Exhibit 99.1
FOR IMMEDIATE RELEASE IN EUROPE & NORTH AMERICA
CanArgo Announces Preliminary 2007 Year End Results
March 2, 2008 — Guernsey, Channel Islands — CanArgo Energy Corporation (“CanArgo” or the “Company”) (OSE:CNR, AMEX:CNR) today announced its preliminary unaudited results for the fiscal year ended December 31, 2007 and provided an update on operation activities.
Operating Revenues from Continuing Operations for 2007 increased by approximately 10% over 2006 to $7.2 million. The increase in revenue was attributable to an increase in the realised price for its oil produced at the Ninotsminda Field in Georgia.
The Company reported a net loss for 2007 of $53.8 million compared to a net loss for 2006 of $60.5 million. During the year, the Company disposed of its entire interest in its project in Kazakhstan and used the proceeds generated from the sale to significantly reduce its long term debt. Gains recorded in Net Income from Discontinued Operations partially offset by Loss/Cost recorded on Debt Extinguishment contributed to the overall reduced net loss for 2007.
Operating Loss from Continuing Operations for 2007 also improved to $46.6 million for 2007 compared to $48.5 million in 2006. This was due to improvements in Operating revenues from Continuing Operations, Field Operating Expenses, Direct Project Costs, Selling, General and Administrative Expenses and Depreciation, Depletion and Amortization, however, this was partially offset by an increased Impairment of Oil and Gas Properties, Ventures and Other Assets of $42.0 million compared to $39.0 million in 2006.
The Company performed its annual assessment of its costs classified as unproved property to determine if they should be transferred to the cost pool. After evaluating a number of factors including the length of time that these costs remained classified as unproved property, the Company determined that approximately $49.1 million of costs principally relating to the drilling of exploration wells should be moved to the cost pool. The quarterly “ceiling test” determined that the net capitalized costs in the cost pool exceeded the 10% net present value of cash flows generated from the Company’s proved reserves resulting in an Impairment of Oil and Gas Properties, Ventures and Other assets of $42.0 million in the last quarter of 2007.
The Company also provided an operations update on its activities in Georgia.
Production at the Ninotsminda Field averaged approximately 425 barrels of oil per day gross and approximately 2.36 million cubic feet (“MMcf”) (67.26 thousand cubic metres (“MCM”)) of gas per day for January 2008.
Further to an ongoing technical re-evaluation of the Ninotsminda Field, the Company believes that there are significant potential reserves remaining both within and surrounding the main field area and the Company is working on a production enhancement strategy to increase the level of production subject to financing being available. Such strategy may include: the drilling of horizontal wells in the undeveloped eastern part of the field; drilling a new vertical well to exploit potential oil reserves in the Oligocene interval over the northern flank of the field; and utilising new technology to access isolated reserves in shallower reservoirs overlying the main field area.
A gas pipeline connecting the region in which the Ninotsminda Field is located to the Georgian gas network was completed in February 2008. This infrastructure may provide the Company with access to an alternative market for its gas production and with potential for higher prices and regular sales. For the past couple of years, rather than flaring the gas produced from the Ninotsminda Field which is mainly associated gas, CanArgo’s wholly owned subsidiary company, Ninotsminda Oil Company Limited (“NOC”), has supplied this gas at a low price to local villages as part of a social program. Despite the price being only $0.71 per thousand cubic feet (“Mcf”) ($25.00 per MCM) there is a significant outstanding debt to NOC for the gas supplied. It was not socially or politically acceptable for NOC to terminate or restrict supply in order to force payment as these villages did not have access to an alternative supply of gas. With the connection of these areas to the domestic gas grid, both NOC and Georgian Oil and Gas Corporation (“GOGC”), who is also the State representative in the Production Sharing Contract and sells its share of the gas together with NOC, believe that they are now in a better position to enforce payment and commercialise gas sales. Following the completion of the gas connection, the existing gas sales agreement between NOC, GOGC and the local gas supply company has been amended to increase the price for gas to an average of approximately $2.72 per Mcf ($97 per MCM). The new price is based on a quantity of gas being set aside for domestic household consumption at $0.71 per Mcf ($25.00 per MCM) with the balance supplied to the gas distribution company at $4.73 per Mcf ($167.00 per MCM). The amendment is effective from February 1, 2008 and the gross quantity of gas to be supplied under the agreement is approximately 2.12 MMcf (60 MCM) per day. At present, the local gas distribution companies in Georgia are State entities, but plans are in place to privatize all gas distribution companies in the near future. This is also expected to help with the payment for gas.
At the Manavi 12 well, the acid fracturing stimulation was successfully completed in January 2008 with pressure data suggesting that the formation had been fractured. The initial flow-back of frac fluids (spent acid and chemicals) contained encouraging shows of oil and gas, but following clean-up, the maximum oil cut observed was only 5-7%. It appeared that there was a significant water incursion into the wellbore with no indication as to the source of this excess water. It was noted that following the simple acid wash completed in April 2007, an oil cut of approximately 50% was observed. Before further testing could be done, it was necessary to replace the 5 inch frac string required for the stimulation operation with proper 2 7/8 inch production grade tubing as planned.
The original plan was to set a plug in the well using the Schlumberger coiled tubing unit which was onsite for the stimulation operation, however, a failure of the injector head led to the coil parting and dropping into the well. It took several days to retrieve the coil and it was only then realised that the plug had been damaged and lodged in the well. A wireline unit was mobilised from Baku to reset the plug. This was successfully completed, but on extraction of the frac string by CanArgo Georgia it became apparent that damage had also been caused to the completion which resulted in a modification to the final well completion being required. The production tubing is now in place and pressure tested and operations are progressing to retrieve the mechanical plug and continue with the well testing operation. In the meantime, Schlumberger has demobilised from the site.
As part of the testing program, a wireline-conveyed production logging tool will be run in the well to help locate fluid entry points to the well and provide downhole flow rate and pressure data during the test. This data will assist in the evaluation of well conditions and reservoir performance and help assess the overall potential of the well.
The MK72 exploration well completed by CanArgo in 2006 in the Norio Production Sharing Agreement area encountered hydrocarbons in both target horizons, but was never fully tested for operational reasons. In order to finance an appraisal well, the Company has been pursuing a farm-out strategy for this acreage. Several oil and gas companies evaluated this opportunity in 2007 and a number of these are continuing farm-in negotiations with the Company today.
CanArgo is an independent oil and gas exploration and production company with its oil and gas operations currently located in Georgia.
The matters discussed in this press release include forward-looking statements, which 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. Such risks, uncertainties and other factors include the uncertainties inherent in oil and gas development and production activities, the effect of actions by third parties including government officials, fluctuations in world oil prices and other risks detailed in the Company’s reports on Forms 10-K and 10-Q filed with the Securities and Exchange Commission. The forward-looking statements are intended to help shareholders and others assess the Company’s business prospects and should be considered together with all information available. They are made in reliance upon the safe harbour provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The Company cannot give assurance that the results will be attained.
For more information please contact:
US and NORWAY
Eric Cameron, Christopher Rodsten, Fredrik Tangeraas
Gambit Hill & Knowlton AS
Tel: +47 96 62 55 94
Email: canargo@hillandknowlton.com
Eric Cameron, Christopher Rodsten, Fredrik Tangeraas
Gambit Hill & Knowlton AS
Tel: +47 96 62 55 94
Email: canargo@hillandknowlton.com
Consolidated Statement of Operations
Expressed in United States dollars
Expressed in United States dollars
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | December 31, | December 31, | |||||||||||||
| 2007 | 2006 | 2007 | 2006 | |||||||||||||
| (Unaudited) | (Unaudited) | (Unaudited) | (Audited) | |||||||||||||
| Operating Revenues from Continuing Operations: | ||||||||||||||||
| Oil and gas sales | $ | 3,813,858 | $ | 2,434,436 | $ | 7,208,666 | $ | 6,526,660 | ||||||||
| 3,813,858 | 2,434,436 | 7,208,666 | 6,526,660 | |||||||||||||
| Operating Expenses: | ||||||||||||||||
| Field operating expenses | 679,302 | 362,510 | 1,370,153 | 1,702,679 | ||||||||||||
| Direct project costs | 146,859 | 134,139 | 662,798 | 811,795 | ||||||||||||
| Selling, general and administrative | 1,836,212 | 1,921,968 | 7,163,951 | 9,732,142 | ||||||||||||
| Depreciation, depletion and amortization | 1,076,285 | 1,567,408 | 2,592,531 | 3,798,727 | ||||||||||||
| Impairment of oil and gas properties, ventures and other assets | 42,000,000 | 39,000,000 | 42,000,000 | 39,000,000 | ||||||||||||
| 45,738,658 | 42,986,025 | 53,789,433 | 55,045,343 | |||||||||||||
Operating Loss from Continuing Operations | (41,924,800 | ) | (40,551,589 | ) | (46,580,767 | ) | (48,518,683 | ) | ||||||||
| Other Income (Expense): | ||||||||||||||||
| Interest income | 65,156 | 148,666 | 315,302 | 426,816 | ||||||||||||
| Interest and amortization of debt discount and expense | (901,356 | ) | (510,516 | ) | (6,208,660 | ) | (5,112,471 | ) | ||||||||
| Loss/Cost on debt extinguishment | — | — | (12,127,494 | ) | — | |||||||||||
| Foreign exchange gains (losses) | (35,057 | ) | (148,293 | ) | (73,863 | ) | (314,853 | ) | ||||||||
| Other | 122,092 | (730,265 | ) | (639,104 | ) | (912,506 | ) | |||||||||
Total Other Expense | (749,165 | ) | (1,240,408 | ) | (18,733,819 | ) | (5,913,014 | ) | ||||||||
Loss from Continuing Operations Before Taxes | (42,673,965 | ) | (41,791,997 | ) | (65,314,586 | ) | (54,431,697 | ) | ||||||||
| Income taxes | — | — | — | — | ||||||||||||
Loss from Continuing Operations | (42,673,965 | ) | (41,791,997 | ) | (65,314,586 | ) | (54,431,697 | ) | ||||||||
Net Income (Loss) from Discontinued Operations, net of taxes | 43,687 | (4,866,559 | ) | 11,537,372 | (6,109,154 | ) | ||||||||||
Net Loss | $ | (42,630,278 | ) | $ | (46,658,556 | ) | $ | (53,777,214 | ) | $ | (60,540,851 | ) | ||||
| Weighted average number of common shares outstanding | ||||||||||||||||
| - Basic | 241,245,192 | 224,260,628 | 239,442,275 | 227,001,672 | ||||||||||||
| - Diluted | 241,245,192 | 224,260,628 | 239,442,275 | 227,001,672 | ||||||||||||
Basic Net Income (Loss) Per Common Share | ||||||||||||||||
| - from continuing operations | $ | (0.18 | ) | $ | (0.19 | ) | $ | (0.27 | ) | $ | (0.24 | ) | ||||
| - from discontinued operations | $ | 0.00 | $ | (0.02 | ) | $ | 0.05 | $ | (0.03 | ) | ||||||
Basic Net Income (Loss) Per Common Share | $ | (0.18 | ) | $ | (0.21 | ) | $ | (0.22 | ) | $ | (0.27 | ) | ||||
Diluted Net Income (Loss) Per Common Share | ||||||||||||||||
| - from continuing operations | $ | (0.18 | ) | $ | (0.19 | ) | $ | (0.27 | ) | $ | (0.24 | ) | ||||
| - from discontinued operations | $ | 0.00 | $ | (0.02 | ) | $ | 0.05 | $ | (0.03 | ) | ||||||
Diluted Net (Income) Loss Per Common Share | $ | (0.18 | ) | $ | (0.21 | ) | $ | (0.22 | ) | $ | (0.27 | ) | ||||
Consolidated Balance Sheet
Expressed in United States dollars
Expressed in United States dollars
| December 31, | December 31, | |||||||
| 2007 | 2006 | |||||||
| (Unaudited) | (Audited) | |||||||
| Cash and cash equivalents | $ | 6,869,381 | $ | 14,689,289 | ||||
| Assets to be disposed | 71,294 | 5,965,341 | ||||||
| Other current assets | 1,231,979 | 3,674,354 | ||||||
| Capital assets | 51,304,619 | 87,307,700 | ||||||
| Other non current assets | — | 24,560,166 | ||||||
| Other Intangible assets | 74,804 | 288,632 | ||||||
| Total Assets | $ | 59,552,077 | $ | 136,485,482 | ||||
| Liabilities to be disposed | 336,446 | 1,625,282 | ||||||
| Other current liabilities | 7,121,552 | 11,075,714 | ||||||
| Long term liabilities | 11,965,729 | 42,295,604 | ||||||
| Stockholders’ equity | 40,128,350 | 81,488,882 | ||||||
| Total liabilities and stockholders’ equity | $ | 59,552,077 | $ | 136,485,482 | ||||