Edgar Filing: CANARGO ENERGY CORP

10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO

Commission File Number 0001-32145

CANARGO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		91-0881481

(State or other jurisdiction of Incorporation or organization)		(I.R.S. Employer Identification No.)

CanArgo Energy Corporation P.O. Box 291, St. Peter Port, Guernsey, British Isles		GY1 3RR

(Address of principal executive offices)		(Zip Code)

(44) 1481 729 980

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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, as amended (the “Exchange Act”) during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

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

Yes þ No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)

Yes o No þ

The number of shares of registrant’s common stock, par value $0.10 per share, outstanding on November 1, 2005 was 222,573,283.

CANARGO ENERGY CORPORATION
FORM 10-Q
TABLE OF CONTENTS


	Page
PART 1. FINANCIAL INFORMATION:
Item 1. Financial Statements
Consolidated Condensed Balance Sheets — unaudited		4
Consolidated Condensed Statements of Operations — unaudited		5
Consolidated Condensed Statements of Cash Flows — unaudited		6
Notes to Unaudited Consolidated Condensed Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

Item 3. Quantitative and Qualitative Disclosures about Market Risk		42

Item 4. Controls and Procedures		43

PART 2. OTHER INFORMATION:

Item 1. Legal Proceedings		46

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46

Item 6. Exhibits
(a) Exhibit Index		46

Signatures		51
Exhibit 31.1
Exhibit 31.2
Exhibit 32

Below is a list of terms that are common to our industry and used throughout this document:


/d		= per day
Bbl		= barrels
BBtu		= billion British thermal units
Bcf		= billion cubic feet
Bcfe		= billion cubic feet of natural gas equivalents
MBbls		= thousand barrels
Mcf		= thousand cubic feet
Mcfe		= thousand cubic feet of natural gas equivalents
MMBtu		= million British thermal units
MMcf		= million cubic feet
MMcfe		= million cubic feet of natural gas equivalents
MW		= megawatt
N GL		= natural gas liquids
T Btu		= trillion British thermal units

When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

When we refer to “us”, “we”, “our”, “ours”, the “Company”, or “CanArgo”, we are describing CanArgo Energy Corporation and/or our subsidiaries.

FORWARD-LOOKING STATEMENTS

The United States Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for certain forward-looking statements. Such forward-looking statements are based upon the current expectations of CanArgo and speak only as of the date made. These forward-looking statements involve risks, uncertainties and other factors. The factors discussed elsewhere in this Quarterly Report on Form 10-Q are among those factors that in some cases have affected CanArgo’s historic results and could cause actual results in the future to differ significantly from the results anticipated in forward-looking statements made in this Quarterly Report on Form 10-Q, future filings by CanArgo with the Securities and Exchange Commission, in CanArgo’s press releases and in oral statements made by authorized officers of CanArgo. When used in this Quarterly Report on Form 10-Q, the words “estimate,” “project,” “anticipate,” “expect,” “intend,” “believe,” “hope,” “may” and similar expressions, as well as “will,” “shall” and other indications of future tense, are intended to identify forward-looking statements. Few of the forward-looking statements in this Report deal with matters that are within our unilateral control. Acquisition, financing and other agreements and arrangements must be negotiated with independent third parties and, in some cases, must be approved by governmental agencies. These third parties generally have interests that do not coincide with ours and may conflict with our interests. Unless the third parties and we are able to compromise their various objectives in a mutually acceptable manner, agreements and arrangements will not be consummated.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CANARGO ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Condensed Balance Sheets


	September 30,			December 31,
	2005			2004
	(Unaudited)			(Audited)
ASSETS

Cash and cash equivalents	$	27,020,001		$	24,617,047
Restricted cash		3,155,269			1,400,000
Accounts receivable		2,162,635			2,526,442
Crude oil inventory		611,693			253,858
Prepayments		3,856,708			1,517,836
Assets held for sale		600,000			600,000
Other current assets		129,415			121,610

Total current assets	$	37,535,721		$	31,036,793

Capital assets, net (including unevaluated amounts of $42,383,952 and $25,102,945 respectively)		109,118,307			72,995,666
Prepaid financing fees		300,082			648,507
Investments in and advances to oil and gas and other ventures — net		—			478,632



Total Assets	$	146,954,110		$	105,159,598


LIABILITIES AND STOCKHOLDERS’ EQUITY

Accounts payable — trade	$	1,931,035		$	2,331,945
Loans payable		930,943			1,500,000
Other liabilities		37,043			3,080,839
Accrued liabilities		6,015,933			172,117

Total current liabilities	$	8,914,954		$	7,084,901

Long term debt		25,000,000			832,165
Other non current liabilities		439,156			—
Provision for future site restoration		699,650			422,000


Total Liabilities	$	35,053,760		$	8,339,066


Commitments and contingencies

Stockholders’ equity:
Common stock, par value $0.10; authorized - 300,000,000 shares; shares issued, issuable and outstanding - 222,586,867 at September 30, 2005 and 195,212,089 at December 31, 2004		22,258,685			19,521,208
Capital in excess of par value		204,595,666			184,141,618
Deferred compensation expense		(2,415,920	)		(1,976,102	)
Accumulated deficit		(112,538,081	)		(104,866,192	)

Total stockholders’ equity	$	111,900,350		$	96,820,532


Total Liabilities and Stockholders’ Equity	$	146,954,110		$	105,159,598

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

CANARGO ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Operations


	Unaudited						Unaudited
	Three Months Ended						Nine Months Ended
	September 30,			September 30,			September 30,			September 30,
	2005			2004			2005			2004
Operating Revenues from Continuing Operations:
Oil and gas sales	$	2,580,847		$	2,007,838		$	5,147,056		$	7,446,862

		2,580,847			2,007,838			5,147,056			7,446,862

Operating Expenses:
Field operating expenses		778,242			457,663			1,747,472			1,690,623
Direct project costs		349,646			591,454			1,130,842			1,218,589
Selling, general and administrative		2,354,045			1,602,983			5,712,782			3,728,290
Non-cash stock compensation expense		920,720			158,446			1,762,890			158,446
Depreciation, depletion and amortization		769,909			458,833			1,800,947			2,265,878
Impairment of oil and gas ventures and other assets		—			139,552			—			139,552
Income on dispositions		—			—			—			(335,014	)

		5,172,562			3,408,931			12,154,933			8,866,364


Operating Loss from Continuing Operations		(2,591,715	)		(1,401,093	)		(7,007,877	)		(1,419,502	)

Other Income (Expense):
Interest, net		(458,084	)		(408,259	)		(435,264	)		(664,645	)
Other		107,869			(834,521	)		(73,732	)		(933,241	)
Equity Loss from investments		—			—			(155,016	)		—

Total Other Expense		(350,215	)		(1,242,780	)		(664,012	)		(1,597,886	)

Loss from Continuing Operations Before Minority Interest and Taxes		(2,941,930	)		(2,643,873	)		(7,671,889	)		(3,017,388	)

Minority interest in loss (income) of consolidated subsidiaries		—			(301	)		—			—

Loss from Continuing Operations		(2,941,930	)		(2,644,174	)		(7,671,889	)		(3,017,388	)
Net Income from Discontinued Operations, net of taxes and minority interest		—			95,384			—			542,210


Net Loss	$	(2,941,930	)	$	(2,548,790	)	$	(7,671,889	)	$	(2,475,178	)


Weighted average number of common shares outstanding
- Basic		221,485,695			120,589,698			207,880,022			113,468,383

- Diluted		221,485,695			120,589,698			207,880,022			113,468,383

Basic Net Loss Per Common Share
- from continuing operations	$	(0.01	)	$	(0.02	)	$	(0.04	)	$	(0.03	)
- from discontinued operations	$	—		$	0.00		$	—		$	0.00


Basic Net Loss Per Common	$	(0.01	)	$	(0.01	)	$	(0.04	)	$	(0.02	)


Diluted Net Loss Per Common Share
- from continuing operations	$	(0.01	)	$	(0.02	)	$	(0.04	)	$	(0.03	)
- from discontinued operations	$	—		$	0.00		$	—		$	0.00

Diluted Net Loss Per Common	$	(0.01	)	$	(0.01	)	$	(0.04	)	$	(0.02	)


Other Comprehensive Income:
Foreign currency translation		—			90,708			—			310,231

Comprehensive Loss	$	(2,941,930	)	$	(2,458,082	)	$	(7,671,889	)	$	(2,164,947	)

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

CANARGO ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Cash Flows


	Nine months ended September, 30
	2005			2004
	(Unaudited)			(Unaudited)
Operating activities:
Loss from continuing operations		(7,671,889	)		(3,017,388	)
Adjustments to reconcile net loss from continuing operations to net cash provided by (used in) operating activities:
Non-cash stock compensation expense		1,762,890			158,446
Non-cash interest expense and amortization of debt discount		608,132			619,781
Non-cash debt extinguishment expense		—			349,923
Common stock issued for services		53,600			17,280
Non-cash miscellaneous expenses		32,890			—
Depreciation, depletion and amortization		1,800,947			2,265,878
Impairment of oil and gas ventures and other assets		—			139,552
Equity loss from investments		155,016			—
Gain on dispositions		—			(335,014	)
Allowance for doubtful accounts		155,686			—
Changes in assets and liabilities:
Restricted cash		(1,755,269	)		—
Accounts receivable		208,121			129,751
Inventory		(357,835	)		302,414
Prepayments		(158,656	)		27,245
Other current assets		(7,805	)		(695,807	)
Accounts payable		(698,072	)		341,006
Deferred revenue		(3,043,796	)		(899,247	)
Income taxes payable		—			(87,000	)
Accrued liabilities		696,477			271,108

Net cash used by operating activities		(8,219,563	)		(412,072	)


Investing activities:
Capital expenditures		(25,853,318	)		(7,387,430	)
Proceeds from disposition of subsidiary		—			250,001
Acquisitions, net of cash acquired		609,553			—
Investments in oil and gas and other ventures		—			(15,610	)
Advance proceeds from the sale of CanArgo Standard Oil Products		—			1,670,000
Change in non-cash working capital items		(395,514	)		363,469

Net cash used in investing activities		(25,639,279	)		(5,119,570	)


Financing activities:
Proceeds from sale of common stock		4,429,303			37,999,516
Share issue costs		(581,877	)		(2,817,179	)
Deferred offering costs		—			(433,376	)
Advances from joint venture partner		—			290,000
Payments of joint venture obligations		—			(1,063,146	)
Proceeds from loans		40,000,000			3,806,000
Repayment of loans		(7,200,000	)		(1,408,179	)
Deferred loan costs		(385,630	)		—

Net cash provided by financing activities		36,261,796			36,373,636


Net cash flows from assets and liabilities held for sale		—			(7,301	)


Net increase in cash and cash equivalents		2,402,954			30,834,693
Cash and cash equivalents, beginning of period		24,617,047			3,472,252

Cash and cash equivalents, end of period	$	27,020,001		$	34,306,945

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

CANARGO ENERGY CORPORATION AND SUBSIDIARIES

Notes to Unaudited Consolidated Condensed Financial Statements

1.		Basis of Presentation

		The interim consolidated condensed financial statements and notes thereto of CanArgo Energy Corporation and its subsidiaries (collectively, “we”, “our”, “CanArgo” or the “Company”) have been prepared by management without audit pursuant to the rules and regulations of the U.S. Securities and Exchange Commission. In the opinion of management, the consolidated condensed financial statements include all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results for the interim period. Although management believes that the disclosures are adequate to make the information presented not misleading, certain information and footnote disclosures, including a description of significant accounting policies normally included in the financial statements prepared in accordance with accounting principles generally accepted in the U.S., have been condensed or omitted pursuant to such rules and regulations. The accompanying consolidated condensed financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in CanArgo’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission. All amounts are in U.S. dollars. The results of operations for interim periods are not necessarily indicative of the results for any subsequent quarter or the entire fiscal year ending December 31, 2005.

		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.

2.		Business Combination

		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 Russ Hammond (one of our non-executive directors) is Investment Advisor and 5,500,000 shares to Vando in connection with this transaction. At June 7, 2005, the closing price of CanArgo total common stock was $0.76 giving the common stock consideration a market value of $8,360,000 for the 11 million shares. On completion of the acquisition, CanArgo held 100% of the ordinary share capital of Tethys through its subsidiary CanArgo Limited and Tethys became a wholly-owned subsidiary of the Company. We have recorded our interest as if the acquisition occurred on June 30, 2005. Tethys’ primary asset was its 70% interest in BN Munai, a Kazakhstan limited partnership.

		The purchase price was allocated to the net assets of Tethys as follows:


Cash	$	609,553
Oil and Gas Properties		6,599,315
Other Current Assets		1,688,294
Current Liabilities		(297,162	)
Provision for future site restoration		(240,000	)

	$	8,360,000

The following pro forma presentation assumes the Company’s acquisition of Tethys took place on January 1, 2004. The historical column presents the unaudited financial information of the Company for the periods indicated.


	Pro Forma (Unaudited)
	Nine Months Ended September 30, 2005
	Historical			Tethys			Adjustments			Combined
Revenue	$	5,147,056		$	—		$	—		$	5,147,056


Loss from continuing operations		($7,007,877	)		($215,649	)	$	155,016	⁽¹⁾		($7,068,510	)


Net (loss)		($7,671,889	)		($215,649	)	$	155,016			($7,732,522	)


Basic and diluted loss per share											($0.04	)


Basic and diluted weighted average common shares outstanding											214,286,615


(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.


	Pro Forma (Unaudited)
	Three Months Ended September 30, 2005
	Historical			Tethys		Adjustments		Combined
Revenue	$	2,580,847		$	—	$	—	$	2,580,847


Loss from continuing operations		($2,591,715	)	$	—	$	—		($2,591,715	)


Net (loss)		($2,941,930	)	$	—	$	—		($2,941,930	)


Basic and diluted loss per share									($0.01	)


Basic and diluted weighted average common shares outstanding									221,485,695


	Pro Forma (Unaudited)
	Nine Months Ended September 30, 2004
	Historical			Tethys		Adjustments		Combined
Revenue	$	7,446,862		$	—	$	—	$	7,446,862


Loss from continuing operations		($1,419,502	)	$	—	$	—		($1,419,502	)


Net (loss)		($2,475,178	)	$	—	$	—		($2,475,178	)


Basic and diluted income per share									($0.02	)


Basic and diluted weighted average common shares outstanding									113,468,383


	Pro Forma (Unaudited)
	Three Months Ended September 30, 2004
	Historical			Tethys		Adjustments		Combined
Revenue	$	2,007,838		$	—	$	—	$	2,007,838


Loss from continuing operations		($1,401,093	)	$	—	$	—		($1,401,093	)


Net income		($2,548,790	)	$	—	$	—		($2,548,790	)


Basic and diluted loss per share									($0.02	)


Basic and diluted weighted average common shares outstanding									120,589,698

3		Dismantlement, Restoration and Environmental Costs

		Effective January 1, 2003, 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. As at September 30, 2005 the asset retirement obligation, which is included on the consolidated balance sheet in provision for future site restoration, was $699,650 , which includes $246,000 for retirement obligations related to our acquired Tethys operations.

4		Foreign Operations

		Our current and future operations and earnings depend upon the results of our operations primarily in the Republic of Georgia (“Georgia”) and to a lesser degree in the Republic of Kazakhstan (“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 our financial position, results of operations and cash flows. Also, the success of our operations generally 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, 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 restrictive regulations.

5		New Accounting Standards

		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. The Company is currently assessing the impact of Interpretation No. 47 on its results of operations and 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.


6		Restricted Cash

		Restricted cash consisted of the following at September 30, 2005 and December 31, 2004:


	September 30,		December 31,
	2005		2004
	(Unaudited)		(Audited)
Restricted Cash — Escrow	$	—	$	1,400,000

Restricted Cash — Secured deposits		3,155,269		—


	$	3,155,269	$	1,400,000

		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 accordance with the terms of the escrow agreement.

		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 is due to become unrestricted in January 2006.

		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.

7		Accounts Receivable

		Accounts receivable at September 30, 2005 and December 31, 2004 consisted of the following:


	September 30,			December 31,
	2005			2004
	(Unaudited)			(Audited)

Trade receivables before allowance for doubtful debts	$	1,047,700		$	1,081,055
Allowance for doubtful debts		(1,021,925	)		(866,239	)
Due from Samgori PSC partner		1,050,398			1,057,534
Insurance receivable		549,793			1,047,359
Other receivables		536,669			206,733


	$	2,162,635		$	2,526,442

		Bad debt expense for the nine month period ended September 30, 2005 and September 30, 2004 was $155,686 and $0 respectively.

		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 September 30, 2005 and December 31, 2004, $549,793 and $1,047,359 was recorded as a receivable, respectively.

		Included in receivables as of September 30, 2005 and December 31, 2004 was $1,050,398 and $1,057,534, respectively, 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 have funded 100% of the costs so far and should GOSL not be in a position to or elect not to fund its share of the program costs, we are entitled to continue the project at our sole risk at which time the receivable would be transferred to oil and gas properties. We would be entitled to 100% of the contractor’s share of any incremental production resulting from the sole risk operations where we were the party undertaking the sole risk.

8		Inventory

		Inventory of crude oil at September 30, 2005 and December 31, 2004 consisted of the following:


	September 30,		December 31,
	2005		2004
	(Unaudited)		(Audited)

Crude oil	$	611,693	$	253,858


	$	611,693	$	253,858

9		Capital Assets

		Capital assets, net of accumulated depreciation and impairment, include the following at September 30, 2005:


			Accumulated			Net
			Depreciation			Capital
	Cost		And Impairment			Assets
Oil and Gas Properties
Proved properties	$	77,831,054	$	(24,826,329	)	$	53,004725
Unproved properties		44,475,011		—			44,475,011

		122,306,065		(24,826,329	)		97,479,736


Property and Equipment
Oil and gas related equipment		16,085,242		(5,032,872	)		11,052,370
Office furniture, fixtures and equipment and other		875,340		(289,139	)		586,201

		16,960,582		(5,322,011	)		11,638,571


	$	139,266,647	$	(30,148,340	)	$	109,118,307

Capital assets, net of accumulated depreciation and impairment, include the following at December 31, 2004:


			Accumulated			Net
			Depreciation			Capital
	Cost		And Impairment			Assets
Oil and Gas Properties
Proved properties	$	61,458,503	$	(23,382,448	)	$	38,076,055
Unproved properties		25,102,945		—			25,102,945

		86,561,448		(23,382,448	)		63,179,000


Property and Equipment
Oil and gas related equipment		14,119,443		(4,693,368	)		9,426,075
Office furniture, fixtures and equipment and other		689,439		(298,848	)		390,591

		14,808,882		(4,992,216	)		9,816,666


	$	101,370,330	$	(28,374,664	)	$	72,995,666

		Oil and Gas Properties

		Unproved property additions relate to our exploration activity in the period.

		Property and Equipment

		Oil and gas related equipment includes materials, drilling rigs and related equipment currently in use by us in the development of the Ninotsminda, Norio and Samgori Fields.

10		Prepaid financing fees

		Prepaid financing fees at September 30, 2005 and December 31, 2004:


	September 30, 2005		December 31, 2004
	(Unaudited)		(Audited)

Commission and Professional fees	$	300,082	$	648,507


	$	300,082	$	648,507

		Prepaid financing fees as at September 30, 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 and the additional Ozturk Long Term Loan with Detachable Warrants, both discussed in Note 12.

		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.

11		Investments in and Advances to Oil and Gas and Other Ventures

		As discussed in Note 2, 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 September 30, 2005 and December 31, 2004:


	September 30, 2005		December 31, 2004
	(Unaudited)		(Audited)

Kazakhstan — Through 45% ownership of Tethys Petroleum Investments Limited	$	—	$	683,862


Total Investments in and Advances to Oil and Gas and Other Ventures	$	—	$	683,862


Equity in Profit (Loss) of Oil and Gas and Other Ventures
Kazakhstan		—		(205,230	)

Cumulative Equity in Profit (Loss) of Oil and Gas and other ventures		—		(205,230	)


Total Investments in and Advances to Oil and Gas and Other Ventures, Net of Equity Loss	$	—	$	478,632

12		Loans Payable and Long Term Debt

		Loans payable at September 30, 2005 and December 31, 2004 consisted of the following:


	September 30,			December 31,
	2005			2004
	(Unaudited)			(Audited)
Short term loans payable
Promissory Notes	$	—		$	1,500,000
Loan with detachable warrants	$	1,050,000		$	—

Unamortized debt discount		(119,057	)		—


Loans payable	$	930,943		$	1,500,000


Long term debt
Senior Convertible Secured Loan Notes	$	25,000,000		$	—
Long term loans with detachable warrants	$	—		$	1,050,000
Unamortized debt discount	$	—		$	(217,835	)


Long term debt	$	25,000,000		$	832,165

		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:

		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 16,938,558 shares of CanArgo common stock. 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 the third quarter 2005 are described below.

		Long Term Loan with Detachable Warrants: This loan from Salahi Ozturk advanced pursuant to the amended and restated loan and warrant agreement dated August 27, 2004 (“Amended Agreement”) matures in August 2006 unless it has previously been converted. Corporate finance fees of $50,000 were paid in respect of the loan. Interest is payable quarterly at a rate of 7.5% per annum. The loan is convertible into shares of CanArgo Common Stock at 15% above a market price of $0.60 in effect when the agreement was reached in August 2004, subject to customary anti-dilution adjustments. We have the option to force conversion of the loan if our share price exceeds 160% of $0.60 (or $0.96 per share) for a period of 20 consecutive trading days. No conversion was possible until August 28, 2005.

		The Company’s closing stock price on the American Stock Exchange at the time of the 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 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.
		We used the following assumptions to determine the fair value of the debt and warrants:


	Additional Loan
Stock price on date of grant	$	0.51
Risk free rate of interest		2.51	%
Expected life of warrant – months		48
Dividend rate		—
Historical volatility		108	%

		The discounts are being amortized to expense interest over the life of the loan using the effective interest method. The effective interest rate was 18.9%. As of September 30, 2005 we had amortized $144,729 of the debt discount as interest expense.

		Promissory Note: On May 19, 2004, we signed a promissory note with Cornell Capital whereby Cornell Capital agreed to advance us the sum of $1,500,000. We have repaid the promissory note in full by making a series of takedowns in February and March 2005 under the SEDA.

		Senior Secured Convertible Loan Notes: On July 25, 2005, CanArgo completed a private placement of $25,000,000 in aggregate principal amount of our Senior Secured Convertible Loan 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 Note 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 (3% per annum) and the effective interest rate (12.3% per annum) which totalled $439,156 as of September 30, 2005 has been accrued as a non-current liability.

		The Company is amortising the professional fees incurred in relation to the Senior Secured Notes over the term of the Senior Secured Notes.

		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.

		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 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. (See page 30 “Liquidity and Capital Resources” section of Item 2 below for a more detailed discussion of covenants).

13		Other Liabilities

		Other liabilities consisted of the following at September 30, 2005 and December 31, 2004:


	September 30, 2005		December 31, 2004
	(Unaudited)		(Audited)

Prepaid sales and oil sales security deposit	$	17,043	$	2,699,644
Prepaid licence fees		20,000		80,000
Advanced proceeds from the sale of other assets		—		301,195


	$	37,043	$	3,080,839

		As of December 31, 2004 prepaid sales and oil sales security deposit included $2,300,000 arising from security deposit payments under an oil sales agreement with Primrose Financial Group (“Primrose”) dated May 5, 2004. In February 2005, we cancelled the May 2004 oil sales agreement with Primrose, repaid the security deposit in full and concluded a new oil sales agreement with Primrose.

		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.

14		Accrued Liabilities

		Accrued liabilities consisted of the following at September 30, 2005 and December 31, 2004:


	September 30, 2005		December 31, 2004
	(Unaudited)		(Audited)
Drilling contractors	$	5,143,111	$	—
Professional fees		704,984		93,001
Other		167,838		79,116


	$	6,015,933	$	172,117

		Included in the amounts due to drilling contractors at September 30, 2005 are amounts invoiced by Weatherford totalling $5,004,846. We have formally notified Weatherford that we dispute the validity of certain billings to the Company for work Weatherford performed in the first and second quarter of 2005. The amount under dispute is approximately $4.9 million. We have recorded all amounts billed by Weatherford as of September 30, 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.

15		Minority Interest

		Through our acquisition of 100% of Tethys Petroleum Investments Limited on June 9, 2005 we acquired a 70% ownership interest in the Kazakhstan based limited liability partnership, BN Munai LLP (“BN Munai”). BN Munai has only suffered losses from inception and currently the Company is the only partner funding the current operating losses, therefore, no minority interest is recorded at September 30, 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.


16		Stockholders’ Equity


	Common Stock
	Number of
	Shares				Additional			Deferred						Total
	Issued and				Paid-In			Compensation			Accumulated			Stockholders
	Issuable		Par Value		Capital			Expense			Deficit			Equity

Total, December 31, 2004		195,212,089	$	19,521,208	$	184,141,618		$	(1,976,102	)	$	(104,866,192	)	$	96,820,532

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		380,836		38,084		469,514									507,598

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		335,653		33,565		458,837									492,402

Exercise of stock options		1,067,833		106,783		255,850									362,633

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		344,758		34,476		498,072									532,548

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		370,599		37,060		562,940									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		381,170		38,117		561,883									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		495,745		49,574		550,426									600,000

Exercise of stock options		1,570,000		157,000		11,000									168,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		552,639		55,264		544,736									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		473,634		47,363		552,637									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		837,054		83,705		516,295									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		813,670		81,367		518,633									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		872,854		87,285		512,715									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		847,458		84,746		515,254									600,000

Shares Issueable pursuant to consultancy agreement (CEOCast)		80,000		8,000		45,600									53,600

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		801,068		80,107		519,893									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		812,348		81,235		518,765									600,000

Shares Issued pursuant to Tethys buy-out		11,000,000		1,100,000		7,260,000									8,360,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		639,591		63,959		536,041									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		596,421		59,642		540,358									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		613,246		61,325		538,675									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		630,120		63,012		536,988									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		669,568		66,957		533,043									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		761,325		76,133		523,867									600,000

Shares Issued pursuant to Standby Equity Distribution agreement (Cornell Capital)		783,188		78,319		521,681									600,000

Exercise of stock options		360,000		36,000		481,320									517,320

Exercise of stock options		284,000		28,400		352,950									381,350

Stock based compensation under SFAS 148		—		—		2,202,708			(439,818	)					1,762,890

Share issue costs		—		—		(1,186,633	)								(1,186,633	)

Net Loss		—		—		—						(7,671,889	)		(7,671,889	)


Total, September 30, 2005		222,586,867	$	22,258,685	$	204,595,666		$	(2,415,920	)	$	(112,538,081	)	$	111,900,350

		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. 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 SEDA, Cornell Capital provided 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 was $20,000,000. Subject to this limitation, we could draw down up to $600,000 in any seven trading-day period (a “Put”). The SEDA 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 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. Such discount comprised (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 SEDA; 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. On July 25, 2005, we issued to Cornell Capital a notice 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, referred to below.

		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 was payable either in cash or using the net proceeds of drawdowns under the SEDA, within 270 days from the date of the Promissory Note. The Promissory Note was repaid in full in cash on August 1, 2005.

		On June 9, 2005 we issued 11,000,000 shares of CanArgo Common Stock by way of exchange for 55% of the share capital of Tethys Petroleum Investments Limited, (“Tethys”), thereby making Tethys a wholly owned subsidiary of CanArgo. (See “Notes to Unaudited Consolidated Condensed Financial Statements, Item 2 Business Combination” above for a more detailed discussion).

		On October 5, 2005, we passed a resolution to cancel the 7,260,647 shares of CanArgo common stock returned from escrow following the termination of the SEDA on August 24, 2005.

17		Net Income (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 and net income (loss). Basic earnings (loss) per share is computed based upon the 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.

		Basic and diluted net loss per common share for the nine month and three month periods ended September 30, 2005 and September 30, 2004 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 nine months ended September 30, 2005 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 41,255,621 for the nine months ended September 30, 2005.

18		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 September 30, 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 XI^G and XI^H (the “Tbilisi PSC”) in the Republic of 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 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 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 December 2006 and in full by December 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.

		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.

		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.

19		Discontinued Operations

		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 exploration and production activities. 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 results of discontinued operations in respect of CSOP consisted of the following for the nine month period ended September 30, 2004:


	September 30,		September 30,
	2005		2004
	(Unaudited)		(Unaudited)

Operating Revenues	$	—	$	11,537,284

Loss Before Income taxes and Minority Interest		—		(36,484	)
Income Taxes		—		—
Minority Interest in Loss		—		18,242

Net Loss from Discontinued Operation	$	—	$	(18,242	)

The results of discontinued operations in respect of CSOP consisted of the following for the three month period ended September 30, 2004:


	September 30,		September 30,
	2005		2004
	(Unaudited)		(Unaudited)

Operating Revenues	$	—	$	5,801,742

Income before income taxes and minority interest		—		(146,465	)
Income tax benefit		—		(41,278	)
Minority interest in loss		—		92,359

Net income from discontinued operation	$	—	$	95,384

		Lateral Vector Resources Inc

		Lateral Vector Resources Inc. (“LVR”), a wholly-owned subsidiary of CanArgo, negotiated and concluded with Ukrnafta, the Ukrainian State Oil Company, a Joint Investment Production Activity (“JIPA”) agreement in 1998 to develop the Bugruvativske 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 if certain production targets are achieved on the project.

The results of discontinued operations in respect of LVR consisted of the following for the nine month period ended September 30, 2004:


	September 30,		September 30,
	2005		2004
	(Unaudited)		(Unaudited)

Loss (Income) Before Income taxes and Minority Interest	$	—	$	—


Net Loss (Income) from Discontinued Operation	$	—	$	—

The results of discontinued operations in respect of LVR consisted of the following for the three month period ended September 30, 2004:


	September 30,		September 30,
	2005		2004
	(Unaudited)		(Unaudited)
Loss (Income) Before Income taxes and Minority Interest	$	—	$	—


Net Loss (Income) from Discontinued Operation	$	—	$	—

		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 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. The gain recorded on disposition of GAOR was $330,923.

		The results of operations of GAOR have been classified as discontinued for all periods presented. Net income from discontinued operations is disclosed net of taxes and minority interest. The plan to dispose of the asset 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 nine months ended September 30, 2004:


	September 30,		September 30,
	2005		2004
	(Unaudited)		(Unaudited)
Operating Revenues	$	—	$	—

Loss (Income) Before Income taxes and Minority Interest		—		—

Minority Interest in Loss		—		(523,968	)


Net Income from Discontinued Operation	$	—	$	(523,968	)

The results of discontinued operations in respect of GAOR consisted of the following for the three months ended September 30, 2004:


	September 30,		September 30,
	2005		2004
	(Unaudited)		(Unaudited)
Operating Revenues	$	—	$	—

Loss (Income) Before Income taxes and Minority Interest		—		—

Minority Interest in Loss		—		—


Net Loss (Income) from Discontinued Operation	$	—	$	—

		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. Following receipt of a non-refundable deposit of $300,000, the unit was shipped to the US for testing. The test was completed at the beginning of 2005, however, the proposed buyer failed to meet the sale contract terms resulting in the loss of its deposit in the third quarter, 2005.

		The generator has been classified as “Assets held for sale” for all periods presented and we expect to agree a sale with a different buyer in the near future.

		Gross consolidated assets in respect of the generator included in “assets held for sale” consisted of the following at September 30, 2005 and December 31, 2004:


	September 30, 2005		December 31, 2004
	(Unaudited)		(Audited)
Assets held for sale:
Capital assets, net	$	600,000	$	600,000

	$	600,000	$	600,000

20		Segment and Geographical Data

		The segment and geographical data below is presented for the nine and three month periods ended September 30, 2005. For the nine and three month periods ended September 30, 2004 the Republic of Georgia represented the only geographical segment.

Operating revenues from continuing operations for the nine month period ended September 30, 2005 by geographical area were as follows:


	September 30,
	2005
	(Unaudited)
Oil and Gas Exploration, Development And Production
Republic of Georgia	$	5,147,056
Republic of Kazakhstan		—


Total	$	5,147,056

Operating revenues from continuing operations for the three month period ended September 30, 2005 by geographical area were as follows:


	September 30,
	2005
	(Unaudited)
Oil and Gas Exploration, Development And Production
Republic of Georgia	$	2,580,847
Republic of Kazakhstan		—


Total	$	2,580,847

Operating (loss) income from continuing operations for the nine month period ended September 30, 2005 by geographical area was as follows:


	September 30,
	2005
	(Unaudited)
Oil and Gas Exploration, Development And Production
Republic of Georgia	$	1,119,974
Republic of Kazakhstan		(486,492	)

Corporate and Other Expenses		(7,641,359	)


Total Operating Loss	$	(7,007,877	)

Operating income (loss) income from continuing operations for the three month period ended September 30, 2005 by geographical area was as follows:


	September 30,
	2005
	(Unaudited)
Oil and Gas Exploration, Development And Production
Republic of Georgia	$	1,172,162


	September 30,
	2005
	(Unaudited)
Republic of Kazakhstan		(486,492	)

Corporate and Other Expenses		(3,277,385	)


Total Operating Loss	$	(2,591,715	)

Net (loss) income before minority interest from continuing operations for the nine month period ended September 30, 2005 by geographical area was as follows:


	September 30,
	2005
	(Unaudited)
Oil and Gas Exploration, Development And Production
Republic of Georgia	$	1,119,974
Republic of Kazakhstan		(486,492	)

Corporate and Other Expenses		(8,305,371	)


Net (Loss) Income Before Minority Interest	$	(7,671,889	)

Net (loss) income before minority interest from continuing operations for the three month period ended September 30, 2005 by geographical area was as follows:


	September 30,
	2005
	(Unaudited)
Oil and Gas Exploration, Development And Production
Republic of Georgia	$	1,172,162
Republic of Kazakhstan		(486,492	)

Corporate and Other Expenses		(3,627,600	)


Net (Loss) Income Before Minority Interest	$	(2,941,930	)

The segment and geographical data below is presented as of September 30, 2005. As of December 31, 2004 the Republic of Georgia represented the only geographical segment.

Identifiable assets of continuing and discontinued operations as of September 30, 2005 by business segment and geographical area were as follows:


	September 30,
	2005
	(Unaudited)
Corporate
Republic of Georgia	$	511,050
Republic of Kazakhstan		—
Western Europe (principally cash)		37,344,287

Total Corporate		37,855,337


Oil and Gas Exploration, Development and Production
Republic of Georgia		97,948,276
Republic of Kazakhstan		10,550,497

Assets Held for Sale
Western Europe		600,000



Total Identifiable Assets	$	146,954,110

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.

Overview

Operationally, during the quarter, we continued to progress our exploration, appraisal and development plans both in our core area of Georgia and on our more recently acquired assets in Kazakhstan.

Georgia

Following the failure of Weatherford International Ltd, (“Weatherford”) to successfully complete any horizontal sidetrack development wells on the Ninotsminda Field using Under-Balanced Coiled Tubing Drilling (“UBCTD”) technology, Weatherford demobilised its equipment and left Georgia in July. Despite this lack of success, which we attribute mainly to multiple equipment failures, we still believe that underbalanced technology is the best technology with which to develop both the Ninotsminda and Samgori Fields. In this respect, we continue our negotiations with other UBCTD equipment and service suppliers and hope to be in a position to return to under-balanced drilling operations in 2006.

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 (“Baker Hughes”) 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 having drilled a horizontal section of 1,667 feet (508 metres). A pre-perforated liner has been run over a 1,421 foot (433 metres) interval in the horizontal section and the well is currently being tested

On August 26, 2005 we announced that the Manavi M11Z well had reached a TD of 14,994 feet (4,570 metres) measured depth (MD) in the Cretaceous. This well was drilled to appraise the Manavi M11 oil discovery which was made in 2003 but not fully tested due to the collapse of the production tubing due to pressure during testing. The M11Z well has been deviated to a location some 0.37 miles (0.6 kilometres) away from the original hole. It was sidetracked using a Saipem S.p.A. (“Saipem”) Ideco E-2100Az drilling rig and a Baker-Hughes oil-based mud system to drill through the over-pressured swelling clays that had proven challenging in the past. The well was completed in the Cretaceous using slim-hole drilling technology.

In the M11Z well, the primary Cretaceous limestone target was encountered at 14,032 feet (4,277 metres) MD some 230 feet (70 metres) MD higher than in the original M11 well while the secondary Middle Eocene target zone was penetrated at 13,009 feet (3,965 metres) 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 2^7/8 inch (73 mm) liner was run in the slim hole, and the Saipem drilling rig removed from the site while CanArgo Rig #1 was mobilised 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.

We are continuing to consult with Schlumberger, our well completions experts, to advise on the best technique in which to re-establish communication with the formation in M11Z by removing near-wellbore damage. A number of proposals are being considered including matrix acidizing performed below fracturing rate and pressure with the acid conveyed to the area of interest by coiled tubing, and slickline conveyed perforating. However, neither option excludes the other and we are making preparations to recommence the testing operations within the next two weeks.

We have identified further appraisal locations on the Manavi structure. The next well, M12, will be drilled approximately 2.5 miles (4 kilometres) to the west of the M11 location along the crest of the structure. The drilling site is already prepared and a CanArgo rig is being mobilised to the site to drill out and set the surface casing in advance of Saipem being mobilised from the Norio exploration well.

Following the success of drilling through over-pressured clays on the M11Z well with the Saipem rig and the Baker-Hughes oil based mud system, the Saipem drilling rig was mobilised to the Norio MK72 exploration well where drilling operations are ongoing.

The well, located within the Norio Production Sharing Agreement area is targeting a potentially large prospect mapped at Middle Eocene level just to the north of the Samgori Field. The well is currently at a depth of 15,853 feet (4,832 metres), is drilling ahead and is near to the prognosed target zone. Oil has already been encountered in the well which penetrated approximately 985 feet (300 metres) of net sandstones in the Oligocene secondary target, with oil being indicated by electric logs and with good oil and gas shows while drilling.

Negotiations are continuing with the Georgian Government on the principles of a long-term gas offtake agreement and subject to concluding the agreement, we plan to drill an appraisal well on the Kumisi gas prospect to the west of the Rustavi R16 well, which flowed gas from the Cretaceous sequence at a depth of 12,792 feet (3,900 metres), close to the interpreted gas-water contact. Given our current level of operations in the country, it is unlike any well would now commence before the second half of 2006.

Kazakhstan

In Kazakhstan, our Kyzyloi Gas Field development project and further exploration in the surrounding area is progressing well. The Kyzyloi Gas Field is located within the Akkulka exploration block, a 411,749 acres (1,667 km²) area located in the North Ustyurt basin in western Kazakhstan, just to the west of the Aral Sea.

On the Kyzyloi Field three wells have been tested to date, namely the KYZ105, KYZ104 and KYZ102 wells. Well KYZ105 was perforated and flowed gas at a rates of up to 1.77 million cubic feet (50,000 cubic metres) per day on an 20/64 inch (8 mm) choke. The KYZ104 well flowed gas at a rate of 3.39 million cubic feet (96,000 cubic metres) per day on a 40/64 inch (16 mm) choke while well KYZ102 flowed gas at a rate in excess of 4.24 million cubic feet (120,000 cubic metres) per day on a 60/64 inch (20 mm) choke. All three wells are now shut in waiting for the installation of field development equipment. Three further wells are to be tested for the initial field development in

which a 37.3 mile (60 km) pipeline is planned to tie the field to the main Bukhara-Urals gas trunkline. A long-term gas offtake agreement is currently under negotiation, with first gas expected in Q2 2006, with an initial plateau rate of 17.7 million cubic feet (500,000 cubic metres) per day.

On October 6, 2005 we announced the execution of a Memorandum of Understanding covering co-operation in the gas sector in Kazakhstan with Gaz Impex S.A., one of the leading Kazakh based companies involved in gas marketing.

The Akkulka Block exploration program is continuing, with a further two year extension having now been agreed by the Expert Commission. Currently three of the five planned exploration wells have reached Total Depth (TD) (AKK03 — TD 2,461 feet (750 metres), AKK05 — TD 2,215 feet (675 metres) and AKK04 — TD 1,969 feet (600 metres)). These well are being drilled on seismic anomalies which we have identified on modern seismic data in our acreage surrounding the Kyzyloi Field and are analogous to the Kyzyloi structure. In all three wells gas shows have been observed while drilling and wireline logs indicate the presence of gas bearing sands in the wells. The AKK03 and AKK05 wells are cased and casing is being run in the AKK04 well. Testing has commenced but is not yet completed on any well as such testing is being undertaken as part of a co-ordinated testing programme including the Kyzyloi Field development wells. This co-ordinated approach is both cost-effective and assists in logistics operating in this area.

On October 6, 2005 we announced that our Kazakh subsidiary BN Munai LLP had signed with the Minister of Energy and Mineral Resources of Kazakhstan, the Parliament of Kazakhstan, and in conjunction with the major operating companies in Kazakhstan, a Memorandum of Understanding on Extractive Industries Transparency Initiative.

The seismic reprocessing and interpretation project on the Akkulka contract area is on schedule. The existing seismic data is being reprocessed with the objective of improving the resolution at depth in an attempt to firm up deeper prospects. A number of potential structures have already been identified. We believe that these prospects have potential to be similar to the reported large gas condensate fields just to the south in Uzbekistan which lie along the same structural trend. Based on the results of the interpretation of the reprocessed date, we may include a deep exploration well in our plans for 2006.

Work is continuing to finalise the acquisition of the exploration contract for the Greater Akkulka area, an area of approximately 10,000 km² (10.9 million acres) surrounding the Akkulka Block where we are currently conducting our exploration drilling program. We believe that this area has substantial exploration potential. We have also submitted an application for two further areas in the recent Kazakh licensing round and expect that the winners will be announced in the early part of 2006.

Liquidity and Capital Resources

As of September 30, 2005 we had working capital of $28,621,000 compared to working capital of $23,952,000 as of December 31, 2004.

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 the appraisal of a new gas project in Georgia, to fund the development of the Kyzyloy Gas Field in Kazakhstan and adjacent exploration areas, and for additional working capital for our development, appraisal and exploration activities in Georgia. 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 of 1933, as amended (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.

The terms of the Note Purchase Agreement and related agreements include the following:

Interest . The unpaid principal balance under the Note bears interest (computed on the basis of a 360-day year of twelve 30-day months) (a) at increasing rates ranging from 3% per annum from the date of issuance to December 31, 2005; 10% per annum from January 1, 2006 until December 31, 2006; and 15% per annum from January 1, 2007 until final payment, payable semi-annually, on June 30 and December 30 , commencing December 30, 2005, until the principal shall have become due and payable and (b) at 3% per annum above the applicable rate on any overdue payments of principal and interest.

Optional Prepayments. CanArgo may, at its 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 Note, 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.

Mandatory Prepayment. CanArgo shall offer to prepay all, but not less than all, of the Note, on not less than 15 business days prior written notice, in the event of an occurrence of a Change of Control or Control Event. “Change in Control” is defined to mean (a) if CanArgo shall at any time cease to be a publicly held company or cease to have its capital stock traded on an exchange or (b) a transaction or series of related transactions pursuant to which (i) at least fifty-one percent (51%) of the outstanding shares of CanArgo’s common stock or, on a fully diluted basis, shall subsequent to July 25, 2005 be owned by any person which is not related to or affiliated with CanArgo, (ii) if CanArgo merges into or with, consolidates with or effects any plan of share exchange or other combination with any person which is not related to or affiliated with CanArgo, or (iii) if CanArgo disposes of all or substantially all of its assets other than in the ordinary course of business and “Control Event” is defined to mean (i) the execution by CanArgo or any material subsidiary of CanArgo which has guaranteed the indebtedness evidenced by the Note (a “CanArgo Group Member”) of any agreement or letter of intent with respect to any proposed transaction or event or series of transactions or events which, individually or in the aggregate, may reasonably be expected to result in a Change in Control, or (ii) the execution of any written agreement which, when fully performed by the parties thereto, would result in a Change in Control.

Conversion. The Note is convertible, at the option of holders, into shares of CanArgo common stock (“Conversion Stock”) at a conversion price per share of $0.90 (the “Conversion Price”), which is subject to adjustment: (a) if CanArgo issues any equity securities (other than pursuant to the granting of employee stock options pursuant to shareholder approved employee stock option plans or existing outstanding options, warrants and convertible securities) at a price per share of less than $0.90 per share net of all fees, costs and expenses in which case the Conversion Price will be reset to such lower price and (b) in connection with any stock split, stock dividend, reverse stock split, reclassification, recapitalization, combination, merger, consolidation or any similar transaction, in which case the Conversion Price and number of shares of Conversion Stock will be appropriately adjusted to reflect any such event, such that the holders of the Note will receive upon conversion the identical number of shares of common stock or other consideration or property to be received by the holders of the common stock as if the holders had converted the Note immediately prior to any such event as such amount would then be adjusted by reason of such stock split, stock dividend, reverse stock split, reclassification, recapitalization, combination, merger, consolidation or other similar transaction. No fractional shares of common stock shall be issued upon any conversion; instead the Conversion Price shall be appropriately adjusted so that holders shall receive the nearest whole number of shares upon any conversion.

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.

Security. Payment of all amounts due and payable under the Note Purchase Agreement, the Note and all related agreements (collectively, the “Loan Documents”) is secured by a security interest in all of CanArgo’s assets, including its principal Guernsey bank account, as well as, guarantees from each other CanArgo Group Member and pledges of all of the outstanding capital stock of Ninotsminda Oil Company Limited, a limited liability company incorporated under the laws of the Republic of Cyprus; CanArgo Limited, a company incorporated under the laws of the Island of Guernsey; and Tethys Petroleum Investments Limited, a company incorporated under the laws of the Island of Guernsey, each of which is an indirect subsidiary of CanArgo. If CanArgo forms or acquires a Material Subsidiary (as defined in the Note Purchase Agreement) it shall cause such Subsidiary to execute a Subsidiary Guaranty (other than for certain excepted companies and legal entities) and thereby become a CanArgo Group Member subject to the provisions of the Note Purchase Agreement.

Covenants. Under the terms of the Note Purchase Agreement CanArgo is subject to certain affirmative and negative covenants, which can be waived by the beneficial holders of at least 51% of the outstanding principal amount of the Note (the “Required Holders”), including the following affirmative and negative covenants, respectively: (a) providing current information regarding CanArgo and rights of inspection; compliance with laws; maintenance of corporate existence, insurance and properties; payment of taxes; providing additional security; payment of counsel fees for the Purchasers (not in excess of $100,000) and a placement fee of $250,000; and termination of the SEDA, and (b) restrictions on: transactions with affiliates; mergers, consolidations and sales of all of CanArgo’s assets; liens (except for certain permitted liens); the issuance of additional senior or pari passu indebtedness; changes in CanArgo’s line of business; certain types of payments; sale-and leasebacks; sales of assets other than in the ordinary course of business; future Indebtedness, as defined in the Note Purchase Agreement (other than certain permitted indebtedness); canceling, terminating, waiving or amending provisions of, or selling any interests in (other than under certain circumstances) any of the Basic Agreements (as defined in the Note Purchase Agreement); and adopting any anti-take-over defenses except as permitted by the Note Purchase Agreement. CanArgo is not subject to any financial covenants, such as the maintenance of minimum net worth or coverage ratios, other than the restriction on its ability to incur additional Indebtedness.

Events of Default. An “Event of Default” shall exist if one or more of the following occurs and is continuing: (i) failure to pay when due any principal and, after 5 days, any interest, payable under the Note or any Security Document; (ii) default in the performance of certain enumerated covenants; (iii) default in the performance or compliance with any other terms which remains unremedied for 30 days after the earlier of a Responsible Officer first obtaining actual and not constructive knowledge of the default or the receipt of notice; (iv) any representation or warranty made in writing on behalf of CanArgo or any other CanArgo Group Member proves to have been false or incorrect in any material respect; (v) customary events involving bankruptcy, insolvency or reorganization; (vi) the entry of a final judgment or judgments in excess of $2,500,000 (uncovered by insurance), which is not discharged or settled; (vii) violations of ERISA or the Internal Revenue Code of 1986, as amended, under funding of accrued benefit liabilities and other matters relating to employee benefit plans subject to ERISA or Foreign Pension Plans; (viii) any Loan Document ceases to be in full force and effect (except in accordance with its terms) or its validity is challenged by CanArgo or any affiliate; (ix) CanArgo or any other CanArgo Group Member modifies its Charter Document which results in a Default or Event of Default or will adversely affect the rights of Noteholders; or (x) a change occurs in the consolidated financial condition of CanArgo or in the physical, operational or financial status of the Properties (as defined in the Note Purchase Agreement), which change has a Material Adverse Effect (as defined in the Note Purchase Agreement).

Other than for certain Events of Default that will result in an automatic acceleration without notice, such as bankruptcy, if an Event of Default occurs and is continuing, the Required Holders may at any time at its or their option, by notice to CanArgo, declare all outstanding Notes to be immediately due and payable and holders of the Note may proceed to enforce their rights under the Loan Documents at law or in equity. CanArgo is responsible for the payment of all costs of collection, including all reasonable legal fees actually incurred in connection therewith.

Miscellaneous. The Note Purchase Agreement, the Note, the Security Agreement, the Subsidiary Guaranty and the Registration Rights Agreement are all governed by New York Law and the CanArgo Group Members party thereto subject themselves to the jurisdiction of New York Courts and waive the right to jury trial. The Pledge Agreements and the Security Interest Agreement relating to CanArgo’s bank account are governed by the laws of the Bailiwick of Guernsey and the Republic of Cyprus, as provided therein. The Company incurred fees and commissions in connection with the placement of the Senior Secured Notes in the aggregate amount of $385,000.

On August 1, 2005, we made a payment of $7,422,410.96 being the outstanding principal and accrued interest amount payable by CanArgo to Cornell Capital under the terms of both the Promissory Note and the SEDA. In accordance with Section 6 of the Promissory Note, upon receipt of such outstanding sums the Promissory Note is deemed cancelled.

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.

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) means we have 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, and our exploration and development plans in the Republic of Kazakhstan, absent any unforeseen circumstances.

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

•		funding of a field development plan will be timely;

•		that our development plan will be successfully completed or will increase production; or

•		that field operating revenues after completion of the development plan will exceed operating costs.

Under the terms of the Senior Secured Notes we are restricted from incurring future indebtedness and from issuing additional senior or pari passu indebtedness, except with the prior consent of the Required Holders or in limited permitted circumstances. The definition of indebtedness encompasses all customary forms of indebtedness including, without limitation, liabilities for the deferred consideration, liabilities for borrowed money secured by any lien or other specified security interest, liabilities in respect of letters of credit or similar instruments (excluding letters of credit which are 100% cash collateralised) and guarantees in relation to such forms of indebtedness (excluding parent company guarantees provided by the Company in respect of the indebtedness or obligations of any of the Company’s subsidiaries under its Basic Documents (as defined in the Note Purchase Agreement)). Pursuant to the terms of the Note Purchase Agreement, permitted future indebtedness is (a) indebtedness outstanding under the Senior Secured Notes; (b) any additional unsecured indebtedness, the aggregate amount outstanding thereunder at any time not exceeding $1,250,000 and; (c) certain unsecured intra-group indebtedness (in the case of indebtedness of a CanArgo Group Member (as defined in the Note Purchase Agreement) to a direct or indirect subsidiary of the Company which is not deemed to be a Material Subsidiary under the Note Purchase Agreement the aggregate amount outstanding under the particular indebtedness shall not exceed $1,000,000 at any time).

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. As discussed above, under the terms of the Senior Secured Notes we are restricted from incurring additional Indebtedness.

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:

•		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, 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 increased $2,403,000 from $24,617,000 at December 31, 2004 to $27,020,000 at September 30, 2005. The increase was primarily due to cash received pursuant to the takedowns under the SEDA and the Senior Secured Notes. This has been partially offset by 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, activities in Kazakhstan and net cash used by operating activities.

Restricted cash increased to $3,155,000 at September 30, 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 $2,163,000 at September 30, 2005 primarily due to 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 $612,000 at September 30, 2005 due to the accumulation of larger batches of oil for export sales.

Prepayments increased from $1,518,000 at December 31, 2004 to $3,857,000 at September 30, 2005 as a result of an increase in prepayments for materials and services related to our appraisal activities at the Manavi oil discovery, our horizontal well development program at the Ninotsminda and Samgori Fields and 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 September 30, 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 $129,000 at September 30, 2005.

Capital assets net, increased to $109,118,000 at September 30, 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 acquisition of Tethys Petroleum Investments Limited and its 70% interest in the Kazakhstan based company BN Munai LLP.

Prepaid financing fees decreased to $300,000 at September 30, 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 September 30, 2005.

Accounts payable decreased to $1,931,000 at September 30, 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.

Loans payable decreased to $931,000 at September 30, 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 $931,000 loan payable at September 30, 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 September 30, 2005 the unamortized discount amounted to $119,000.

Other liabilities decreased to $37,000 at September 30, 2005 from $3,081,000 at December 31, 2004 primarily 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 $6,016,000 at September 30, 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.

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, now recorded in loans payable.

Other non current liabilities of $439,000 at September 30, 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 $700,000 at September 30, 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.

Deferred compensation expense increased to $2,415,000 at September 30, 2005 from $1,976,102 at December 31, 2004 due to share options issue expensed during the period.

Contractual Obligations and Commercial Terms

Our principal business and assets are derived from production sharing contracts and agreements (“PSCs”) in the Republic of Georgia and to a lesser extent, in the Republic of Kazakhstan. 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:

•		The State of Georgia recognizes and confirms the validity and enforceability of the Ninotsminda PSC and the license and all undertakings the State has covenanted with Ninotsminda Oil Company Limited (“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 Ninotsminda PSC.

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 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 ten 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, it is planned that 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.

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 September 30, 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. The Company currently estimates that the total costs attributable to the blow out, including compensation and cleaning of the environment will be approximately $2,000,000.

Results of Continuing Operations

Nine Month Period Ended September 30, 2005 Compared to Nine Month Period Ended September 30, 2004

We recorded operating revenue from continuing operations of $5,147,000 during the nine month period ended September 30, 2005 compared with $7,447,000 for the nine month period ended September 30, 2004. The decrease is attributable to lower oil and gas revenues being recorded in the nine month period ended September 30, 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 117,933 barrels of oil for the nine month period ended September 30, 2005 compared to 297,876 barrels of oil for the nine month period ended September 30, 2004.

NOC generated $3,931,000 of oil and gas revenue in the nine month period ended September 30, 2005 compared with $6,407,000 for the nine month period ended September 30, 2004 primarily due to a lower production achieved in the nine month period ended September 30, 2005 compared to the nine month period ended September 30, 2004 offset partially by a higher average net sales price achieved in the nine month period ended September 30, 2005 compared to the nine month period ended September 30, 2004. Its net share of the 138,319 barrels (507 barrels per day) of gross oil production for sale from the Ninotsminda Field in the period amounted to 89,907 barrels. For the nine month period ended September 30, 2004, NOC’s net share of the 314,972 barrels (1,150 barrels per day) of gross oil production was 245,209 barrels.

CSL generated $1,216,000 of oil and gas revenue for the nine month period ended September 30, 2005 compared to $1,040,000 from the April 2004 purchase date to September 30, 2004. Its net share of 127,122 barrels (695 barrels per day) of gross oil production for sale from the Samgori Field in the period amounted to 46,671 barrels. As at September 30, 2005, 24,957 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 nine months of 2005 averaged $43.79 per barrel as compared with an average of $24.82 per barrel in the first nine months of 2004. Its net share of the 89,300 thousand cubic feet (mcf) of gas delivered was 46,307 mcf at an average net sale price of $0.53 per mcf of gas. For the nine month period ended September 30, 2004, NOC’s net share of the 57,453 mcf of gas delivered was 37,416 mcf at an average net sales price of $1.41 per mcf of gas.

The operating loss from continuing operations for the nine month period ended September 30, 2005 amounted to $7,008,000 compared with an operating loss of $1,420,000 for the nine month period ended September 30, 2004. The increase in operating loss is attributable to increased field operating expenses, 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 nine month period ended September 30, 2004, partially offset by a reduced depreciation, depletion and amortization in the period.

Field operating expenses increased to $1,747,000 for the nine month period ended September 30, 2005 as compared to $1,690,000 for the nine month period ended September 30, 2004. The increase is primarily a result of increased oil processing fees in relation to the Samgori field during the period partially offset by a decrease in production at the Ninotsminda Field . 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 decreased to $1,131,000 for the nine month period ended September 30, 2005, from $1,219,000 for the nine month period ended September 30, 2004, primarily due to decreased costs directly associated with non operating activity at the Ninotsminda Field partially offset by 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 $5,713,000 for the nine month period ended September 30, 2005 from $3,728,000 for the nine month period ended September 30, 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.

Non cash stock compensation expense increased to $1,763,000 for the nine month period ended September 30, 2005 from $158,000 for the nine month period ended September 30, 2004 due to share options issue 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 decrease in depreciation, depletion and amortization expense to $1,801,000 for the nine month period ended September 30, 2005 from $2,266,000 for the nine month period ended September 30, 2004 is attributable principally to lower production and sales from the Ninotsminda Field for the nine month period ended September 30, 2005 compared to the nine month period ended September 30, 2004.

The gain on disposal of subsidiaries of $335,000 recorded for the nine month period ended September 30, 2004 reflects a gain from the disposal of our interest in the Georgian American Oil Refinery, partially offset by a loss from the disposal of our interest in the Bugruvativske Field through the disposal of Lateral Vector Resources Inc.

The decrease in other expense to $664,000 for the nine month period ended September 30, 2005, from $1,598,000 for the nine month period ended September 30, 2004 is primarily a result of higher interest income as a result placing surplus cash on term deposits until needed, realization of the advanced proceeds on the sale of the generator that was abandoned, partially offset by increased levels of bad debts and foreign exchange losses.

Equity loss from investments for the nine month period ended September 30, 2005 of $155,000 relates to the loss incurred on the project in Kazakhstan to the date of the acquisition of 100% ownership in Tethys Petroleum Investments Limited.

The loss from continuing operations of $7,672,000 or $0.04 per share for the nine month period ended September 30, 2005 compares to a net loss from continuing operations of $3,017,000 or $0.02 per share for the nine month period ended September 30, 2004. The weighted average number of common shares outstanding was higher during the nine month period ended September 30, 2005 than during the nine month period ended September 30, 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.

Three Month Period Ended September 30, 2005 Compared to Three Month Period Ended September 30, 2004

We recorded operating revenue from continuing operations of $2,581,000 during the three month period ended September 30, 2005 compared with $2,008,000 for the three month period ended September 30, 2004. The increase is attributable to higher price per barrel realized by the company in 2005, partially offset by lower production levels relating to a delay in the UBCTD program on both the Ninotsminda and Samgori Fields. Ninotsminda Oil Company Limited (“NOC”) sold 51,507 barrels of oil and CanArgo Samgori Limited (“CSL”) sold no barrels of oil for the three month period ended September 30, 2005 compared to 54,719 barrels of oil for NOC for the three month period ended September 30, 2004 and CSL.

NOC generated $2,581,000 of oil and gas revenue in the three month period ended September 30, 2005 compared with $1,253,000 for the three month period ended September 30, 2004 primarily due to the accumulation of larger batches of oil for export sales, partially offset by a lower production achieved in the three month period ended September 30, 2005 compared to the three month period ended September 30, 2004 offset partially by a higher average net sales price achieved in the three month period ended September 30, 2005 compared to the three month period ended September 30, 2004. Its net share of the 43,292 barrels (471 barrels per day) of gross oil production for sale from the Ninotsminda Field in the period amounted to 28,140 barrels. In the period, 23,368 barrels of oil were sold from storage. For the three month period ended September 30, 2004, NOC’s net share of the 71,093 barrels (773 barrels per day) of gross oil production was 46,727 barrels.

CSL generated nil oil and gas revenue for the three month period ended September 30, 2005 compared to $738,000 from the April 2004 purchase date to September 30, 2004 due to the accumulation of larger batches of oil for export sales. Its net share of 37,274 barrels (405 barrels per day) of gross oil production for sale from the Samgori Field in the period amounted to 13,978 barrels. As at September 30, 2005, 24,957 barrels of oil remained in storage. From the purchase date to September 30, 2004, CSL’s net share of the 54,502 barrels (588 barrels per day) of gross oil production was 20,270 barrels.

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 third quarter of 2005 averaged $50.11 per barrel as compared with an average of $30.68 per barrel in the third quarter of 2004. No gas sales were delivered for the three month period ended September 30, 2005. For the three month period ended September 30, 2004, NOC’s net share of the 18,924 mcf of gas delivered was 12,300 mcf at an average net sales price of $1.41 per mcf of gas.

The operating loss from continuing operations for the three month period ended September 30, 2005 amounted to $2,592,000 compared with an operating loss of $1,401,000 for the three month period ended September 30, 2004. The increase in operating loss is attributable to increased field operating expenses, increased selling, general and administration costs, increased non cash stock compensation expense, partially offset by increased oil and gas revenue and reduced direct project costs,and increased depreciation, depletion and amortization in the period.

Field operating expenses increased to $778,000 for the three month period ended September 30, 2005 as compared to $458,000 for the three month period ended September 30, 2004. The increase is primarily a result of increased oil processing fees in relation to the Samgori field during the period partially offset by a decrease in production at the Ninotsminda Field. 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 decreased to $350,000 for the three month period ended September 30, 2005, from $591,000 for the three month period ended September 30, 2004, primarily due to decreased costs directly associated with non operating activity at the Ninotsminda Field.

Selling, general and administrative costs increased to $2,354,000 for the three month period ended September 30, 2005 from $1,602,000 for the three month period ended September 30, 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.

Non cash stock compensation expense increased to $921,000 for the three month period ended September 30, 2005 from $158,000 for the three month period ended September 30, 2004 due to share options issue 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 $770,000 for the three month period ended September 30, 2005 from $459,000 for the three month period ended September 30, 2004 is attributable principally to the increased amount of our oil and gas cost pool for the three month period ended September 30, 2005 compared to the three month period ended September 30, 2004.

The decrease in other expense to $350,000 for the three month period ended September 30, 2005, from $1,243,000 for the three month period ended September 30, 2004 is primarily a result of higher interest income as a result placing surplus cash on term deposits until needed, realization of the advanced proceeds from the sale of the generator that was abandoned, partially offset by increased levels of bad debts and foreign exchange losses.

The loss from continuing operations of $2,942,000 or $0.01 per share for the three month period ended September 30, 2005 compares to a net loss from continuing operations of $2,644,000 or $0.01 per share for the three month period ended September 30, 2004. The weighted average number of common shares outstanding was higher during the three month period ended September 30, 2005 than during the three month period ended September 30, 2004, principally due to 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.

Results of Discontinued Operations

Nine Month Period Ended September 30, 2005 Compared to Nine Month Period Ended September 30, 2004

The net income from discontinued operations, net of taxes and minority interest for the nine month period ended September 30, 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.

Three Month Period Ended September 30, 2005 Compared to Three Month Period Ended September 30, 2004

The net income from discontinued operations, net of taxes and minority interest for the three month period ended September 30, 2004 amounted to $95,000 related principally to the activities of CSOP. All discontinued operations had been disposed by December 31, 2004.

Commitments and Contingencies

See Item 1, Financial Statements, Note 18, which is incorporated herein by reference.

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:

•

world economic conditions;

•		the state of 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 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.

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:

•		uncertainty as to the enforceability of contracts;

•		currency convertibility and transferability;

•		unexpected changes in fiscal and tax policies;

•		sudden or unexpected changes in demand for crude oil and or natural gas;

•		the lack of trained personnel; and

•		the lack of equipment and services and other factors that could significantly change the economics of production.

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

Management’s Responsibility for Financial Statements

Our management is responsible for the integrity and objectivity of all information presented in this Quarterly 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.

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors. Based on their evaluation as of September 30, 2005, our Chairman of the Board of Directors, President and Chief Executive Officer, Dr. David Robson (principal executive officer), and Richard Battey, our Chief Financial Officer (principal financial officer) have concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) are effective to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act with the Securities and Exchange Commission (“SEC”) (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (2) is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the rules promulgated under the Exchange Act. 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 based on the framework in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As a result of our efforts in 2004 to comply with Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX 404”) and the rules issued thereunder, we reported in our Form 10-K, as amended, for the fiscal year ended December 31, 2004 and our Quarterly Reports on Form 10-Q for the fiscal quarters ended March 31, 2005 and June 30, 2005 that we had identified material weaknesses listed below in the design or operation of internal control over financial reporting that required remediation and, if left unremedied, were reasonably likely to affect our ability to record, process, summarize and report financial data in a timely and accurate manner.

In the course of our evaluation, we identified the following material weaknesses in internal control over financial reporting under the standards adopted by the Public Company Accounting Oversight Board:

•

A number of deficiencies that were symptomatic of and contributed to the overall material weakness relating to the financial statement close process were identified by management and the independent registered accountants during the SOX 404 evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2004. Each deficiency identified fell within one of the following categories:

	1.		the lack of adequate review and supervision over the financial statement close process (which is primarily related to the lack of segregation of duties as a result of the Company’s limited number of personnel);

	2.		the lack of documentation of standard processes and policies to insure a consistent and accurate closing process;

	3.		too much dependence on the use of spreadsheets that are not properly protected from unauthorized access and/or errors in formulas used; and

	4.		the number of audit adjustments required to be recorded after being identified by the independent registered accountants.

•

A material weakness relating to lack of 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 was identified by management and the independent registered accountants during the SOX 404 evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2004.

Although as of September 30, 2005 the material weaknesses identified above have not been remediated, we have taken a number of appropriate actions to insure that the assessment process for 2005 is properly completed and the material weaknesses noted from 2004 are addressed. Management has implemented the following actions in the period since it issued its assessment report (some of which are described in greater detail below in “Changes in internal control over financial reporting”):

•		Improvement in accounting and reporting processes and related controls.

•		In order to address the lack of adequate review and supervision over the financial statement close process the Company enhanced its management resources through the appointment of a new Chief Financial Officer in May 2005. Furthermore, the number of designated accounting staff employed by the Company was increased in both its head office in Guernsey and in its offices in the Republic of Georgia.

•		Discussed with the Company’s audit committee the assessment and a timetable to address the material weaknesses. Various personnel have been assigned responsibilities in connection with this timetable.

•		Management has scheduled discussions among management, the Company’s SOX 404 consultant and the Company’s independent registered accountants to commence prior to the start of the assessment process this year to review open items and to map out the steps necessary to correct outstanding deficiencies in a timely manner.

•		Management is performing its 2005 ongoing assessment in a more timely fashion.

•		We are in the process of appointing a firm of accountants to provide us with advice on the application of generally accepted accounting principles relating to non-routine transactions, estimates and financial statement disclosures.

Management anticipates that as a result of the remediation that has taken place and is currently ongoing, we will have appropriately addressed the open issues and will be able to conclude that our internal control over financial reporting is effective as of the end of the fiscal year ended December 31, 2005.

Changes in internal control over financial reporting

As a result of the remediation efforts described above there have been the following changes in our internal control over financial reporting in the third quarter:

•

We have introduced more comprehensive formal preparation and review checklists and sign-off procedures at both group and subsidiary level on key reconciliations and accounting schedules.

•		We have increased the level of review of the preparation of the quarterly financial statements which has significantly reduced the number of adjustments required in the post closing process.

•		We have improved the documentation of procedures for closing the books and preparing financial statements.

•		We have improved access controls over key spreadsheets

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

On September 12, 2005, WEUS Holding Inc (“WEUS”) a subsidiary of Weatherford International Limited 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 underbalanced 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.

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 the Republic of Georgia on September 11, 2004. The relief sought pursuant to the claim is payment of the sum of 28.925 million GEL.

The Company believes that it has meritorious defenses to both claims and intends to defend them vigorously.

Other than the foregoing, as at September 30, 2005 there were no legal proceedings pending involving the Company, which, if adversely decided, would have a material adverse effect on the Company’s financial position on business. From time to time we are subject to various legal proceedings in the ordinary course of our business.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On July 25, 2005, we closed the private placement of $25,000,000 issue of Senior Secured Notes with a group of private investors, all of whom represented that they qualified as “accredited investors” under Rule 501(a) promulgated under the Securities Act of 1933 as amended (“Purchasers”). In connection with the placement we entered into a Note Purchase Agreement with the Purchasers, pursuant to which we issued a note due July 25, 2009 (“Note”) 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. The Note is convertible, at the option of the holders, into shares of CanArgo common stock (“Conversion Stock”) at a price per share of $0.90 (“Conversion Price”), subject to adjustment (i) if CanArgo issues certain specified securities at a price per share of less than $0.90 per share in which case the Conversion Price shall be reset to such lower amount; and (ii) subject to customary anti-dilution adjustments. A Registration Statement on Form S-3 (File No 333-127841) in respect of the Conversion Stock was filed with the SEC on August 25, 2005 pursuant to which the Company intend to register the Conversion Stock for resale under the Securities Act. As at November 8, 2005, the Registration Statement has not yet been declared effective.

Item 6. Exhibits

(a)

Exhibits


		Management Contracts, Compensation Plans and Arrangements are identified by an asterisk (*) Documents filed herewith are identified by a cross (†).

1	(1)	Engagement Agreement with Sundal Collier & Co ASA dated August 13, 2001.


				(Incorporated herein by reference from Post-Effective Amendment No. 2 to Form S-1 Registration Statement, File No. 333-85116 filed on September 10, 2002)).

	1(2)			Standby Equity Distribution Agreement between Cornell Capital Partners, L.P. and CanArgo Energy Corporation dated February 11, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2003 (Reg. No. 333-115261)).

	1(3)			Placement Agent Agreement between CanArgo Energy Corporation, Newbridge Securities Corporation and Cornell Capital Partners, L.P. dated February 11, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2003 (Reg. No. 333-115261)).

	1(4)			Placement Agent Agreement dated September 22, 2004 by and between ABG Sundal Collier, Norge ASA and CanArgo Energy Corporation (Incorporated herein by reference from Amendment No 2 to Registration Statement on Form S-3 filed August 31, 2004 (Reg. No. 333-115645)).

	1(5)			Placement Agent Agreement dated September 22, 2004 by and between ABG Sundal Collier Inc. and CanArgo Energy Corporation (Incorporated herein by reference from Amendment No 1 to Registration Statement on Form S-3 filed July 1, 2004 (Reg. No. 333-115645)).

	1(6)			Engagement letter between ABG Sundal Collier Norge ASA and CanArgo Energy Corporation dated March 23, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q).

	2(4)			Memorandum of Agreement between Fielden Management Services Pty, Ltd., A.C.N. 005 506 123 and Fountain Oil Incorporated dated May 16, 1995 (Incorporated herein by reference from December 31, 1997 Form 10-K/A).

	3(1)			Registrant’s Certificate of Incorporation and amendments thereto (Incorporated by reference from the Company’s Proxy Statements filed May 10, 1999 and May 9, 2000 and Form 8-K filed July 24, 1998).

	3(2)			Registrant’s Bylaws (Incorporated herein by reference from Post-Effective Amendment No. 1 to Form S-1 Registration Statement, File No. 333-72295 filed on July 29, 1999).

	*4(1)			Amended and Restated 1995 Long-Term Incentive Plan (Incorporated herein by reference from Post-Effective Amendment No. 1 to Form S-1 Registration Statement, File No. 333-72295 filed on July 29, 1999).

	*4(2)			Amended and Restated CanArgo Energy Inc. Stock Option Plan (Incorporated herein by reference from March 31, 1998 Form 10-Q).

	4(3)			Registration Rights Agreement between CanArgo Energy Corporation and Cornell Capital Partners, LP dated February 11, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2003 (Reg. No. 333-115261)).

	4(4)			Escrow Agreement among CanArgo Energy Corporation, Cornell Capital Partners, LP and Butler Gonzalez LLP dated February 11, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2003 (Reg. No. 333-115261)).

	*4(5)			CanArgo Energy Corporation 2004 Long Term Incentive Plan (Incorporated herein by reference from Form 8-K dated May 19, 2004).

	4(6)			Amended and Restated Loan and Warrant Agreement between CanArgo Energy


				Corporation and Salahi Ozturk dated August 27, 2004 (Incorporated herein by reference from Form 8-K dated August 27, 2004).

	4(6)			Note Purchase Agreement dated July 25, 2005 among CanArgo Energy Corporation and Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K/A dated July 28, 2005).

	4(7)			Registration Rights Agreement dated July 25, 2005 among CanArgo Energy Corporation and Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K dated July 27, 2005).

	10(1)			Production Sharing Contract between (1) Georgia and (2) Georgian Oil and JKX Ninotsminda Ltd. dated February 12, 1996 (Incorporated herein by reference from Form S-1 Registration Statement, File No. 333-72295 filed on September 7, 1999).

	*10(2)			Management Services Agreement between CanArgo Energy Corporation and Vazon Energy Limited relating to the provisions of the services of Dr. David Robson dated June 29, 2000 (Incorporated herein by reference from March 31, 2000 Form 10-Q). As amended by Deed of Variation of Management Services Agreement between CanArgo Energy Corporation and Vazon Energy Limited dated May 2, 2003 (Incorporated herein by reference to Form 8-K dated May 13, 2003).

	10(3)			Tenancy Agreement between CanArgo Energy Corporation and Grosvenor West End Properties dated September 8, 2000 (Incorporated herein by reference from March 31, 2000 Form 10-Q).

	10(4)			Production Sharing Contract between (1) Georgia and (2) Georgian Oil and CanArgo Norio Limited dated December 12, 2000 (Incorporated herein by reference from December 31, 2000 Form 10-K).

	*10(5)			Service Agreement between CanArgo Energy Corporation and Vincent McDonnell dated December 1, 2000 (Incorporated herein by reference from December 31, 2001 Form 10-K).

	10(6)			Sale agreement of CanArgo Petroleum Products Limited between CanArgo Limited and Westrade Alliance LLC dated October 14, 2002. (Incorporated herein by reference from March 31, 2002 Form 10-Q).

	10(7)			Farm-in Agreement dated September 4, 2003 relating to the Norio (Block XI^C) and North Kumisi Production Sharing Agreement in the Republic of Georgia with a wholly owned subsidiary of Georgian Oil, the Georgian State Oil Company (Incorporated herein by reference from March 31, 2003 Form 10-Q).

	10(8)			Stock Purchase Agreement dated September 24, 2003 regarding the sale of all of the issued and outstanding stock of Fountain Oil Boryslaw (Incorporated herein by reference from March 31, 2003 Form 10-Q).

	10(9)			Manavi Termination Agreement dated December 5, 2003 (Incorporated herein by reference from December 31, 2004 Form 10-K).

	10(10)			Termination Agreement between CanArgo Energy Corporation and Cornell Capital Partners, L.P. dated February 11, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2003 (Reg. No. 333-115261)).

	10(11)			Agreement between CanArgo Samgori Limited and Georgian Oil Samgori Limited dated January 8, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2003 (Reg. No. 333-115261)).


10	(12)	Consultancy Agreement between CanArgo Energy Corporation and Europa Oil Services Limited dated January 8, 2004 (Incorporated herein by reference from Form S-3 filed May 6, 2003 (Reg. No. 333-115261)).

10	(13)	Loan Agreement between CanArgo Energy Corporation and Salahi Ozturk dated April 26, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q).

10	(14)	Loan Agreement between CanArgo Energy Corporation and C A Fiduciary Services Limited AS dated April 29, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q).

10	(15)	Oil Sales Agreement between CanArgo Energy Corporation and Primrose Financial Group dated May 5, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q).

10	(16)	Oil Sales Agreement between CanArgo Energy Corporation and Sveti Limited dated April 1, 2004 (Incorporated herein by reference from March 31, 2004 Form 10-Q).

10	(17)	Agreement dated April 25, 2004 between Ninotsminda Oil Company Limited, Sveti Limited and Primrose Financial Group on the termination of the Crude Oil Sales Agreement dated April 1, 2004 between Ninotsminda Oil Company Limited and Sveti Limited and the terms for the conclusion of a new crude oil sales agreement between Ninotsminda Oil Company Limited and Primrose Financial Group (Incorporated herein by reference from March 31, 2004 Form 10-Q).

10	(18)	Promissory Note dated May 19, 2004 between CanArgo Energy Corporation and Cornell Capital Partners, LP (Incorporated herein by reference from Form 8-K dated May 19, 2004) as amended by Letter of Amendment between Cornell Capital Partners, LP and CanArgo Energy Corporation dated December 21, 2004 (Incorporated herein by reference from Form 8-K dated December 21, 2004).

10	(19)	Agreement dated March 17, 2004 between CanArgo Acquisition Corporation and Stanhope Solutions Ltd for the sale of Lateral Vector Resources Ltd. (Incorporated herein by reference from Form 8-K dated May 19, 2004).

10	(20)	Master Service Contract dated June 1, 2004 between CanArgo Energy Corporation and WEUS Holding Inc. (Incorporated herein by reference from Form 8-K dated June 1, 2004).

10	(21)	Agreement number GN-070/RIG/NOC dated 21 June, 2004 between Ninotsminda Oil Company Limited and Great Wall Drilling Company Limited (Incorporated herein by reference from Form 8-K dated June 21, 2004).

10	(22)	Agreement between Ninotsminda Oil Company Limited and Saipem S.p.A. dated January 27, 2005 (Incorporated herein by reference from Form 8-K dated January 27, 2005).

10	(23)	Agreement between Ninotsminda Oil Company Limited and Primrose Financial Group dated February 4, 2005 (Incorporated herein by reference from Form 8-K dated February 4, 2005).

10	(24)	Termination Agreement between Ninotsminda Oil Company Limited and Primrose Financial Group dated February 4, 2005 (Incorporated herein by reference from Form 8-K dated February 4, 2005).


	10(25)			Promissory Note dated April 26, 2005 between CanArgo Energy Corporation and Cornell Capital Partners, LP (Incorporated herein by reference from Form 8-K dated April 26, 2005).

	10(26)			Subsidiary Guaranty dated July 25, 2005 by and among Ninotsminda Oil Company Limited, CanArgo (Nazvreri) Limited, CanArgo Norio Limited, CanArgo Limited, CanArgo Samgori Limited, Tethys Petroleum Investments Limited and CanArgo Ltd for the benefit of the holders of the Notes 10(2&

	10(27)			Security Agreement dated July 25, 2005 among Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K dated July 27, 2005).

	10(28)			Form of Management Services Agreement for Richard J. Battey, Chief Financial Officer.

	10(29)			Agreement dated July 25, 2005 among CanArgo Limited and Ingalls & Snyder Value Partners, L.P. together with the other Purchasers (Incorporated herein by reference from Form 8-K dated July 27, 2005).

	10(30)			Security Interest Agreement (Securities) dated July 25, 205 among CanArgo Ltd, CanArgo Limited, Ingalls & Snyder LLC as Security Agent for the Secured Parties (Incorporated herein by reference from Form 8-K dated July 27, 2005).

	10(31)			Security Interest Agreement (Securities) dated July 25, 2005 among Tethys Petroleum Investments Limited, CanArgo Limited, Ingalls & Snyder LLC, as Security Agent for the Secured Parties and the Secured Parties (Incorporated herein by reference from Form 8-K dated July 27, 2005).

	10(32)			Security Interest Agreement (Bank Account) dated July 25, 2005 by and among CanArgo Energy Corporation, Ingalls & Snyder LLC, as Security Agent for the Secured Parties and the Secured Parties (Incorporated herein by reference from Form 8-K dated July 27, 2005).

	14			Code of Ethics (Incorporated herein by reference from December 31, 2004 Form 10-K).

	21			List of Subsidiaries (Incorporated herein by reference from June 30, 2005 Form 10-Q).

	†33(1)			Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer of CanArgo Energy Corporation.

	†31(2)			Rule 13a-14(c)/15d-14(a) Certification of Chief Financial Officer of CanArgo Energy Corporation.

	†32			Section 1350 Certifications.

SIGNATURES

In accordance with the requirements of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	CANARGO ENERGY CORPORATION
Date: November 9, 2005	By:	/s/Richard J. Battey
		Richard J. Battey
		Chief Financial Officer