Tanganyika Oil Company Ltd.
TSX VENTURE : TYK

Tanganyika Oil Company Ltd.

February 28, 2007 02:30 ET

Tanganyika Announces Fourth Quarter 2006 Results

CALGARY, ALBERTA--(CCNMatthews - Feb. 28, 2007) - Tanganyika Oil Company Ltd. (the "Company") (TSX VENTURE:TYK)(OMX:TYKS) today announces interim operating and financial results for the fourth quarter ended December 31, 2006. Unless otherwise stated, all figures contained in this report are in United Stated Dollars.



Three Three Seven
months Year months months Year
ended ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31, May 31,
2006 2006 2005 2005 2005
Financial
Highlights

Revenue 7,442,740 32,789,955 5,851,642 13,409,742 12,767,679
Net
profit
(loss) (410,024) (8,200,450) (2,614,984) 911,124 (1,850,777)
Per share
(basic) (0.008) (0.172) (0.059) 0.021 (0.049)
Per share
(diluted) (0.008) (0.172) (0.059) 0.021 (0.049)
Cash Flow
from
Operations
(i) 7,447,035 5,240,850 (1,070,593) 3,957,933 3,436,947
Per share
(basic) 0.146 0.110 (0.024) 0.091 0.090
Per share
(diluted) 0.145 0.109 (0.024) 0.091 0.090
Total
Assets 231,531,927 231,531,927 82,914,955 82,914,955 42,403,737
Working
Capital,
including
cash 95,672,786 95,672,786 30,337,821 30,337,821 18,317,411
Working
Capital,
excluding
cash 1,007,295 1,007,295 (3,067,053) (3,067,053) 2,842,718
Weighted
Average
shares
outstanding
(basic) 50,934,854 47,702,202 44,299,404 43,271,237 38,138,151
Weighted
Average
shares
outstanding
(diluted) 51,507,220 48,076,905 45,583,541 43,624,537 38,393,722

Operational
Highlights

Average
daily
production -
Company
share
(bbl/d)
Syria - Oudeh 946 890 946 725 534
Syria -
Tishrine-Sheikh
Mansour 554 290 - - -
Egypt 750 742 750 709 595
Total
Company 2,250 1,922 1,696 1,434 1,129

Average sales
price ($)
Syria
Oudeh 38.20 47.46 42.04 44.70 33.09
Tishrine 32.76 36.29 - - -
Egypt 40.28 44.99 37.67 40.01 28.49

Operating
costs (bbl)
Syria 7.77 8.30 4.43 5.23 9.49
Egypt 5.04 4.00 1.95 2.48 3.78

(i) Cash flow from operations is a non-GAAP measure that represents cash
generated from operating activities before changes in non-cash
working capital.


NOTICE OF NO AUDITOR REVIEW OF INTERIM FINANCIAL STATEMENTS

The accompanying unaudited interim financial statements of the Company have been prepared by and are the responsibility of the Company's management. The Company's independent auditor has not performed a review of these financial statements in accordance with standards established by the Canadian Institute of Chartered Accountants for a review of interim financial statements by an entity's auditor.

MESSAGE TO SHAREHOLDERS

During 2006, Tanganyika Oil Company Ltd ("Tanganyika" or "the Company") made significant achievements with the appraisal of value enhancing opportunities in Syria and Egypt which included testing enhanced oil recovery ("EOR") techniques and exploration drilling. The stated objectives of the Company include the consistent growth of reserves, production and cash flow per share. During 2006, proven plus probable reserves, net to the Company, increased from 42 to 421.5 million barrels (using constant prices and costs). These reserves were evaluated by DeGolyer and MacNaughton Canada Ltd. under Canadian National Instrument 51-101 guidelines.

The most significant challenge to growth of production and cash flow has been the facilities investments required in Syria. These investments range from reliable power to retrofitting existing facilities for cold weather production. At the end of 2006, the Company has elected to move beyond the two year feasibility periods defined in the contracts for both Tishrine and Oudeh to the second three year phase. Electing to move beyond the feasibility phase will now allow long term infrastructure investments required for the 20 year primary contract term and five year extension option.

Another important achievement in 2006 was the resolution of the base crude production allocation principles at Oudeh. Payments for base crude production costs started at the end of 2006 and our expectation is to have the same principles implemented at Tishrine in early 2007.

Enhancing Recovery in Syria

The most significant result was in Syria where proven plus probable reserves, net to the Company, increased from 41 to 416 million barrels (using constant prices and costs).

This significant increase is from a combination of activities conducted by the company including:

1. 3D seismic coverage across all major fields

2. Appraisal drilling success

a. Extending the field limits of recoverable reserves

b. Demonstrating economic production in a new reservoir at Tishrine (Chilou A)

c. Demonstrating EOR potential from downspacing

3. Conducted thermal (steam) EOR pilot tests at the Oudeh and Tishrine fields

4. Significant reduction in capital development costs

The success of these programs has been encouraging and the Company plans to accelerate the activities during 2007 to further enhance both rate and ultimate oil recovery from all of the operated fields in Syria.

In December 2006, we advised the Government of Syria of our intentions to enter the second phase of the production sharing agreement ("PSA") for the Tishrine and Sheikh Mansour fields, and field- test proven EOR techniques. The Government accepted our three year program, which is now underway.

Successful Exploration in Egypt

The Company had additional success with the exploration program in the West Gharib Block, Egypt. An additional four fields were discovered in Egypt, bringing the total discovered fields to seven. In addition to the newly discovered fields, appraisal work was conducted on existing fields to better define the reserves potential. As of December 31, 2006 the proven plus probable reserves, net to the Company, increased from 0.8 to 5.6 million barrels (using constant prices and costs).

The eight year exploration period for the West Gharib block ended in 2006. All seven of the discovered fields have been isolated from the original land concession and are now held under development licenses. Development leases are pending for two additional fields. With the end of the exploration period, all of the unexplored lands have been returned to the Government of Egypt and the Company's emphasis has now been shifted to further appraisal and development of discovered fields under license.

Potential in the Growth Portfolio

By far the most significant component of value growth in the Company's portfolio is EOR for the large fields in Syria. Part of this potential has been recognized in the current Reserves Report based on success of the cyclic steam injection pilot tests. Our expectation is continued recognition of additional recovery as the significant capital investments are made in the coming years through reinvestment of cash flow.

One of the secondary benefits of the 3D seismic program has been the identification of exploration potential across all three land concessions - Oudeh, Tishrine and Sheikh Mansour.

- At Oudeh we anticipate extensions of reserves potential for all three productive horizons - Shiranish, Butmah and Kurrachine Dolomite. The light oil and natural gas potential in the Butmah and Kurrachine are especially exciting.

- At Tishrine we anticipate the potential for extensions and additional reservoir traps for the three currently active producing reservoirs - Chilou, Jaddala and Shiranish. In addition, several large structures have been identified at deeper horizons which could contain light oil and natural gas for thermal EOR requirements. What is most encouraging is the evidence of hydrocarbon presence from multiple tests at multiple horizons conducted by the Syrian Petroleum Company (SPC) in the past.

- At Sheikh Mansour we anticipate the ability to confirm the economic feasibility of the Sheikh Mansour field and the lighter oil and natural gas at the Sheikh Suliman field. Both of these fields required 3D seismic for appraisal and delineation drilling and EOR testing.

The Corporate Front

The Company is entering 2007 with a strong balance sheet. A total of $131 million net in new funds was raised during 2006 and as of December 31, 2006 the Company had net cash reserves of $69.7 million with no debt.

A proud moment for the Company was the recent acceptance of our application for a primary listing of Tanganyika's Swedish Depository Receipts on Stockholmsborsen (the Stockholm Stock Exchange). This speaks to the quality and strength of the Company's asset portfolio and will expose more shareholders to Tanganyika. We have a large shareholder base in Sweden and we are very pleased to have the important recognition of now being listed on the Stockholm Stock Exchange.

The Road Ahead

We will continue our focus on value creation in each of our contract areas. The strategy and 2007 budget approved by the Board of Directors includes a significant increase in activity. This activity ranges from increased drilling to significant infrastructure and facilities investments in Syria.

The Company is focused on aggressive value creation and has the high quality growth portfolio within our control to succeed. We are excited about the steam pilot tests and drilling activity results in 2006. We are also excited about the prospect of further reserves growth as we develop and explore, especially in Syria. Our team remains dedicated to systematically adding reserves, production and cash flow for each host country, and for each shareholder.

"signed"

Gary Guidry, President and CEO

February 22, 2007

TANGANYIKA OIL COMPANY LTD.

MANAGEMENT'S DISCUSSION AND ANALYSIS

(Amounts in United States Dollars unless otherwise indicated)

Year ended December 31, 2006, seven months ended December 31, 2005 and year ended May 31, 2005

Management's discussion and analysis ("MD&A") of Tanganyika Oil Company Ltd.'s (the "Company" or "Tanganyika") financial condition and results of operations should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2006, seven months ending December 31, 2005 and year ended May 31, 2005 and related notes therein prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). The effective date of this MD&A is February 22, 2007.

Additional information relating to the Company is available on SEDAR at www.sedar.com and on the Company's web-site at www.tanganyikaoil.com.

Overview

Tanganyika is a Canadian-based company whose common shares are traded on the TSX Venture Exchange under the symbol "TYK". The Company also has Swedish Depository Receipts that trade on the Stockholm Stock Exchange. Additional information about the Company and its business activities, including the Company's Annual Information Form ("AIF"), will be available March 31, 2007 on SEDAR at www.sedar.com.

The Company is an international oil and gas exploration and development company based in Canada with interests in exploration and development properties in Syria and Egypt.

Syria

Oudeh Block

The Company acquired its interest in the Oudeh Block ("Oudeh") in 2003 pursuant to a Contract for Development and Production of Petroleum with the Government of Syria (the "Government"). The objective of the contract, which has a term of 20 years with a provision for a five year extension, is to increase oil recovery and crude oil production within the block by applying enhanced oil recovery ("EOR") techniques. The Company began EOR through the use of thermal (steam) technology during 2006.

The Company has an interest in all incremental production above the base crude oil production ("BCP") level from wells in existence at the time the contract was signed. The BCP level declines at a rate of five percent per annum calculated on a monthly basis. A schedule of BCP levels for the Oudeh Block for 2006 to 2008 is included in the Company's AIF which will be available on SEDAR March 31, 2007. Under the terms of the contract, SPC is responsible for reimbursing the Company for all operating costs attributable to the BCP.

After deduction of the BCP, a royalty of 12.5 percent is deducted and submitted to the Government. The remaining production is then shareable among the Company and the Syrian Petroleum Company ("SPC") as follows:

- 30 percent of the shareable crude oil production from the block is designated as profit oil and is split among the Company and SPC. The profit oil is split 30 percent to the Company and 70 percent to SPC.

- Up to 70 percent of the remaining crude oil production is available as cost oil to the Company to recover exploration, development and operating costs (other than operating costs associated with the BCP that have been recovered directly from SPC). To the extent that these costs exceed the proceeds from the sale of cost oil in any quarter, the excess can be carried forward into subsequent quarters.

- If the costs are less than the proceeds of the cost oil, the excess proceeds are split between the Company and SPC in the same manner as profit oil.

All Syrian taxes are the responsibility of SPC from its share of profit and excess cost oil.

Tishrine-Sheikh Mansour Fields

The Company acquired its interest in the Tishrine-Sheikh Mansour Fields ("Tishrine") in November 2004 pursuant to a Contract for Development and Production of Petroleum with the Government. The objective of the contract, which has a term of 20 years with a provision for a five year extension, is to apply EOR techniques to increase crude oil production and recoverability. The Company began EOR through the use of thermal (steam) technology during 2006.

The Company has an interest in all incremental production above the BCP level from wells in existence at the time the contract was signed. The BCP level declines at a rate of five percent per annum calculated on a monthly basis. A schedule of BCP levels for the Tishrine-Sheikh Mansour fields for 2006 to 2008 is included in the Company's AIF which will be available on SEDAR March 31, 2007. Under the terms of the contract, SPC is responsible for reimbursing the Company for all operating costs attributable to the BCP.

After deduction of the BCP, a royalty of 12.5 percent is deducted and submitted to the Government. The remaining production is then shareable among the Company and SPC as follows:

- 52 percent of the shareable crude oil production from the block is designated as profit oil and is split among the Company and SPC. The profit oil is split 30 percent to the Company and 70 percent to SPC.

- Up to 48 percent of the remaining crude oil production is available as cost oil to the Company to recover exploration, development and operating costs (other than operating costs associated with the BCP that have been recovered directly from SPC). To the extent that these costs exceed the proceeds from the sale of cost oil in any quarter, the excess can be carried forward into subsequent quarters.

- If the costs are less than the proceeds of the cost oil, the excess proceeds are split between the Company and SPC in the same manner as profit oil.

All Syrian taxes are the responsibility of SPC from its share of profit and excess cost oil.

Egypt

The Company acquired its interest in the West Gharib Block, Egypt in 1998 pursuant to a Concession Agreement for Petroleum Exploration and Exploitation (the "Concession Agreement"). The original exploration term of the Concession Agreement was three years with extensions available if commercial production was not attained. The exploration term was subsequently extended to 2006. The Concession Agreement provided that a field was eligible for a development lease once commercial production was attained and upon approval by the government. Once a field was granted a development lease, the term of the agreement for that field became 20 years with a five year extension option. There are seven development fields within the West Gharib Block: Hana, Hoshia, West Hoshia, Fadl, South Rahmi, Arta and North Hoshia. The Hana field was converted to a development lease in 1999, the Hoshia and Fadl fields were converted to development leases during 2005 and the development leases for the other fields were granted in 2006. Development leases for two additional fields, East Hoshia and East Arta, are pending approval of the government. The exploration term under the Concession Agreement terminated in 2006 and all remaining exploration land reverted back to the government. All fields with development leases, either granted or pending, remain under the Concession Agreement.

In prior years, the Company farmed out a portion of its interest in the West Gharib block. The Company retained a 70 percent participating interest in the Hana field and a 45 percent participating interest in all other fields within the block. Gross production from the block is divided among the Company, its partners and the Egyptian General Petroleum Company ("EGPC") as follows:

- 70 percent of the crude oil and natural gas production from the block is designated as profit oil and is split among the Company, its partners and EGPC. The percentage available to the Company and its partners is on a declining scale starting at 30 percent and reducing to 15 percent as gross average daily production increases to 100,000 barrels per day.

- Up to 30 percent of the remaining crude oil and natural gas production is available as cost oil to the Company and its partners to recover exploration, development and operating costs. To the extent that these costs exceed the proceeds from the sale of cost oil in any quarter, the excess can be carried forward into subsequent quarters.

- If the costs are less than the proceeds of the cost oil, the excess proceeds are split between the Company, its partners and EGPC in the same manner as profit oil.

All Egyptian royalties and taxes are the responsibility of EGPC from its share of profit and excess cost oil.

Selected Annual Information



Seven months
Year ended ended Year ended
($000s, except per share data) Dec 31, 2006 Dec 31, 2005 May 31, 2005
--------------------------------------------------------------------------
Oil revenue 31,463 13,010 12,635
Earnings (loss) (8,200) 911 (1,851)
Per share basic (0.172) 0.021 (0.049)
Per share diluted (0.172) 0.021 (0.049)
Total assets 231,532 82,915 42,404
Long term liabilities - - -


The increases in the Company's oil revenues and assets are consistent with the Company's continued development of its concession interests in both Syria and Egypt. Total assets at December 31, 2006 increased significantly over the balance at December 31, 2005. This is mainly the result of $131 million from private placements during the year which provided additional funds for exploration and development activities. Approximately $72 million was added to the Company's oil and gas interests for exploration, development and acquisition activities during the year and the year-end cash position increased approximately $61 million.

The loss for the year ended December 31, 2006 reflects the early stage of investment in the Company's significant oil and gas assets in Syria. In addition, a portion of the loss reported for the year ended December 31, 2006 is because the Company has not included 100 percent of the BCP operating cost recovery for Tishrine. The Company is entitled to recover the costs applicable to the BCP from SPC. The Company has included only the portion of the recoveries for Tishrine that relate to SPC invoices for operating costs in the Statement of Operations. This matter is discussed in more detail in the section "Results of Operations: Base Crude Production Recoverable Costs".

The analysis that follows provides additional information on operations and financial condition.

Selected Quarterly Information



($000s,
except per Three Months Ended (1)
share &
production Dec 31 Sept 30 Jun 30 Mar 31 Dec 31 Sept 30 May 31 Feb 28
data) 2006 2006 2006 2006 2005 2005 2005 2005
---------------------------------------------------------------------------
Total
revenues 7,442 10,562 7,479 7,307 5,852 7,558 3,730 2,826
Earnings
(loss) (410) (4,115) (4,208) 532 (2,615) 3,526 (258) 1,429
Per share
basic (0.008) (0.084) (0.091) 0.012 (0.059) 0.083 (0.007) 0.038
Per share
diluted (0.008) (0.084) (0.091) 0.012 (0.059) 0.080 (0.007) 0.037
Cash flow from
operations
(2) 7,447 (1,993) (2,196) 1,983 (1,071) 5,029 1,540 2,336
Per share
basic 0.146 (0.040) (0.048) 0.045 (0.024) 0.118 0.040 0.062
Per share
diluted 0.146 (0.040) (0.048) 0.044 (0.024) 0.115 0.039 0.061
Average
production
(bopd) 2,250 2,184 1,583 1,670 1,522 1,382 1,182 1,322
Total
production
(barrels) 207,000 201,000 144,000 150,000 140,000 169,000 109,000 119,000

(1) Except for September 2005 which is for the four months ended

(2) Cash generated from operating activities before changes in non-cash
working capital


The 2006 fourth quarter revenues, on a monthly basis, decreased in comparison to the prior quarter. Production volumes were up over the prior quarter, however the marketing contract in Syria was in the process of being re-negotiated. The Company and SPC agreed that the prior Oudeh marketing formula would be used in the interim and that SPC would withhold 20 percent from Oudeh revenues and 30 percent from Tishrine revenues until the new pricing formula was finalized by a third party evaluator. The result of the holdback was that oil revenues decreased from the prior period. The Company believes the oil revenues would have been higher if the new marketing contracts had been in place in 2006. The Company is unable to estimate any such potential adjustment at this time. See the section "Oil Sales" for further discussion on the Syrian marketing contracts.

The revenue increase as of the quarter ending September 30, 2006 was the result of Tishrine's production exceeding the BCP production levels. Earnings have fluctuated from quarter to quarter as a result of oil price, exchange rate and operating cost fluctuations and increases in total expenses.

Results of Operations

The Company had a consolidated net loss for the year ended December 31, 2006 of $8.2 million ($0.172 per share) compared to a consolidated net profit of $911,000 ($0.021 per share) for the seven months ended December 31, 2005. The decrease in the Company's profit is largely the result of an increase in operating, depletion and general and administration costs.

The loss for the year ended December 31, 2006 reflects the early stage of investment in the Company's significant oil and gas assets in Syria. During 2006 and 2005, the Company added operating, technical and support staff as required to evaluate the EOR feasibility of the large oil and gas fields in Syria. The potential identified by the work programs and capital deployed in Syria has been reflected in the significant growth in reserves recognized by the third party reserves evaluators. This is discussed in more detail in the Company's NI 51-101 reserves report as of December 31, 2006 that is filed on SEDAR.

A portion of the loss reported for the year ended December 31, 2006 is because the Company has not included 100 percent of the BCP operating cost recovery for Tishrine. The Company is entitled to recover the costs applicable to the BCP from SPC. The Company has included only the portion of the recoveries that relate to SPC invoices for operating costs in the Statement of Operations. The Company has estimated the unrecognized BCP cost recovery at approximately $8.4 million. This matter is discussed in more detail in the section "Results of Operations: Base Crude Production Recoverable Costs".

For the year ended December 31, 2006 total revenue was $32,790,000 compared to $13,410,000 for the seven month period ended December 31, 2005. Total revenue increased as a result of significantly higher oil sales plus higher interest income.

Oil Sales

Oil sales have increased significantly during 2006. Total oil sales were $31,463,000 for the year ended December 31, 2006 compared to $13,010,000 for the seven months ended December 31, 2005.



---------------------------------------------------------------------------
Seven months
Year ending ending Year ending
Dec. 31, 2006 Dec. 31, 2005 May 31, 2005
---------------------------------------------------------------------------
Sales of Oil:
---------------------------------------------------------------------------
Syria:
---------------------------------------------------------------------------
Oudeh $ 15,423,000 $ 6,929,000 $ 6,453,000
---------------------------------------------------------------------------
Tishrine (1) $ 3,847,000 - -
---------------------------------------------------------------------------
Egypt $ 12,193,000 $ 6,081,000 $ 6,182,000
---------------------------------------------------------------------------
Total $ 31,463,000 $ 13,010,000 $ 12,635,000
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Average oil sales price ($ per bbl):
---------------------------------------------------------------------------
Syria:
---------------------------------------------------------------------------
Oudeh $ 47.46(4) $ 44.70 $ 33.09
---------------------------------------------------------------------------
Tishrine $ 36.29(4) - -
---------------------------------------------------------------------------
Egypt $ 44.99 $ 40.01 $ 28.49
---------------------------------------------------------------------------
Production:
---------------------------------------------------------------------------
Syria
---------------------------------------------------------------------------
Oudeh:
---------------------------------------------------------------------------
Company share (2) 325,000 155,000 195,000
---------------------------------------------------------------------------
Bbl/day 890 725 534
---------------------------------------------------------------------------
Tishrine:
---------------------------------------------------------------------------
Company share (2) 106,000 - -
---------------------------------------------------------------------------
Bbl/day 290 - -
---------------------------------------------------------------------------
Egypt
---------------------------------------------------------------------------
Company share (3) 271,000 152,000 217,000
---------------------------------------------------------------------------
Bbl/day 742 709 595
---------------------------------------------------------------------------
Total Company share for
Syria and Egypt bbl/day 1,922 1,434 1,129
---------------------------------------------------------------------------
1) Tishrine's production did not exceed the BCP until mid-2006.
2) Company share of Syria's Oudeh and Tishrine production represents the
Company's share of cost and profit oil after deduction of royalty and
base crude production (i.e. incremental production).
3) Company share of Egypt production represents the Company's share of
revenue generating production (i.e. cost and profit oil).
4) Syria oil prices are net of holdback. See discussion below regarding
marketing contracts for Oudeh and Tishrine.


The increase in oil sales is due predominantly to an increase in production volumes resulting from exploration and development activities in both Syria and Egypt. In total, the Company's share of production volumes increased 34 percent from 1,434 barrels per day to 1,922 barrels per day. See the "Operational Update" section which follows for details on 2006 drilling and development activities.

Increases in oil prices also impacted the increase in total oil sales for the year.

The average oil price received for Syria's Oudeh production was $47.46 per barrel, an increase of 6 percent over the prior year period price of $44.67. Tishrine's average oil price was $36.29 per barrel. The Company is currently negotiating new oil marketing contracts for both Oudeh and Tishrine. The Government of Syria has requested a third party re-evaluation of the pricing differential formula for Oudeh, and will use a similar formula for the new production from Tishrine which now exceeds the BCP level. For Tishrine oil sales from July 2006 and Oudeh oil sales from August 2006, the Company and SPC agreed that oil sales would be based on the existing Oudeh marketing formula. SPC is holding back 20 percent from Oudeh sales and 30 percent from Tishrine sales until the new oil marketing contracts are in place. It is expected that the revised pricing differential formula will result in an increase in the deduction for the API differences between Syrian blend benchmark crude and the Company's crude production as the API differences have increased over time. However, the Company believes the holdback amount will exceed the revised pricing differential that will be determined by the third party evaluator. Once the new marketing contracts are finalized, the Company's share of revenues will be re-calculated using the new formula for oil sales and any difference owing to the Company will be refunded from the holdback. The average prices calculated for Oudeh and Tishrine oil sales are based on the oil sales invoiced to SPC which are net of the holdback. The Company believes the average oil prices, and therefore oil sales, would be higher if the new marketing contracts had been in place during 2006. The Company is unable to estimate any such potential adjustment at this time.

The average oil price received for Egypt's production was $44.99 per barrel, an increase of 12 percent over the prior year period price of $40.14.

Operational Update

Syria - Oudeh

In Syria, the Company share of production from Oudeh increased 23 percent from 725 barrels per day to 890 barrels per day. There were 12 wells drilled during 2006 into the Shiranish reservoir. All are producing oil except OD-141 and OD-144H which have only produced water. Sidetracks from the original well paths were completed during the fourth quarter of 2006; however oil production was not achieved. Further remediation of these wells will be assessed in 2007. An additional sidetrack well, OD-139, was drilled and resulted in oil production from the Shiranish B reservoir.

In December 2006, the Company spud OD-153 and completed drilling this well in early 2007. OD-153 will test the Shiranish reservoir in an area where reserves have not been recognized in the 2006 evaluation, and will also test the deeper petroleum potential in the Butmah and Kurrachine Dolomite reservoirs. If successful, the well is expected to add reserves in untested areas and reservoirs of the Oudeh field.

The thermal (steam) EOR pilot program was initiated in 2006 with cyclic steam injection at three wells: OD-146H, OD-147H and OD-148H. Injection of steam was successful in all three wells. Production rates increased in the range of two to three times cold production during the production cycle. Longer steam injection periods will be undertaken in 2007 to optimize the stimulation effects of the steam on production rates and ultimate oil recovery per well.

Syria - Tishrine

Tishrine's gross production started exceeding the BCP levels beginning mid-July 2006, and the Company's share of production averaged approximately 588 barrels per day up to the year end. When averaged over the entire year, the Company's share of Tishrine's production was 290 barrels per day.

Drilling began at the Tishrine West field during April 2006 with a total of 14 wells drilled. Three of these wells targeted the Chilou A reservoir and proved new oil reserves and sustainable production. The remaining 11 wells were drilled as vertical and horizontal wells as Chilou B reservoir and Jaddala reservoir oil producers.

Cyclic steam injection began in the latter half of 2006 in the Tishrine West field at three wells: T-206, T-207H and T-208. The initial steam cycle was able to increase daily production rates from cold production by two to three times from the Chilou A, Chilou B and Jaddala reservoirs. Like Oudeh, longer steam injection periods will be undertaken in 2007 to optimize the stimulation effects of the steam on production rates and ultimate oil recovery per well.

Three dimensional seismic data was acquired and processed in 2006 at both the Tishrine field (330 km2) and the Sheikh Mansour field (153 km2). The 3D seismic provides for contiguous information across the Tishrine anticline and across both the Sheikh Mansour and Sheikh Suliman fields to identify the structural geometry and trends for the existing oil fields and discoveries. Verification of the larger extent of the field limits from the seismic data will be utilized for the 2007 drilling program. In addition, the exploration potential for other petroleum traps in both fields will be confirmed and reviewed for drilling activity in 2007.

Drilling at the Sheikh Mansour field began in March 2006 with the SHM-5H appraisal well offsetting the SHM-2 Chilou reservoir oil discovery well. The well was completed as a Chilou A reservoir oil producer but is suspended due to intermittent oil production and the remote location of the well. The SHS-6 well at the Sheikh Suliman field was reactivated and oil production began at 30 barrels per day from the Chilou A reservoir. This well is also suspended due to intermittent oil productivity and the remote location of the well.

With the completion of the 3D seismic interpretation over the Sheikh Mansour and Sheikh Suliman fields, plans are underway for additional appraisal drilling to delineate these two discovered fields. In addition, long term testing will be facilitated at both fields by temporary production facilities to be installed by the Company. Finally, the Company has committed to a steam pilot test in the Sheikh Mansour field sometime over the next three years.

Egypt

In Egypt, the Company share of production increased 5 percent from 709 barrels per day to 742 barrels per day. Twenty wells were drilled in 2006: 12 exploration wells and eight appraisal wells. A significant number of exploration wells were drilled to test prospects in the West Gharib block as the exploration term under the Concession Agreement expired during 2006. The Concession Agreement is still in effect for all seven fields covered by issued development leases and for two additional fields for which development leases are pending. Exploration sections within the West Gharib Block that were not covered by the development leases either issued or pending reverted back to the Egyptian government in November 2006. Development leases for Arta, North Hoshia, West Hoshia and South Rahmi were approved by the Minister of Petroleum in 2006, and oil field development permits were submitted for approval for East Hoshia and East Arta. At the end of 2006, the Hana, Hoshia, West Hoshia, Fadl, South Rahmi and Arta fields had a total of 17 wells on production.

Base Crude Production Recoverable Costs

Under the terms of the Syrian production sharing agreements for Oudeh and Tishrine, the Company is responsible for paying 100 percent of production costs and is entitled to reimbursement of the portion of costs attributable to the BCP. In the prior year, the Company did not reflect the potential BCP operating cost recoveries for Oudeh and Tishrine in its results of operations as SPC had not approved the allocation method or the amounts submitted as recoverable. During 2006, SPC agreed to the allocation method and recoverable amounts for Oudeh. The Tishrine recoverable amounts had not been approved by year end. The current year treatment of the BCP cost recoveries is explained in more detail below.

Oudeh BCP Recovery:

During 2006, SPC approved the Oudeh BCP recovery allocation method and $4,952,000 of recoverable amounts relating to the years 2004 and 2005 plus the first quarter of 2006. In December 2006, SPC paid the Company $1,688,000 for BCP recoveries. Subsequent to the year end, SPC paid an additional $818,000 to the Company. It is expected that SPC will reimburse the Company in full for the remainder of the 2004 and 2005 BCP recoveries in 2007.

The Company has accrued BCP cost recoveries of $3,025,000 relating to the last three quarters of 2006. The actual recoverable amount may vary as the BCP costs for these three quarters are subject to SPC cost recovery audits.



--------------------------------------------------------------------------
Calendar year
--------------------------------------------------------------------------
2004 2005 2006 Total
--------------------------------------------------------------------------
BCP cost recovery invoiced
and approved $ 2,064,000 $ 1,972,000 $ 916,000 $ 4,952,000
--------------------------------------------------------------------------
BCP cost recovery
accrued - - 3,025,000 3,025,000
--------------------------------------------------------------------------
Total BCP cost recovery $ 2,064,000 $ 1,972,000 $ 3,941,000 $ 7,977,000
--------------------------------------------------------------------------
BCP cost recovery
received (772,000) - (916,000) (1,688,000)
--------------------------------------------------------------------------
BCP cost recovery
outstanding $ 1,292,000 $ 1,972,000 $ 3,025,000 $ 6,289,000
--------------------------------------------------------------------------


Tishrine BCP Recovery:

SPC has approved the Tishrine BCP recovery allocation method but has not yet approved the recovery amounts relating to 2005 and 2006. The Company has estimated $506,000 as the 2005 total recoverable amount and $13.5 million as the 2006 total recoverable amount. At December 31, 2006, the Company has included only the portion of the BCP recoveries that relate to SPC invoices for 2006 of approximately $5,042,000 in the Statement of Operations. Amounts Receivable includes both the 2005 and 2006 SPC invoice amounts totalling $5,548,000. The reason the Company has reflected only the SPC amounts at this time is that the Company is offsetting the receivable for BCP recoveries against SPC operating cost payables. The Company believes that SPC will approve the recovery amounts for Tishrine in early 2007 based on the positive outcome of the Oudeh BCP recovery issue in 2006. Any amounts ultimately recovered will reduce the total operating costs reflected in the Company's Statement of Operations.

Interest and Other Income

Interest income was $1,236,000 for the year ended December 31, 2006 compared to $359,000 for the seven month period ended December 31, 2005. The increase is due to bank interest earned on surplus cash from the private placements completed in 2006.

Other income was $91,000 for the year ended December 31, 2006 compared to $41,000 for the seven month period ended December 31, 2005. Other income is mainly the overhead provision that Egypt is entitled to as operator.

Production Costs

Production costs for the year ended December 31, 2006 were $15,317,000 compared to $6,802,000 for the seven month period ended December 31, 2005.

Production costs for Syria for the year ended December 31, 2006 were $8.30 per barrel compared to $5.23 per barrel for the seven month period ended December 31, 2005. The higher production costs on a per barrel basis in Syria reflect current infrastructure and logistical constraints (particularly at Tishrine) in accessing equipment and services, including drilling and workover rigs. The Company anticipates it will be able to attain a target of production costs below $5 per barrel once the impact of these constraints has been reduced.

Production costs for Egypt for the year ended December 31, 2006 were $4.00 per barrel compared to $2.48 per barrel for the seven month period ended December 31, 2005. The production costs in Egypt increased in the current year as a result of workovers, an increase in the price of diesel and an increase in EGPC handling fees. The Company believes the increase in Egypt's production costs on a per barrel basis is temporary as the new development leases were only added later in the year and therefore provided limited increases in production over which to spread the costs.



---------------------------------------------------------------------------
Seven months
Year ending ending Year ending
Dec. 31, 2006 Dec. 31, 2005 May 31, 2005
---------------------------------------------------------------------------
Gross Production Costs &
Production Volumes:
---------------------------------------------------------------------------
Syria:
---------------------------------------------------------------------------
Gross production costs (3) $ 26,451,000 $ 6,186,000 $ 6,156,000
---------------------------------------------------------------------------
Gross production volumes (3) 3,185,000 1,183,000 649,000
---------------------------------------------------------------------------
Cost per bbl $ 8.30 $ 5.23 $ 9.49
---------------------------------------------------------------------------
Egypt:
---------------------------------------------------------------------------
Gross production costs (1) $ 1,885,000 $ 617,000 $ 1,171,000
---------------------------------------------------------------------------
Gross production volumes(2) 471,000 249,000 310,000
---------------------------------------------------------------------------
Cost per bbl $ 4.00 $ 2.48 $ 3.78
---------------------------------------------------------------------------
1) Egypt gross production costs that are included in the Company's
Statement of Operations are total production costs for the concession
net of the partners' share. The partners are billed by the Company for
their share of costs. The Company recovers the remaining production
costs through the allocation of cost oil.
2) Egypt's gross production volumes are net of partners' share.
3) Oudeh and Tishrine gross production costs and gross production volumes
represent 100 percent costs and volumes before any deductions relating
to the base crude production.


Depletion

Depletion for the year ended December 31, 2006 was $11,318,000 compared to $1,750,000 for the seven month period ended December 31, 2005. Depletion is calculated on a unit-of-production basis using estimated proved oil and gas reserves. The higher depletion expense for the current year is the result of higher production volumes and higher capitalized costs. Depletion, on a per-unit basis, was approximately $2.50 per barrel for Egypt and $3.01 per barrel for Syria. Depletion is calculated based on gross production as the capitalized costs for oil and gas interests relate to the development of gross reserves.

General and Administrative

For the year ended December 31, 2006, general and administration expenses were $12,230,000 compared to $4,079,000 for the seven month period ended December 31, 2005. The increase in general and administration costs was largely the result of an increase in salaries and benefits for additional operational, technical and support staff being added for the Syria operations and Calgary corporate office. Salaries and benefits for the year ended December 31, 2006 were $6,588,000 compared to $1,897,000 for the seven month period ended December 31, 2005.

In addition, travel expenses increased approximately $1.1 million over the prior period reflecting the increased travel for rotational staff working in Syria, and travel between Canada and Syria to assist with the management of the steam pilot project and the Syrian operations.

The Company also incurred costs of approximately $321,000 relating to its Swedish Stock exchange listing application.

Increases in other general and administration expenses reflect an additional five months of operations for the current year in comparison to the prior year seven month period.

Stock-based Compensation

The Company uses the fair value method of accounting for stock options granted to directors, officers and employees whereby the fair value of all stock options granted is recorded as a charge to operations. Stock-based compensation for the year ended December 31, 2006 was $1,505,000 compared to $1,046,000 for the seven month period ended December 31, 2005. For the year ended December 31, 2006, the Company issued 1,455,500 options at prices ranging from CDN $9.00 to CDN $17.51.

Interest and Bank Charges

Interest and bank charges for the year ended December 31, 2006 were $70,000 compared to $56,000 for the seven month period ended December 31, 2005. Interest relates mainly to charges for letters of credit that were issued during the year. The Company has stopped issuing letters of credit to suppliers therefore the interest charges have decreased compared to the prior year period on an annualized basis.

Depreciation

Depreciation for the year ended December 31, 2006 was $618,000 compared to $251,000 for the seven month period ended December 31, 2005. The increase in depreciation is mainly the result of a full year of depreciation versus seven months depreciation for the prior period. There was also an increase in depreciation due to additional furniture and office equipment acquired in 2006.

Foreign Exchange Gain

The exchange gain for the year ended December 31, 2006 was $68,000 compared to $1,485,000 for the seven month period ending December 31, 2005. The exchange gains relate mainly to the translation of the Canadian dollar denominated cash balance to U.S. dollars.

Financial Condition

At December 31, 2006, total assets were $231,532,000 compared to $82,915,000 at December 31, 2005. The increase of approximately $148.6 million is mainly due to increases in the cash balances, amounts receivable and oil and gas interests.

The total cash balance at December 31, 2006 is approximately $61.3 million higher than the balance as at December 31, 2005. The increase is largely due to the private placements completed in 2006. The restricted cash in the amount of $900,000 at December 31, 2006 represents the remaining balance on a letter of guarantee issued in favour of SPC for the Tishrine work program. In the prior year, the restricted cash included the full $9 million amount that was issued under the Tishrine letter of guarantee plus letters of credit issued to suppliers in Egypt and Syria. During 2006, the Company stopped issuing letters of credit to suppliers which has helped reduce annual interest charges.

Oil and gas interests by country:



---------------------------------------------------------------------------
December 31, 2006 December 31, 2005 May 31, 2005
---------------------------------------------------------------------------
Syria $ 83,187,000 $ 30,020,000 $ 13,915,000
---------------------------------------------------------------------------
Egypt & North Africa $ 20,558,000 $ 9,057,000 $ 5,525,000
---------------------------------------------------------------------------
Total $ 103,745,000 $ 39,077,000 $ 19,440,000
---------------------------------------------------------------------------


Syria's oil and gas assets have increased $53,167,000 as a result of development drilling and seismic acquisition. For more details on 2006 activities, see the section "Operational Update" above. In accordance with the production sharing agreements, tangible costs will be recovered from cost oil over time periods specified in the individual agreements.

Since December 31, 2005, Egypt and North Africa oil and gas assets have increased $11,501,000 as a result of exploration drilling, seismic acquisition and the North Africa acquisition.

During the second quarter of 2006, the Company acquired a 50 percent interest in a private entity which holds certain rights associated with the development of oil and gas properties located in North Africa in exchange for 372,954 common shares having a deemed value of $3.5 million. As part of the acquisition, the Company agreed to fund 100 percent of the private entity's work program obligations to a maximum of $2 million. The Company has an option to acquire the remaining 50 percent interest in the private entity within 60 days after the date a development lease is issued in respect of the oil and gas properties for a purchase price of common shares of the Company having a deemed value of $6 million. An application for a development lease was submitted during the third quarter of 2006.

There is currently a legal dispute on whether the private entity has complied with its obligations under the concession agreement. If the entity is found not to have complied with its obligations, the concession may be discontinued. In such case, no development lease could be received and the Company would need to write down its investment in the entity.

Net property, plant and equipment increased from $1,077,000 at December 31, 2005 to $1,623,000 at December 31, 2006. The increase is the result of additions for leasehold improvements in Calgary, additions of office equipment and furniture for new staff and additional field vehicles in Syria and Egypt.

The advances to contractors increased from $1,120,000 at December 31, 2005 to $5,879,000 at December 31, 2006. This represents advances made by the Company to contractors in Syria for services and equipment relating to drilling and workover programs. The Company has replaced letters of credit with cash advances to suppliers. This change has reduced the Company's interest charges.

The amounts receivable and other assets increased from $7,981,000 at December 31, 2005 to $25,129,000 at December 31, 2006. The main reasons for the increase is that oil sales receivable have increased due to higher oil prices and higher volumes, and include six month's of accruals for Tishrine's oil sales. Receivables also include BCP cost recoveries as discussed in the section "Base Crude Production Recoverable Costs". In accordance with the terms of the agreements in Syria and Egypt, the national oil companies are required to market the Company's share of crude production but the Company retains the right to sell its share of crude production on its own behalf. The Company does not believe that this concentration of credit risk resulting from the national oil companies selling its share of crude production will result in any loss to the Company based on past payment experience.

Prepaid expenses increased from $254,000 at December 31, 2005 to $490,000 at December 31, 2006. The prepaid expenses at December 31, 2006 include approximately $355,000 for prepaid accommodation costs in Syria, approximately $81,000 for prepaid rent in Calgary and $54,000 for other items.

The Company had total liabilities of $30,491,000 at December 31, 2006 compared to $12,423,000 at December 31, 2005. The majority of the increase is due to payables relating to the Syrian operations for operating and capital costs.

Liquidity and Capital Resources

The Company completed two private placements during 2006. In May 2006, the Company issued 4.3 million shares for gross proceeds of approximately $51.8 million. A finder's fee of four percent was paid with respect to a portion of the private placement and the net proceeds received by the Company were approximately $49.7 million. In November 2006, the Company issued six million shares for gross proceeds of approximately $82.7 million. A finder's fee of 3.5 percent was paid with respect to a portion of the private placement. The net proceeds received by the Company were approximately $81.0 million. The proceeds from the private placements are being used towards development of the Company's oil and gas assets in Syria as well as general corporate purposes.

At December 31, 2006 the Company held a free cash amount of $93,765,000 compared to $16,678,000 at December 31, 2005. The increase is mainly due to the remaining funds received from the private placements completed during the year. In addition, the Company completed the majority of the work program at Tishrine resulting in the release of $8.1 million from a letter of guarantee that was issued to SPC and reported as part of restricted cash at December 31, 2005.

The Company's working capital was $95,673,000 at December 31, 2006 compared to $30,338,000 at December 31, 2005. The increase in the working capital is largely due to the increase in cash resulting from the private placements. Increases in amounts receivable and advances to contractors at December 31, 2006 also contributed to the increase in the working capital position.

Net cash flow from operating activities was $5,241,000 for the year ended December 31, 2006 compared to $3,958,000 for the seven month period ended December 31, 2005. The increase is mainly the result of a full year of results versus seven months. On an annualized basis, net cash flow from operations in 2006 actually decreased due to higher costs.

Net cash used in investing activities was $54,990,000 for the year ended December 31, 2006 compared to $22,346,000 for the seven month period ended December 31, 2005. During 2006, the Company invested a further $72.5 million in its oil and gas interests; this amount was offset by a $15.8 million reduction in amounts pledged and guaranteed.

At December 31, 2006, share capital was $228,236,000 compared to $89,906,000 at December 31, 2005. The increase in share capital is the result of the private placements in May and November 2006.

Contributed surplus increased from $5,783,000 at December 31, 2005 to $6,202,000 at December 31, 2006. The increase of $419,000 is due to the net stock based compensation for the period. Contributed surplus was credited in the amount of $1,505,000, the stock compensation expense for the year ended December 31, 2006. This amount was calculated using the Black-Scholes option value method. When options are exercised, a proportionate amount of the value recorded on the granting of the options is moved from contributed surplus to share capital. For the year ended December 31, 2006, contributed surplus was reduced by an amount of $1,086,000 for options exercised.

Management considers that the cash generated from the West Gharib Block in Egypt, after providing for related capital expenditures, will continue to significantly contribute towards funding the Company's exploration and development activities in Egypt. However, the Company does not generate sufficient cash flow from all operations to fund its entire exploration and development activities and has therefore relied upon the issuance of securities and the sale of concession interests to provide additional financing. The Company may also consider additional issuances of equity securities as well as debt instruments, to assist with financing its exploration and development activities to the extent that sufficient cash flow from operations is unavailable in the future. Accordingly, the Company's financial statements are presented on a going-concern basis.

Financial Instruments

The carrying amounts of financial instruments comprising cash, restricted cash, amounts receivable and amounts payable approximate their fair value due to the immediate or short-term nature of these financial instruments.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements.

Outstanding Share Data

As at February 23, 2007 the Company had 55,667,996 common shares outstanding and 2,262,700 stock options outstanding under its stock-based compensation plan.

Related Party Transactions

The Company has entered into transactions with related parties, which were measured at the exchange amounts. During the year ended December 31, 2006, the Company paid $265,000 to Namdo Management Services Ltd. ("Namdo"), a private corporation owned by Lukas H. Lundin, a director of the Company, pursuant to a services agreement. Namdo provides administration and financial services to a number of public companies. The Company also paid $37,000 to Cassels Brock and Blackwell LLP, a legal firm in which a Director is a partner, for various legal and consulting services. In addition, the Company entered into a loan agreement with Pearl Exploration and Production Ltd. ("Pearl") in the amount of $3 million which was subsequently repaid plus interest. The Company and Pearl have certain directors and officers in common.

Critical Accounting Estimates

The preparation of financial statements in conformity with Canadian GAAP requires management to make judgments, assumptions and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses for the period reported. The significant accounting policies used by the Company are disclosed in the Notes to the Consolidated Financial Statements. Management believes that the most critical accounting policies that may have an impact on the Company's financial results relate to the accounting for its oil and gas interests. Amounts recorded for depletion and the impairment test are based on estimates of proved reserves, production rates, oil prices, future costs and other relevant assumptions. Actual results could differ materially from such estimates.

Proved Oil and Gas Reserves

Under National Instrument 51-101("NI 51-101") detailed rules have been developed to provide uniform reserves recognition criteria within the oil and gas industry in Canada. However, the process of estimating oil and gas reserves is inherently judgmental. Technical reserves estimates are made using available geological and reservoir data as well as production performance data. As new data becomes available, reserves estimates may change. Reserves estimates are also impacted by economic conditions, primarily commodity prices. As economic conditions change, production may be added or may become uneconomical and no longer qualify for reserves recognition.

Depletion

The Company uses the full cost method of accounting for its oil and gas activities. In accordance with the full cost accounting guideline, all costs associated with exploration and development are capitalized on a country by country basis whether or not such activities were successful. The total capitalized costs and estimated future development costs are amortized using the unit-of-production method based on proved oil and gas reserves. Accordingly, revisions or changes to estimated proved reserves will impact the depletion expenses.

Impairment of Oil and Gas Interests

The Company's capitalized oil and gas interests are subject to impairment tests on a country by country basis. Impairment is indicated if the undiscounted estimated future cash flows from proved reserves at oil and gas prices in effect at the balance sheet date plus the cost of unproved properties less any impairment is less than the carrying value of the oil and gas interests. The impairment test requires management to make assumptions regarding cash flows into the distant future and is based on estimates of proved reserves.

Changes in Accounting Policies

Effective June 1, 2005, based on the growth in the Company's U.S. dollar denominated revenues and costs, the Company changed its reporting currency to the U.S. dollar and reclassified its foreign operations from integrated to self-sustaining. Effective June 1, 2005 the Company adopted the current rate method of translation in accordance with CICA Handbook Section 1651. All prior periods have been restated in accordance with CICA Emerging Issues Committee Abstract 130.

Effective June 1, 2005, the Company changed its financial year-end from May 31 to December 31. The Company made this change in order that its financial year-end would be comparable to its peers in the oil and gas industry. In accordance with Part 4.8 of National Instrument 51-102 Continuous Disclosure Obligations, the financial statements for the year ended December 31, 2006 (the "current financial year") are presented along with the financial statements for the seven month period ended December 31, 2005 (the "previous financial year") and May 31, 2005.

New Accounting Pronouncements

There have been no changes in the Company's accounting policies during the year ended December 31, 2006. The following summarizes recent accounting pronouncements and the potential impact on the Company:

Financial Instrument - Recognition and Measurement, Hedging and Comprehensive Income

In January 2005, the Canadian Institute of Chartered Accountants ("CICA") released the new Handbook Section 3855, "Financial Instruments -Recognition and Measurement" and Section 1530, "Comprehensive Income", effective for the interim periods and year ends for fiscal years commencing on or after January 1, 2007 on a prospective basis. The Company will adopt these new standards starting on January 1, 2007 on a prospective basis.

Section 3855 establishes standards for the recognition and measurement of all financial instruments, provides a characteristics-based definition of a derivative financial instrument, provides criteria to be used to determine when a financial instrument should be recognized, and provides criteria to be used when a financial instrument is to be extinguished. Section 1530 establishes standards for reporting comprehensive income. These standards require that an enterprise present comprehensive income and its components in a separate financial statement that is displayed with the same prominence as other financial statements.

The adoption of these new standards will require the Company's long-term receivable to be carried at the estimated present value of future payments. Accretion of interest on the discounted value will be recognized in earnings over time.

At December 31, 2006 the Company is not a counter-party to any derivative contracts nor does it believe that it has any embedded derivatives. Should the Company enter into any such contracts in the future it will account for them under these new standards.

Financial Instruments - Disclosure

In December 2006, the AcSB issued Section 3862 as a new accounting standard on disclosures about financial instruments. Section 3862 must be implemented no later than the first reporting period in the first fiscal year beginning on or after October 1, 2007.

Section 3862 places an increased emphasis on disclosures about the risks associated with both recognized and unrecognized financial instruments and how those risks are managed.

The additional disclosures will be evaluated by the Company.

Accounting Changes

In July 2006 the CICA issued revised Section 1506, Accounting Changes.

The main features are as follows:

- Voluntary changes in accounting policy are made only if they result in the financial statements providing reliable and more relevant information.

- Changes in accounting policy are applied retrospectively unless doing so is impracticable.

- Prior period errors are corrected retrospectively.

- New disclosures are required in respect of changes in accounting policies, changes in accounting estimates and correction of errors.

The revised Section applies to interim and annual financial statements relating to fiscal years beginning on or after January 1, 2007. The requirements of this new section will be addressed as circumstances dictate.

Capital Disclosures

In December 2006, the CICA issued a new accounting standard on disclosures about capital. Section 1535, Capital Disclosures, must be implemented no later than the first reporting period in the first fiscal year beginning on or after October 1, 2007. Section 1535 requires an entity to disclose information about its objectives, policies and processes for managing capital, as well as its compliance with any externally imposed capital requirements. The Section requires entities to describe and provide quantitative data about what they manage as capital. The Company is analyzing the additional disclosure requirements and will address these issues at or on October 1, 2007.

International Financial Reporting Standards

Within the next five years, Canadian generally accepted accounting principles for publicly accountable enterprises are expected to be replaced with International Financial Reporting Standards (IFRSs). The CICA anticipates a five-year transition period (ending around 2011). The Company will address the impact of the adoption of IFRSs as and when the transition requirements become more clearly defined. It is possible that the adoption of IFRS will have a material impact on the Company's financial statements.

Risks and Uncertainties

The Company is exposed to a number of risks and uncertainties inherent in exploring for, developing and producing crude oil and natural gas. These risks and uncertainties include, but are not limited to, the following:

- Fluctuations in crude oil or natural gas prices and exchange rates which could have a material effect on the Company's operations and financial condition and the value of its oil and gas reserves;

- Political or economic developments which may adversely affect the Company's operations, including, but not limited to, a change in crude oil or natural gas pricing policies, a change in taxation policies, the imposition of currency controls, the risk of war, terrorism, expropriation, nationalization, renegotiation or nullification of existing concessions and contracts, and the imposition of United Nations or United States sanctions;

- Risks and hazards including the possibilities of fire, explosion, blowouts, sour gas releases, pipeline ruptures and oil spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property, the environment or personal injury;

- Uncertainties with respect to estimating the volume of reserves that may be developed and produced in the future which may differ materially from actual results;

- Environmental regulation which imposes, among other things, restrictions, liabilities and obligations in connection with water and air pollution control, waste management, permitting requirements and restrictions on operations in environmentally sensitive areas;

- Competition within the oil and gas industry, which is highly competitive in all aspects of the business, including the acquisition of oil and gas interests, the marketing of oil and natural gas, acquiring or gaining access to necessary drilling and other equipment and supplies;

- Increased competition from alternative forms of energy, fuel and related products that could have a material adverse effect on the Company's business, prospects and results of operations;

- Cost of capital risks associated with securing needed capital at an acceptable rate to carry out the Company's operations and development; and

- The ability to retain current employees or to attract and retain new key employees which could have a materially adverse effect on the Company's growth and profitability.

Internal Controls over Financial Reporting

MI 52-109 defines internal controls over financial reporting as "a process designed by, or under the supervision of the issuer's chief executive officers and chief financial officers or persons performing similar functions, and effected by the issuer's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer's GAAP and includes those policies and procedures that:

a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;

b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the issuer's GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and

c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer's assets that could have a material effect on the annual financial statements or interim financial statements."

The Company has, under the supervision of its chief financial officer, designed a process for internal control over financial reporting, which process has been effected by the Company's board of directors and management. The process was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the Company's GAAP and incorporates policies and procedures as described above.

Outlook

The work completed in 2006 has provided an exciting preview of the future prospects for the Company. The success of the thermal EOR pilot tests has been quantified by the Company's reserves report as of December 31, 2006. The Company has ordered an additional eight steam generation packages which will bring the steam injection capacity to approximately 16,000 barrels of cold water equivalent per day.

Other activities that have had a significant effect on reserves for Tanganyika include the 3D seismic, development drilling and capital workovers. The Company believes reserves growth through enhanced recovery of identified reserves, extending known discoveries and low risk exploration will continue to have a positive impact in the coming years. This applies in Syria as well as in Egypt where development of the newly discovered fields started in late 2006.

The Company has committed in Syria to significant infrastructure upgrades, a doubling of drilling rigs from three to six and exclusive contracting of workover rigs during 2007.

Forward-Looking Statements

Certain information regarding the Company contained herein may constitute forward-looking statements. Forward-looking statements may include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact. By their nature, forward-looking statements and information involve assumptions, inherent risks and uncertainties, many of which are difficult to predict, and are usually beyond the control of management, that could cause actual results to be materially different from those expressed by these forward-looking statements and information. The Company does not undertake to update or re-issue the forward-looking statements and information that may be contained herein, whether as a result of new information, future events or otherwise. The Company's forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Non-GAAP Measures

Certain measures in this MD&A do not have any standardized meaning as prescribed Canadian GAAP such as Cash Flow from Operations and Cash Flows and therefore are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this MD&A in order to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations. Management's use of these measures has been disclosed further in this MD&A as these measures are discussed and presented.

BOEs

Throughout this MD&A the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil and is based on an energy equivalence conversion method. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.

Key Data



Three Three Seven
months Year months months Year
ended ended ended ended ended
December 31 December 31 December 31 December 31 May 31
2006 2006 2005 2005 2005
----------- ----------- ----------- ----------- -----------
Return on
equity, %(1) -0.26% -6.04% -3.67% 1.68% -5.74%
Return on
capital
employed, %(2) -0.30% -6.42% -3.58% -1.032% -3.53%
Debt/equity
ratio, %(3) 0% 0% 0% 0% 0%
Equity
ratio, %(4) 87% 87% 85% 85% 90%
Share of risk
capital, %(5) 87% 87% 85% 85% 90%
Interest
coverage
ratio, %(6) 786% -11697% -6276% 4386% -1027%
Operating cash
flow/interest
expense, %(7) -21408% 23226% 2498% 11102% 2656%
Yield, %(8) 0% 0% 0% 0% 0%

(1) Return on equity is defined as the Company's net results divided by
average shareholders' equity (the average over the financial period).
(2) Return on capital employed is defined as the Company's profit before
tax and minority interest plus interest expense plus/less exchange
differences on financial loans divided by the total average capital
employed (the average balance sheet total less non interest-bearing
liabilities).
(3) Debt/equity ratio is defined as the Company's interest-bearing
liabilities in relation to shareholders' equity.
(4) Equity ratio is defined as the Company's shareholders' equity,
including minority interest, in relation to balance sheet total.
(5) Share of risk capital is defined as the sum of the Company's
shareholders' equity and deferred taxes, including minority interest,
in relation to balance sheet total.
(6) Interest coverage ratio is defined as the Company's profit before tax
and minority interest plus interest expense plus/less exchange
differences on financial loans divided by interest expense.
(7) Operating cash flow/interest ratio is defined as the Company's
operating income less production costs and less current taxes divided
by the interest charge for the financial period.
(8) Yield is defined as dividend in relation to quoted share price at the
end of the financial period.


Data per share

Three Three Seven
months Year months months Year
ended ended ended ended ended
December 31 December 31 December 31 December 31 May 31
2006 2006 2005 2005 2005
----------- ----------- ----------- ----------- -----------
Shareholders'
equity,
USD(1) 3.61 3.61 1.59 1.59 .98
Operating
cash flow,
USD(2) .25 .34 0.02 0.14 0.14
Cash flow from
operations(3) 0.146 0.11 (0.02) 0.09 0.09
Earnings(4) (0.008) (0.172) (0.06) 0.02 (0.049)
Earnings
(fully
diluted)(5) (0.008) (0.172) (0.06) 0.02 (0.049)
Dividend 0 0 0 0 0
Quoted price
at the end
of the
financial
period 19.96 19.96 8.71 8.71 8.39
P/E-ratio(6) (116.1) (116.1) (147.6) 413.7 (138.0)
Number of
shares at
financial
period end 55,632,696 55,632,696 44,347,475 44,347,475 39,129,641
Weighted
average
number
of shares
for the
financial
period(7) 50,934,854 47,702,202 44,299,404 43,271,237 38,138,151
Weighted
average
number
of shares
for the
financial
period
(fully
diluted)
(5,7) 51,507,220 48,076,905 45,583,541 43,624,537 39,172,196

(1) Shareholders' equity per share defined as the Company's equity divided
by the number of shares at period end.
(2) Operating cash flow per share defined as the Company's operating
income less production costs and less current taxes divided by the
weighted average number of shares for the financial period.
(3) Cash flow from operations per share defined as cash flow from
operations in accordance with the consolidated summarized cash flow
statements divided by the weighted average number of shares for the
financial period.
(4) Earnings per share defined as the Company's net results divided by
the weighted average number of shares for the financial period.
(5) Earnings per share defined as the Company's net results divided by
the weighted average number of shares for the financial period after
considering the dilution effect of outstanding options and warrants.
(6) P/E-ratio defined as quoted price at the end of the period divided
by earnings per share.
(7) Weighted average number of shares for the financial period is defined
as the number of shares at the beginning of the financial period with
new issue of shares weighted for the proportion of the period they are
in issue.


Tanganyika Oil Company Ltd.
Consolidated Balance Sheets
As at December 31, 2006, December 31, 2005 and May 31, 2005
(expressed in U.S. dollars)
(Unaudited)

December 31, 2006 December 31, 2005 May 31, 2005
$ $ $

Assets
Current Assets
Cash 93,765,491 16,678,492 4,220,427
Restricted cash
(note 4) 900,000 16,726,382 11,254,266
Advance relating to
Exploration
commitment (note 5) - - 1,372,163
Advances to
contractor 5,879,418 1,120,717 585,871
Amounts receivable
and other assets
(note 6) 25,128,845 7,981,340 4,918,818
Prepaid expenses 490,399 254,280 115,155
----------------- ----------------- ------------

126,164,153 42,761,211 22,466,700

Oil and gas interests
(note 8) 103,744,946 39,077,166 19,440,439

Property, plant and
equipment (note 9) 1,622,828 1,076,578 496,598
----------------- ----------------- ------------

231,531,927 82,914,955 42,403,737
----------------- ----------------- ------------
----------------- ----------------- ------------

Liabilities
Current liabilities
Amounts payable and
accrued liabilities 30,491,367 12,423,390 4,149,289
----------------- ----------------- ------------

30,491,367 12,423,390 4,149,289
----------------- ----------------- ------------

Shareholders' Equity
Capital stock
(note 11) 228,236,373 89,905,794 59,302,193

Contributed surplus
(note 12) 6,201,643 5,782,777 5,060,385

Cumulative translation
adjustment (note 2) (175,745) (175,745) (175,745)

Deficit (33,221,711) (25,021,261) (25,932,385)
----------------- ----------------- ------------

201,040,560 70,491,565 38,254,448
----------------- ----------------- ------------

231,531,927 82,914,955 42,403,737
----------------- ----------------- ------------
----------------- ----------------- ------------

Contingencies and Commitments (note 17)

Approved by the Directors:

William A. Rand Keith Hill
Director Director


Tanganyika Oil Company Ltd.
Consolidated Statements of Changes in Shareholders' Equity
As at December 31, 2006, December 31, 2005 and May 31, 2005
(expressed in U.S. dollars)
(Unaudited)

Contri- Cumulative
May 31, Share buted Translation
2005 Capital Surplus Deficit Adjustment Total
--------------------------------------------------------------------------

As at May 31,
2004 47,638,690 4,185,419 (24,081,608) (1,450,620) 26,291,881
Issue of shares 11,458,924 - - - 11,458,924
Stock-based
compensation 204,579 874,966 - - 1,079,545
Loss for the
period - - (1,850,777) - (1,850,777)
Changes in
Cumulative
Translation
adjustment - - - 1,274,875 1,274,875
----------------------------------------------------------
As at May 31,
2005 59,302,193 5,060,385 (25,932,385) (175,745) 38,254,448
----------------------------------------------------------

Contri- Cumulative
December 31, Share buted Translation
2005 Capital Surplus Deficit Adjustment Total
--------------------------------------------------------------------------

Issue of shares 30,279,825 - - - 30,279,825
Stock-based
compensation 323,776 722,392 - - 1,046,168
Profit for the
period - - 911,124 - 911,124
----------------------------------------------------------
As at December
31, 2005 89,905,794 5,782,777 (25,021,261) (175,745) 70,491,565
----------------------------------------------------------

Contri- Cumulative
December 31, Share buted Translation
2006 Capital Surplus Deficit Adjustment Total
--------------------------------------------------------------------------

Issue of shares 137,244,557 - - - 137,244,557
Stock-based
compensation 1,086,022 418,866 - - 1,504,888
Loss for the
Period - - (8,200,450) - (8,200,450)
----------------------------------------------------------
As at December
31, 2006 228,236,373 6,201,643 (33,221,711) (175,745) 201,040,560
----------------------------------------------------------


Tanganyika Oil Company Ltd.
Consolidated Statements of Operations and Deficit
Year ended December 31, 2006 compared to the seven months ended December
31, 2005 and year ended May 31, 2005
(expressed in U.S. dollars)
(Unaudited)

Three Three Seven
months Year months months Year
ended ended ended ended ended
December 31, December 31, December 31, December 31, May 31,
2006 2006 2005 2005 2005
$ $ $ $ $
(see (see (see (see (see
note 21) note 21) note 21) note 21) note 21)
Revenue
Sale of oil 7,049,861 31,463,001 5,583,207 13,009,695 12,634,713
Interest
income 351,057 1,235,520 251,876 358,574 81,468
Other
income 41,822 91,434 16,559 41,473 51,498
---------- ---------- ---------- ---------- ----------

7,442,740 32,789,955 5,851,642 13,409,742 12,767,679

Expenses
Production
costs (5,748,472) 15,317,423 4,510,304 6,802,305 7,327,088
Depletion 7,466,062 11,318,350 715,178 1,750,004 2,583,197
General and
Adminis-
tration 4,362,396 12,230,284 2,245,126 4,079,004 2,804,834
Stock-based
Compen-
sation
(note 14) 199,696 1,504,888 692,682 1,046,168 1,079,545
Interest and
Bank
charges (59,784) 69,515 42,954 55,912 235,364
Depreciation 191,301 618,062 136,531 250,637 130,492
Foreign
Exchange
Loss
(gain) 1,441,565 (68,117) 123,851 (1,485,412) 457,936
----------- ---------- ---------- ---------- ----------

7,852,764 40,990,405 8,466,626 12,498,618 14,618,456

----------- ---------- ---------- ---------- ----------
Profit (loss)
for the
period (410,024) (8,200,450) (2,614,984) 911,124 (1,850,777)

Deficit -
Beginning
of period (32,811,687) (25,021,261) (22,406,277) (25,932,385) (24,081,608)
----------- ---------- ---------- ---------- ----------

Deficit -
end of
period (33,221,711) (33,221,711) (25,021,261) (25,021,261) (25,932,385)
----------- ---------- ---------- ---------- ----------
----------- ---------- ---------- ---------- ----------

Profit
(loss)
per share
Basic (0.008) (0.172) (0.059) 0.021 (0.049)
Diluted (0.008) (0.172) (0.059) 0.021 (0.049)

Weighted
Average
number
of shares
outstanding
Basic 50,934,854 47,702,202 44,299,404 43,271,237 38,138,151
Diluted 51,507,220 48,076,905 45,583,541 43,624,537 38,393,722


Tanganyika Oil Company Ltd.
Consolidated Statements of Cash Flows
Year ended December 31, 2006 compared to the seven months ended December
31, 2005 and year ended May 31, 2005
(expressed in U.S. dollars)
(Unaudited)

Three Three Seven
months Year months months Year
ended ended ended ended ended
December 31, December 31, December 31, December 31, May 31,
2006 2006 2005 2005 2005
$ $ $ $ $

Cash flows
from
operating
activities
Profit (loss)
for the
year (410,024) (8,200,450) (2,614,984) 911,124 (1,850,777)
Items not
affecting
cash
Stock-based
compen-
sation 199,696 1,504,888 692,682 1,046,168 1,079,545
Interest
expense - - - - 204,830
Depreci-
ation 191,301 618,062 136,531 250,637 130,492
Depletion 7,466,062 11,318,350 715,178 1,750,004 2,583,197
Unrealized
foreign
exchange
loss - - - - 8,253
Effect of
changes
in exchange
rates - - - - 1,281,407

---------- ----------- ---------- ---------- ----------

7,447,035 5,240,850 (1,070,593) 3,957,933 3,436,947
---------- ----------- ---------- ---------- ----------
Changes in
non-cash
operating
working
capital
Changes in
non-cash
balances
related
to oper-
ations (8,389,515) (6,891,651) 1,158,862 566,207 (6,417,220)
---------- ----------- ---------- ---------- ----------

(942,480) (1,650,801) 88,269 4,524,140 (2,980,273)
---------- ----------- ---------- ---------- ----------
Cash flows
From
Investing
activities
Investment
in oil and
gas inter-
ests (27,455,615) (72,469,193) (14,916,408) (21,386,731) (8,379,532)
Investment
in
property,
plant and
equipment (600,188) (1,164,312) (576,767) (830,617) (428,802)
Pledge for
bank
guarantee
issued 6,950,000 15,826,382 (4,863,489) (5,472,116) (11,848,067)
Advance
relating
to
exploration
commitment - - - - 35,737
Deposit in
lieu of
guarantee
for explor-
ation
license - - - - 2,160,190
Partial
release of
pledged
deposit in
lieu of
guarantee
issued - - - - (66,038)
Release of
exploration
commitment - - 252,163 1,372,163 584,064
Changes in
non-cash
balances
related to
investing
activities 2,817,303 2,817,303 3,971,401 3,971,401 1,854,151
---------- ----------- ---------- ---------- ----------

(18,288,500) (54,989,820) (16,133,100) (22,345,900) (16,088,297)
---------- ----------- ---------- ---------- ----------
Cash flows
from
financing
activities
Issuance of
Common
shares and
special
warrants 82,587,334 133,727,620 357,370 30,279,825 11,052,125
Repayment
of loan
from a
shareholder - - - - (3,005,103)
Incidental
revenues
from Syria - - - - 55,600
---------- ----------- ---------- ---------- ----------

82,587,334 133,727,620 357,370 30,279,825 8,102,622
---------- ----------- ---------- ---------- ----------

Increase
(decrease)
in cash 63,356,354 77,086,999 (15,687,461) 12,458,065 (10,965,948)

Cash -
Beginning
of period 30,409,137 16,678,492 32,365,953 4,220,427 15,186,375
---------- ----------- ---------- ---------- ----------

Cash - end
of period 93,765,491 93,765,491 16,678,492 16,678,492 4,220,427
---------- ----------- ---------- ---------- ----------
---------- ----------- ---------- ---------- ----------

Supplementary
Information
Interest
paid $ - $ - $ - $ - $ -
Taxes
paid $ - $ - $ - $ - $ -


Tanganyika Oil Company Ltd.

Notes to the Consolidated Financial Statements

Year ended December 31, 2006, seven months ended December 31, 2005 and year ended May 31, 2005

(Unaudited)

(in US Dollars)

1. Nature of Operations

Tanganyika Oil Company Ltd. (collectively with its subsidiaries, the "Company") was incorporated in 1986 and is primarily engaged in the exploration, development and operation of oil and gas interests in the Oudeh Block, and Tishrine and Sheikh Mansour Fields in the Syrian Arab Republic and the West Gharib Block in the Arab Republic of Egypt.

2. Accounting Changes

Change in Financial Year-end:

Effective June 1, 2005, the Company changed its financial year-end from May 31 to December 31. The Company made this change in order that its financial year-end would be comparable to its peers in the oil and gas industry. In accordance with Part 4.8 of National Instrument 51-102 Continuous Disclosure Obligations, the financial statements for the year ended December 31, 2006 ("current financial year") are presented along with the financial statements for the seven month period ended December 31, 2005 (the "previous financial year") and the financial statements for the year ended May 31, 2005.

3. Summary of Significant Accounting Policies

The consolidated financial statements of the Company are prepared in accordance with accounting principles generally accepted in Canada ("Canadian GAAP"). Significant measurement differences and their impact on these financial statements as a result of differences between Canadian GAAP and International Financial Reporting Standards are set out in note 19.

The significant accounting policies used in these consolidated financial statements are as follows:

a) Basis of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries: Tanganyika Oil (Bermuda) I Ltd., Dublin International Petroleum (Sinai) Limited, Bermuda (formerly Dublin International Petroleum (Tanzania) Limited, Bermuda), Dublin International Petroleum (Egypt) Limited, Bermuda, Dublin International Petroleum (Syria) Limited, Bermuda, Dublin International Petroleum (Damascus) Limited, Bermuda, and Drucker Petroleum Inc., British Virgin Islands.

b) Use of Estimates

The preparation of financial statements in conformity with Canadian GAAP 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. These estimates are subject to measurement uncertainty. Actual results could differ from and affect the results reported in these consolidated financial statements.

In the accounting for oil and gas interests, amounts recorded for depletion and amounts used for impairment test calculations are based on estimates of oil and gas reserves and future cash flows, including development costs. By their nature, the estimates of reserves and the related future cash flows are subject to measurement uncertainty and the impact on the consolidated financial statements of future periods could be material.

c) Foreign Currency Translation

The Company's reporting currency is U.S. dollars.

Monetary assets and liabilities denominated in foreign currencies are translated into U.S. dollars at exchange rates prevailing at the balance sheet date and non-monetary assets and liabilities are translated at rates in effect on the date of the transaction. Revenues and expenses are translated at the average rate of exchange in effect during the period other than depreciation which is translated at historical rates. Exchange gains or losses arising from translation are included in operations.

d) Joint Interests

The Company's activities in Egypt under the concession agreement with the Egyptian government are conducted jointly with others. The parties share all revenues and costs associated with the concession agreement. These financial statements reflect only the Company's proportionate share of these revenues and costs.

e) Oil and Gas Interests

The Company follows the full cost method of accounting for its oil and gas interests. In accordance with Accounting Guideline 16 (AcG 16) issued by the CICA, all costs relating to the exploration for and development of oil and gas reserves are capitalized in country-by-country cost centres and charged against income as set out below. Capitalized costs include expenditures for geological and geophysical surveys, concession acquisition, drilling exploration and development wells, gathering and production facilities and other development expenditures.

Capitalized costs along with estimated future capital costs to develop proved reserves are depleted on a unit-of-production basis using estimated proved oil and gas reserves. Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether proved reserves are attributable to the properties or impairment occurs. Unproved properties are evaluated for impairment on at least an annual basis. If an unproved property is considered to be impaired, the amount of the impairment is added to costs subject to depletion.

The Company engages independent reservoir engineers in order to determine its share of reserves.

Proceeds from the sale or farm-out of oil and gas interests are offset against the related capitalized costs and any excess of net proceeds over capitalized costs is included in operations. Gains or losses from the sale or farm-out of oil and gas interests in the producing stage are recognized only when the effect of crediting the proceeds to capitalized costs would result in a change of 20 percent or more in the depletion rate.

The net amount at which oil and gas interests are carried is subject to a cost recovery test (the "ceiling test"). The ceiling test is a two-stage process which is performed at least annually. The first stage is a recovery test whereby undiscounted estimated future cash flows from proved reserves at oil and gas prices in effect at the balance sheet date ("forecast prices") plus the cost of unproved properties less any impairment is compared to the net book value of the oil and gas interests to determine if the assets are impaired. An impairment loss exists if the net book value of the oil and gas interests exceeds such undiscounted estimated cash flows. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the net book value of the oil and gas interests exceeds the future estimated discounted cash flows from proved plus probable reserves at the forecast prices. Any impairment is recorded as additional depletion cost.

The Company has no significant asset retirement obligations associated with its oil and gas interests.

f) Revenue Recognition

Revenue from the sale of petroleum and natural gas are recorded when title passes to an external party.

g) Cash

Cash comprises cash in banks less outstanding cheques.

h) Property, Plant & Equipment

Property, plant and equipment are recorded at cost less accumulated depreciation. Depreciation is calculated on a straight-line basis over the estimated useful life based on the original cost less any expected residual value. The Company uses periods of three to five years as the estimated useful life for property, plant and equipment.

i) Earnings per Share

Earnings per share are presented for basic and diluted earnings. Basic per share information is computed by dividing the net profit or loss by the weighted average number of common shares outstanding during the year. The weighted average number of shares for fully diluted earnings per share information is calculated using the treasury stock method whereby it is assumed that proceeds obtained upon exercise of options and warrants would be used to purchase common shares at the average market price during the period. Under the treasury stock method, options and warrants have a dilutive effect only when the average market price of the common shares during the period exceeds the exercise price of the options or warrants (they are "in-the-money"). Exercise of in-the-money options and warrants is assumed at the beginning of the year or date of issuance, if later. Should the Company have a net loss for the period, options and warrants would be anti-dilutive and therefore will have no effect on the determination of loss per share.

j) Stock-based Compensation

The Company has a stock option plan as described in note 14. The Company uses the fair value method, utilizing the Black-Scholes option pricing model, for valuing stock options granted to directors, officers, consultants and employees. The estimated fair value is recognized over the applicable vesting period, except for stock options granted to consultants which are expensed immediately, as stock-based compensation expense and an increase to contributed surplus. When the stock options are exercised, the proceeds received and the applicable amounts in contributed surplus are credited to share capital.

k) Income Taxes

The Company follows the liability method of accounting for income taxes. Under this method, future income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Future tax liabilities and assets are measured using enacted or substantially enacted tax rates. The effect on future tax liabilities and assets of a change in tax rates is recognized in income in the period that the change occurs.

4. Restricted Cash

The Company has provided cash security for certain letters of guarantee and credit issued to third parties. At December 31, 2006, restricted cash represents a pledged amount of $900,000 (December 31, 2005 - $9,000,000 and May 31, 2005 - $9,000,000) against the issuance of a letter of guarantee in favour of the Syrian Petroleum Company (SPC) in connection with the production sharing agreements. Restricted cash also includes outstanding balances relating to letters of credit issued to various suppliers for operations in Syria and Egypt. At December 31, 2006, an amount of $nil (December 31, 2005 - $7,726,382 and May 31, 2005 - $2,254,266) is restricted as security for letters of credit.

5. Advance Relating to Exploration Commitment

At December 31, 2006 an amount of $nil (December 31, 2005 - $nil and May 31, 2005 - $1,372,163) was held by the Egyptian General Petroleum Company (EGPC) in respect of an advance associated with the extension of the Egyptian concession exploration license.

6. Amounts Receivable and Other Assets

At December 31, 2006, amounts receivable and other assets include trade receivable balances of $11,409,301 (December 31, 2005 - $5,466,000 and May 31, 2005 - $3,845,000) from the national oil companies, SPC and EGPC, in respect of the production and delivery of oil. In accordance with the terms of the agreements in Syria and Egypt, the Company sells all oil to SPC and EGPC, respectively. Management does not believe that this concentration of credit risk will result in any loss to the Company based on past payment experience.

In addition to the trade receivables, at December 31, 2006 amounts receivable and other assets includes $11,837,395 (December 31, 2005 - $nil and May 31, 2005 - $nil) receivable from SPC related to recoveries of based crude production operating costs for Oudeh and Tishrine.

7. Acquisitions

During the second quarter of 2006, the Company acquired a 50 percent interest in a private entity which holds certain rights associated with the development of oil and gas properties located in North Africa in exchange for 372,954 common shares having a deemed value of $3.5 million. As part of the acquisition, the Company agreed to fund 100 percent of the private entity's work program obligations to a maximum of $2 million. The Company has an option to acquire the remaining 50 percent interest in the private entity within 60 days after the date a development lease is issued in respect of the oil and gas properties for a purchase price of common shares of the Company having a deemed value of $6 million. An application for a development lease was submitted during the third quarter of 2006. See also note 17 (f).

8. Oil and Gas Interests



December 31, 2006
Accumulated
Cost depletion Net book value
------------------------------------------
Syrian Arab Republic 94,867,241 11,680,092 83,187,149
Arab Republic of Egypt 32,114,384 11,556,587 20,557,797
------------------------------------------
Total 126,981,625 23,236,679 103,744,946
------------------------------------------

December 31, 2005
Accumulated
Cost depletion Net book value
------------------------------------------
Syrian Arab Republic 32,129,921 2,109,602 30,020,319
Arab Republic of Egypt 18,865,574 9,808,727 9,056,847
------------------------------------------
Total 50,995,495 11,918,329 39,077,166
------------------------------------------

May 31, 2005
Accumulated
Cost depletion Net book value
------------------------------------------
Syrian Arab Republic 15,148,268 1,233,011 13,915,257
Arab Republic of Egypt 14,460,496 8,935,314 5,525,182
------------------------------------------
Total 29,608,764 10,168,325 19,440,439
------------------------------------------


The depletion and ceiling test calculations have excluded the cost of unproved properties of $4,256,882 (December 31, 2005 - $4,298,383, May 31, 2005 - $1,365,241) and included the cost of future development costs of $848,000,000 (December 31, 2005 - $55,015,964, May 31, 2005 - $55,237,951).

The Company performs a ceiling test annually in accordance with the Canadian Institute of Chartered Accountants' full cost accounting guidelines. No impairment provision was required for either country for the period ended December 31, 2006 (December 31, 2005 - $nil; May 31, 2005 - $nil).



----------------------------------------------------------------------
Brent North Syria Egypt
----------------------------------------------------------------------
First five years of pricing:
----------------------------------------------------------------------
2007 $ 64.00 $ 36.69 $ 43.78
----------------------------------------------------------------------
2008 $ 62.00 $ 37.10 $ 44.13
----------------------------------------------------------------------
2009 $ 59.00 $ 36.47 $ 43.28
----------------------------------------------------------------------
2010 $ 55.50 $ 35.12 $ 41.54
----------------------------------------------------------------------
2011 $ 52.00 $ 33.78 $ 39.72
----------------------------------------------------------------------


9. Property, Plant and Equipment



------------------------------------------
Accumulated
Cost depreciation Net book value
------------------------------------------
December 31, 2006 3,206,710 1,583,882 1,622,828
------------------------------------------
December 31, 2005 2,042,398 965,820 1,076,578
------------------------------------------
May 31, 2005 1,211,781 715,183 496,598
------------------------------------------


10. Loan Payable and Advances due to Shareholder

During the year ended May 31, 2005 a loan payable and various unsecured advances were provided by a shareholder of the Company at interest rates ranging from five to 12 percent per annum. During the year ended May 31, 2005 the Company paid to the shareholder 17,842 common shares as a bonus in relation to the loan payable, the fair value of which was recorded as interest expense. All amounts outstanding were repaid during the year ended May 31, 2005.

11. Share Capital

(a) The authorized and issued share capital is as follows:

Authorized - Unlimited number of common shares without par value

Issued and outstanding:



------------------------------------------------------------------
December 31, 2006 December 31, 2005 May 31, 2005
Number Amount Number Amount Number Amount
------------------------------------------------------------------
Balance,
beginning
of year 44,347,475 89,905,794 39,129,641 59,302,193 36,891,166 47,638,690
Private
placements,
net 10,300,000 130,679,517 5,000,000 29,447,369 2,000,000 10,910,885
North
Africa
Acquisition 372,954 3,501,862
Issue of
shares to
shareholder
(note 10) - - - - 17,842 102,194
Exercise of
options 612,267 4,149,200 217,834 1,156,232 220,633 650,424
------------------------------------------------------------------
Balance,
end of
year 55,632,696 228,236,373 44,347,475 89,905,794 39,129,641 59,302,193
------------------------------------------------------------------


(b) During the year ended December 31, 2006, the Company had the following issuances of shares:

(i) the Company completed a private placement consisting of 4,300,000 common shares at CDN $13.83 (SEK 92) per share for net proceeds of $49.7 million; and

(ii) the Company completed a private placement consisting of 6,000,000 common shares at CDN $15.91 (SEK 97) per share for net proceeds of $81.0 million.

(iii) options to purchase 612,267 common shares for cash were exercised at prices ranging from CDN $1.95 to $11.00 per share.

(c) During the seven month period ended December 31, 2005, the Company had the following issuances of shares:

(i) the Company completed a private placement consisting of 5,000,000 common shares at CDN $7.60 per share for net proceeds of $29.4 million; and

(ii) options to purchase 217,834 common shares for cash were exercised at prices ranging from CDN $1.95 to $7.25 per share.

(d) During the year ended May 31, 2005, the Company had the following issuances of shares:

(i) the Company completed a private placement consisting of 2,000,000 common shares at CDN $6.75 per share for net proceeds of $10.9 million;

(ii) options to purchase 220,633 common shares for cash were exercised at prices ranging from CDN $0.50 to $6.50 per share; and

(iii) the Company issued 17,842 common shares to a shareholder as settlement for a bonus to the shareholder related to a loan agreement (note 8).

12. Contributed Surplus



Seven months
Year ended ended Year ended
December 31, December 31, May 31,
2006 2005 2005
-------------------------------------------------------------------------

Balance, beginning
of the period 5,782,777 5,060,385 4,185,419
Stock-based compensation 1,504,888 1,046,168 1,079,545
Transfer to share capital
on exercise of options (1,086,022) (323,776) (204,579)
-------------------------------------------------------------------------
Balance, end of period 6,201,643 5,782,777 5,060,385
-------------------------------------------------------------------------


13. Related Party Transactions

The Company has entered into transactions with related parties, which were measured at the exchange amounts. Significant related party transactions were as follows:

a) The Company paid $265,476 (December 31, 2005 - $104,868 and May 31, 2005 - $158,109) to Namdo Management Services Ltd., a private corporation owned by Lukas H. Lundin, a director of the Company, pursuant to a services agreement.

b) During the year ended December 31, 2006, the Company received $216,752 (2005 - $43,478) from Pearl Exploration and Production Ltd. ("Pearl") for administrative and other services. The Company and Pearl have certain officers and directors in common.

c) On October 27, 2006, the Company loaned $3,000,000 to Pearl which was repayable on or before November 30, 2006. Interest was charged at a rate equal to prime plus 2% per annum. Pearl repaid the loan in full on November 22, 2006 plus accrued interest of $15,780.

d) A law firm in which a director of the Company is a partner provided various legal and consulting services in the amount of $36,652 (December 31, 2005 - $10,349 and May 31, 2005 - $22,600).

e) The Company paid $339,000 to United Petroleum Business, a company owned by an employee of the Company, to supply fuel.

f) On August 31, 2001, the Company received an unsecured advance in the amount of $200,000 from a director. Interest on the advance accrued at the rate of 10% per annum. At May 31, 2004 the advance amount including interest amounted to $229,922. The Company repaid the loan plus accrued interest during the year ended May 31, 2005.

14. Stock Option Information

The Company has a stock option plan (the "plan") for directors, officers, consultants and employees of the Company and its subsidiaries. A total of 3,500,000 stock options are authorized to be issued under the plan. The plan is administered by the Board of Directors. In accordance with the policies of the TSX Venture Exchange, the option exercise price, when granted, reflects current trading values of the Company's shares and all of the options are subject to a four-month "hold" period. The exercise period of the options is fixed by the Board of Directors and is not to exceed the maximum period permitted by the TSX Venture Exchange. Vesting rights are determined at the discretion of the Board of Directors.

The continuity of incentive stock options issued and outstanding is as follows:



--------------------------------------------------------------
December 31, 2006 December 31, 2005 May 31, 2005
--------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Options Exercise Options Exercise Options Exercise
Outstand- Price Outstand- Price Outstand- Price
ing CDN$ ing CDN$ ing CDN$
--------------------------------------------------------------
Outstanding
at beginning
of year 1,444,767 6.81 1,151,101 5.61 719,234 3.49
Granted 1,455,500 13.93 511,500 8.88 652,500 6.94
Exercised (612,267) 5.69 (217,834) 4.56 (220,633) 2.61
Cancelled/
expired (184,000) 9.38 - - - -
--------------------------------------------------------------
Outstanding
at end
of year 2,104,000 11.94 1,444,767 6.81 1,151,101 5.61
--------------------------------------------------------------
--------------------------------------------------------------


The following table summarizes information about stock options outstanding at December 31, 2006:



Options Outstanding Options Exercisable
---------------------------------------- ----------------------------
Weighted Weighted
average average
remaining remaining
Exercise contractual contractual
Price- Options life in Options life in
CDN$ Outstanding years Exercisable years
---------------------------------------- ----------------------------
$ 6.90 421,000 0.34 421,000 0.34
$ 7.50 25,000 0.47 25,000 0.47
$ 7.90 112,500 0.86 112,500 0.86
$ 8.85 70,000 0.99 70,000 0.99
$ 9.00 131,000 1.15 63,500 1.15
$ 9.35 112,000 1.08 43,500 1.08
$10.65 85,000 1.49 42,500 1.49
$11.00 74,000 0.66 74,000 0.66
$11.00 125,000 1.62 - -
$11.50 37,500 1.22 37,500 1.22
$12.31 40,000 1.41 20,000 1.41
$13.00 170,000 1.75 - -
$14.00 51,000 1.87 - -
$15.60 20,000 1.36 10,000 1.36
$17.51 630,000 4.93 - -
-------------- --------------
2,104,000 919,500
-------------- --------------


Employee stock options are measured at their fair value on the date of the grant and recognized on a straight line basis as an expense over the vesting period, if any, applicable to the options. The fair value of options granted to consultants is recognized immediately.

The estimated fair value of options granted during the period ended December 31, 2006 ranged from CDN $2.09 to CDN $6.41 per option, determined using the Black-Scholes option pricing model with the following assumptions:



Dec 31, 2006 Dec 31, 2005 May 31, 2005
Risk-free rate 3.79% - 4.27% 2.78% - 3.60% 3.15% - 3.41%
Expected life 2-3 years 2 years 2 years
Estimated volatility in the
market price of common shares 36% - 50% 52% - 63% 52% - 66%
Expected dividend rate 0% 0% 0%


15. Supplemental Cash Flow Information



Supplemental Cash Flow Information
Three Twelve Three Seven Twelve
months months months months months
ending ending ending ending ending
December 31, December 31, December 31, December 31, May 31,
2006 2006 2005 2005 2005
-------------------------------------------------------------------------
Changes in
non-cash
Working capital:
Accounts
receivable
and other
assets and
advances (14,158,333) (21,906,206) (1,056,694) (3,597,368) (4,537,190)
Due to
joint
venture
partners (2,837) 32,433 330,485 - 524
Prepaid
expenses 199,063 (236,119) 32,057 (139,125) 59,443
Accounts
payable and
accrued
liabil-
ities 8,389,895 18,035,544 5,824,415 8,274,101 184,587
Due to
directors - - - - (270,433)
---------------------------------------------------------------
(5,572,212) (4,074,348) 5,130,263 4,537,608 (4,563,069)

Changes in
non-cash
working
capital
relating to:
Operating
activi-
ties (8,389,515) (6,891,651) 1,158,862 566,207 (6,417,220)
Investing
activi-
ties 2,817,303 2,817,303 3,971,401 3,971,401 1,854,151
---------------------------------------------------------------
(5,572,212) (4,074,348) 5,130,263 4,537,608 (4,563,069)
---------------------------------------------------------------


16. Income Taxes

The differences between the income tax provision calculated using enacted combined federal and provincial rates and the reported income tax provision are as follows:



Dec 31, 2006 Dec 31, 2005 May 31, 2005
--------------------------------------------------------------------------

32.5% 33.62% 35.62%
--------------------------------------------------------------------------

Income tax expense computed
at Canadian statutory rates (2,665,146) 306,320 (718,276)
Unrecognized losses
(benefits) of tax concessions
in Egypt and Syria 1,387,031 (745,135) (563,694)
Permanent differences 498,224 (110,302) 696,439
Change in valuation allowance 97,954 479,412 585,531
Changes in tax rates and other 681,937 69,705 -
--------------------------------------------------------------------------

- - -
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Future income tax assets and liabilities are recognized for temporary differences between the carrying amount of the balance sheet items and their corresponding tax values as well as for the benefit of losses available to be carried forward to future years for tax purposes that are likely to be realized.

Significant components of the Company's future tax assets and liabilities, after applying enacted corporate income tax rates, are as follows:



Dec 31, 2006 Dec 31, 2005 May 31, 2005

Future income tax assets
Fixed asset and mineral
properties 121,828 104,080 91,075
Non-capital losses
carried forward 3,526,426 2,935,780 2,357,072
Other 1,424,105 698,683 344,735
--------------------------------------------------------------------------

5,072,360 3,738,543 2,792,881
Valuation allowance for
future income tax assets (5,072,360) (3,738,543) (2,792,881)
--------------------------------------------------------------------------

Future income tax assets, net - - -
--------------------------------------------------------------------------
--------------------------------------------------------------------------


The Company has available losses for Canadian income tax purposes of $12,160,000 which may be carried forward to reduce taxable income of future years. A summary of these losses is provided below:

Non-capital losses expiring in:



($)
--------------------------------------------
2007 1,090,000
2008 1,225,000
2009 878,000
2013 1,490,000
2014 1,810,000
2015 1,947,000
2026 3,720,000
-----------
12,160,000
-----------


Syrian Income Tax

The Company is tax protected by SPC under the terms of the Syrian concession agreement. In accordance with the terms of the concession agreement, the Company determines the liability for income tax which would otherwise be payable in connection with its Syrian operations. Any such tax determined in connection with the Company's Syrian operations is paid by SPC from their share of production and the Company retains no liability for payment of income or other taxes.

Egyptian Income Tax

The Company is tax protected by EGPC under the terms of the Egyptian concession agreement. In accordance with the terms of the concession agreement, the Company determines the liability for income tax which would otherwise be payable in connection with its Egyptian operations. Any such tax determined in connection with the Company's Egyptian operations is paid by EGPC from their share of production and the Company retains no liability for payment of income or other taxes.

17. Contingencies and Commitments

a) Under the terms of the Syrian Oudeh production sharing agreement, the Company has a minimum financial obligation of $5 million for drilling, workovers and other activities. The Company has met these minimum financial obligations. If the Company proceeds to the EOR field implementation phase, as it plans to do, it must undertake to drill a minimum of five wells per calendar year until either (i) a total of 75 wells are drilled, (ii) the total number of wells recommended under the field development plan are drilled, if less than 75, or (iii) the Company and SPC agree that further drilling is not technically or economically justifiable.

b) Under the terms of the Syrian Tishrine-Sheikh Mansour production sharing agreement, the Company has minimum financial commitments during the technical evaluation phase of $9 million for drilling, workovers and other activities. The Company has issued a letter of guarantee in favour of SPC to cover these minimum financial commitments (note 4). The Company has completed $8.1 million of the minimum work obligations thereby reducing its remaining financial obligations to $0.9 million. Following the technical evaluation phase, the Company may proceed to an EOR field implementation phase. If the Company proceeds with the EOR field implementation phase, it will have minimum financial obligations of $13 million for drilling, workovers and other activities.

c) Under the terms of the West Gharib, Egypt concession agreement, the Company has minimum financial obligations of $13.5 million. The Company has fully met these obligations.

d) Under the terms of the Syrian production sharing agreements, the Company is responsible for paying 100% of operating costs up-front and is entitled to claim for reimbursement of the portion of costs attributable to base crude production. The Company has estimated the total base crude production recoveries for Tishrine at $13,989,301. The Company has recorded only $5,547,990 of the estimated recoveries in amounts receivable and has recorded an amount payable to SPC for an equivalent amount. The Company has not recognized the difference as a reduction to its production costs or included the difference in its amounts receivable as SPC has not yet approved the recovery amounts.

e) The Company is a defendant in a lawsuit filed for non-payment of rent and abandonment of premises in March 1990. This event took place prior to the change in control of the Company and current management believes that the claim is without merit. The amount of the claim is CDN$ 513,000 including costs.

f) In relation to the 50% interest the Company acquired during the second quarter of 2006 in a private entity that holds certain rights associated with a North African oil and gas property (note 7), there is currently a legal dispute on whether the private entity has complied with its obligations under the concession agreement. If the entity is found not to have complied with its obligations, the concession may be discontinued. In such case, no development licenses could be received and the Company would need to write down its investments in the entity.

g) On February 15, 2007, a statement of claim was filed in the Court of Queen's Bench of Alberta, Canada by a former employee of the Company regarding the terms of his termination of employment. The Company is preparing to file a statement of defence to be filed with the court. The amount of the former employee's claim is approximately CDN$ 175,000, plus interest and fees.

h) The Company has committed to a five year office lease for its corporate offices in Calgary. The estimated future minimum commitments under these office leases are as follows:



---------------------------------------------------------------------------
Subse-
quent
to
2007 2008 2009 2010 2011 2009 Total
---------------------------------------------------------------------------
Office
lease 357,660 357,660 357,660 357,660 238,440 596,100 1,669,080
---------------------------------------------------------------------------


18. Segmented Information

Based on Geographical Regions



Three months ended December 31, 2006
Egypt
and
North
Syria Africa Canada Total
-----------------------------------------------------------
Sale of oil (4,270,578) (2,779,283) - (7,049,861)
Interest
income 32,772 (7,437) (376,391) (351,056)
Service income - (38,052) - (38,052)
Other income (3,770) - - (3,770)
Production
cost and
depletion (203,046) 1,920,636 - 1,717,590
Depreciation 119,123 28,371 43,806 191,300
Foreign
exchange
(gain)/loss (42,488) (221) 1,484,273 1,441,564
Other
expenses 3,398,639 85,330 1,018,339 4,502,308
-----------------------------------------------------------
Segment
(profit) loss (969,348) (790,656) 2,170,028 410,024
-----------------------------------------------------------

Segment assets 111,560,248 29,687,905 90,283,774 231,531,927
-----------------------------------------------------------

Segment
expenditures
Oil and gas
interests 28,645,879 (1,190,264) - 27,455,615
Property,
plant and
equipment 314,314 77,929 207,945 600,188
-----------------------------------------------------------
28,960,193 (1,112,335) 207,945 28,055,803
-----------------------------------------------------------


Three months ended December 31, 2005
Syria Egypt Canada Total
-----------------------------------------------------------
Sale of oil (2,984,249) (2,598,958) - (5,583,207)
Interest
income (5,635) (1,192) (245,049) (251,876)
Service income - (16,559) - (16,559)
Other income (3,171) 3,171 - -
Production
cost and
depletion 4,643,525 581,957 - 5,225,482
Depreciation 104,870 15,612 16,049 136,531
Foreign
exchange
(gain)/loss (12,341) (7,983) 144,175 123,851
Other
expenses 1,168,229 44,936 1,767,597 2,980,762
-----------------------------------------------------------
Segment
(profit) loss 2,911,228 (1,979,016) 1,682,772 2,614,984
-----------------------------------------------------------

Segment assets 46,155,025 17,492,958 19,266,972 82,914,955
-----------------------------------------------------------

Segment
expenditures
Oil and gas
interests 12,803,422 2,112,986 - 14,916,408
Property,
plant and
equipment 419,955 74,386 82,426 576,767
-----------------------------------------------------------
13,223,377 2,187,372 82,426 15,493,175
-----------------------------------------------------------


Twelve months ended December 31, 2006
Egypt
and
North
Syria Africa Canada Total
-----------------------------------------------------------
Sale of oil (19,270,217) (12,192,784) - (31,463,001)
Interest
income - (8,297) (1,227,222) (1,235,519)
Service income - (87,664) - (87,664)
Other income (3,770) - - (3,770)
Production
cost and
depletion 22,134,440 4,501,333 - 26,635,773
Depreciation 424,276 97,119 96,666 618,061
Foreign
exchange
(gain)/loss (62,719) (600) (4,798) (68,117)
Other
expenses 8,362,282 374,389 5,068,016 13,804,687
-----------------------------------------------------------
Segment
(profit) loss 11,584,292 (7,316,504) 3,932,662 8,200,450
-----------------------------------------------------------

Segment assets 111,560,248 29,687,905 90,283,774 231,531,927
-----------------------------------------------------------

Segment
expenditures
Oil and gas
interests 62,737,319 9,731,874 - 72,469,193
Property,
plant and
equipment 683,981 189,884 290,447 1,164,312
-----------------------------------------------------------
63,421,300 13,438,695 290,447 77,150,442
-----------------------------------------------------------


Seven months ended December 31, 2005
Syria Egypt Canada Total
-----------------------------------------------------------
Sale of oil (6,928,648) (6,081,047) - (13,009,695)
Interest
income (6,896) (6,525) (345,153) (358,574)
Service income - (38,302) - (38,302)
Other income (3,171) - - (3,171)
Production
cost and
depletion 7,062,151 1,490,158 - 8,552,309
Depreciation 187,835 28,630 34,172 250,637
Foreign
exchange
(gain)/loss (26,208) (18,838) (1,440,366) (1,485,412)
Other
expenses 1,980,122 136,028 3,064,934 5,181,084
-----------------------------------------------------------
Segment
(profit) loss 2,265,185 (4,489,896) 1,313,587 (911,124)
-----------------------------------------------------------

Segment assets 46,155,025 17,492,958 19,266,972 82,914,955
-----------------------------------------------------------

Segment
expenditures
Oil and gas
interests 16,981,651 4,405,080 - 21,386,731
Property,
plant and
equipment 493,355 126,722 210,540 830,617
-----------------------------------------------------------
17,475,006 4,531,802 210,540 22,217,348
-----------------------------------------------------------

May 31, 2005
Syria Egypt Canada Total
-----------------------------------------------------------
Sale of oil (6,453,149) (6,181,564) - 12,634,713)
Interest
income (3,130) - (78,338) (81,468)
Service income - (51,498) - (51,498)
Production
cost and
depletion 7,405,841 2,504,444 - 9,910,285
Depreciation 100,522 29,970 - 130,492
Foreign
exchange
(gain)/loss (203,801) 215,841 445,896 457,936
Other
expenses 1,436,523 199,342 483,878 4,119,743
-----------------------------------------------------------
Segment
(profit) loss 2,282,806 (3,283,465) 851,436 1,850,777
-----------------------------------------------------------

Segment assets 19,906,029 12,318,005 10,179,703 42,403,737
-----------------------------------------------------------

Segment
expenditures
Oil and gas
interests 6,118,718 2,260,814 - 8,379,532
Property,
plant and
equipment 311,594 117,208 - 428,802
-----------------------------------------------------------
6,430,312 2,378,022 - 8,808,334
-----------------------------------------------------------


19. Summary of Significant Differences Between Canadian GAAP and International Financial Reporting Standards (IFRS)

The Company's consolidated financial statements have been prepared in accordance with Canadian GAAP, which differ in certain material respects from International Financial Reporting Standards ("IFRS"). The principal difference between Canadian GAAP and IFRS from a measurement perspective, as applied to the Company's consolidated financial statements is asset impairment.

a) Impairment of oil and gas interests

Under Canadian GAAP, each cost centre should be assessed for impairment as at each annual balance sheet date or whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. An impairment loss should be recognized when the carrying amount of a cost centre is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. Unproved properties and major development projects are included in this recoverability test. A cost centre impairment loss should be measured as the amount by which the carrying amount of assets capitalized in a cost centre exceeds the sum of: the fair value of proved and probable reserves; and the costs (less any impairment) of unproved properties that have been subject to a separate test for impairment and contain no probable reserves. IFRS requires (i) an impairment to be recognized when the recoverable amount of an asset (cash generating unit) is less than the carrying amount; (ii) the impairment loss is determined as the excess of the carrying amount above the recoverable amount (the higher of fair value less costs to sell and value in use, calculated as the present value of future cash flows from the asset); and (iii) the reversal of an impairment loss when the recoverable amount changes. The differences in accounting policy described above had no impact on these financial statements.

b) Oil and gas interest

The Company follows the full cost method of accounting for oil and gas interest, as set out in AcG 16 issued by the CICA. Under this method, all costs related to exploration and development of oil and gas reserves are capitalized and accumulated in country-by-country cost centres. For purposes of reporting in accordance with IFRS, the Company has early adopted IFRS 6, Exploration For and Evaluation of Mineral Resources, which permits an entity to continue applying its existing policy in respect of exploration and evaluation costs. Under IFRS, once commercial reserves are established and technically feasibility for extraction is demonstrated, the related capitalized costs are allocated to cash generating units. This difference in accounting policy had no impact on the Company's financial statements. The company's Egyptian assets are considered to be in the development stage for the purposes of IFRS 6. The Egyptian assets are however within one cash generating unit and accordingly there is no difference from AcG 16 where assets are amortized on a country basis. The company's Syrian assets are considered to be in the exploration and evaluation stage as the company is still determining the technical feasibility and commercial viability of these assets. Accordingly, the company continues to account for the Syrian assets under its existing accounting policies.

c) Impairment of long lived assets

Under Canadian GAAP, a long-lived asset should be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. An impairment loss should be recognized when the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. Under IFRS, the carrying amounts of the Company's assets, other than oil and gas properties, are reviewed at each balance sheet date to determine whether there is any indication of impairment. If any such indication exists, the assets' recoverable amounts are estimated. An impairment loss is recognized when the carrying amount of an asset exceeds its recoverable amount. Impairment losses, if any, are recognized in the income statement. Under Canadian GAAP, the carrying amount of a long-lived asset is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. This assessment is based on the carrying amount of the asset at the date it is tested for recoverability, whether it is in use or under development. Under IFRS, the recoverable amount of the Company's assets other than oil and gas properties is the greater of their net selling price and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For an asset that does not generate cash inflows largely independent of those from other assets, the recoverable amount is determined for the cash generating unit to which the asset belongs. In respect of impairment of assets other than oil and gas properties, under Canadian GAAP, an impairment loss is not reversed if the fair value subsequently increases. For IFRS, an impairment loss may be reversed if there has been a change in the estimates used to determine the recoverable value. An impairment loss, on assets other than oil and gas properties, is only reversed to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized. The differences in accounting policy described above had no impact on these financial statements.

20. Subsequent Events

On February 7, 2007, the Company announced that Stockholmborsen's Listing Committee had approved the Company's application for a primary listing of its Swedish Depository Receipts on Stockholmborsen (the Stockholm Stock Exchange). The first date of trading on Stockholmborsen was February 14, 2007. The last day of trading on First North was February 13, 2007. The Company's trading symbol "TYKS" remained the same.

21. Certain figures for prior years have been reclassified in the financial statements to conform with the current year's presentation.



SUPPLEMENTARY INFORMATION

1. LIST OF DIRECTORS AND OFFICERS AT DECEMBER 31, 2006
a. Directors
Lukas H. Lundin
Gary S. Guidry
Bryan Benitz
John H. Craig
Hakan Ehrenblad
Keith Hill
William A. Rand

b. Officers:
Lukas H. Lundin, Chairman
Gary S. Guidry, President and CEO
Mamdouh Nagati, Executive Vice President
Arlene E. Weatherdon, CFO
Diane Phillips, Corporate Secretary

2. FINANCIAL INFORMATION
The audited report for the year-ended December 31, 2006 will be
published on March 30, 2007.

3. SPECIAL AND ANNUAL GENERAL MEETING
The Special and Annual General Meeting is scheduled for May 10, 2007
in Calgary, Alberta, Canada.

4. OTHER INFORMATION
Address (Corporate Office)
1400, 700 - 4th Avenue S.W.
Calgary, Alberta T2P 3J4
Canada

The corporate number of the Company is 318368-8.

Contact Information

  • Tanganyika Oil Company Ltd.
    Gary Guidry
    President and CEO
    (403) 663-2999
    (403) 261-1007 (FAX)
    Website: www.tanganikaoil.com