UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10-Q

Commission File Number 0001-32145

CANARGO ENERGY CORPORATION

(44) 1481 729 980

Indicate by check whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Act). þ

The number of shares of registrant’s common stock outstanding on May 6, 2005 was 201,171,372.

CANARGO ENERGY CORPORATION
FORM 10-Q
TABLE OF CONTENTS

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CANARGO ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Condensed Balance Sheets

The accompanying notes are an integral part of the Condensed Consolidated Financial Statements.

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CANARGO ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Operations

The accompanying notes are an integral part of the Condensed Consolidated Financial Statements.

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CANARGO ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Cash Flows

The accompanying notes are an integral part of the Condensed Consolidated Financial Statements.

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CANARGO ENERGY CORPORATION AND SUBSIDIARIES

Notes to Unaudited Consolidated Condensed Financial Statements

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On February 11, 2004, we entered into a SEDA that allowed us, at our option, periodically to issue shares of our common stock to US-based investment fund Cornell Capital. On February 03, 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 SEDA. Under the terms of the Agreement, Cornell Capital will provide us with an equity line of credit for 24 months from the date the registration statement became effective. The maximum aggregate amount of the equity placements pursuant to the Agreement is $20,000,000. Subject to this limitation, we can draw down up to $600,000 in any seven trading-day period (a “Put”). The Cornell Facility could be used in whole or in part entirely at our discretion. Shares issued to Cornell Capital would be 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 Agreement, Cornell Capital will receive a substantial discount to the current market price of CanArgo common stock. The level of the total discount will vary depending on the market price of our stock and the amount drawn down under the Agreement. Such discount will comprise (1) 3% discount to, the lowest volume weighted average price of our common stock; (2) 5% of the proceeds that we receive for each advance under the Agreement; and (3) a commitment fee. The commitment fee, which has been paid, consisted of $10,000 in cash and 850,000 shares of our common stock.

As of May 11, 2005, we have received $4,532,548 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 eight takedowns under the Cornell Facility in which we issued a total of 3,335,034 shares of our common stock to Cornell Capital at an average price of $1.3591 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.

On April 26, 2005 we signed a promissory note with Cornell Capital whereby Cornell Capital agreed to advance us the sum of $15,000,000. This amount and interest at a rate of 7.5% per annum shall be payable either in cash or using the net proceeds of drawdowns under the SEDA, within 270 days from the date of the promissory note. (See “Notes to Unaudited Consolidated Condensed Financial Statements, Item 20 Subsequent Events” below for a more detailed discussion).

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Qualifying Statement With Respect To Forward-Looking Information

THE FOLLOWING INFORMATION CONTAINS FORWARD-LOOKING STATEMENTS. SEE “FORWARD-LOOKING STATEMENTS” BELOW AND ELSEWHERE IN THIS REPORT.

In addition to the historical information included in this report, you are cautioned that this Form 10-Q contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. When the words “believes,” “plans,” “anticipates,” “will likely result,” “will continue,” “projects,” “expects,” and similar expressions are used in this Form 10-Q, they are intended to identify “forward-looking statements,” and such statements are subject to certain risks and uncertainties which could cause actual results to differ materially from those projected. Furthermore, our plans, strategies, objectives, expectations and intentions are subject to change at any time at the discretion of management and the Board.

These forward-looking statements speak only as of the date this report is filed. The Company does not intend to update the forward-looking statements contained in this report, so as to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events, except as may occur as part of our ongoing periodic reports filed with the SEC.

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated annual financial statements and the notes thereto, included in our Annual Report on Form 10-K filed for the year ended December 31, 2004 and subsequent amendments thereof filed on Forms 10-K/A in addition to our condensed consolidated quarterly financial statements and the notes thereto, included in Item 1 of this report.

Operationally, during the quarter, we continued to focus on our horizontal development drilling program on our Ninotsminda and Samgori Fields, and the appraisal drilling program on our Manavi oil discovery. On the Ninotsminda and Samgori Fields, we plan to drill up to 15 horizontal well sections which will be mainly drilled as sidetracks from existing vertical wells but the program also includes a new well to be drilled in the eastern part of the Ninotsminda Field which will be designed so as to have more than one horizontal section drilled from it. The horizontal component of these wells will be drilled under balanced through the reservoir section using the latest Under Balanced Coiled Tubing Drilling (“UBCTD”) technology. WEUS Holding Inc., a subsidiary of Weatherford International Ltd, will supply the UBCTD equipment and services under the terms of a contract signed in June 2004.

The first UBCTD well, N22H on the Ninotsminda Field, commenced in December 2004 but was only completed in March 2005 with a horizontal section only 23% of that intended. The delay in completing this well and the failure to achieve the drilling objective was due to mechanical problems with the UBCTD equipment.

This well was drilled in the north-east of the Ninotsminda Field, an area where the reservoir is regarded as being of lower overall permeability, with the build-up section of the well penetrating the gas cap. While drilling under-balanced Weatherford measured gas production from the well at rates in the range of 20 — 25 MMscf (560 to 700 MCM) per day with the well effectively un-choked. We believe that this is the biggest rate ever measured on a well in Georgia to date thus demonstrating the potential for under balanced drilling in this reservoir. A slotted liner has been run over the production interval and the well tested at various choke sizes. Initially the well flowed mainly gas, with production of approximately 5.3 MMscf (150 MCM) per day of gas and 85 barrels of oil and condensate per day (968 barrels oil-equivalent (“boe”) (assuming 6,000 standard cubic feet of gas = 1 barrel of oil)) on a 16 mm (40/64ths in) choke, and a flowing tubing head pressure of 60 atmospheres (882 psi). During testing there was an improvement in the ratio of oil to gas produced. However, as a result of current problems with the export pipeline, this well is currently severely choked back due to constraints on flaring. Having analysed the results of the well to date in conjunction with the field reservoir model, it is planned to pull the production liner and complete the well as originally planned. The objectives of the well have not been fully met and as a result a significant area of the reservoir is not being drained of oil.

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Following an extended break during which Weatherford made certain modifications to its equipment and mobilised additional equipment to Georgia, drilling operations commenced on the N100H2 well on the Ninotsminda Field in early April. The total planned footage to be drilled is approximately 3,035 feet (925 meters) with a planned horizontal section length of 2,100 feet (640 meters). The N100 area has been historically a much more productive area of the Field than the N22 area, and as such it would be expected that the N100H2 well should be more productive than N22H, particularly as the horizontal section is planned to be much longer than that which was actually drilled in N22H.

Having successfully drilled 213 feet (65 meters) of the build-up section of N100H2, and having encountered what appears to be a significant fracture in the build-up section, Weatherford encountered problems with the bottom-hole assembly (“BHA”) which ultimately resulted in the BHA detaching and being left in the hole. Subsequent fishing operations using coiled tubing proved unsuccessful and the well has now been suspended and the equipment moved to the nearby N49 well location. Our operating company plans to re-enter the N100H2 well using our own conventional drilling rig and hopefully retrieve the fish. If this is not possible we will prepare the well for a further horizontal kick-off point just above the current hole. Because of the close proximity of the N100 well to the surface location of N49, further work cannot be carried out on N100H2 until operations have been completed on N49H.

The Ninotsminda N49H well will commence drilling around May 16 after the Weatherford crew have returned from their scheduled break. In this way, the well should be completed in one drilling session. Depending when the N49H well is completed, Weatherford will then either complete the N100H2 well or the next well in the program. It is planned that three horizontal wells will be drilled in the next two months.

On the Samgori Production Sharing Contract area, our partner Georgian Oil Samgori Limited (“GOSL”), a subsidiary of the Georgian State Oil Company Georgian Oil, have indicated that they may not be in a position to participate in the first horizontal wells to be drilled in the Samgori Field. We have been informed by the Georgian government that investment in oil and gas development and exploration activities is not a priority for the State budget. Under the terms of the agreement with GOSL, we may proceed with these activities on a sole-risk basis, retaining the Contractor’s entire share of production from such activities, and with GOSL being required to pay a 500% penalty to take back their interest. We have therefore issued sole-risk notices for the first two UBCTD horizontal wells on Samgori, and if GOSL do not wish to participate we may proceed on a sole-risk basis, but we are under no obligation to do so.

The appraisal of the Manavi Cretaceous oil discovery is moving ahead. Having encountered significant difficulties in drilling the M11Z sidetrack due to extremely over-pressured swelling clays in the section above the reservoir, operations were suspended. After extensive technical analysis and discussions with the international drilling contractor Saipem S.p.A. (“Saipem”), and with a major drilling mud company, it has been decided that the optimum way to sidetrack this well to the top of the reservoir as planned will be to use an oil-based mud system (to control the swelling clays) on Sapiem’s 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). As described below, we have already concluded an agreement with Saipem to provide a rig and drilling services to the company. It is expected that the sidetrack will be completed in a more effective manner utilising this new equipment. It is now planned to sidetrack the well with the Saipem rig to the top of the reservoir sequence at 13,633 feet (4,155 meters) where a 5-inch casing will be set. The Saipem rig has been mobilised to Georgia and is currently being rigged up and should be ready to re-commence drilling of the sidetrack by the end of May. The conventional drilling operations are expected to be completed by early July, after which Weatherford will take over using the UBCTD unit to drill down into the Cretaceous and fully evaluate the oil discovery.

Although management is excited about the potential of the Manavi prospect, a fair amount of additional drilling and analysis is still required before we will be able to fully evaluate the reserves and productive possibilities of this prospect. On June 22, 2004 we announced that our operating subsidiary in Georgia had signed a contract with Great Wall Drilling Company (“GWDC”) of China to supply drilling services for the drilling of a first appraisal well (M12) on the Manavi oil discovery with an option to drill further wells. However, due to an unacceptable delay in mobilising the rig to Georgia, on January 27, 2005 we signed an alternative contract with Saipem.

Under the terms of the contract, Saipem will supply an Ideco E-2100 Az drilling rig complete with crew to drill the Manavi 12 appraisal well to an approximate depth of 16,400 feet (5,000 meters) in the Cretaceous. The contract includes an option to drill further wells. This option is now being exercised with the M11Z sidetrack being the first

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well. On completion of this sidetrack, the rig will be moved to the M12 location which is approximately 4 km to the west of the Manavi M11 Cretaceous oil discovery well, and located on seismic data acquired by CanArgo in 1998.

The MK72 exploration well on the Norio (Block XI^c) & North Kumisi Production Sharing Agreement (“Norio PSA”) area which is testing a potentially large prospect mapped at Middle Eocene level remains suspended. The well is currently cased at a depth of 14,830 feet (4,520 meters) 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 15 to 20%. From the oil shows while drilling and log analysis, these sands appear to be oil bearing. It is planned to test the Oligocene sands once the well has reached total depth. Data obtained from the vertical seismic profile run in the well indicates that there is a seismic reflector some 984 feet (300 meters) below the current depth of the well which may be the primary target.

We announced on April 8, 2005 that our wholly owned subsidiary CanArgo Norio Limited had reached an agreement with a wholly owned subsidiary of the Georgian State Oil Company (“Georgian Oil”) to secure 100% of the contractor share in the Norio PSA. Georgian Oil were farming in for a 15% interest in the Norio PSA through a contribution to the Norio MK72 exploration well (plus an option to increase this to a 50% interest), and we have reached agreement (subject to final contractual documentation), to pay Georgian Oil $1.75 million to terminate the farm-in agreement and secure a 100% working interest in the Norio PSA. On May 9, 2005 we announced that the final documentation was signed on May 6.

It is planned to recommence drilling activities on the MK72 well within the next two months, with a planned total depth of 16,733 feet (5,100 meters).

Average gross oil production from the Ninotsminda and Samgori Fields for the three month period ending March 31, 2005 was 1,012 barrels of oil per day (“bopd”). At the end of the period, our net after tax entitlement to production (the allocation of a share of production to the State relieves us of all obligations we would otherwise have to pay the Republic of Georgia for taxes, duties and levies related to activities covered by the production sharing contracts) from the two fields was 516 bopd. Gross production from our two Fields as of April 30, 2005 is approximately 1,060 bopd.

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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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.

On May 9, 2005 we announced that on May 5, 2005 the Ministry of Energy and Mineral Resources of the Republic of Kazakhstan signed and registered the Production Contract for the Kyzyloy Field. We hold our interest in the Kyzyloy Field through our 45% holding in Tethys. Tethys in turn holds a 70% interest in the Kazakh Limited Liability Partnership BN-Munai (“BNM”). BNM holds a 100% interest in the 1,667 square kilometre (411,749 acre) Akkulkovsky exploration contract area, in the North Ustyurt Basin of Kazakhstan, just to the west of the Aral Sea, and surrounding the Kyzyloy Gas Field licence. Management believes that this is a significant event, as it will allow BNM to proceed with the development of this field and tie-in to the nearby Bukhara-Urals gas trunk-line, with first gas projected to be produced from this shallow gas field (the reservoir is at approximately 1,476 feet (450 meters)) by the end of this year. Management believes that production from the Kyzyloy Field will make BNM one of the first domestic producers of dry gas in Kazakhstan.

On the surrounding Akkulkovsky exploration contract area, BNM plans to drill a number of shallow gas tests this summer on identified seismic anomalies (which are analogous to the Kyzyloy Field), for potential tie-in to the Kyzyloy development. BNM has also signed an agreement to acquire a 100% interest in the large (approximately 10,000 square kilometres (2,470,000 acre)) Greater Akkulkovsky area. Just to the south of this area, in Northern Uzbekistan, lie some large gas condensate fields in the deeper section, and although further work is required, management believes that significant exploration potential may exist in the Greater Akkulkovsky contract area. Tethys is currently in the process of raising equity capital for the development of its business in Kazakhstan and Central Asia.

Liquidity and Capital Resources

As of March 31, 2005 we had working capital of $21,304,000 compared to working capital of $23,952,000 as of December 31, 2004.

Proceeds received from a global public offering of 75 million shares of our common stock in September 2004 along with on going cash flows from our Georgian operations together with access to the $20,000,000 Cornell Facility being provided by Cornell Capital (detailed below) and the proceeds from the $15,000,000 promissory note signed with Cornell Capital on April 26, 2005 (described above) means we have or should secure the working capital necessary to cover our immediate and near term funding requirements with respect to our currently planned development activities in the Republic of Georgia on our Ninotsminda and Samgori Fields and the appraisal of our Manavi oil discovery.

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”). On February 03, 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. Under the terms of the SEDA, Cornell Capital will provide us with an equity line of credit for 24 months from the date the registration statement became effective. The maximum aggregate amount of the equity placements pursuant to the SEDA is $20,000,000. Subject to this limitation, we can draw down up to $600,000 in any seven trading-day period (a “Put”). The Cornell Facility could be used in whole or in part entirely at our discretion. Shares issued to Cornell Capital would be 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 will receive a

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substantial discount to the current market price of CanArgo common stock. The level of the total discount will vary 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 May 11, 2005 of $0.825, Cornell Capital will receive a total discount of 11.56% to the market price of our stock. Such discount will comprise (1) 3% discount to, the lowest volume weighted average price of our common stock; (2) 5% of the proceeds that we receive for each advance under the Agreement; and (3) a commitment fee of 3.56%. The commitment fee, which has been paid, consisted of $10,000 in cash (paid in two tranches) and 850,000 shares of our common stock (issued in three tranches). 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 filed on May 6, 2004.

As of May 11, 2005, we have received $4,532,548 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 eight takedowns under the Cornell Facility in which we issued a total of 3,335,034 shares of our common stock to Cornell Capital at an average price of $1.3591 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 (See “Notes to Unaudited Consolidated Condensed Financial Statements, Item 11 Loans Payable and Long Term Debt” above for a more detailed discussion).

While a considerable amount of infrastructure for the Ninotsminda and Samgori Fields has already been put in place, we cannot provide assurance that:

To pursue existing projects beyond our immediate appraisal and development plans and to pursue new opportunities, we may 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, we believe 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, we may not be able to pursue projects beyond our current appraisal and development plans or to pursue new opportunities.

Development of the oil and gas properties and ventures in which we have interests involves multi-year efforts and substantial cash expenditures. While funding is available to us to pursue our current appraisal and development plans, full development of our oil and gas properties and ventures may 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 the corporate and other activities of CanArgo. There can also be no assurance that such financing will be available 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 CanArgo. Establishment of successful oil and gas operations is dependent upon, among other factors, the following:

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Subject to our ability to raise additional capital, above, 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.

Balance Sheet Changes

Cash and cash equivalents decreased $12,262,000 from $24,617,000 at December 31, 2004 to $12,355,000 at March 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 and net cash used by operating activities. This has been partially offset by cash received pursuant to the takedowns under the Cornell Facility.

Restricted cash increased to $5,300,000 at March 31, 2005 from $1,400,000 at December 31, 2004 due to the funding of a certificate of deposit 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.

Accounts receivable decreased from $2,526,000 at December 31, 2004 to $2,397,000 at March 31, 2005 primarily due to timing issues related to sales of crude oil at month end.

Subscription receivables of $569,500 at March 31, 2005 represent an outstanding amount due from Cornell Capital relating to a takedown under the Cornell Facility at the period end.

Subscription receivables from related parties of $168,014 at March 31, 2005 represent an outstanding amount due from the exercise of vested stock options at the period end.

Inventory increased from $254,000 at December 31, 2004 to $386,000 at March 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 $2,698,000 at March 31, 2005 as a result of an increase in prepayments for materials and services related to our appraisal activities at the Manavi oil discovery and for our horizontal well development program at the Ninotsminda and Samgori Fields. 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 March 31, 2005 and December 31, 2004 consist of a 3-megawatt duel fuel power generator.

Other current assets increased from $122,000 at December 31, 2004 to $128,000 at March 31, 2005.

Capital assets net, increased to $76,886,000 at March 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.

Prepaid financing fees decreased to $38,000 at March 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.

Investments in and advances to oil and gas and other ventures, increased to $877,000 at March 31, 2005 from $479,000 at December 31, 2004 as a result of further 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.

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Accounts payable decreased to $2,179,000 at March 31, 2005 from $2,332,000 at December 31, 2004 primarily due to increased payments to suppliers in respect of preparing wells for our horizontal development program at the Ninotsminda Field in Georgia.

Loans payable decreased to nil at March 31, 2005 from $1,500,000 at December 31, 2004 due to the repayment of a promissory note issued to Cornell Capital by making a series of takedowns in February and March 2005 under the SEDA.

Other liabilities decreased to $525,000 at March 31, 2005 from $3,081,000 at December 31, 2004 primarily due to the repayment in full of an oil sales security deposit.

Accrued liabilities increased from $172,000 at December 31, 2004 to $594,000 at March 31, 2005 due primarily to an increase in accrued professional fees relating to compliance with the Sarbanes-Oxley Act of 2002 and audit fees.

Long term debt increased to $865,000 at March 31, 2005 from $832,000 at December 31, 2004 due to amortization of debt discount related to the $1,050,000 convertible loan facility 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 March 31, 2005 the unamortized discount amounted to $79,000.

Contractual Obligations and Commercial Terms

Our principal business and assets are derived from production sharing contracts and agreements (“PSCs”) in the Republic of Georgia. The legislative and procedural regimes governing PSCs and mineral use licenses in Georgia have undergone a series of changes in recent years resulting in certain legal uncertainties.

Our PSCs 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 PSCs, conflicts between the interpretation of our PSCs and mineral use licenses and current legislation could arise. Such conflicts, if they arose, could cause an adverse effect on our rights under the PSCs. 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 (the “Ninotsminda PSC”) 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:

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Despite this confirmation and the grandfathering of the terms of existing PSCs in the Petroleum Law, subsequent legislative or other governmental changes could conflict with, challenge our rights or otherwise change current operations under the Ninotsminda PSC. No challenge has been made to date.

In 2002, the Participation Agreement for the three well exploration program on the Ninotsminda / Manavi area with a subsidiary of the US power company 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 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.

Under the Production Sharing Contract for Blocks XI^G and XI^H (the “Tbilisi PSC”) in the Republic of Georgia our subsidiary 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 Agreement which is September 29, 2003. The total commitment over the next sixteen 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 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 is 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 is due to be completed by June 2008, is anticipated to be up to $13,500,000.

The original Contractor party to the Samgori PSC, National Petroleum Limited (“NPL”), has 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 is not completed in part by September 2006 and in full by June 2008. Furthermore, 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 continue to have unrecovered costs, they will receive 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 will receive 30% of Profit Oil (net 15% to us). The allocation of a share of production to the State, however, relieves the Contractor parties of all obligations they would otherwise have to pay the Republic of Georgia for taxes, duties and levies related to activities covered by the Samgori PSC. 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 shall 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 Oil, cumulative Cost Recovery Natural Gas, 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.

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.

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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.

At March 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, we had a blow out of our N100 well. The Company estimates that the total costs attributable to the blow out, including compensation and cleaning of the environment will be $[???????]. The Company insurance policies covers 80% of these costs, the other 20% insurance retention being payable by CanArgo. The Company has accrued liabilities of $[315,000] to cover these costs.

Results of Continuing Operations

Three Month Period Ended March 31, 2005 Compared to Three Month Period Ended March 31, 2004

We recorded operating revenue from continuing operations of $1,334,000 during the three month period ended March 31, 2005 compared with $3,360,000 for the three month period ended March 31, 2004. The decrease is attributable to lower oil and gas revenues being recorded in the three month period ended March 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 37,590 barrels of oil for the three month period ended March 31, 2005 compared to 148,752 barrels of oil for the three month period ended March 31, 2004.

NOC generated $608,000 of oil and gas revenue in the three month period ended March 31, 2005 compared with $3,360,000 for the three month period ended March 31, 2004 primarily due to a lower production achieved in the three month period ended March 31, 2005 compared to the three month period ended March 31, 2004 offset partially by a higher average net sales price achieved in the three month period ended March 31, 2005 compared to the three month period ended March 31, 2004. Its net share of the 44,545 barrels (495 barrels per day) of gross oil production for sale from the Ninotsminda Field in the period amounted to 28,955 barrels. In the period, 8,564 barrels of oil were added to storage. For the three month period ended March 31, 2004, NOC’s net share of the 148,672 barrels (1,652 barrels per day) of gross oil production was 96,636 barrels.

CSL generated $725,000 of oil and gas revenue for the three month period ended March 31, 2005. Its net share of 46,578 barrels (518 barrels per day) of gross oil production for sale from the Samgori Field in the period amounted to 17,467 barrels. As at March 31, 2005, 12,011 barrels of oil remained in storage.

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 the first three months of 2005 averaged $36.49 per barrel as compared with an average of $22.32 per barrel in the first three months of 2004. Its net share of the 4,264 thousand cubic feet (mcf) of gas delivered was 2,771mcf at an average net sale price of $1.23 per mcf of gas. For the three month period ended March 31, 2005, NOC’s net share of the 50,553 mcf of gas delivered was 33,691mcf at an average net sales price of $1.23 per mcf of gas.

The operating loss from continuing operations for the three month period ended March 31, 2005 amounted to $2,207,000 compared with an operating profit of $974,000 for the three month period ended March 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, reduced oil and gas revenue and a gain generated from the disposal of GAOR in the three month period ended March 31, 2004, partially offset by a reduced depreciation, depletion and amortization in the period.

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Field operating expenses decreased to $499,000 for the three month period ended March 31, 2005 as compared to $668,000 for the three month period ended March 31, 2004. The decrease is primarily a result of a decrease in production at the Ninotsminda 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 decrease in our operating cost as the majority of our operating costs are fixed.

Direct project costs increased to $369,000 for the three month period ended March 31, 2005, from $280,000 for the three month period ended March 31, 2004, primarily due to costs directly associated with non operating activity at the Ninotsminda Field and the inclusion of Samgori project cost expenditures resulting from the acquisition of the Samgori (Block XI^B) Production Sharing Contract in Georgia.

Selling, general and administrative costs increased to $1,829,000 for the three month period ended March 31, 2005 from $912,000 for the three month period ended March 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, higher insurance premiums and a general increase in corporate activity.

Non cash stock compensation of $332,000 for the three month period ended March 31, 2005 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 $512,000 for the three month period ended March 31, 2005 from $881,000 for the three month period ended March 31, 2004 is attributable principally to lower production and sales from the Ninotsminda Field for the three month period ended March 31, 2005 compared to the three month period ended March 31, 2004.

The gain on disposal of subsidiaries of $354,000 recorded for the three month period ended March 31, 2004 reflects a gain from the disposal of our interest in the Georgian American Oil Refinery.

We recorded net other expense of $267,000 for the three month period ended March 31, 2005, as compared to net other income of $57,000 for the three month period ended March 31, 2004. The increase in net other expense of $324,000 is primarily due to an increase in foreign exchange losses, bank charges, bad debts, and equity loss from investments.

Equity loss from investments for the three month period ended March 31, 2005 of $93,000 relates to the loss incurred on the project in Kazakhstan to acquire oil and gas properties.

The loss from continuing operations of $2,473,000 or $0.01 per share for the three month period ended March 31, 2005 compares to a net income from continuing operations of $1,522,000 or $0.01 per share for the three month period ended March 31, 2004. The weighted average number of common shares outstanding was higher during the three month period ended March 31, 2005 than during the three month period ended March 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 Cornell Facility to repay the Cornell Capital promissory note and in connection with additional takedowns under the Facility and the exercise of share options in 2005.

Results of Discontinued Operations

Three Month Period Ended March 31, 2005 Compared to Three Month Period Ended March 31, 2004

The net income from discontinued operations, net of taxes and minority interest for the three month period ended March 31, 2004 amounted to $490,000 resulting from our refinery operation where the plan to dispose of the asset

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led to the write-off of an inter-company payable relating to oil sales purchased from Ninotsminda Oil Company Limited. All discontinued operations had been disposed by December 31, 2004.

Forward-Looking Statements

The forward-looking statements contained in this Item 2 and elsewhere in this Form 10-Q 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.

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.

We may not have a majority of the equity that is the licence developer of some projects that we may pursue in 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 such 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 ability to finance all of our present oil and gas projects and other ventures according to present plans is dependent upon obtaining additional funding. An inability to obtain financing could require us to scale back or abandon part or all of our project development, capital 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:

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.

The development of oil and gas properties is subject to substantial risks. Expectations regarding production, even if estimated by independent petroleum engineers, may prove to be unrealized. There are many uncertainties in estimating production quantities and in projecting future production rates and the timing and amount of future development expenditures. Estimates of properties in full production are more reliable than production estimates for new discoveries and other properties that are not fully productive. Accordingly, estimates related to our properties are subject to change as additional information becomes available.

Most of our interests in oil and gas properties and ventures are located in former Soviet Union countries. Operations in those countries are subject to certain additional risks including the following:

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Production estimates are subject to revision as prices and costs change. Production, even if present, may not be recoverable in the amount and at the rate anticipated and may not be recoverable in commercial quantities or on an economically feasible basis. World and local prices for oil and gas can fluctuate significantly, and a reduction in the revenue realizable from the sale of production can affect the economic feasibility of an oil and gas project. World and local political, economic and other conditions could affect our ability to proceed with or to effectively operate projects in various foreign countries.

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.

Item 3. 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 its revenues. We do not engage in any commodity hedging activities. Due to the ready market for our production in the Republic of Georgia, we do not believe that any current exposures from this risk will materially affect our financial position at this time, but there can be no assurance that changes in such market will not affect CanArgo adversely in the future.

Also, as indicated elsewhere in this Report, because all of our operations are being conducted in countries that were a part of 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 operates. At present we do not engage in any currency hedging operations since, to the extent we receive payments for our production in local currencies, we are utilizing such currencies to pay for our local operations. In addition, we frequently sell our production from the Ninotsminda Field and more recently from the Samgori Field in the Republic of Georgia under export contracts which provide for payment in US dollars.

CanArgo had no material interest in investments subject to market risk during the period covered by this report.

Item 4. Controls and Procedures

The Company maintains disclosure controls and procedures, as defined in Rule 13a-15 under the Securities Exchange Act of 1934, as amended, that are intended to ensure that information required to be disclosed in the Company’s reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that the Company’s employees accumulate this information and communicate it to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding the required disclosure.

As a result of our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and the rules issued thereunder, we reported in our Form 10-K/A filed with the Securities and Exchange Commission on May 2, 2005 that we had identified a number of deficiencies that were symptomatic of and contributed to the overall material weakness relating to our financial statement close process identified in our evaluation of

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the effectiveness of our internal control over financial reporting as of December 31, 2004. We also identified a material weakness relating to sufficient controls being in place to ensure adequate review of the application of generally accepted accounting principles relating to non-routine transactions, estimates and financial statement disclosures. Although as of March 31, 2005 these material weaknesses have not been fully remediated, we have been actively remedying the deficiencies described above, and have taken a number of appropriate remediation actions. The remediation efforts to date have generally involved the addition of staff, improvement in accounting and reporting processes and related controls and the appointment and training of dedicated controls personnel to remedy a number of the above deficiencies relating to the financial statement close process. Our remediation efforts represent a long-term commitment to continually evaluate and improve our financial statement closing process and our ability to properly apply generally accepted accounting principles relating to non-routine transactions, estimates and financial statement disclosures, in an effort to reduce to a minimal level the risk that a material error in our financial statements could occur. Other than this ongoing remediation effort there were no changes in our internal control over financial reporting or in other factors that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

CANARGO ENERGY CORPORATION AND SUBSIDIARIES

Item 6. Exhibits

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33

34

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SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

INDEX TO EXHIBITS