and gas producing activities, all in Georgia, for 2005, 2004 and 2003 are as follows:
Georgia was the only country where we had oil and gas producing activities for 2005, 2004 and 2003. Although we have Proved Undeveloped reserves in Kazakhstan as at December 31, 2005, we have not yet completed the infrastructure to produce these reserves.
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Costs incurred for oil and gas property acquisition, exploration and development activities
Costs incurred for oil and gas property acquisition, exploration and development activities for 2005, 2004 and 2003 are as follows:
(1)
On June 9, 2005 we acquired 100% ownership of Tethys Petroleum Investments Limited (TPI) and this entity as at 31 December 2005, is now consolidated in our financial statements. 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. Prior to 100% ownership, we chose to use our equity ownership percentage as the basis for recording our portion of our investees’ loss.
(2)
These amounts represent costs incurred by CanArgo and excluded from the amortization base until proved reserves are established or impairment is determined.
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Aggregate Capitalized Costs
Capitalized costs relating to Oil and Gas Activities is as follows:
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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
The following information has been developed utilizing procedures prescribed by SFAS No. 69 Disclosure about Oil and Gas Producing Activities (“SFAS 69”) and based on crude oil reserve and production volumes estimated by the Company’s engineering staff. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of
the Company.
CanArgo believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying period-end oil prices adjusted for fixed and determinable escalations to the estimated future production of period-end proven reserves. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow before tax. Future income tax expenses has been computed by applying period-end statutory tax rates to aggregate future pre-tax net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by SFAS No. 69.
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Management does not rely solely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proven reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:
(1)
In Georgia, future cash flows are based on PSC Entitlement Volumes attributed to CanArgo using the “economic interest method” applied to the terms of the production sharing contract. PSC Entitlement Volumes are those produced volumes which, through the production sharing contract, accrue to the benefit of Ninotsminda Oil Company Limited after deduction of Georgian Oil’s share which includes all Georgian taxes, levies and duties. As a result of our interest in Ninotsminda Oil Company Limited, these
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volumes accrue to the benefit of CanArgo for the recovery of capital, repayment of operating costs and share of profit.
In Kazakhstan, 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.
(2)
On June 9, 2005 we acquired 100% ownership of Tethys Petroleum Investments Limited (TPI) and as at December 31, 2005 this entity is now consolidated in our financial statements. 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. Prior to 100% ownership, we chose to use our equity ownership percentage as the basis for recording our portion of our investees’ loss.
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and gas reserves for Georgia is as follows:
(1)
Other changes include a reduction in our cash flows resulting from a change in our oil entitlement as goverened by the Ninotsminda PSC primarily due to increased oil prices used in the standardized measure of discounted future net cash flow for 2005.
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