IVANHOE ENERGY INC - FORM 8-K - EX-99.3

Attached files

file	filename
8-K - 8-K - IVANHOE ENERGY INC	o59094e8vk.htm
EX-99.2 - EX-99.2 - IVANHOE ENERGY INC	o59094exv99w2.htm
EX-99.1 - EX-99.1 - IVANHOE ENERGY INC	o59094exv99w1.htm

Exhibit 99.3

IVANHOE ENERGY INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS (Revised)

In January 2010, Ivanhoe Energy Inc. (“Ivanhoe Energy” or “Ivanhoe” or the “Company”) completed a private placement (the “Private Placement”) of special warrants (the “Special Warrants”). Each Special Warrant is convertible into one common share of the Company and one-quarter of a share purchase warrant (collectively, the “Underlying Ivanhoe Securities”). Under the terms of the Private Placement, the Company is required to file, and obtain a receipt for, a prospectus (the “Prospectus”) qualifying the distribution of the Underlying Ivanhoe Securities to be issued upon the conversion of the Special Warrants in the Provinces of British Columbia, Alberta, Manitoba and Ontario. Certain documents filed by the Company with securities commissions or similar authorities in Canada are required to be incorporated by reference into the Prospectus, including the Company’s audited consolidated financial statements as at December 31, 2008 and 2007 and for each of the three years in the period ended December 31, 2008 (the “2008 Annual Financial Statements”).

On July 17, 2009, the Company sold all of its oil and gas exploration and production operations in the United States, including production properties and infrastructure in California and Texas and additional exploration acreage in California, to a third party for approximately U.S.$39.2 million (the “Disposition”). As the 2008 Annual Financial Statements are required to be incorporated by reference in the Prospectus, generally accepted accounting principles in Canada (“Canadian GAAP”) require that the assets and liabilities sold pursuant to the Disposition must be presented in the 2008 Annual Financial Statements as discontinued operations. Accordingly, the Company has revised the 2008 Annual Financial Statements solely for the purpose of presenting the assets and liabilities sold pursuant to the Disposition as discontinued operations in accordance with the requirements of Canadian GAAP (the “Revised 2008 Annual Financial Statements”).

The following revised management discussion and analysis, which has been revised solely for the purpose of conforming to, and reflecting, the revisions made in the Revised 2008 Annual Financial Statements (the “Revised MD&A”) presents management’s view of the Company’s historical financial and operating results as at March 16, 2009 (except as to the treatment of discontinued operations which are as of January 29, 2010). The Revised MD&A should be read in conjunction with the Revised 2008 Annual Financial Statements, which have been prepared in accordance with Canadian GAAP and are expressed in U.S. dollars. Canadian GAAP differs in certain respects from those principles that we would have followed had our financial statements been prepared in accordance with accounting principles generally accepted in the United States. Additional information relating to the Company is available at www.sedar.com and www.sec.gov. The information on such websites is not, and shall not be, deemed to be part of this Revised MD&A.

The Revised 2008 Annual Financial Statements and this Revised MD&A are being filed concurrently with, and are incorporated by reference into, the Prospectus. No attempt has been made in this Revised MD&A to modify or update other events occurring or disclosures presented in the management discussion and analysis originally presented as at March 16, 2009, except as required to reflect the revisions made in the Revised 2008 Annual Financial Statements.

TABLE OF CONTENTS


		Page
Currency and Exchange Rates		2
Abbreviations		2
Select Defined Terms		3
Forward Looking Statements		3
Ivanhoe Energy’s Business		3
Executive Overview of 2008 Results		4
Financial Results — Year to Year Change in Net Loss		6
Revenues and Operating Costs		7
General and Administrative		8
Business and Technology Development		10
Net Interest		10
Unrealized Gain (Loss) on Derivative Instruments		10
Depletion and Depreciation		11
Provision for Impairment of GTL Intangible Assets and Development Costs		12
Write-off of Deferred Financing Costs		12
Provision for Impairment of Oil and Gas Properties		12
Net Income (Loss) from Discontinued Operations		12
Financial Condition, Liquidity and Capital Resources		15
Sources and Uses of Cash		15
Outlook for 2009		16
Contractual Obligations and Commitments		17


		Page
Critical Accounting Principles and Estimates		17
2008 Accounting Changes		20
Impact of New and Pending Canadian GAAP Accounting Standards		20
Convergence of Canadian GAAP with International Financial Reporting Standards		21
Off Balance Sheet Arrangements		21
Related Party Transactions		21
Quantitative and Qualitative Disclosures about Market Risk		21
Non-Trading		21
Equity Market Risks		21
Commodity Price Risk		22
Foreign Currency Rate Risk		22
Interest Rate Risk		22
Credit Risk		23
Liquidity Risk		23
Trading		23

THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2008. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) IN CANADA.

OUR DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON OUR WORKING INTEREST BASIS AFTER ROYALTIES. ALL TABULAR AMOUNTS ARE EXPRESSED IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AND PRODUCTION DATA INCLUDING REVENUES AND COSTS PER BOE.

Currency and Exchange Rates

Unless otherwise specified, all reference to “dollars” or to “$” are to U.S. dollars and all references to “Cdn.$” are to Canadian dollars. The closing, low, high and average noon buying rates in New York for cable transfers for the conversion of Canadian dollars into U.S. dollars for each of the five years ended December 31 as reported by the Federal Reserve Bank of New York were as follows:


	2008		2007		2006		2005		2004
Closing	$	0.82	$	1.01	$	0.86	$	0.86	$	0.83
Low	$	0.77	$	0.84	$	0.85	$	0.79	$	0.72
High	$	1.01	$	1.09	$	0.91	$	0.87	$	0.85
Average Noon	$	0.94	$	0.94	$	0.88	$	0.83	$	0.77

Abbreviations

As generally used in the oil and gas business and in this Management Discussion and Analysis, the following terms have the following meanings:


Boe		= barrel of oil equivalent
Bbl		= barrel
MBbl		= thousand barrels
MMBbl		= million barrels
Mboe		= thousands of barrels of oil equivalent
Bopd		= barrels of oil per day
Bbls/d		= barrels per day
Boe/d		= barrels of oil equivalent per day
Mboe/d		= thousands of barrels of oil equivalent per day
MBbls/d		= thousand barrels per day
MMBls/d		= million barrels per day
MMBtu		= million British thermal units
Mcf		= thousand cubic feet
MMcf		= million cubic feet
Mcf/d		= thousand cubic feet per day
MMcf/d		= million cubic feet per day

When we refer to oil in “equivalents”, we are doing so to compare quantities of oil with quantities of gas or express these different commodities in a common unit. In calculating Bbl equivalents (Boe), we use a generally recognized industry standard in which one Bbl is equal to six Mcf. Boes may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Select Defined Terms

Ivanhoe Energy Inc. — “Ivanhoe Energy” or “Ivanhoe” or “the Company”
The Company’s proprietary, patented rapid thermal processing process (“RTP^TM Process”) for heavy oil upgrading (“HTL^TM Technology” or “HTL^TM”)

Syntroleum Corporation’s (“Syntroleum”) proprietary technology (“GTL Technology” or “GTL”) to convert natural gas into ultra clean transportation fuels and other synthetic petroleum products

United States Securities and Exchange Commission — “SEC”
Canadian Securities Administrators — “CSA”
Enhanced oil recovery — “EOR”
Steam Assisted Gravity Drainage — “SAGD”
Memorandum of Understanding — “MOU”
Toronto Stock Exchange — “TSX”

Forward Looking Statements

Certain statements in this document are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. Such forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance or achievements, or other future events, to be materially different from any future results, performance or achievements or other events expressly or implicitly predicted by such forward-looking statements. Such risks, uncertainties and other factors include our short history of limited revenue, losses and negative cash flow from our current exploration and development activities in China, Canada and Ecuador; our limited cash resources and consequent need for additional financing; our ability to raise additional financing. The availability of financing is dependent in part on the return of the credit and equity markets to normalized conditions. During the fourth quarter of 2008, as a result of the global economic crisis, the terms and availability of equity and debt capital have been materially restricted and financing may not be available when it is required or on acceptable terms. In addition to the above financing risks, uncertainties, risk and other factors also include uncertainties regarding the potential success of heavy-to-light oil upgrading and gas-to-liquids technologies; uncertainties regarding the potential success of our oil and gas exploration and development properties in China; oil price volatility; oil and gas industry operational hazards and environmental concerns; government regulation and requirements for permits and licenses, particularly in the foreign jurisdictions in which we carry on business; title matters; risks associated with carrying on business in foreign jurisdictions; conflicts of interests; competition for a limited number of what appear to be promising oil and gas exploration properties from larger more well financed oil and gas companies; and other statements contained herein regarding matters that are not historical facts. Forward-looking statements can often be identified by the use of forward-looking terminology such as “may”, “expect”, “intend”, “estimate”, “anticipate”, “believe” or “continue” or the negative thereof or variations thereon or similar terminology. We believe that any forward-looking statements made are reasonable based on information available to us on the date such statements were made. However, no assurance can be given as to future results, levels of activity and achievements. Except as required by law, we undertake no obligation to update publicly or revise any forward-looking statements contained in this report. All subsequent forward-looking statements, whether written or oral, attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

Ivanhoe Energy’s Business

Ivanhoe Energy is an independent international heavy oil development and production company focused on pursuing long term growth in its reserve base and production. Ivanhoe Energy plans to utilize technologically innovative methods designed to significantly improve recovery of heavy oil resources, including the application of HTL^TM Technology and EOR techniques. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production of oil and gas. Our core operations are currently carried out in China, the United States, Canada and Ecuador, with business development opportunities worldwide. In mid-2008, the Company acquired two leases located in the heart of the Athabasca oil sands region in Alberta, Canada and recently signed a contract in Ecuador for the appraisal and development of a heavy oil lease in Ecuador. It is anticipated that these sites will provide for the first commercial applications of the Company’s HTL™ Technology in major, integrated heavy oil projects.

Ivanhoe Energy’s proprietary, patented heavy oil upgrading technology upgrades the quality of heavy oil and bitumen by producing lighter, more valuable crude oil, along with by-product energy which can be used to generate steam or electricity. The HTL^TM Technology has the potential to substantially improve the economics and transportation of heavy oil. There are significant quantities of heavy oil throughout the world that have not been developed, much of it stranded due to the lack of on-site energy, transportation issues, or poor heavy-light price differentials. In remote parts of the world, the considerable reduction in viscosity of the heavy oil through the HTL^TM process will allow the oil to be transported economically by pipelines. In addition to a dramatic improvement in oil quality, an HTL^TM facility can yield large amounts of surplus energy for production of the steam and electricity used in heavy oil

production. The thermal energy from the HTL^TM process would provide heavy oil producers with an alternative to increasingly volatile prices for natural gas that now is widely used to generate steam. Yields of the low-viscosity, upgraded product can be greater than 85% by volume, and high conversion of the heavy residual fraction is achieved. In addition to the liquid upgraded oil product, a small amount of valuable by-product gas is produced, and usable excess heat is generated from the by-product coke.

HTL^TM can virtually eliminate cost exposure to natural gas and diluent, solve the transport challenge, and capture a substantial portion of the heavy to light oil price differential for oil producers. HTL^TM accomplishes this at a much smaller scale and at lower per barrel capital costs compared with established competing technologies, using readily available plant and process components. As HTL^TM facilities are designed for installation near the wellhead, they eliminate the need for diluent and make large, dedicated upgrading facilities unnecessary.

Executive Overview of 2008 Results

During the year, the value attributed to our reserves of our China oil and gas based on a standardized measure of discounted future cash flows decreased by 72% to $14.1 million. These values decreased principally as a result of significant year-over-year decreases in oil prices as at the end of the year of 50%. Total revenues increased as a result of price increases during a portion of the year and a $6.7 million increase in gains on derivative instruments that were required by the Company’s bank loan agreement. General and administrative costs increased as the Company continued to invest significant resources in the development and commercial deployment of its patented HTL™ heavy oil upgrading technology. In addition, in 2008 the Company made a $15.1 million provision for impairment of its GTL intangible assets and development costs.

In the second and third quarters of 2008, the Company completed three key transactions: 1) the acquisition of what we believe to be high quality oil sand assets in the Athabasca region of Canada (our “Tamarack” project), 2) an agreement with the Government of Ecuador on the development of a major heavy oil block in Ecuador (“Pungarayacu”), and 3) a Cdn.$88 million equity financing. With these transactions, the Company has taken significant steps towards its transition to a heavy oil exploration, production and upgrading company.

The remainder of 2008 was dedicated primarily to formulating the development plans for the Tamarack project in Alberta and for Pungarayacu in Ecuador, including advancing the permitting processes. In addition, the Company commissioned and began operating the HTL Feedstock Test Facility in San Antonio, and continues with HTL engineering of commercial scale HTL facilities consistent with the development plans for Tamarack and Pungarayacu.

The Company’s four reportable business segments are: Oil and Gas — Integrated, Oil and Gas — Conventional, Business and Technology Development and Corporate. These segments are different than those reported in the Company’s previous financial statements included in its Form 10-Ks and as such the presentation has been changed to conform to the new segments. Due to newly established geographically focused entities and the initiation of two new integrated projects, new segments are being reported to reflect how management now analyzes and manages the Company.

Oil and Gas

Integrated

Projects in this segment will have two primary components. The first component consists of conventional exploration and production activities together with enhanced oil recovery techniques such as steam assisted gravity drainage. The second component consists of the deployment of the HTL^TM Technology which will be used to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude. The Company has two such projects currently reported in this segment — a heavy oil project in Alberta and a heavy oil property in Ecuador. The integrated segments were established in 2008 and therefore there is no comparative information for 2007 and 2006.

Conventional

The Company explores for, develops and produces crude oil and natural gas in China and in the U.S. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and its exploration activities are conducted on the Zitong block located in Sichuan Province. In the U.S., the Company’s exploration, development and production activities are primarily conducted in California and Texas (see Net Income (Loss) from Discontinued Operations).

Business and Technology Development

The Company incurs various costs in the pursuit of HTL^TM and GTL projects throughout the world. Such costs incurred prior to signing a MOU or similar agreement, are considered to be business and technology development and are expensed as incurred. Upon

executing a MOU to determine the technical and commercial feasibility of a project, including studies for the marketability for the projects products, the Company assesses whether the feasibility and related costs incurred have potential future value, are probable of leading to a definitive agreement for the exploitation of proved reserves and should be capitalized.

Additionally, the Company incurs costs to develop, enhance and identify improvements in the application of the HTL^TM and GTL technologies it owns or licenses. The cost of equipment and facilities acquired, or construction costs for such purposes, are capitalized as development costs and amortized over the expected economic life of the equipment or facilities, commencing with the start up of commercial operations for which the equipment or facilities are intended.

Corporate

The Company’s corporate segment consists of costs associated with the board of directors, executive officers, corporate debt, financings and other corporate activities.

The following table sets forth certain selected consolidated data for the past three years:


	Year ended December 31,
	2008			2007			2006
Oil revenues	$	48,370		$	31,365		$	35,683
Net loss from continuing operations	$	(38,476	)	$	(33,433	)	$	(25,677	)
Net loss from continuing operations per share — basic and diluted	$	(0.15	)	$	(0.14	)	$	(0.11	)
Net loss and comprehensive loss	$	(34,193	)	$	(39,207	)	$	(25,492	)
Net loss per share — basic and diluted	$	(0.13	)	$	(0.16	)	$	(0.11	)
Average production (Boe/d)		1,339			1,325			1,576
Net revenue (loss) from operations per Boe	$	7.59		$	(1.75	)	$	0.89
Cash flow provided by operating activities from continuing operations	$	10,780		$	1,168		$	8,504
Cash flow provided by operating activities	$	17,050		$	5,489		$	14,352
Capital investments (continuing operations)	$	(21,063	)	$	(28,585	)	$	(12,296	)

Financial Results — Year to Year Change in Net Loss

The following provides a summary analysis of our net loss for each of the three years ended December 31, 2008 and a summary of year-over-year variances for the year ended December 31, 2008 compared to 2007 and for the year ended December 31, 2007 compared to 2006:


				*Favorable*						*Favorable*
				*(Unfavorable)*						*(Unfavorable)*
	2008			*Variances*			2007			*Variances*			2006
Summary of Net Loss by Significant Components:
Oil Revenues:	$	48,370					$	31,365					$	35,683
Production volumes				$	398					$	(5,667	)
Oil prices					16,607						1,349
Realized gain (loss) on derivative instruments		(4,430	)		(4,096	)		(334	)		(334	)		—
Operating costs		(21,515	)		(8,515	)		(13,000	)		(1,166	)		(11,834	)

General and administrative, less stock based compensation		(13,329	)		(5,350	)		(7,979	)		(1,407	)		(6,572	)
Business and technology development, less stock based compensation		(5,884	)		2,716			(8,600	)		(1,379	)		(7,221	)
Net interest		(585	)		(549	)		(36	)		(158	)		122
Current income tax provision		(654	)		(654	)		—			—			—

Total Cash Variances		1,973			557			1,416			(8,761	)		10,178


Unrealized gain (loss) on derivative instruments		6,118			10,777			(4,659	)		(4,659	)		—
Depletion and depreciation		(25,761	)		(5,121	)		(20,640	)		6,532			(27,172	)
Stock based compensation		(3,016	)		135			(3,151	)		(782	)		(2,369	)
Provision for impairment of GTL intangible assets and development costs		(15,054	)		(15,054	)		—			—			—
Impairment of oil and gas properties		—			6,130			(6,130	)		(710	)		(5,420	)
Write off of deferred financing costs		(2,621	)		(2,621	)		—			—			—
Acquisition costs		—			—			—			736			(736	)
Discontinued operations (net of tax)		4,283			10,057			(5,774	)		(5,959	)		185
Other		(115	)		154			(269	)		(111	)		(158	)

Net Loss	$	(34,193	)	$	5,014		$	(39,207	)	$	(13,715	)	$	(25,492	)

Our net loss for 2008 was $34.2 million ($0.13 per share) compared to our net loss in 2007 of $39.2 million ($0.16 per share). The decrease in our net loss from 2007 to 2008 of $5.0 million was due to an increase of $12.9 million in combined oil revenues and realized gain on derivative instruments. These were offset by increases in operating costs of $8.5 million, a $2.6 million increase in general and administrative and business and technology development expenses excluding stock based compensation and a $5.1 million increase in depletion and depreciation. In addition, there was a $10.8 million increase in income as a result of unrealized gain on derivative instruments offset by a combined $8.9 million expense increase arising from the impairment of assets.

Our net loss for 2007 was $39.2 million ($0.16 per share) compared to our net loss in 2006 of $25.5 million ($0.11 per share). The increase in our net loss from 2006 to 2007 of $13.7 million was due to decrease of $4.7 million in combined oil revenues and realized loss on derivative instruments, an increase in operating costs of $1.2 million, a $2.8 million increase in general and administrative and business and technology development expenses excluding stock based compensation and an $4.7 million increase in unrealized loss on derivative instruments. These increases were partially offset by a $6.5 million decrease for depletion and depreciation.

Significant variances in our net losses are explained in the sections that follow.

Revenues and Operating Costs

The following is a comparison of changes in production volumes for the year ended December 31, 2008 when compared to the same period in 2007 and for the year ended December 31, 2007 when compared to the same period for 2006:


	Years ended December 31,							Years ended December 31,
	Net Boe’s				Percentage			Net Boe’s				Percentage
	2008		2007		Change			2007		2006		Change
China:
Dagang		471,817		464,206		2	%		464,206		554,185		-16	%
Daqing		18,096		19,379		-7	%		19,379		20,946		-7	%

		489,913		483,585		1	%		483,585		575,131		-16	%

Net production volumes in 2008 increased 1% from 2007, resulting in increased revenues of $0.4 million.

Net production volumes in 2007 decreased 16% from 2006, resulting in decreased revenues of $5.7 million.

Oil prices increased in 2008 contributing to a $16.6 million increase in revenue as compared to 2007. We realized an average of $98.73 per Boe from operations in China during 2008, which was an increase of $33.87 per Boe from 2007 prices. We expect crude oil prices to remain volatile in 2009.

Oil prices increased in 2007 generating $1.3 million in additional revenue as compared to 2006. We realized an average of $64.86 per Boe from operations in China during 2007, which was an increase of $2.82 per Boe from 2006 prices.

The increased revenues from higher oil prices in 2008 and 2007 were offset by the realized loss on derivatives resulting from settlements from our costless collar derivative instruments. As benchmark prices rise above the ceiling price established in the contract the Company is required to settle monthly (see further details on these contracts below under “Unrealized Gain (Loss) on Derivative Instruments”). The Company realized a net loss on these settlements in 2008 of $4.4 million. This compares to a realized net loss in 2007 of $0.3 million. Changes in these realized settlement gains (losses) are detailed below:

Year Ended

Favorable

Year Ended

Favorable

Year Ended

December 31

(Unfavorable)

December 31,

(Unfavorable)

December 31,

2008

Variances

2007

Variances

2006

(4,430)

(4,096

)

(334

)

(334

)

—

Operating costs, including Windfall Levy (the “Windfall Levy”) and production taxes and engineering and support costs, for 2008 increased $17.04, or 63%, per Boe for 2008 when compared to 2007. These costs increased $6.30, or 31%, per Boe for 2007 when compared to 2006. Of the total $8.5 million increase in these costs for 2008 compared to 2007, $6.7 million were a result of the change in Windfall Levy which is explained in more detail below under the China – Operating Costs section.

China

•

Production Volumes 2008 vs. 2007

Net production volumes during 2008 increased by 6,328 Boe when compared to 2007. The normal field decline was offset by the production from five new development wells that were completed and put on production in the second half of 2007, as well as productivity increases from adding new perforations, fracture stimulations and water flood response. The expected production rates for 2009 will be similar to those averaged in 2008, but may be lower than the exit rate at December 31, 2008. At the end of 2008, there were 43 producing wells at the Dagang field and 42 producing wells at the end of 2007.

•

Production Volumes 2007 vs. 2006

The December 31, 2007 exit production rate at Dagang was 1,900 Gross Bopd, compared to 1,877 Gross Bopd at the end of 2006. Normal field decline was offset by the production of 290 Gross Bopd from five new development wells completed and put on production in the second half of 2007. Overall, net production volumes decreased 16% at the Dagang field for 2007 as in addition to normal declines within the field; we incurred abnormal downtimes due to problems encountered with sub-surface equipment. These equipment issues were resolved with a change in equipment suppliers.

•

Operating Costs 2008 vs. 2007

Operating costs in China, including engineering and support costs and Windfall Levy, increased 63% or $17.04 per Boe for 2008 when compared to 2007. Field operating costs increased $3.62 per Boe mainly as a result of a higher percentage of field office costs allocated to operations versus capital as capital activity has decreased. In addition there were more service rig days worked and higher power costs resulting from greater water injection in 2008 when compared to 2007. These increases were offset by decreases resulting from road access costs, insurance coverage and lower project management salaries.

In March 2006, the Ministry of Finance of the Peoples Republic of China (“PRC”) issued the “Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business” (the “Windfall Levy Measures”). According to the Windfall Levy Measures, effective as of March 26, 2006, enterprises exploiting and selling crude oil in the PRC are subject to a windfall gain levy if the monthly weighted average price of crude oil is above $40 per barrel. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted average sales price exceeding $40 per barrel. The cost associated with Windfall Levy has been included in operating costs in our financial statements. Consequently, as oil prices have increased, the amount of the Windfall Levy also increased significantly, resulting in $13.46 per Boe increase in 2008 when compared to 2007.

We expect operating costs in 2009 to decrease on a per barrel basis as compared to 2008. The most significant component of the expected decrease in operating expenses will be related to the Windfall Levy, as oil prices are not expected to reach the same levels in 2009 as 2008. In addition, there will be a decrease in operating costs due to the ability to charge CNPC for its share of operating costs, as “commercial production” status, currently 18% then 51% after cost recovery, will commence on January 1, 2009. These increases will be somewhat offset by an increase in office costs allocated to operations as we continue to reduce the number of capital projects.

•

Operating Costs 2007 vs. 2006

Operating costs in China, including engineering and support costs and Windfall Levy, increased 31% or $6.30 per Boe for 2007 when compared to 2006. Field operating costs increased $4.01 per Boe. In addition to the excessive down hole maintenance problems mentioned above, which resulted in increased workover and maintenance costs, increased power costs, additional operator salaries and higher supervision charges in relation to reduced volumes contributed to the increase. The Windfall Levy resulted in a $1.94 per Boe increase for 2007 partially as a result of the 2007 being the first full year of the Levy and partially due to higher oil prices. Engineering and support costs for 2007 increased by $0.35 per Boe or 46% as we reduced the number of capital projects.

* * *

Production and operating information including oil revenue, operating costs and depletion, on a per Boe basis, are detailed below:


	Year ended December 31,
	2008		2007			2006
Net Production:
Boe		489,913		483,585			575,131
Boe/day for the period		1,339		1,325			1,576

	Per Boe

Oil revenue	$	98.73	$	64.86		$	62.04

Field operating costs		21.70		18.08			14.07
Windfall Levy		21.14		7.68			5.74
Engineering and support costs		1.08		1.12			0.77

		43.92		26.88			20.58

Net operating revenue		54.81		37.98			41.46
Depletion		47.22		39.73			40.57

Net revenue (loss) from operations	$	7.59	$	(1.75	)	$	0.89

General and Administrative

Changes in general and administrative expenses, before and after considering increases in non-cash stock based compensation, by segment for the year ended December 31, 2008 when compared to the same period for 2007 and for the year ended December 31, 2007 when compared to the same period for 2006 were as follows:


	2008 vs.			2007 vs.
	2007			2006
Favorable (unfavorable) variances:
Oil Activities:
Canada	$	(1,653	)	$	—
Ecuador		(658	)		—
China		(203	)		(705	)
Corporate		(3,161	)		(847	)

		(5,675	)		(1,552	)
Less: stock based compensation		325			145

	$	(5,350	)	$	(1,407	)

•

General and Administrative 2008 vs. 2007

Canada

As noted elsewhere in this Annual Report, the Company acquired working interests in two leases located in Alberta, Canada in July 2008. General and administrative costs related to Canada in 2008 consist of hiring key staff, reallocation of existing resources and some initial office setup costs. In prior periods, some of these costs were recorded in the Business and Technology Development segment.

Ecuador

As noted elsewhere in this Annual Report, in the fourth quarter of 2008 the Company signed a contract to explore and develop Block 20. General and administrative costs related to Ecuador in 2008 consist of travel costs, contract services, hiring key staff, reallocation of existing resources and some initial office setup costs.

China

General and administrative expenses related to the China operations increased $0.2 million for 2008 as compared to 2007 mainly resulting from increases in consulting and audit fees, rent and facility costs and unrealized foreign exchange loss.

Corporate

General and administrative costs related to Corporate activities increased $3.2 million for 2008 when compared to 2007. The overall increase was mainly due to the following increases; $0.6 million provision for uncollectible accounts, corporate aircraft costs of $1.0 million, and increases in third party recruiting fees of $0.5 million and foreign exchange losses of $1.1 million.

•

General and Administrative 2007 vs. 2006

China

General and administrative expenses related to the China operations increased $0.7 million for 2007 mainly due to a decrease in allocations to capital investments as a result of fewer capital projects in 2007 when compared to 2006.

Corporate

General and administrative costs related to Corporate activities increased $0.8 million for 2007 when compared to 2006. The increase for 2007 was due to a $1.4 million increase in salaries and benefits partially resulting from discretionary bonuses paid in 2007, the addition of new executives mid way through 2006, and other key personnel added in 2007. This increase was offset by a decrease in outside legal costs of $0.2 million, a decrease in professional fees incurred to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”) in the amount of $0.1 million and a $0.3 million decrease for a one-time charge in 2006 for the write off of the deferred loan costs on the convertible loan that was paid by way of the issuance of common shares in the April 2006 private placement.

Business and Technology Development

Changes in business and technology development costs, before and after considering increases in non-cash stock based compensation, for the year ended December 31, 2008 when compared to 2007 and for the year ended December 31, 2007 when compared to 2006 were as follows:

•

Business and Technology Development 2008 vs. 2007

Business and technology development expenses decreased $3.2 million (including changes in stock based compensation) in 2008 when compared to 2007, mainly as a result of a decrease in CDF operating costs due to several heavy oil upgrading runs in the first and second quarters of 2007. These decreases were offset by increases in compensation costs as the Company assembled a core HTL^TMtechnology team.

•

Business and Technology Development 2007 vs. 2006

Business and technology development expenses increased $2.0 million in 2007 compared to 2006 as we focused on business and technology development activities related to HTL^TM opportunities. The overall increase in HTL^TM related to salaries and benefits was $1.4 million. In addition to a reallocation of resources (see G&A explanations above) to HTL^TM, and 2007 discretionary bonuses, key personnel were added to this segment throughout 2007 as the Company developed its commercialization program for its technology. This increase was partially offset by an increased $0.5 million allocation to capital investments. This segment also increased as a result of $0.3 million higher operating costs at the CDF. Operating expenses of the CDF to develop and identify improvements in the application of the HTL^TM Technology are a part of our business and technology development activities. This increase was in part the result of several heavy oil upgrading runs in the first and second quarters of 2007, including a key Athabasca bitumen test run. The Company used the information derived from the Athabasca bitumen test run for the design and development of full-scale commercial projects. In addition, the HTL^TM segment increased $0.4 million as a result of higher outside engineering fees and legal fees related to patents and $0.6 million due to a shift in resources from GTL. The remainder of the increase is related to consulting fees and travel costs to develop opportunities for our HTL^TM Technology.

Net Interest

•

Net Interest 2008 vs. 2007

Interest expense increased $0.6 million for 2008 when compared to 2007 due to borrowings under a new loan for our China operations in the fourth quarter of 2007 and a short term loan that was outstanding from May 2008 to August 2008. Interest income also increased slightly in 2008 when compared to 2007 due to cash deposits from the July 2008 private placement.

•

Net Interest 2007 vs. 2006

Interest expense was higher in 2007 when compared to 2006 partially due to the funding of a new loan for China in 2007. In addition, interest income decreased by $0.3 million as average cash balances were lower throughout 2007 when compared to 2006.

Unrealized Gain (Loss) on Derivative Instruments

As required by the Company’s lender, the Company entered into costless collar derivatives to minimize variability in its cash flow from the sale of approximately 50% of the Company’s estimated production from its Dagang field in China over a three-year period starting September 2007. This derivative has a ceiling price of $84.50 per barrel and a floor price of $55.00 per barrel using the WTI as the index traded on the NYMEX.

The Company is required to account for these contracts using mark-to-market accounting. As forecasted benchmark prices exceed the ceiling prices set in the contract, the contracts have negative value or a liability. These benchmark prices reached record highs at the beginning of the third quarter of 2008 before steadily declining at the end of the fourth quarter to a level that is the lowest dating back several years. For the year ended December 31, 2008, the Company had $6.1 million unrealized gains in these derivative transactions. This compares to an unrealized net loss in 2007 of $4.7 million and $ nil in 2006. Changes in these unrealized settlement (losses) and gains are detailed below:


Year Ended		*Favorable*		Year Ended			*Favorable*			Year Ended
December 31,		*(Unfavorable)*		December 31,			*(Unfavorable)*			December 31,
2008		*Variances*		2007			*Variances*			2006
$	6,118	$	10,777	$	(4,659	)	$	(4,659	)	$	—

Depletion and Depreciation

The primary expense in this classification is depletion of the carrying values of our oil and gas properties in our China cost center over the life of their proved oil and gas reserves as determined by independent reserve evaluators. For more information on how we calculate depletion and determine our proved reserves see “Critical Accounting Principles and Estimates – Oil and Gas Reserves and Depletion”.

•

Depletion and Depreciation 2008 vs. 2007

Depletion and depreciation increased $5.1 million for 2008 as compared to 2007. This is partially due to a $1.2 million increase in depreciation of the CDF and increases in depletion rates for China.

China

China’s depletion rate increased $7.49 per Boe for 2008 when compared to 2007, resulting in a $3.7 million increase in depletion expense for 2008. The increase in the rates from year to year was mainly due to an impairment of the drilling and completion costs associated with the second Zitong exploration well in the fourth quarter of 2007. The remaining increase of $0.2 million was related to increased production.

Business and Technology Development

Depreciation of the CDF is calculated using the straight-line method over its current useful life which is based on the existing term of the agreement with Aera Energy LLC (“Aera”) to use their property to test the CDF. A formal study was conducted in 2008 whereby the estimated salvage value of the property was decreased and the asset retirement obligation was increased resulting in an increased depreciable base.

•

Depletion and Depreciation 2007 vs. 2006

Depletion and depreciation decreased $6.5 million in 2007, partially due to reduced depletion of $4.2 million for 2007. This decrease was somewhat offset by a higher depletion rate of $47.22 per Boe. Reduced depreciation of the CDF as a result of a longer depreciation period also contributed to the overall decrease in depletion and depreciation in the amount of $2.4 million for 2007.

China

Decreases in production volumes in China resulted in a decrease in depletion expense of $3.7 million for 2007 when compared to 2006.

China’s depletion rate decreased $0.84 per Boe to $39.73 for 2007 when compared to 2006, resulting in a $0.4 million decrease in depletion expense. The decrease in the rates from year to year was mainly due to a $5.4 million ceiling test write down in the fourth quarter of 2006. This decrease was somewhat offset by an increase to the depletable pool in the fourth quarter of 2007 for the impairment of the drilling costs associated with the second exploration well in the Zitong Block.

Business and Technology Development

Depreciation of the CDF is calculated using the straight-line method over its current useful life which is based on the existing term of the agreement with Aera to use their property to test the CDF. The end term of this agreement was extended in August 2006 from December 31, 2006 to December 31, 2008 and the useful life was extended to coincide with the new term of the agreement. In addition to the change in life, depreciation expense also decreased as a result of a reduction in the depreciable base during the second quarter of 2007 due to a portion of the payment from INPEX being applied against those costs.

Provision for Impairment of GTL Intangible Assets and Development Costs

The Company has been pursuing a GTL project for an extended period of time and has not been able to obtain a definitive agreement or appropriate financing. As a result the Company has impaired the entire carrying value of the costs associated with GTL as at December 31, 2008. The carrying value for GTL development costs of $5.1 million and intangible GTL license costs of $10.0 million have been reduced to nil with a corresponding reduction in our results of operations. This impairment does not affect the Company’s intention to continue to pursue the current GTL project in Egypt.

In 2007 and 2006, we had no write downs of our GTL assets.

Write-off of Deferred Financing Costs

The Company incurred professional fees and expenses associated with the pursuit of corporate financing initiatives by the Company’s Chinese subsidiary, Sunwing Energy. In the fourth quarter of 2008 this financing initiative was postponed indefinitely and therefore the associated costs were written down to nil with a corresponding reduction in our results of operations.

Provision for Impairment of Oil and Gas Properties

As discussed below in “Critical Accounting Principles and Estimates — Impairment of Proved Oil and Gas Properties”, we evaluate our cost center’s proved oil and gas properties for impairment on a quarterly basis. If as a result of this evaluation, a cost center’s carrying value exceeds its expected future net cash flows from its proved and probable reserves then a provision for impairment must be recognized in the results of operations.

•

Impairment of Oil and Gas Properties 2008 vs. 2007

We did not impair our oil and gas properties in 2008, compared to $6.1 million impairment of our China oil and gas properties in 2007.

•

Impairment of Oil and Gas Properties 2007 vs. 2006

We impaired our China oil and gas properties by $6.1 million in 2007, compared to $5.4 million in 2006. The 2007 impairment was mainly the result of impairing our costs incurred in the Zitong block due to an unsuccessful second exploration well resulting in those costs of $17.6 million being included with the carrying value of proved properties for the ceiling test calculation. The 2006 impairment was a result increased operating costs of the Dagang field, including cost of the Windfall Levy established in March 2006.

Net Income (Loss) from Discontinued Operations

The following applies to the U.S operations only. The sale of the U.S. operations closed July 17, 2009. The U.S. operations have been accounted for as discontinued operations in accordance with Canadian GAAP on a retroactive basis and the results as at December 31, 2008 and 2007 and for the three years ended December 31, 2008 have been amended accordingly.

The operating results for this discontinued operation for the periods noted were as follows:


	Year Ended December 31,
	2008		2007			2006
Revenue
Oil and gas revenue	$	18,120	$	12,270		$	12,065
Gain (loss) on derivative instruments		278		(5,594	)		(424	)
Interest income		98		152			139

		18,496		6,828			11,780


Expenses
Operating costs		5,137		4,319			4,299
General and administrative		2,413		1,972			1,628
Depletion and depreciation		6,143		5,884			5,378
Interest expense and financing costs		520		427			290

		14,213		12,602			11,595


Net Income (Loss) from discontinued operations	$	4,283	$	(5,774	)	$	185

•

Revenues and Operating Costs

Prices and gain/loss on derivatives

From the U.S. operations, we realized an average of $88.67 per Boe during 2008, which was an increase of $26.96 per Boe and accounted for $5.5 million of our increased revenues, and we realized an average of $61.71 per Boe during 2007, which was an increase of $6.85 per Boe and accounted for $1.3 million of our increased revenues.

The increased revenues from higher oil and gas prices were offset by the realized loss on derivatives resulting from settlements from our costless collar derivative instruments. As benchmark prices rise above the ceiling price established in the contract the Company is required to settle monthly (see further details on these contracts below under “Unrealized Gain (Loss) on Derivative Instruments”). The Company realized a net loss on these settlements in 2008 of $5.2 million, which compares to a realized net loss in 2007 of $1.3 million and a $0.1 million realized gain in 2006.

Production Volumes


	Years ended December 31,							Years ended December 31,
	Net Boe’s				Percentage			Net Boe’s				Percentage
	2008		2007		Change			2007		2006		Change
U.S.:
South Midway		188,911		177,745		6	%		177,745		188,379		-6	%
Spraberry		13,484		19,587		-31	%		19,587		23,242		-16	%
Others		1,960		1,512		30	%		1,512		8,309		-82	%

		204,355		198,844		3	%		198,844		219,930		-10	%

There was a 3% increase in U.S. production volume for 2008 as compared to 2007 and accounted for $0.3 million of our increased revenues. The overall changes to the U.S. production volumes were mainly due to the 2008 first quarter drilling program at South Midway. In addition, an increase in production in 2008 was due to increased steaming in the first two months of 2008 and abnormal downtimes in the steaming operations in 2007 due the absence of our two steam generators for extended period of time. U.S. production volumes decreased 10% in 2007 when compared to 2006 mainly due to a decline in production at South Midway resulting from steam generator downtime during the second and third quarters, along with certain wells taken offline to be soaked and steamed once that steaming operation came back on line. The purchase of a second steam generator and the retrofit of an existing generator allowed for a full steaming program in 2008. This decrease in volumes accounted for $1.1 million of our decreased revenues for this period.

Operating Costs

Field operating costs increased $4.21 per Boe in 2008 mainly due to an increase in steaming operations at South Midway. Both steam generators were down in the latter part of the first quarter and through the second quarter of 2007. In addition, the price of natural gas has been significantly higher in 2008 when compared to 2007.

In 2007, field operating costs increased $0.97 per Boe due to increases to maintenance costs and workovers at Spraberry and steaming projects in the diatomite formation at North Salt Creek. These increases were somewhat offset due to a reduction in the aforementioned downtime in our South Midway steaming operations in 2007. In addition to this overall increase, engineering and support costs for 2007 increased by $1.11 per Boe mainly due to a higher allocation of support to production as capital activity decreased.


	Year ended December 31,
	2008		2007		2006
Net Production:
Boe		204,355		198,844		219,930
Boe/day for the period		558		545		603

			Per Boe

Oil and gas revenue	$	88.67	$	61.71	$	54.86

Field operating costs		19.62		15.41		14.44
Production tax		1.31		1.25		1.15
Engineering and support costs		4.21		5.06		3.95

		25.14		21.72		19.54

Net operating revenue		63.53		39.99		35.32
Depletion		29.88		29.38		24.23

Net revenue (loss) from operations	$	33.65	$	10.61	$	11.09

•

General and Administrative Expenses

General and administrative expenses increased $0.4 million in 2008 and $0.3 million in 2007 as compared to the previous years. The increase in 2008 was mainly resulting from a lower allocation to capital and operations, provision for uncollectible accounts related to certain joint interest billings, offset by reallocation of staff to business and technology development. The increase in 2007 was the result of the following: allocations to capital investments and operations decreased $0.9 million as a result of less capital activity for 2007 when compared to 2006 and discretionary bonuses paid in 2007, offset by a decrease of $0.5 million for salaries and benefits, which was a result of reallocation of resources to HTL^TM activities beginning in the second half of 2006 and continuing through all of 2007.

•

Net Interest

Interest expense increased for 2008 and 2007 when compared to prior years due to additional draws on our loan facility.

•

Unrealized Gain (Loss) on Derivative Instruments

As required by the Company’s lenders, the Company entered into costless collar derivatives to minimize variability in its cash flow from the sale of approximately 75% of the Company’s estimated production from its South Midway Property in California and Spraberry Property in West Texas over a two-year period starting November 2006 and a six-month period starting November 2008. The derivatives have a ceiling price of $65.20, and $70.08, per barrel and a floor price of $63.20, and $65.00, per barrel, respectively, using WTI as the index traded on the NYMEX.

The Company is required to account for these contracts using mark-to-market accounting. As forecasted benchmark prices exceed the ceiling prices set in the contract, the contracts have negative value or a liability. These benchmark prices reached record highs at the beginning of the third quarter of 2008 before steadily declining at the end of the fourth quarter to a level that is the lowest dating back several years. For the year ended December 31, 2008, the Company had $5.5 million unrealized gains in these derivative transactions. This compares to an unrealized net loss in 2007 of $4.3 million and $0.5 million in 2006.

•

Depletion and Depreciation

The depletion rate for 2008 was $29.88 per Boe compared to $29.38 per Boe for 2007, an increase of $0.50 per Boe resulting in a $0.2 million increase in depletion expense. The depletion rate for 2007 was $29.38 per Boe compared to $24.23 per Boe for 2006, an increase of $5.15 per Boe resulting in a $1.0 million increase in depletion expense. This increase was mainly due to the 2006 fourth quarter impairment of certain properties, resulting in $4.8 million of those costs being included with our proved properties and therefore subject to depletion. In addition, the capital spending we incurred in 2007 was related to facilities, versus drilling, and therefore did not correspondingly increase our reserve base. Additionally, decreases in production volumes in the U.S. accounted for $0.5 million of the decrease in depletion expense for 2007.

Financial Condition, Liquidity and Capital Resources

Sources and Uses of Cash

Net cash and cash equivalents increased by $27.9 million for the year ended December 31, 2008 compared to a decrease of $2.5 million for 2007 and a decrease of $7.2 million for 2006.

•

Operating Activities

Our operating activities provided $17.1 million in cash for the year ended December 31, 2008 compared to $5.5 million and $14.4 million for the same periods in 2007 and 2006. The increase in cash from operating activities for the year ended December 31, 2008 was mainly due to a 51% increase in oil production prices offset by an increase in expenses, as well as an increase in changes in non-cash working capital when compared to 2007. The decrease in cash from operating activities for the year ended December 31, 2007 was mainly due to a decrease in net production volumes of 16% offset by an increase in oil prices of 5%, net of realized loss on derivative instruments associated with oil and gas operations. In addition, increases to operating costs, general and administrative and business and technology development expenses also reduced operating cash flows.

•

Investing Activities

Our investing activities used $49.3 million in cash for the year ended December 31, 2008 compared to $22.3 million for the same period in 2007 and $25.6 million for 2006. For 2008, the main reason for the differences is the $22.3 million paid as part of the cost of the acquisition of the 100% working interests in two leases located in the Athabasca oil sands region in the Province of Alberta, Canada (see Note 18 in the accompanying financial statements for more details). In addition the Company received $10.0 million in proceeds from the sale of assets and a recovery of development costs in 2007, compared to nil in 2008 and $6.0 million in proceeds from asset sales in 2006. There was also a decrease in capital asset expenditures for continuing operations of $7.5 million for 2008 as compared to 2007 and increase of $12.3 million for 2007 when compared to 2006.

Changes in capital investments by segment are detailed below:


	For the Year Ended							For the Year Ended
	December 31,							December 31,
					(Increase)							(Increase)
	2008		2007		Decrease			2007		2006		Decrease
Oil and Gas Activities:
Canada	$	6,484	$	—	$	(6,484	)	$	—	$	—	$	—
Ecuador		1,369		—		(1,369	)		—		—		—
China		8,378		23,488		15,110			23,488		9,086		(14,402	)
Business and Technology Development		4,832		5,097		265			5,097		3,210		(1,887	)

	$	21,063	$	28,585	$	7,522		$	28,585	$	12,296	$	(16,289	)

Canada

As noted above, two leases located in Canada were acquired in the third quarter of 2008. Capital investments this quarter consisted of capitalized interest, seismic/ERT and environmental work. In 2008, the overall focus has been on delineation activities, engineering and pre-filing regulatory requirements.

Ecuador

The increase in 2008 of $1.4 million of investment activities is due to a new project’s activities related to the signing of a contract to explore and develop Ecuador’s Pungarayacu heavy-oil field using our HTL^TM upgrading technology.

China

The decrease in investment in China in 2008 compared to 2007 was the result of a $9.6 million decrease in capital spending at Zitong and a $5.5 million decrease in capital spending at Dagang. Spending at Zitong during 2008 was limited to expenditures relating to the commencement of the second phase of the exploration program which were relatively minor compared to the drilling and completion costs incurred during 2007 for completing the first phase of the program which was concluded in December 2007. At Dagang, we spud five new development wells in 2007 compared to 2008 where we only completed a series of fracture stimulation projects. The increase from 2006 to 2007 was the result of a $9.1 million increase at our Zitong project and $5.3 million increase for the five new wells in 2007 at our Dagang project.

Business and Technology Development

The decrease in capital spending during 2008 when compared to 2007 was due to the timing of costs relating to the construction and delivery of the Feedstock Test Facility (“FTF”). The increase of $1.9 million, when comparing 2007 to 2006, resulted from expenditures for the FTF increasing by $3.9 million which were offset by decreased expenditures of $1.2 million for the CDF and $0.4 million for GTL and $0.4 million for other capitalized development costs.

Discontinued Operations

The $1.5 million increase in U.S. capital spending in 2008 compared to 2007 and the $2.5 million decrease in U.S. capital spending in 2007 compared to 2006 was mainly due to the eight well drilling program at South Midway in 2008 and a ten well drilling program at South Midway compared to the cost of a new steam generator in 2007.

•

Financing Activities

Financing activities for the year ended December 31, 2008 consisted mainly of an equity private placement in the third quarter of 2008. In July 2008, the Company completed a Cdn.$88.0 million private placement consisting of 29,334,000 special warrants (“Special Warrants”) at Cdn.$3.00 per Special Warrant (the “Offering”). Each Special Warrant entitled the holder to one common share of the Company upon exercise of the Special Warrant. In August 2008, all of the Special Warrants were exercised for 29,334,000 common shares. The net proceeds from the Offering of the Special Warrants was approximately Cdn.$83.4 million.

In addition, in April 2008, the Company obtained a loan from a third party finance company in the amount of Cdn.$5.0 million bearing interest at 8% per annum. At the lender’s option the principal and accrued and unpaid interest was converted in August 2008 into the Company’s common shares at a conversion price of Cdn.$2.24 per share.

These cash inflows were offset by $2.6 million in professional fees and expenses associated with the pursuit of corporate financing initiatives by the Company’s Chinese subsidiary, Sunwing Energy and the payment at maturity on December 31, 2008 of a promissory note to Talisman in the principal amount of Cdn.$12.5 million plus accrued interest.

Financing activities for the year ended December 31, 2007 consisted of two draws totaling $10.0 million ($9.4 million net of financing costs) on a bank loan facility. This increase in borrowings was offset by scheduled debt payments of $2.5 million. In 2006, we repaid notes in the amount of $4.0. million prior to maturity, made scheduled repayments of long-term debt of $2.0 million. Financing activities in 2007 also consisted of $4.0 million received from the exercise of warrants compared to 2006 when there were no warrants exercised but there was a $25.3 million private placement of common shares.

In April 2006, the Company closed a private placement of 11.4 million special warrants at $2.23 per special warrant for a total of $25.4 million. Each special warrant entitled the holder to receive, at no additional cost, one common share and one common share purchase warrant. All of the special warrants were subsequently exercised for common shares and common share purchase warrants. Each common share purchase warrant originally entitled the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing. In September 2007, these warrants were listed on the TSX and the exercise price was changed to Cdn.$2.93.

Outlook for 2009

Our 2009 capital program budget ranges from approximately $15 million to $20 million and will encompass the following: a) continuing development of our existing producing oil and gas properties to maximize near-term cash flow, b) the preparation of Tamarack and Pungarayacu for development, and c) engineering and development costs related to the preparation of our proprietary HTL^TM oil upgrading technology for full scale deployment in Canada and Ecuador. Management’s plans for financing its 2009 requirements and beyond include the potential for alliances or other arrangements with strategic partners as well as traditional project financing, debt and mezzanine financing or the sale of equity securities.

Discussions with potential strategic partners are focused primarily on national oil companies and other sovereign or government entities from Asian and Middle Eastern countries that have approached the Company and expressed interest in participating in the Company’s heavy oil activities in Ecuador, Canada and around the world.

The Company intends to utilize revenue from existing operations to fund the continuing transition of the Company to a heavy oil exploration, production and upgrading company and non-heavy oil related investments in our portfolio will be leveraged or monetized to capture value and provide maximum return for the Company. No assurances can be given that we will be able to enter into one or more alternative business alliances with other parties or raise additional capital. If we are unable to enter into such business alliances

or obtain adequate additional financing, we will be required to curtail our operations, which may include the sale of assets.

In addition to Tamarack and Pungarayacu, the Company will continue to pursue ongoing discussions related to other HTL heavy oil opportunities in Canada, Latin America, the Middle East and North Africa.

Contractual Obligations and Commitments

The table below summarizes the contractual obligations that are reflected in our 2008 consolidated balance sheets and/or disclosed in the accompanying Notes:


	Payments Due by Year
	(stated in thousands of U.S. dollars)
	Total		2009		2010		2011		2012		After 2012
Consolidated Balance Sheets:
Note payable – current portion	$	412	$	412	$	—	$	—	$	—	$	—
Long term debt		37,855		—		6,549		31,306		—		—
Asset retirement obligation		1,928		—		1,928		—		—		—
Long term obligation		1,900		—		—		—		1,900		—
Other Commitments:
Interest payable		8,144		3,071		2,884		2,189		—		—
Lease commitments		3,337		1,191		1,009		680		331		126
Zitong exploration commitment		24,694		13,123		11,571		—		—		—

Total	$	78,270	$	17,797	$	23,941	$	34,175	$	2,231	$	126

We have excluded our normal purchase arrangements as they are discretionary and/or being performed under contracts which are cancelable immediately or with a 30-day notification period.

Critical Accounting Principles and Estimates

Our accounting principles are described in Note 2 to Notes to the Consolidated Financial Statements. We prepare our Consolidated Financial Statements in conformity with GAAP in Canada.

The preparation of our financial statements requires us to make estimates and judgments that affect our reported amounts of assets, liabilities, revenue and expenses. On an ongoing basis we evaluate our estimates, including those related to asset impairment, revenue recognition, fair market value of derivatives, allowance for doubtful accounts and contingencies and litigation. These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could vary from those estimates under different assumptions and conditions.

We have identified the following critical accounting policies that affect the more significant judgments and estimates used in preparation of our consolidated financial statements.

Full Cost Accounting — We follow Accounting Guideline 16 “Oil and Gas Accounting — Full Cost” (“AcG 16”) in accounting for our oil and gas properties. Under the full cost method of accounting, all exploration and development costs associated with lease and royalty interest acquisition, geological and geophysical activities, carrying charges for unproved properties, drilling both successful and unsuccessful wells, gathering and production facilities and equipment, financing, administrative costs directly related to capital projects and asset retirement costs are capitalized on a country-by-country cost center basis. As at December 31, 2008, the carrying values of our Canada, Ecuador and China cost centers were $81.1 million, $1.5 million and $48.1 million, respectively.

The other generally accepted method of accounting for costs incurred for oil and gas properties is the successful efforts method. Under this method, costs associated with land acquisition and geological and geophysical activities are expensed in the year incurred and the costs of drilling unsuccessful wells are expensed upon abandonment.

As a consequence of following the full cost method of accounting, we may be more exposed to potential impairments if the carrying value of a cost center’s oil and gas properties exceeds its estimated future net cash flows than if we followed the successful efforts method of accounting. Impairment may occur if a cost center’s recoverable reserve estimates decrease, oil and natural gas prices decline or capital, operating and income taxes increase to levels that would significantly affect its estimated future net cash flows. See “Impairment of Proved Oil and Gas Properties” below.

Oil and Gas Reserves — The process of estimating quantities of reserves is inherently uncertain and complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change

substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. Our reserve estimates are based on current production forecasts, prices and economic conditions. Reserve numbers and values are only estimates and you should not assume that the present value of our future net cash flows from these estimates is the current market value of our estimated proved oil and gas reserves.

Reserve estimates are critical to many accounting estimates and financial decisions including:

	•		determining whether or not an exploratory well has found economically recoverable reserves. Such determinations involve the commitment of additional capital to develop the field based on current estimates of production forecasts, prices and other economic conditions.

	•		calculating our unit-of-production depletion rates. Proved reserves are used to determine rates that are applied to each unit-of-production in calculating our depletion expense. In 2008, oil and gas depletion of $23.1 million was recorded in depletion and depreciation expense. If our reserve estimates changed by 10%, our depletion and depreciation expense for 2008 would have changed by approximately $1.7 million assuming no other changes to our reserve profile. See “Depletion” below.

	•		assessing our proved oil and gas properties for impairment on a quarterly basis. Estimated future net cash flows used to assess impairment of our oil and gas properties are determined using proved and probable reserves⁽¹⁾. See “Impairment of Proved Oil and Gas Properties” below.

Management is responsible for estimating the quantities of proved oil and natural gas reserves and preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements, generally accepted industry practices in the U.S. as promulgated by the Society of Petroleum Engineers, and the standards of the COGE Handbook modified to reflect SEC requirements.

Independent qualified reserves evaluators prepare reserve estimates for each property at least annually and issue a report thereon. The reserve estimates are reviewed by our engineers who are familiar with the property and by our operational management. Our CEO and CFO meet with our operational personnel to review the current reserve estimates and related disclosures and upon their review and approval present the independent qualified reserves evaluators’ reserve reports to our Board of Directors with a recommendation for approval. Our Board of Directors has approved the reserve estimates and related disclosures.

The estimated discounted future net cash flows from estimated proved reserves included in the Supplementary Financial Information are based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net cash flows will also be affected by factors such as actual production levels and timing, and changes in governmental regulation or taxation, and may differ materially from estimated cash flows.

(1) “Proved” oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty can be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic recoverability is supported by either actual production or a conclusive formation test. “Probable” reserves are those additional reserves that are less likely to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of estimated proved plus probable reserves.

Depletion —As indicated previously, our estimate of proved reserves are critical to calculating our unit-of-production depletion rates.

Another critical factor affecting our depletion rate is our determination that an impairment of unproved oil and gas properties has occurred. Costs incurred on an unproved oil and gas property are excluded from the depletion rate calculation until it is determined whether proved reserves are attributable to an unproved oil and gas property or upon determination that an unproved oil and gas property has been impaired. An unproved oil and gas property would likely be impaired if, for example, a dry hole has been drilled and there are no firm plans to continue drilling on the property. Also, the likelihood of partial or total impairment of a property increases as the expiration of the lease term approaches and there are no plans to drill on the property or to extend the term of the lease. We assess each of our unproved oil and gas properties for impairment on a quarterly basis. If we determine that an unproved oil and gas property has been totally or partially impaired we include all or a portion of the accumulated costs incurred for that unproved oil and gas property in the calculation of our unit-of–production depletion rate. As at December 31, 2008, we had $81.1 million, $1.5 million and $5.2 million of costs incurred on unproved oil and gas properties in Canada, Ecuador and China, respectively.

Our depletion rate is also affected by our estimates of future costs to develop the proved reserves. We estimate future development costs using quoted prices, historical costs and trends. It is difficult to predict prices for materials and services required to develop a field particularly over a period of years with rising oil and gas prices during which there is generally increased competition for a limited number of suppliers. We update our estimates of future costs to develop our proved reserves on a quarterly basis.

Impairment of Proved Oil and Gas Properties — We evaluate each of our cost centers’ proved oil and gas properties for impairment on a quarterly basis.

For Canadian GAAP, AcG 16 requires recognition and measurement processes to assess impairment of oil and gas properties (“ceiling test”). In the recognition of an impairment, the carrying value⁽¹⁾ of a cost center is compared to the undiscounted future net cash flows of that cost center’s proved reserves using estimates of future oil and gas prices and costs plus the cost of unproved properties that have been excluded from the depletion calculation. If the carrying value is greater than the value of the undiscounted future net cash flows of the proved reserves plus the cost of unproved properties excluded from the depletion calculation, then the amount of the cost center’s potential impairment must be measured. A cost center’s impairment loss is measured by the amount its carrying value exceeds the discounted future net cash flows of its proved and probable reserves using estimates of future oil and gas prices and costs plus the cost of unproved properties that have been excluded from the depletion calculation and which contain no probable reserves. The net cash flows of a cost center’s proved and probable reserves are discounted using a risk-free interest rate adjusted for political and economic risk on a country-by-country basis. The amount of the impairment loss is recognized as a charge to the results of operations and a reduction in the net carrying amount of a cost center’s oil and gas properties. We provided for nil, $6.1 million and $5.4 million in a ceiling test impairment for our China cost center for the years ended December 31, 2008, 2007 and 2006, respectively.

Asset Retirement Obligations — For Canadian GAAP, we follow Canadian Institute of Chartered Accountants (“CICA”) Section 3110, “Asset Retirement Obligations” which requires asset retirement costs and liabilities associated with site restoration and abandonment of tangible long-lived assets be initially measured at a fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements at the present value of expected future cash outflows to satisfy the obligation. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations. We measure the expected costs required to retire our producing U.S. oil and gas properties at a fair value, which approximates the cost a third party would incur in performing the tasks necessary to abandon the field and restore the site. We do not make such a provision for our oil and gas operations in China as there is no obligation on our part to contribute to the future cost to abandon the field and restore the site. Asset retirement costs are depleted using the unit of production method based on estimated proved reserves and are included with depletion and depreciation expense. The accretion of the liability for the asset retirement obligation is included with interest expense.

Research and Development — We incur various expenses in the pursuit of HTL^TM and GTL projects, including HTL^TM Technology for heavy oil processing, throughout the world. For Canadian GAAP, such expenses incurred prior to signing a MOU, or similar agreements, are considered to be business and technology development expenses and are charged to the results of operations as incurred. Upon executing a MOU to determine the technical and commercial feasibility of a project, including studies for the marketability of the projects’ products, we assess that the feasibility and related costs incurred have potential future value, are probable of leading to a definitive agreement for the exploitation of proved reserves and should be capitalized. If no definitive agreement is reached, then the capitalized costs, which are deemed to have no future value, are written down to our results of operations with a corresponding reduction in our investments in HTL^TM or GTL assets. For the years ended December 31, 2008, 2007 and 2006, we wrote down $5.1 million, nil and nil, respectively, of capitalized negotiation and feasibility costs associated with our GTL projects which did not result in definitive agreements with no write downs in those same periods related to our HTL^TM projects.

Additionally, we incur costs to develop, enhance and identify improvements in the application of the HTL^TM and GTL technologies we license or own. We follow CICA Section 3450 “Research and Development Costs” in accounting for the development costs of equipment and facilities acquired or constructed for such purposes. Development costs are capitalized and amortized over the expected economic life of the equipment or facilities commencing with the start up of commercial operations for which the equipment or facilities are intended. We review the recoverability of such capitalized development costs annually, or as changes in circumstances indicate the development costs might be impaired, through an evaluation of the expected future discounted cash flows from the associated projects. If the carrying value of such capitalized development costs exceeds the expected future discounted cash flows, the excess is written down to the results of operations with a corresponding reduction in the investments in HTL^TM and GTL assets.

Costs incurred in the operation of equipment and facilities used to develop or enhance HTL^TM and GTL technologies prior to commencing commercial operations are business and technology development expenses and are charged to the results of operations in the period incurred.

Intangible Assets — Our intangible assets consists of the underlying value of an exclusive, irrevocable license to deploy, worldwide, the RTP^TMProcess for petroleum applications (HTL^TM Technology) as well as the exclusive right to deploy the RTP^TMProcess in all applications other than biomass and a master license from Syntroleum permitting us to use the Syntroleum Process in an unlimited number of projects around the world. For Canadian GAAP, we follow CICA Section 3062 “Goodwill and Other Intangible Assets” whereby intangible assets, acquired individually or with a group of other assets, are initially recognized and measured at cost. Intangible assets with finite lives are amortized over their useful lives whereas intangible assets with indefinite useful lives are not amortized unless it is subsequently determined to have a finite useful life. Intangible assets are reviewed annually for impairment, or

when events or changes in circumstances indicate that the carrying value of an intangible asset may not be recoverable. If the carrying value of an intangible asset exceeds its fair value or expected future discounted cash flows, the excess is written down to the results of operations with a corresponding reduction in the carrying value of the intangible asset. The HTL^TM Technology and the Syntroleum GTL master license have finite lives, which correlate with the useful lives of the facilities we expect to develop that will use the technologies. The amount of the carrying value of the technologies we assign to each facility will be amortized to earnings on a basis related to the operations of the facility from the date on which the facility is placed into service. We evaluate the carrying values of the HTL^TM Technology and the Syntroleum GTL master license annually, or as changes in circumstances indicate the intangible assets might be impaired, based on an assessment of its fair market value.

2008 Accounting Changes

On January 1, 2008, the Company adopted three new accounting standards that were issued by the Canadian Institute of Chartered Accountants (“CICA”): Handbook Section 1535 “Capital Disclosures” (“S.1535”), Handbook Section 3862 “Financial Instruments — Disclosures” (“S.3862”), and Handbook Section 3863 “Financial Instruments — Presentation” (“S.3863”). S.1535 establishes standards for disclosing information about an entity’s capital and how it is managed. The objective of S.3862 is to require entities to provide disclosures in their financial statements that enable users to evaluate both the significance of financial instruments for the entity’s financial position and performance; and the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks. The purpose of S.3863 is to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. The latter two replaced Handbook Section.3861 “Financial Instruments – Disclosure and Presentation”. The Company adopted the new standards on January 1, 2008 with additional disclosures included in these consolidated financial statements. There was no transitional adjustment to the consolidated financial statements as a result of having adopted these standards.

Impact of New and Pending Canadian GAAP Accounting Standards

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible assets,” (“S.3064”) replacing Handbook Section 3062, “Goodwill and Other Intangible Assets” (“S.3062”) and Handbook Section 3450, “Research and Development Costs”. S.3064 will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. The new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous S.3062. Management has concluded that the requirements of this new Section as they relate to goodwill will not have a material impact on its consolidated financial statements.

Also in February 2008, the CICA amended portions of Handbook Section 1000, “Financial Statement Concepts”, which the CICA concluded permitted deferral of costs that did not meet the definition of an asset. The amendments apply to annual and interim financial statements relating to fiscal years beginning on or after October 1, 2008. Upon adoption of S.3064 and the amendments to Section 1000 on January 1, 2009, capitalized amounts that no longer meet the definition of an asset will be expensed retrospectively. Management has concluded that the requirements of this new Section will not have a material impact on its consolidated financial statements.

Effective January 1, 2008, the Company implemented amendments to CICA Handbook Section 1400 “General Standards of Financial Statement Presentation” that incorporates going concern guidance. These changes require management to make an assessment of an entity’s ability to continue as a going concern when preparing financial statements. Financial statements shall be prepared on a going concern basis unless management either intends to liquidate the entity or to cease trading, or has no realistic alternative but to do so. When management is aware, in making its assessment, of material uncertainties related to events or conditions that may cast significant doubt upon the entity’s ability to continue as a going concern, those uncertainties shall be disclosed. The new requirements are applicable to all entities and are effective for annual financial statements relating to fiscal years beginning on or after January 1, 2008. There was no material impact on the Company’s consolidated financial statements as the Company already going concern disclosure in its consolidated financial statements.

Convergence of Canadian GAAP with International Financial Reporting Standards

In April 2008, the CICA published the exposure draft “Adopting IFRSs in Canada”. The exposure draft proposes to incorporate International Financial Reporting Standards (“IFRS”) into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS.

Under IFRS, the primary audience is capital markets and, as a result, there is significantly more disclosure required, specifically for quarterly reporting. Further, while IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policy which must be addressed. The Company has not completed development of its IFRS changeover plan, which will include project structure and governance, deployment of resources and training, analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company hopes to complete its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, once the exemptions as described below relating to full cost oil and gas companies have been determined.

The International Accounting Standards Board (“IASB”) has stated that it plans to issue an exposure draft relating to certain amendments to IFRS 1 in order to make it more useful to Canadian entities adopting IFRS for the first time. One such exemption relating to full cost oil and gas accounting is expected to result in a reduced administrative transition from the current Canadian AcG-16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late in 2009. The amendment will potentially permit the Company to apply IFRS prospectively to its full cost pool, rather than the retrospective assessment of capitalized exploration and development expenses, with the proviso that a ceiling test, under IFRS standards, be conducted at the transition date.

Off Balance Sheet Arrangements

At December 31, 2008 and 2007, we did not have any relationships with unconsolidated entities or financial partnerships, such as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships. We do not have relationships and transactions with persons or entities that derive benefits from their non-independent relationship with us, or our related parties, except as disclosed herein.

Related Party Transactions

The Company has entered into agreements with a number of entities which are related through common directors or shareholders. These entities provide access to an aircraft, the services of administrative and technical personnel and office space or facilities in Vancouver, London and Singapore. The Company is billed on a cost recovery basis. For the year ended December 31, 2008 the costs incurred in the normal course of business with respect to the above arrangements amounted to $3.0 million ($3.3 million for 2007 and $3.0 million for 2006), and are recorded in general and administrative expense in the statement of operations. As at December 31, 2008 amounts included in accounts payable and accrued liabilities on the balance sheet under these arrangements were $0.1 million ($0.2 million at December 31, 2007).

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to normal market risks inherent in the oil and gas business, including equity market risk, commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We recognize these risks and manage our operations to minimize our exposures to the extent practicable.

NON-TRADING

Equity Market Risks

We currently have limited production in China, which has not generated sufficient cash from operations to fund our exploration and development activities. Historically, we have relied on the equity markets as the primary source of capital to fund our expansion and growth opportunities. Based on our current plans, we estimate that we will need approximately $15 to $20 million to fund our capital investment programs for 2009.

We can give no assurance that we will be successful in obtaining financing as and when needed. Factors beyond our control, such as the recent credit crisis, may make it difficult or impossible for us to obtain financing on favorable terms or at all. Failure to obtain any

required financing on a timely basis may cause us to postpone our development plans, forfeit rights in some or all of our projects or reduce or terminate some or all of our operations.

Commodity Price Risk

Commodity price risk related to crude oil prices is one of our most significant market risk exposures. Crude oil prices and quality differentials are influenced by worldwide factors such as the recent credit crisis, OPEC actions, political events and supply and demand fundamentals. Using the Company’s 2008 actual worldwide crude oil production levels as an estimate for 2009 production, a $1.00/Bbl change in the realized price of oil, would increase or decrease net income and cash from operations for 2009 by $0.5 million.

We periodically engage in the use of derivatives to minimize variability in our cash flow from operations and currently have costless collar contracts put in place as part of our bank loan facility. The Company entered into costless collar derivatives to minimize variability in its cash flow from the sale of approximately 50% of the Company’s estimated production from its Dagang field in China over a three-year period starting September 2007. This derivative had a ceiling price of $84.50 per barrel and a floor price of $55.00 per barrel using WTI as the index traded on the NYMEX. See Note 12 to the Consolidated Financial Statements.

On December 31, 2008, the Company’s open positions on the derivatives mentioned above had a fair value of $1.5 million. A 10% increase in oil prices would reduce the fair value by approximately $0.9 million, while a 10% decrease in prices would increase the fair value by approximately $0.9 million. The fair value change assumes volatility based on prevailing market parameters at December 31, 2008.

Decreases in oil and natural gas prices would negatively impact our results of operations as a direct result of a reduction in revenues but may also do so in the ceiling test calculation for the impairment of our oil and gas properties. On a quarterly basis, we compare the value of our proved and probable reserves, using estimated future oil and gas prices, to the carrying value of our oil and gas properties. The ceiling test calculation is sensitive to oil and gas prices and in a period of declining prices could result in a charge to our results of operations as we experienced in 2001 when we recorded a $14.0 million provision for impairment for Canadian GAAP mainly due to a decline in oil and gas prices. Decreases in oil and gas prices from those used in our ceiling test calculation as at December 31, 2008 as discussed above in “Critical Accounting Principles and Estimates — Impairment of Proved Oil and Gas Properties” may result in additional impairment provisions of our oil and gas properties.

Foreign Currency Rate Risk

Foreign currency risk refers to the risk that the value of a financial commitment, recognized asset or liability will fluctuate due to changes in foreign currency rates. The main underlying economic currency of the Company’s cash flows is the U.S. dollar. This is because the Company’s major product, crude oil, is priced internationally in U.S. dollars. Accordingly, the Company does not expect to face foreign exchange risks associated with its production revenues. However, some of the Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The majority of the operating costs incurred in the Chinese operations are paid in Chinese renminbi. The majority of costs incurred in the administrative offices in Vancouver and Calgary, as well as some business development costs, are paid in Canadian dollars. In addition, with the recent property acquisition in Alberta (see Note 18) the Company’s Canadian dollar expenditures have increased during the last half of 2008 along with an increase in cash and debt balances denominated in Canadian dollars. Disbursement transactions denominated in Chinese renminbi and Canadian dollars are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date. Foreign currency gains and losses also come about when monetary assets and liabilities, mainly short term payables and receivables, denominated in foreign currencies are translated at the end of each month. The estimated impact of a 10% strengthening or weakening of the Chinese renminbi, and Canadian dollar, as of December 31, 2008 on net loss and accumulated deficit for the year ended December 31, 2008 is a $3.6 million increase, and a $3.7 million decrease, respectively. To help reduce the Company’s exposure to foreign currency risk it seeks to maximize the expenditures and contracts denominated in U.S. dollars and minimize those denominated in other currencies, except for its Canadian activities where it attempts to hold cash denominated in Canadian dollars in order to manage its currency risk related to outstanding debt and current liabilities denominated in Canadian dollars.

Interest Rate Risk

Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. The Company currently has a bank loan facility, a promissory note and a convertible note with fluctuating interest rates. The Company estimates that its net loss and accumulated deficit for the year ended December 31, 2008 would have changed $0.1 million for every 1% change in interest rates as of December 31, 2008. The Company is not currently actively attempting to mitigate this interest rate risk given the limited amount and term of its borrowings and the current global interest rate environment.

Credit Risk

The Company is exposed to credit risk with respect to its cash held with financial institutions, accounts receivable and advance balances. The Company believes its exposure to credit risk related to cash held with financial institutions is minimal due to the quality of the institutions where the cash is held and the nature of the deposit instruments. Most of the Company’s accounts receivable balances relate to oil and natural gas sales and are exposed to typical industry credit risks. In addition, accounts receivable balances consist of costs billed to joint venture partners where the Company is the operator and advances to partners for joint operations where the Company is not the operator. The advance balance relates to an arrangement whereby scheduled advances were made to a third party contractor associated with negotiating an HTL^TM and/or GTL project for the Company. The Company manages its credit risk by entering into sales contracts only with established entities and reviewing its exposure to individual entities on a regular basis. Of the $3.8 million trade receivables balance as at December 31, 2008, $3.1 million is due from a single customer. There are no other customers who represent more than 5% of the total balance of trade receivables. During the quarter ended September 30, 2008 the Company recorded an allowance associated with the advance balance for the entire outstanding amount of $0.7 million. The provision was recorded in General and Administrative expense in the accompanying Statement of Operations and Comprehensive Loss. There were no other changes to the allowance for credit losses account during the three-month period ended December 31, 2008 and no other losses associated with credit risk were recorded during this same period.

Liquidity Risk

Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available, which means it may be forced to sell financial assets or non-financial assets, refinance existing debt, raise new debt or issue equity. The Company’s present plans to generate sufficient resources to assure continuation of its operations and achieve its capital investment objectives include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt financing or the sale of equity securities. The availability of financing is dependent in part on the return of the credit and equity markets to normalized conditions. During the fourth quarter of 2008, as a result of the global economic crisis, the terms and availability of equity and debt capital have been materially restricted and financing may not be available when it required or on commercially acceptable terms.

TRADING

We do not enter into contracts for trading or speculative purposes. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had entered into such contracts.

Attached files

Stock widget

Investing forum

IVANHOE ENERGY INC Reports

Also read