Edgar Filing: IVANHOE ENERGY INC

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006


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

For the transition period from to

Commission file number 000-30586

IVANHOE ENERGY INC.

(Exact name of registrant as specified in its charter)


Yukon, Canada		98-0372413
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

Suite 654 – 999 Canada Place
Vancouver, British Columbia, Canada		V6C 3E1
(Address of principal executive office)		(zip code)

(604) 688-8323
(registrant’s telephone number, including area code)

No Changes
(Former name, former address and former fiscal year, if changed since last report)

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

Yes þ No o

Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer þ Non-accelerated filer o

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

Yes o No þ

The number of shares of the registrant’s capital stock outstanding as of September 30, 2006 was 241,195,798 Common Shares, no par value.

TABLE OF CONTENTS


		Page
PART I	Financial Information

Item 1	Financial Statements

	Unaudited Condensed Consolidated Balance Sheets as at September 30, 2006 and December 31, 2005		3

	Unaudited Condensed Consolidated Statements of Operations and Accumulated Deficit for the Three-Month and Nine-Month Periods Ended September 30, 2006 and 2005		4

	Unaudited Condensed Consolidated Statements of Cash Flow for the Three-Month and Nine-Month Periods Ended September 30, 2006 and 2005		5

	Notes to the Unaudited Condensed Consolidated Financial Statements		6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3.	Quantitative and Qualitative Disclosures About Market Risks		41

Item 4.	Controls and Procedures		41

PART II	Other Information

Item 1.	Legal Proceedings		42

Item 1A.	Risk Factors		42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		42

Item 3.	Defaults Upon Senior Securities		42

Item 4.	Submission of Matters To a Vote of Security Holders		42

Item 5.	Other Information		42

Item 6.	Exhibits		42

Part I – Financial Information

Item 1 Financial Statements

IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Balance Sheets
(stated in thousands of U.S. Dollars, except share amounts)


	September 30, 2006			December 31, 2005
Assets
Current Assets
Cash and cash equivalents	$	19,535		$	6,724
Accounts receivable (net of allowance for doubtful accounts of $116 and $83 as at September 30, 2006 and December 31, 2005, respectively)		9,071			9,994
Prepaid and other current assets		381			338

		28,987			17,056

Oil and gas properties and investments, net		130,878			119,654
Intangible assets — technology		102,153			102,068
Long term assets		2,224			2,099

	$	264,242		$	240,877


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities	$	12,385		$	25,791
Project advance from partner		2,186			—
Notes payable — current portion		3,493			1,667
Asset retirement obligations — current portion		—			950

		18,064			28,408


Long term debt		3,290			4,972


Asset retirement obligations		2,046			830


Long term obligation		1,900			1,900


Commitments and contingencies

Shareholders’ Equity
Share capital, issued 241,195,798 common shares; December 31, 2005 220,779,335 common shares		318,692			291,088
Purchase warrants		23,955			5,150
Contributed surplus		5,755			3,820
Accumulated deficit		(109,460	)		(95,291	)

		238,942			204,767

	$	264,242		$	240,877

(See accompanying notes)

IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Statements of Operations and Accumulated Deficit
(stated in thousands of U.S. Dollars, except per share amounts)


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Revenue
Oil and gas revenue	$	13,745		$	8,883		$	36,385		$	21,193
Interest income		270			24			578			95

		14,015			8,907			36,963			21,288


Expenses
Operating costs		4,724			1,731			11,298			5,264
General and administrative		2,921			2,411			7,648			6,328
Business and product development		2,043			1,504			5,159			3,401
Depletion and depreciation		7,772			4,476			24,808			9,250
Interest expense and financing costs		211			541			737			1,036
Write off of deferred acquisition costs		732			—			732			—
Write-downs and provision for impairment		—			357			750			636

		18,403			11,020			51,132			25,915


Net Loss		(4,388	)		(2,113	)		(14,169	)		(4,627	)
Accumulated Deficit, beginning of period		(105,072	)		(84,293	)		(95,291	)		(81,779	)

Accumulated Deficit, end of period	$	(109,460	)	$	(86,406	)	$	(109,460	)	$	(86,406	)


Net Loss per share — Basic and Diluted	$	(0.02	)	$	(0.01	)	$	(0.06	)	$	(0.02	)


Weighted Average Number of Shares (in thousands)		241,181			206,629			233,766			191,374

(See accompanying notes)

IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Statements of Cash Flow
(stated in thousands of U.S. Dollars)


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Operating Activities
Net loss	$	(4,388	)	$	(2,113	)	$	(14,169	)	$	(4,627	)
Items not requiring use of cash:
Depletion and depreciation		7,772			4,476			24,808			9,250
Write-down and provision for impairment		—			357			750			636
Stock based compensation		1,105			594			2,174			1,424
Write off of deferred acquisition costs		732			—			732			—
Write off of debt financing costs		—			857			—			857
Other		143			24			650			64
Changes in non-cash working capital items		279			(1,671	)		(3,600	)		(2,415	)

		5,643			2,524			11,345			5,189


Investing Activities
Capital investments		(5,019	)		(9,789	)		(13,622	)		(34,144	)
Merger, net of cash acquired		—			(117	)		—			(10,096	)
Merger and acquisition related costs		(230	)		—			(732	)		(1,687	)
Proceeds from sale of assets		—			—			5,350			—
Advance payments		—			(300	)		(125	)		(900	)
Other		(335	)		(10	)		(404	)		(86	)
Changes in non-cash working capital items		(5,306	)		1,364			(8,085	)		11,276

		(10,890	)		(8,852	)		(17,618	)		(35,637	)


Financing Activities
Shares issued on private placements, net of share issue costs		—			2,399			25,298			12,552
Proceeds from exercise of options and warrants		22			4,504			471			6,229
Share issue costs on shares issued for Merger		—			—			—			(93	)
Proceeds from debt obligations		—			—			—			8,000
Payments of debt obligations		(1,031	)		(417	)		(6,685	)		(1,250	)
Other		(17	)		(86	)		—			(512	)

		(1,026	)		6,400			19,084			24,926

Increase (decrease) in cash and cash equivalents, for the period		(6,273	)		72			12,811			(5,522	)
Cash and cash equivalents, beginning of period		25,808			3,728			6,724			9,322

Cash and cash equivalents, end of period	$	19,535		$	3,800		$	19,535		$	3,800

(See accompanying notes)

Notes to the Condensed Consolidated Financial Statements
September 30, 2006
(all tabular amounts are expressed in thousands of U.S. dollars except per share amounts)
(Unaudited)

1. BASIS OF PRESENTATION

The Company’s accounting policies are in accordance with accounting principles generally accepted in Canada. These policies are consistent with accounting principles generally accepted in the U.S., except as outlined in Note 15. The unaudited condensed consolidated financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2005 consolidated financial statements. These interim condensed consolidated financial statements do not include all disclosures normally provided in annual consolidated financial statements and should be read in conjunction with the most recent annual consolidated financial statements. The December 31, 2005 condensed consolidated balance sheet was derived from the audited consolidated financial statements, but does not include all disclosures required by generally accepted accounting principles (“GAAP”) in Canada and the U.S. In the opinion of management, all adjustments (which included normal recurring adjustments) necessary for the fair presentation for the interim periods have been made. The results of operations and cash flows are not necessarily indicative of the results for a full year.

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts and other disclosures in these condensed consolidated financial statements. Actual results may differ from those estimates.

2. SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

As more fully described in Note 13, on April 15, 2005 the Company acquired all the issued and outstanding common shares of Ensyn Group, Inc. (“Ensyn”) pursuant to a merger between Ensyn and a wholly owned subsidiary of the Company (“Merger”) in accordance with an Agreement and Plan of Merger dated December 11, 2004 (“Merger Agreement”). This acquisition was accounted for using the purchase method. These condensed consolidated financial statements include the accounts of Ivanhoe Energy Inc. and its subsidiaries, including those acquired in the Merger, all of which are wholly owned.

The Company conducts most exploration, development and production activities in its oil and gas business jointly with others. Our accounts reflect only the Company’s proportionate interest in the assets and liabilities of these joint ventures.

All inter-company transactions and balances have been eliminated for the purposes of these condensed consolidated financial statements.

3. OIL AND GAS PROPERTIES AND INVESTMENTS

Capital assets categorized by geographical location and business segment are as follows:


	As at September 30, 2006
	Oil and Gas
	U.S.			China			HTL			GTL		Total
Oil and Gas Properties:
Proved	$	97,528		$	106,026		$	—		$	—	$	203,554
Unproved		11,249			5,634			—			—		16,883

		108,777			111,660			—			—		220,437
Accumulated depletion		(19,789	)		(33,604	)		—			—		(53,393	)
Accumulated provision for impairment		(50,350	)		(5,750	)		—			—		(56,100	)

		38,638			72,306			—			—		110,944


HTL and GTL Investments:
Feasibility studies and other deferred costs		—			—			6,630			5,009		11,639
Commercial demonstration facility		—			—			11,392			—		11,392
Accumulated depreciation		—			—			(3,300	)		—		(3,300	)

		—			—			14,722			5,009		19,731


Furniture and equipment		508			109			73			—		690
Accumulated depreciation		(412	)		(51	)		(24	)		—		(487	)

		96			58			49			—		203

	$	38,734		$	72,364		$	14,771		$	5,009	$	130,878


	As at December 31, 2005
	Oil and Gas
	U.S.			China			HTL			GTL		Total
Oil and Gas Properties:
Proved	$	99,721		$	71,760		$	—		$	—	$	171,481
Unproved		9,676			5,320			—			—		14,996

		109,397			77,080			—			—		186,477
Accumulated depletion		(15,920	)		(16,036	)		—			—		(31,956	)
Accumulated provision for impairment		(50,350	)		(5,000	)		—			—		(55,350	)

		43,127			56,044			—			—		99,171


HTL and GTL Investments:
Feasibility studies and other deferred costs		—			—			6,142			4,570		10,712
Commercial demonstration facility		—			—			9,599			—		9,599

		—			—			15,741			4,570		20,311


Furniture and equipment		485			95			15			—		595
Accumulated depreciation		(380	)		(37	)		(6	)		—		(423	)

		105			58			9			—		172

	$	43,232		$	56,102		$	15,750		$	4,570	$	119,654

Costs as at September 30, 2006 and December 31, 2005 of $16.9 million and $15.0 million related to unproved oil and gas properties have been excluded from the depletion calculations.

For the three-month and nine-month periods ended September 30, 2006, general and administrative expenses related directly to oil and gas acquisition, exploration and development activities, and investments in our rapid thermal processing technology (“RTP^TM Technology”) for upgrading heavy oil (“HTL”) and gas-to-liquids (“GTL”) projects of $0.8 million and $2.4 million were capitalized. During those same periods in 2005, $1.0 million and $3.1 million were capitalized.

The Company re-acquired a 40% working interest in the Dagang oil project in February of 2006 (See Note 13). The total purchase price was $28.3 million and has been included in China’s proved properties as at September 30, 2006.

The Company sold its interest in certain California properties for $5.4 million with an effective sale date of

February 1, 2006. This sale did not significantly alter the depletion rate, therefore the proceeds were credited to U.S. proved properties with no gain or loss recognized.

As at September 30, 2006 and December 31, 2005, HTL investments included $11.4 million and $9.6 million of costs associated with the RTP^TM Technology commercial demonstration facility (“RTP^TM CDF”) located on Aera Energy LLC’s (“Aera”) property in California’s San Joaquin Basin.

The RTP^TM CDF was in a commissioning phase as at December 31, 2005 and, as such, had not been depreciated, nor impaired, as at December 31, 2005. The commissioning phase ended in January 2006 and the RTP^TM CDF was placed into service. There was no revenue associated with the RTP^TM CDF operations for the three-month and nine-month periods ended September 30, 2006 and 2005. For the three-month and nine-month periods ended September 30, 2006, $0.4 million and $3.3 million of depreciation were recorded for the RTP^TM CDF. Depreciation of the RTP^TM 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 RTP^TM 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.

4. INTANGIBLE ASSETS — TECHNOLOGY

The Company’s intangible assets consist of the following:

RTP^TM Technology

In the Merger with Ensyn, the Company acquired an exclusive, irrevocable license to deploy, worldwide, the RTP^TM Technology for petroleum applications as well as the exclusive right to deploy RTP^TM Technology in all applications other than biomass. The carrying value of the RTP^TM Technology as at September 30, 2006 and December 31, 2005 was $92.2 million and $92.1 million.

Syntroleum Master License

The Company owns a master license from Syntroleum Corporation (“Syntroleum”) permitting the Company to use Syntroleum’s proprietary GTL process in an unlimited number of projects around the world. The Company’s master license expires on the later of April 2015 or five years from the effective date of the last site license issued to the Company by Syntroleum. The Syntroleum GTL process converts natural gas into synthetic liquid hydrocarbons that can be utilized to develop, among other things, clean-burning diesel fuel. The carrying value of the Syntroleum master license as at September 30, 2006 and December 31, 2005 was $10.0 million.

These intangible assets were not amortized and there was no indication of impairment for the three-month and nine-month periods ended September 30, 2006 and 2005.

5. NOTES PAYABLE

Notes payable consisted of the following as at:


	September 30,			December 31,
	2006			2005
Non-interest bearing promissory note, due 2006 through 2009	$	5,951		$	—
Variable rate bank note, 8.375% as at September 30, 2006 and 7.375% as at December 31, 2005, due 2006 though 2007		1,389			2,639
8% promissory note, due 2007		—			4,000

		7,340			6,639


Less:
Unamortized discount		(557	)		—
Current maturities		(3,493	)		(1,667	)

		(4,050	)		(1,667	)

	$	3,290		$	4,972

Promissory Notes

In February 2006, the Company re-acquired the 40% working interest in the Dagang oil project not already owned by the Company. Part of the consideration was the issuance by the Company of a non-interest bearing, unsecured promissory note in the principal amount of approximately $7.4 million ($6.5 million after being discounted to net present value). The note is payable in 36 equal monthly installments commencing March 31, 2006 (See Note 13).

As at December 31, 2004, the Company had a $6.0 million stand-by loan facility. In February 2005, the Company borrowed the full amount available under this stand-by loan facility and amended the loan agreement to provide the lender with the right to convert, at the lender’s election, unpaid principal and interest during the loan term into common shares of the Company at $2.25 per share. In May 2005, the Company entered into a second convertible loan agreement with the same lender for $2.0 million which provided the lender the right to convert, at the lender’s election, unpaid principal and interest during the loan term into common shares of the Company at $2.15 per share.

In November 2005, the Company entered into an agreement with the lender of the two convertible loans referred to above to repay $4.0 million of these loans by issuing 2,453,988 common shares of the Company at $1.63 per share and to refinance the residual $4.0 million outstanding with a new $4.0 million promissory note due November 23, 2007 and bearing interest, payable monthly, at a rate of 8% per annum. The previously granted conversion rights attached to the two previously outstanding convertible loans were cancelled and the Company issued to the lender 2,000,000 purchase warrants, each of which entitles the holder to purchase one common share at a price of $2.00 per share until November 2007. This note was repaid in April 2006 (See Note 8).

Bank Note

In February 2003, the Company obtained a bank facility for up to $5.0 million to develop the southern expansion of its South Midway field. The bank facility was fully drawn in July 2004 and repayment of the principal and interest commenced in August 2004 with interest at 0.5% above the bank’s prime rate or 3.0% over the London Inter-Bank Offered rate, at the option of the Company. The principal and interest are repayable, monthly, over a three-year period ending July 2007. The note is secured by all the Company’s rights and interests in the South Midway properties. Subsequent to September 30, 2006 this note was repaid in advance of its scheduled maturity date from the proceeds of the Company’s new credit facility (See Note 14)

The scheduled maturities of the notes payable, excluding unamortized discount, as at September 30, 2006 were as follows:


2006	$	1,032
2007		3,432
2008		2,460
2009		416

	$	7,340

6. ASSET RETIREMENT OBLIGATIONS

The Company provides for the expected costs required to abandon its producing U.S. oil and gas properties and the RTP^TM CDF. The undiscounted amount of expected future cash flows required to settle the Company’s asset retirement obligations for these assets as at September 30, 2006 was estimated at $2.6 million. The liability for the expected future cash flows, as reflected in the financial statements, has been discounted at 5% to 7% and the changes in the Company’s liability for the nine-month period ended September 30, 2006 were as follows:


Balance as at December 31, 2005	$	1,780
Liabilities incurred		136
Liabilities transferred		(42	)
Accretion expense		60
Revisions in estimated cash flows		112

Balance as at September 30, 2006	$	2,046

7. COMMITMENTS AND CONTINGENCIES

Zitong Block Exploration Commitment

Under the production-sharing contract for the Zitong block, the Company was obligated to conduct a minimum exploration program during the first three years ending December 1, 2005 (“Phase 1”). The Phase 1 work program included acquiring approximately 300 miles of new seismic lines, reprocessing approximately 1,250 miles of existing seismic and drilling a minimum of approximately 23,000 feet. The Company completed Phase 1 with the exception of drilling approximately 13,800 feet. The first Phase 1 exploration well drilled in 2005 was suspended, having found no commercial quantities of hydrocarbons. Drilling on the second exploration well commenced in October 2006, but it is not expected to be completed and tested by November 30, 2006, the current deadline for completing the Phase 1 exploration program. In September 2006 the Company submitted a letter to PetroChina requesting that a further extension be granted to the Phase 1 exploration program, to a date 90 days following the completion of testing of the second well. Testing is estimated to be completed in April 2007. PetroChina replied to the letter and asked for further documentation regarding the adjustment to the work schedule. The Company has submitted this data, has received preliminary approval of the revised timetable and is awaiting PetroChina’s formal approval of the extension.

In January 2006, the Company farmed-out 10% of its working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan (“Mitsubishi”) for $4.0 million subject to the approval of China National Petroleum Corporation (“CNPC”) and PetroChina. The farm-out agreement became effective when this approval was obtained in May 2006 and the advance by Mitsubishi of the $4.0 million dollar farm-in payment to drill the second exploration well was received. Mitsubishi has the option to increase its participating interest to 20% by paying $0.4 million plus costs per percentage point prior to any discovery, or $8.0 million plus costs for an additional 10% interest after completion and testing of the first well drilled under the farm-out agreement. The Company and Mitsubishi (the “Zitong Partners”) will await the results of the second exploration well (see above) after which a decision will be made whether or not to enter into the next three-year exploration phase (“Phase 2”). The $4.0 million advance from Mitsubishi will be used to pay for the well and the unspent balance of the advance in the amount of $2.2 million is recorded as project advance from partner as at September 30, 2006. If the Company elects not to enter into Phase 2, it will be required to pay CNPC, within 30 days after its election, a cash equivalent of its share of the deficiency in the work program estimated to be $0.3 million after the drilling of the second Phase 1 well. If the Company elects not to enter Phase 2, costs related to the Zitong block in the approximate amount of $5.7 million will be required to be included in the depletable base of the China full cost pool. This may result in a ceiling test impairment related to the China full cost pool in a future period.

If the Zitong Partners elect to participate in Phase 2, they must complete a minimum work program involving the acquisition of approximately 200 miles of new seismic lines and approximately 23,000 feet of drilling, with estimated minimum expenditures for the program of $16 million. Following the completion of Phase 2, the Zitong Partners must relinquish all of the property except any areas identified for development and production. If the Zitong Partners elect to enter into Phase 2, they must complete the minimum work program or will be obligated to pay to CNPC the cash equivalent of the deficiency in the work program for that exploration phase.

Long Term Obligation

As part of the Merger with Ensyn, the Company assumed an obligation to pay $1.9 million in the event, and at such time that, the sale of units incorporating the RTP^TM Technology for petroleum applications reach a total of $100.0 million. This obligation has been recorded in the Company’s consolidated balance sheet.

Other Commitments

As part of the Merger with Ensyn, the Company assumed an obligation to advance to a former affiliate of Ensyn (the “Former Ensyn Affiliate”) up to approximately $0.4 million if the Former Ensyn Affiliate cannot meet certain debt servicing ratios required under a Canadian municipal government loan agreement. The principal amount of this loan is repayable in nine equal annual installments commencing April 1, 2006 and ending April 1, 2014. The parent corporation of the Former Ensyn Affiliate has agreed to indemnify the Company for any amounts advanced to the Former Ensyn Affiliate under the loan agreement.

The Company may provide indemnifications, in the course of normal operations, that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid. The Company’s management is of the opinion that any resulting settlements relating to potential litigation matters or indemnifications would not materially affect the financial position of the Company.

8. SHARE CAPITAL

Following is a summary of the changes in share capital and stock options outstanding for the nine-month period ended September 30, 2006:


	Common Shares							Stock Options
											Weighted
											Average
											Exercise
	Number				Contributed			Number			Price
	(thousands)		Amount		Surplus			(thousands)			Cdn.$
Balance December 31, 2005		220,779	$	291,088	$	3,820			10,278		$	2.21
Shares issued for:
Acquisition of oil and gas assets		8,592		20,000		—			—			—
Private placements, net of share issue costs		11,400		6,493		—			—			—
Services		148		401		—			—			—
Exercise of options		277		710		(239	)		(277	)	$	2.09
Options:
Granted		—		—		—			3,200		$	3.12
Expired		—		—		—			(592	)	$	3.42
Stock based compensation		—		—		2,174			—			—

Balance September 30, 2006		241,196	$	318,692	$	5,755			12,609		$	2.39

Purchase Warrants

The following reflects the changes in the Company’s purchase warrants and common shares issuable upon the exercise of the purchase warrants for the nine-month period ended September 30, 2006:


				Common
	Purchase			Shares
	Warrants			Issuable
	(thousands)
Balance December 31, 2005		25,469			21,883
Purchase warrants expired		(7,173	)		(3,587	)
Private placements		11,400			11,400

Balance September 30, 2006		29,696			29,696

On April 7, 2006, the Company closed a special warrant financing by way of private placement for $25.4 million. The financing consisted of 11,400,000 special warrants issued for cash at $2.23 per special warrant. 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 entitles the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing.

A portion of the proceeds of the financing, in the amount of $4.0 million, has been used to pay down long term debt.

As at September 30, 2006, the following purchase warrants were exercisable to purchase common shares of the Company until the expiry date at the price per share as indicated below:


			Purchase Warrants
	Price per						Common					Exercise
Year of	Special						Shares					Price per
Issue	Warrant		Issued		Exercisable		Issuable		Value		Expiry Date	Share
			(thousands)						($U.S. 000)
2005		Cdn. $3.10		4,100		4,100		4,100	$	2,412	April 2007		Cdn. $3.50
2005		Cdn. $3.10		1,000		1,000		1,000		534	July 2007	Cdn. $3.50
2005		U.S. $1.63		11,196		11,196		11,196		1,891	November 2007		U.S. $2.50
2005		n/a		2,000		2,000		2,000		313	November 2007		U.S. $2.00
2006		U.S.$2.23		11,400		11,400		11,400		18,805	May 2011		U.S. $2.63

				29,696		29,696		29,696		23,955

The weighted average exercise price of the exercisable purchase warrants, as at September 30, 2006 was U.S. $2.63 per share.

The Company calculated a value of $18.8 million for the purchase warrants issued in 2006. This value was calculated in accordance with the Black-Scholes (“B-S”) pricing model using a weighted average risk-free interest rate of 4.4%, a dividend yield of 0.0%, a weighted average volatility factor of 75.26% and an expected life of 5 years.

9. STOCK BASED COMPENSATION

The Company accounts for all stock options granted using the fair value based method of accounting. This method was adopted effective January 1, 2004 for stock options granted to employees and directors after January 1, 2002. Under this method, compensation costs are recognized in the financial statements over the stock options’ vesting period using an option-pricing model for determining the fair value of the stock options at the grant date.

For the three-month and nine-month periods ended September 30, 2006, the Company expensed $1.1 million and $2.2 million in stock based compensation. During those same periods in 2005, $0.6 million and $1.4 million were expensed.

10. PROVISION FOR IMPAIRMENT

On March 25, 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 (the “Windfall 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 amounts paid for the Windfall Levy are included with operating expenses in the accompanying statements of operations. The Company understands that the Windfall Levy will be deductible for corporate income tax purposes in the PRC and will not be eligible for cost recovery under the Company’s production sharing contract with CNPC in respect of the Dagang project. In addition, we evaluate the carrying value of our oil and gas properties for impairment and recognize any impairment on a quarterly basis. The imposition of the Windfall Levy resulted in an impairment of the Company’s oil and gas properties of nil and $0.8 million for the three-month and nine-month periods ended September 30, 2006.

11. SEGMENT INFORMATION

The Company has three reportable business segments: Oil and Gas, HTL and GTL.

Oil and Gas

The Company explores for, develops and produces crude oil and natural gas in the U.S. and in China. The Company seeks projects requiring relatively low initial capital outlays to which it can apply innovative technology and enhanced recovery techniques in developing them. In the U.S., the Company’s exploration, development and production activities are primarily conducted in California and Texas. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and exploration activities in the Zitong block located in Sichuan Province.

HTL

A second and more significant segment is to increase the Company’s oil reserves through the deployment of our RTP^TM Technology. The technology can be used to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude. In addition, an RTP^TM facility can yield surplus energy for producing steam and electricity used in heavy-oil production. The thermal energy from the RTP^TM process provides heavy-oil producers with an alternative to natural gas that now is widely used to generate steam.

GTL

The Company holds a master license from Syntroleum to use its proprietary GTL technology to convert natural gas into synthetic fuels. The master license allows the Company to use Syntroleum’s proprietary process in an unlimited number of GTL projects throughout the world to convert natural gas into an unlimited volume of ultra clean transportation fuels and other synthetic petroleum products.

Corporate

The Company’s corporate office is in Canada with its operational office in the U.S. For this note, any amounts for the corporate office in Canada are included in Corporate.

The following tables present the Company’s interim segment information for the three-month and nine-month periods ended September 30, 2006 and 2005 and identifiable assets as at September 30, 2006 and December 31, 2005:


	Three-Month Period Ended September 30, 2006
	Oil and Gas
	U.S.		China			HTL			GTL			Corporate			Total

Oil and gas revenue	$	3,396	$	10,349		$	—		$	—		$	—		$	13,745
Interest income		46		27			—			—			197			270

		3,442		10,376			—			—			197			14,015


Operating costs		976		3,748			—			—			—			4,724
General and administrative		431		359			—			—			2,131			2,921
Business and product development		—		—			1,657			382			4			2,043
Depletion and depreciation		1,445		5,910			413			3			1			7,772
Interest expense and financing costs		60		35			—			—			116			211
Write off of deferred acquisition costs		—		732			—			—			—			732

		2,912		10,784			2,070			385			2,252			18,403


Net Income (Loss)	$	530	$	(408	)	$	(2,070	)	$	(385	)	$	(2,055	)	$	(4,388	)


Capital Investments	$	2,929	$	1,630		$	393		$	67		$	—		$	5,019


	Nine-Month Period Ended September 30, 2006
	Oil and Gas
	U.S.		China			HTL			GTL			Corporate			Total
Oil and gas revenue	$	9,455	$	26,930		$	—		$	—		$	—		$	36,385
Interest income		112		42			—			—			424			578

		9,567		26,972			—			—			424			36,963


Operating costs		3,092		8,206			—			—			—			11,298
General and administrative		1,353		1,038			—			—			5,257			7,648
Business and product development		—		—			4,004			1,151			4			5,159
Depletion and depreciation		3,906		17,573			3,317			8			4			24,808
Interest expense and financing costs		189		141			3			—			404			737
Write off of deferred acquisition costs		—		732			—			—			—			732
Write-downs and provision for impairment		—		750			—			—			—			750

		8,540		28,440			7,324			1,159			5,669			51,132


Net Income (Loss)	$	1,027	$	(1,468	)	$	(7,324	)	$	(1,159	)	$	(5,245	)	$	(14,169	)


Capital Investments	$	4,982	$	6,292		$	1,909		$	439		$	—		$	13,622


Identifiable Assets (As at September 30, 2006)	$	43,296	$	84,036		$	106,997		$	15,038		$	14,875		$	264,242


Identifiable Assets (As at December 31, 2005)	$	48,070	$	65,020		$	107,869		$	14,609		$	5,309		$	240,877


	Three-Month Period Ended September 30, 2005
	Oil and Gas
	U.S.		China			HTL			GTL			Corporate			Total
Oil and gas revenue	$	4,336	$	4,547		$	—		$	—		$	—		$	8,883
Interest income		8		3			—			—			13			24

		4,344		4,550			—			—			13			8,907


Operating costs		1,180		551			—			—			—			1,731
General and administrative		210		1,050			—			—			1,151			2,411
Business and product development		—		—			1,208			296			—			1,504
Depletion and depreciation		1,286		3,185			1			3			1			4,476
Interest expense and financing costs		79		—			2			—			460			541
Write down and provision for impairment		—		—			357			—			—			357

		2,755		4,786			1,568			299			1,612			11,020


Net Income (Loss)	$	1,589	$	(236	)	$	(1,568	)	$	(299	)	$	(1,599	)	$	(2,113	)


Capital Investments	$	2,789	$	5,860		$	894		$	246		$	—		$	9,789


	Nine-Month Period Ended September 30, 2005
	Oil and Gas
	U.S.		China		HTL			GTL			Corporate			Total
Oil and gas revenue	$	10,500	$	10,693	$	—		$	—		$	—		$	21,193
Interest income		18		6		—			—			71			95

		10,518		10,699		—			—			71			21,288


Operating costs		3,448		1,816		—			—			—			5,264
General and administrative		624		1,412		—			—			4,292			6,328
Business and product development		—		—		2,382			1,019			—			3,401
Depletion and depreciation		3,768		5,457		12			8			5			9,250
Interest expense and financing costs		233		—		2			—			801			1,036
Write down and provision for impairment		—		—		357			279			—			636

		8,073		8,685		2,753			1,306			5,098			25,915


Net Income (Loss)	$	2,445	$	2,014	$	(2,753	)	$	(1,306	)	$	(5,027	)	$	(4,627	)


Capital Investments	$	5,309	$	24,120	$	3,738		$	977		$	—		$	34,144

12. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information for the three-month and nine-month periods ended September 30:


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Cash paid during the period for:
Income taxes	$	—		$	13		$	6		$	17

Interest	$	73		$	107		$	371		$	372


Investing and Financing activities, non-cash:
Acquisition of oil and gas assets (see note 13)
Shares issued	$	—		$	—		$	20,000		$	—
Debt issued		—			—			6,547			—
Receivable applied to acquisition		—			—			1,746			—

	$	—		$	—		$	28,293		$	—

Shares issued for Merger (see note 13)	$	—		$	75,000		$	—		$	75,000


Changes in non-cash working capital items
Operating Activities:
Accounts receivable	$	(1,130	)	$	(2,830	)	$	(2,986	)	$	(3,144	)
Prepaid and other current assets		26			101			(71	)		56
Accounts payable and accrued liabilities		1,383			1,058			(543	)		673

		279			(1,671	)		(3,600	)		(2,415	)

Investing Activities
Accounts receivable		(49	)		804			2,163			999
Prepaid and other current assets		(16	)		158			28			508
Accounts payable and accrued liabilities		(4,177	)		402			(12,462	)		9,769
Project advance from partner		(1,064	)		—			2,186			—

		(5,306	)		1,364			(8,085	)		11,276

	$	(5,027	)	$	(307	)	$	(11,685	)	$	8,861

13. MERGER AND ACQUISITIONS

On April 15, 2005, the Company and Ensyn completed the Merger (as more fully described in the Company’s 2005 Annual Report filed on Form 10-K) in which the Company paid $10.0 million in cash and issued approximately 30 million common shares of the Company (“Merger Shares”) in exchange for all of the issued and outstanding Ensyn common shares. Ten million of the Merger Shares issued were deposited in an escrow fund and are being held to secure certain obligations on the part of the former Ensyn stockholders to indemnify the Company for damages in the event of any breaches of representations, warranties and covenants in the Merger Agreement and certain liabilities, including those arising from any failure by Ensyn to meet certain development milestones set out in the Merger Agreement. Subject to any prior claims by the Company for indemnification, one-half of the Merger Shares in this escrow fund will be released to the Ensyn shareholders as of (i) the date that the Company, Ensyn or any of their respective controlled affiliate enters into a definitive agreement with an unaffiliated third party for the construction or use of a process plant equipped with RTP^TM Technology and having a minimum daily input processing capacity of 10,000 Bop/d (an “RTP^TM Plant”) or (ii) the second anniversary of the closing date of the Merger, whichever is earlier. The balance of the Merger Shares will be released, subject to any prior claims by the Company for indemnification, as of (i) the date that the Company, Ensyn or any of their respective controlled affiliates enters into a second definitive agreement for the construction or use of an RTP^TM Plant, (ii) the second anniversary of the date of the initial definitive agreement for the construction or use of any RTP^TM Plant, or (iii) the third anniversary of the closing date of the Merger, whichever is earliest.

The January 2004 Dagang field farm-out agreement between the Company and Richfirst Holdings Limited (“Richfirst”), provided Richfirst with the right to exchange its working interest in the Dagang field for common

shares of the Company at any time prior to eighteen months after the closing of the farm-out transaction contemplated by the agreement. Richfirst elected to exchange its 40% working interest in the Dagang field and, in February 2006, the Company re-acquired Richfirst’s 40% working interest for total consideration of $28.3 million consisting of $20.0 million paid by way of the issuance to Richfirst of 8,591,434 common shares of the Company, a non-interest bearing, unsecured promissory note in the principal amount approximately $7.4 million ($6.5 million after being discounted to net present value) and the forgiveness of $1.8 million of unpaid joint venture receivables. The promissory note is payable in 36 equal monthly installments commencing March 31, 2006. The Company has the right, during the three-year loan repayment period, to require Richfirst to convert the remaining unpaid balance of the promissory note into common shares of Sunwing Energy Ltd (“Sunwing”), the Company’s wholly-owned subsidiary, or another company owning all of the outstanding shares of Sunwing, subject to Sunwing or the other company having obtained a listing of its common shares on a prescribed stock exchange. The number of shares issued would be determined by dividing the then outstanding principal balance under the promissory note by the issue price of shares of the newly listed company issued in the transaction that results in the listing, less a 10% discount.

In February 2006, the Company signed a non-binding memorandum of understanding regarding a proposed merger of Sunwing with China Mineral Acquisition Corporation (“CMA”), a U.S. public corporation. In May 2006 the parties entered a definitive agreement for the transaction. If the transaction had been competed, CMA would have effectively acquired all of the issued and outstanding shares of Sunwing for a deemed estimated value of $100 million subject to working capital and long-term debt adjustments at closing and the Company would have received common stock of CMA representing a substantial majority of the issued and outstanding shares of CMA after the merger. The transaction was expected to be accounted for as a reverse acquisition. CMA’s bylaws stipulated that if the transaction was not completed by August 31, 2006 CMA would be required to dissolve and distribute its assets (substantially all of which was cash) to its shareholders. CMA requested, but was unable to obtain, an extension of this deadline from its shareholders. Insofar as the transaction could not be completed by the August 31 deadline, the definitive agreement was terminated. As a result, the Company wrote off deferred acquisition costs previously capitalized in the amount of $0.7 million.

14. SUBSEQUENT EVENTS

In October 2006 the Company appointed LaSalle Bank N.A. its lead corporate bank for its business transactions worldwide. LaSalle’s parent company is Netherlands-based ABN AMRO N.V. As an initial step, the Company has obtained a $15 million Senior Secured Revolving/Term Credit Facility with an initial borrower base of $8 million. The facility is for two years, the first 18 months in the form of a revolver and at the end of 18 months, the then outstanding amount will convert into a six-month amortizing loan. Depending on the drawn amount, interest, at the Company’s option, will be either at 1.75% to 2.25%, above the bank’s base rate or 2.75% to 3.25% over LIBOR. The loan terms include the requirement for the Company to enter two-year hedging contracts covering approximately 75% of the Company's estimated production from its South Midway property in California. The facility will be available for the development of oil and gas properties, general corporate purposes and for the commencement of engineering of HTL commercial activities.

In October 2006 the Company reached an agreement to sell its interest in the LAK Ranch Project to Derek Oil & Gas for $800,000, comprised of cash of $600,000 due at closing and a maximum of $200,000 to be paid through a 5% gross overriding interest on future production from the project. The agreement is subject to the completion of definitive documentation.

15. ADDITIONAL DISCLOSURE REQUIRED UNDER U.S. GAAP

The Company’s consolidated financial statements have been prepared in accordance with GAAP as applied in Canada. In the case of the Company, Canadian GAAP conforms in all material respects with U.S. GAAP except for certain matters, the details of which are as follows:

Condensed Consolidated Balance Sheets

Shareholders’ Equity and Oil and Gas Properties and Investments


	As at September 30, 2006
	Oil and Gas			Shareholders’ Equity
	Properties and			Share Capital			Contributed			Accumulated
	Investments			and Warrants			Surplus			Deficit			Total
Canadian GAAP	$	130,878		$	342,647		$	5,755		$	(109,460	)	$	238,942
Adjustments for:
Reduction in stated capital (i)		—			74,455			—			(74,455	)		—
Accounting for stock based compensation (ii)		—			(373	)		(3,375	)		3,748			—
Ascribed value of shares issued for U.S. royalty interests, net (iii)		1,358			1,358			—			—			1,358
Provision for impairment (iv)		(18,170	)		—			—			(18,170	)		(18,170	)
Depletion adjustments due to differences in provision for impairment (v)		3,471			—			—			3,471			3,471
HTL and GTL development costs expensed (vi)		(11,643	)		—			—			(11,643	)		(11,643	)

U.S. GAAP	$	105,894		$	418,087		$	2,380		$	(206,509	)	$	213,958


	As at December 31, 2005
	Oil and Gas			Shareholders’ Equity
	Properties and			Share Capital			Contributed			Accumulated
	Investments			and Warrants			Surplus			Deficit			Total
Canadian GAAP	$	119,654		$	296,238		$	3,820		$	(95,291	)	$	204,767
Adjustments for:
Reduction in stated capital (i)		—			74,455			—			(74,455	)		—
Accounting for stock based compensation (ii)		—			(316	)		(3,432	)		3,748			—
Ascribed value of shares issued for U.S. royalty interests, net (iii)		1,358			1,358			—			—			1,358
Provision for impairment (iv)		(8,150	)		—			—			(8,150	)		(8,150	)
Depletion adjustments due to differences in provision for impairment (v)		1,562			—			—			1,562			1,562
HTL and GTL development costs expensed (vi)		(10,712	)		—			—			(10,712	)		(10,712	)

U.S. GAAP	$	103,712		$	371,735		$	388		$	(183,298	)	$	188,825

Shareholders’ Equity

(i) In June 1999, the shareholders approved a reduction of stated capital in respect of the common shares by an amount of $74.5 million being equal to the accumulated deficit as at December 31, 1998. Under U.S. GAAP, a reduction of the accumulated deficit such as this is not recognized except in the case of a quasi reorganization. The effect of this is that under U.S. GAAP, share capital and accumulated deficit are increased by $74.5 million as at September 30, 2006 and December 31, 2005.

(ii) For Canadian GAAP, the Company accounts for all stock options granted to employees and directors since January 1, 2002 using the fair value based method of accounting. Under this method, compensation costs are recognized in the financial statements over the stock options’ vesting period using an option-pricing model for determining the fair value of the stock options at the grant date. For U.S. GAAP, prior to January 1, 2006 the Company applied APB Opinion No. 25, as interpreted by FASB Interpretation No. 44, in accounting for its stock option plan and did not recognize compensation costs in its financial statements for stock options issued to employees and directors. This resulted in a reduction of $3.7 million in the accumulated deficit as at September 30, 2006, and December 31, 2005, equal to accumulated stock based compensation for stock options granted to employees and directors since January 1, 2002 and expensed through December 31, 2005 under Canadian GAAP.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued a revision to SFAS No. 123, “Accounting for Stock Based Compensation” which supersedes APB No. 25, “Accounting for Stock Issued to Employees”. This statement (“SFAS No. 123(R)”) requires measurement of the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant and recognition of the cost in the results of operations over the period during which an employee is required to provide service in exchange for the award. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. The Company elected to implement this statement on a modified prospective basis starting in the first quarter of 2006. Under the modified prospective basis the Company began recognizing stock based compensation in its U.S. GAAP results of operations for the unvested portion of awards outstanding as at January 1, 2006 and for all awards granted after January 1, 2006. There were no differences in the Company’s stock based compensation expense in its financial statements for Canadian GAAP and U.S. GAAP for the three-month and nine-month periods ended September 30, 2006.

Oil and Gas Properties and Investments

(iii) For U.S. GAAP purposes, the aggregate value attributed to the acquisition of U.S. royalty rights during 1999 and 2000 was $1.4 million higher, due to the difference between Canadian and U.S. GAAP in the value ascribed to the shares issued, primarily resulting from differences in the recognition of effective dates of the transactions.

(iv) As more fully described in our financial statements in Item 8 of our 2005 Annual Report filed on Form 10-K, there are differences between the full cost method of accounting for oil and gas properties as applied in Canada and as applied in the U.S. The principal difference is in the method of performing ceiling test evaluations under the full cost method of accounting rules. The Company performed the ceiling test in accordance with U.S. GAAP and determined that for the three-months and nine-months ended September 30, 2006 an impairment provision of $3.6 million and $10.8 million was required compared to nil and a $0.8 million impairment provision under Canadian GAAP for those same periods. The differences in the ceiling test impairments by period for the U.S. and China properties between U.S. and Canadian GAAP as at September 30, 2006 were as follows:


	Ceiling Test Impairments				(Increase)
	U.S. GAAP		Canadian GAAP		Decrease
U.S. Properties
Prior to 2004	$	34,000	$	34,000	$	—
2004		15,000		16,350		1,350
2005		2,800		—		(2,800	)
2006		3,100		—		(3,100	)

		54,900		50,350		(4,550	)

China Properties
Prior to 2004		10,000		—		(10,000	)
2004		—		—		—
2005		1,700		5,000		3,300
2006		7,670		750		(6,920	)

		19,370		5,750		(13,620	)

	$	74,270	$	56,100	$	(18,170	)

(v) The differences in the amount of impairment provisions between U.S. and Canadian GAAP resulted in a reduction in accumulated depletion of $3.5 million and $1.6 million as at September 30, 2006 and December 31, 2005.

(vi) As more fully described in our financial statements in Item 8 of our 2005 Annual Report filed on Form 10-K, for Canadian GAAP, the Company capitalizes certain costs incurred for HTL and GTL projects subsequent to executing a memorandum of understanding to determine the technical and commercial feasibility of a project, including studies for the marketability for the projects’ products. If no definitive agreement is reached, then the project’s capitalized costs, which are deemed to have no future value, are written down and charged to the results

of operations with a corresponding reduction in the investments in HTL and GTL assets. For U.S. GAAP, feasibility, marketing and related costs incurred prior to executing an HTL or GTL definitive agreement are considered to be research and development and are expensed as incurred. As at September 30, 2006 and December 31, 2005, the Company capitalized $11.7 million and $10.7 million for Canadian GAAP, which was expensed for U.S. GAAP purposes.

Condensed Consolidated Statements of Operations

The application of U.S. GAAP had the following effects on net loss and net loss per share as reported under Canadian GAAP:


	Three-Month Periods Ended September 30,
	2006						2005
	Net			Net Loss			Net			Net Loss
	Loss			Per Share			Loss			Per Share
Canadian GAAP	$	(4,388	)	$	(0.02	)	$	(2,113	)	$	(0.01	)
Stock based compensation expense (vii)		—			—			540			—
Provision for impairment (iv and viii)		(3,570	)		(0.01	)		—			—
Depletion adjustments due to differences in provision for impairment (viii)		887			—			418			—
HTL and GTL development costs expensed, net (ix)		(46	)		—			(688	)		—

U.S. GAAP	$	(7,117	)	$	(0.03	)	$	(1,843	)	$	(0.01	)


Weighted Average Number of Shares under U.S. GAAP (in thousands)					241,181						206,629


	Nine Month Periods Ended September 30,
	2006						2005
	Net			Net Loss			Net			Net Loss
	Loss			Per Share			Loss			Per Share
Canadian GAAP	$	(14,169	)	$	(0.06	)	$	(4,627	)	$	(0.02	)
Stock based compensation expense (vii)		—			—			1,338			0.01
Provision for impairment (iv and viii)		(10,020	)		(0.04	)		—			—
Depletion adjustments due to differences in provision for impairment (viii)		1,909			—			846			—
HTL and GTL development costs expensed, net (ix)		(931	)		—			(3,972	)		(0.02	)

U.S. GAAP	$	(23,211	)	$	(0.10	)	$	(6,415	)	$	(0.03	)


Weighted Average Number of Shares under U.S. GAAP (in thousands)					233,766						191,374

(vii) As discussed under “Shareholders’ Equity” in this note, for U.S. GAAP, the Company applied APB Opinion No. 25, as interpreted by FASB Interpretation No. 44, in accounting for its stock option plan and did not recognize compensation costs in its financial statements for stock options issued to employees and directors prior to January 1, 2006. This resulted in a reduction of $0.5 million and $1.3 million in the net loss for the three-month and nine-month periods ended September 30, 2005. Also, discussed under “Shareholders’ Equity” in this note, for U.S. GAAP, the Company implemented SFAS 123(R) on January 1, 2006 which resulted in no differences in stock based compensation expense for the three-month and nine-month periods ended September 30, 2006.

(viii) As discussed under “Oil and Gas Properties and Investments” in this note, there is a difference in performing the ceiling test evaluation under the full cost method of the accounting rules between U.S. and Canadian GAAP. Application of the ceiling test evaluation under U.S. GAAP has resulted in an accumulated net increase in impairment provisions on the Company’s U.S. and China oil and gas properties of $18.2 million as at September 30, 2006. This net increase in U.S. GAAP impairment provisions has resulted in lower depletion rates for U.S. GAAP purposes and a reduction of $0.9 million and $1.9 million in the net losses for the three-month and

nine-month periods ended September 30, 2006 and a reduction of $0.4 million and $0.8 million in the net losses for the three-month an nine-month periods ended September 30, 2005.

(ix) As more fully described under “Oil and Gas Properties and Investments” in this note, for Canadian GAAP, feasibility, marketing and related costs incurred prior to executing an HTL or GTL definitive agreement are capitalized and are subsequently written down upon determination that a project’s future value has been impaired. For U.S. GAAP, such costs are considered to be research and development and are expensed as incurred. For the three-month and nine-month periods ended September 30, 2006 the Company expensed nil and $0.9 million and expensed $0.7 million and $4.0 million for those same periods in 2005 in excess of the Canadian GAAP write-downs during those corresponding periods.

Stock Based Compensation

The Company has an Employees’ and Directors’ Equity Incentive Plan under which it can grant stock options to directors and eligible employees to purchase common shares, issue common shares to directors and eligible employees for bonus awards and issue shares under a share purchase plan for eligible employees. The total shares under this plan cannot exceed 20 million.

Stock options are issued at not less than the fair market value on the date of the grant and are conditional on continuing employment. Expiration and vesting periods are set at the discretion of the Board of Directors. Stock options granted prior to March 1, 1999 vested over a two-year period and expire ten years from date of issue. Stock options granted after March 1, 1999 generally vest over four years and expire five to ten years from the date of issue.

The fair value of each option award is estimated on the date of grant using the B-S option-pricing formula and amortized on a straight-line attribution approach with the following weighted-average assumptions for the nine-month period ended September 30, 2006:


Expected term (in years)	4.00
Volatility	81.96	%
Dividend Yield	0.00	%
Risk-free rate	4.21	%

The Company’s expected term represents the period that the Company’s stock-based awards are expected to be outstanding and was determined based on historical experience of similar awards, giving consideration to the contractual terms of the stock-based awards, vesting schedules and expectations of future employee behavior as influenced by changes to the terms of its stock-based awards. The fair value of stock-based payments were valued using the B-S valuation method with an expected volatility factor based on the Company’s historical stock prices. The B-S valuation model calls for a single expected dividend yield as an input. The Company has not paid and does not anticipate paying any dividends in the near future. The Company bases the risk-free interest rate used in the B-S valuation method on the implied yield currently available on Canadian zero-coupon issue bonds with an equivalent remaining term. When estimating forfeitures, the Company considers historical voluntary termination behavior as well as future expectations of workforce reductions. The estimated forfeiture rate as at September 30, 2006 is 22.3%. The Company recognizes compensation costs only for those equity awards expected to vest.

The summary of option activity as at September 30, 2006, and changes during the nine-month period then ended is presented below:


				Weighted-		Weighted-
	Number			Average		Average		Aggregate
	of Stock			Exercise		Contractual		Intrinsic
	Options			Price		Term		Value
								(Cdn.$ in
	(thousands)			(Cdn.$)				thousands)
Outstanding at December 31, 2005		10,278		$	2.21
Granted		3,200		$	3.12
Exercised		(277	)	$	2.09
Cancelled/forfeited		(592	)	$	3.42

Outstanding at September 30, 2006		12,609		$	2.39		3.4	$	4,277


Options exercisable at September 30, 2006		7,792		$	1.91		2.5	$	4,277

The total intrinsic value of options exercised during the nine-month period ended September 30, 2006 was $0.2 million.

A summary of the Company’s unvested options as at September 30, 2006, and changes during the nine-month period ended September 30, 2006, is presented below:


				Weighted-
	Number			Average
	of Stock			Grant Date
	Options			Fair Value
	(thousands)			(Cdn.$)
Outstanding at December 31, 2005		3,731		$	1.47
Granted		3,200		$	1.44
Vested		(1,835	)	$	1.12
Cancelled/forfeited		(279	)	$	1.22

Outstanding at September 30, 2006		4,817		$	1.53

As at September 30, 2006, there was $5.8 million of total unrecognized compensation costs related to unvested share-based compensation arrangements granted by the Company. That cost is expected to be recognized over a weighted-average period of 1.9 years. The total fair value of shares vested during the nine-month period ended September 30, 2006 was $2.5 million.

Had stock based compensation expense been determined based on fair value at the stock option grant date, consistent with the method of SFAS No. 123 prior to January 1, 2006 the Company’s net loss and net loss per share would have been increased to the pro forma amounts indicated below:


For the three-month period ended September 30, 2005:
Net loss under U.S. GAAP	$	(1,843	)
Stock-based compensation expense determined under the fair value based method for employee and director awards		(570	)

Pro forma net loss under U.S. GAAP	$	(2,413	)


Basic loss per common share under U.S. GAAP:
As reported	$	(0.01	)
Pro forma	$	(0.01	)

Weighted Average Number of Shares under U.S. GAAP (in thousands)		(206,629	)


For the nine-month period ended September 30, 2005:
Net loss under U.S. GAAP	$	(6,415	)
Stock-based compensation expense determined under the fair value based method for employee and director awards		(1,430	)

Pro forma net loss under U.S. GAAP	$	(7,845	)


Basic loss per common share under U.S. GAAP:
As reported	$	(0.03	)
Pro forma	$	(0.04	)

Weighted Average Number of Shares under U.S. GAAP (in thousands)		(191,374	)

Prior to January 1, 2006 stock based compensation for U.S. GAAP was calculated in accordance with the B-S option-pricing model using the same assumptions as used for Canadian GAAP.

Pro Forma Effect of Merger and Acquisition

The Company’s U.S. GAAP consolidated results of operations for the three-month and nine-month periods ended September 30, 2005 included a net loss of $0.7 million, or nil per share and $1.3 million, or $0.01 per share, associated with the operations acquired from Ensyn after the completion of the Merger on April 15, 2005. Had the Merger been completed on January 1, 2005, the U.S. GAAP pro forma revenue, net loss and net loss per share of the merged entity for the three-month and nine-month periods ended September 30, 2005 would have been as follows:


	Three-Month Period Ended
	September 30, 2005
			Net			Net Loss
	Revenue		Loss			Per Share
As reported	$	8,907	$	(1,843	)	$	(0.01	)
Pro forma adjustments		—		—			—

	$	8,907	$	(1,843	)	$	(0.01	)


Weighted Average Number of Shares (in thousands)							206,629


	Nine-Month Period Ended
	September 30, 2005
			Net			Net Loss
	Revenue		Loss			Per Share
As reported	$	21,288	$	(6,415	)	$	(0.03	)
Pro forma adjustments		736		(730	)		—

	$	22,024	$	(7,145	)	$	(0.03	)


Weighted Average Number of Shares (in thousands)							202,583

Had the acquisition of Richfirst’s 40% working interest in the Dagang field been completed January 1, 2006 or 2005, the U.S. GAAP pro forma revenue, net loss and net loss per share of the consolidated operations for the three-month and nine-month periods ended September 30, 2006 and 2005 would have been as follows:


	Three Months Ended September 30,
	2006								2005
			Net Income			Net Income					Net Income			Net Income
	Revenue		(Loss)			(Loss) Per Share			Revenue		(Loss)			(Loss) Per Share
As reported	$	14,015	$	(7,117	)	$	(0.03	)	$	8,907	$	(1,843	)	$	(0.01	)
Pro forma adjustments		—		—			—			2,786		539			—

	$	14,015	$	(7,117	)	$	(0.03	)	$	11,693	$	(1,304	)	$	(0.01	)


Weighted Average Number of Shares (in thousands)							241,181								215,220


	Nine Months Ended September 30,
	2006								2005
			Net Income			Net Income					Net Income			Net Income
	Revenue		(Loss)			(Loss) Per Share			Revenue		(Loss)			(Loss) Per Share
As reported	$	36,963	$	(23,211	)	$	(0.10	)	$	21,288	$	(6,415	)	$	(0.03	)
Pro forma adjustments		1,051		809			—			6,239		1,364			—

	$	38,014	$	(22,402	)	$	(0.10	)	$	27,527	$	(5,051	)	$	(0.03	)


Weighted Average Number of Shares (in thousands)							235,371								199,965

Condensed Consolidated Statements of Cash Flow

As a result of the write-down of HTL and GTL development costs required under U.S. GAAP, the statements of cash flows as reported would result in a cash surplus from operating activities of $5.6 million and $10.4 million for the three-month and nine-month periods ended September 30, 2006. Cash provided by operating activities would be $1.8 million and $0.6 million for the three-month and nine-month periods ended September 30, 2005. Additionally, capital investments reported under investing activities would be $5.0 million and $12.7 million for the three-month and nine-month periods ended September 30, 2006 and $9.1 million and $29.5 million for the three-month and nine-month periods ended September 30, 2005.

Impact of New and Pending Canadian GAAP Accounting Standards

Commencing with the Company’s 2007 fiscal year, the proposed amended recommendations of the CICA for accounting for business combinations will apply to the Company’s business combinations, if any, with an acquisition date of January 1, 2007, or later. Whether the Company would be materially affected by the proposed amended recommendations would depend upon the specific facts of the business combinations, if any, occurring on or after January1, 2007. Generally, the proposed recommendations will result in measuring business acquisitions at the fair value of the acquired entities and a prospectively applied shift from a parent company conceptual view of consolidation theory (which results in the parent company recording the book values attributable to non-controlling interests) to an entity conceptual view (which results in the parent company recording the fair values attributable to non-controlling interests).

In early 2006, Canada’s Accounting Standards Board ratified a strategic plan that will result in Canadian GAAP, as used by public companies, being converged with International Financial Reporting Standards over a transitional period. During 2006, the Accounting Standards Board is expected to develop and publish a detailed implementation plan with a transition period expected to be approximately five years. As this convergence initiative is very much in its infancy as of the date of these interim consolidated financial statements, it would be premature to currently assess the impact of the initiative, if any, on the Company.

In January 2005, the CICA approved Section 1530 “Comprehensive Income” (“S.1530”), Section 3855 “Financial Instruments – Recognition and Measurement” (“S.3855”) and Section 3865 “Hedges” (“S.3865”) to harmonize, in most respects, financial instrument and hedge accounting with U.S. GAAP and introduce the concept of

comprehensive income. S.1530 requires presentation of certain gains and losses outside of net income, such as unrealized gains and losses related to hedges or other derivative instruments. S.3855 establishes standards for recognizing and measuring financial assets and financial liabilities and non-financial derivatives as required to be disclosed under Section 3861 “Financial Instruments Disclosure and Presentation”, S.3865 establishes standards for how and when hedge accounting may be applied. The Company applies SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” for U.S. GAAP purposes and will implement S.3865 for Canadian GAAP for hedging activities. These sections apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. Earlier adoption will be permitted only as of the beginning of a fiscal year. The impact of implementing these new standards is not yet determinable as it is highly dependent on fair values, outstanding positions and hedging strategies as the time of adoption.

In January 2005, the CICA approved Section 3251 “Equity” which establishes standards for the presentation of equity and changes in equity during a reporting period. This section applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2005 and is not expected to have a material impact on the Company’s financial statements.

Impact of New and Pending U.S. GAAP Accounting Standards

In September 2006, the U.S. Securities and Exchange Commission issued Staff Accounting Bulletin 108 (“SAB 108”). The interpretations in this bulletin express the staff’s views regarding the process of quantifying financial statement misstatements and are being issued to address diversity in practice in quantifying financial statement misstatements and the potential under current practice for the build up of improper amounts on the balance sheet. SAB 108 is not expected to have a material impact on the Company’s financial statements.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement does not require any new fair value measurements, however, for some entities the application of this statement will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, although early adoption is permitted. Management is in the process of reviewing the requirements of this recent statement.

In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”) entitled ‘Accounting for Uncertain Tax Positions’ — an interpretation of SFAS No. 109. The interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. The evaluation of a tax position in accordance with this interpretation is a two-step process. Under the recognition step an enterprise determines whether it is more likely than not that a tax position will be sustained upon examination based on the technical merits of the position. Under the measurement step a tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 is effective for fiscal years beginning after December 15, 2006. Earlier application of the provisions of this interpretation is encouraged if the enterprise has not yet issued financial statements, including interim financial statements, in the period this interpretation is adopted. Management is in the process of reviewing the requirements of this interpretation.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB statements No. 133 and 140” (“SFAS No. 155”). SFAS No. 155 resolves issues surrounding the application of the bifurcation requirements to beneficial interests in securitized financial assets. In general, this statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006 and is not expected to have a material impact on the Company’s financial statements.

On January 25, 2006, the FASB issued an exposure draft entitled ‘The Fair Value Option for Financial Assets and

Financial Liabilities (including an amendment of FASB Statement No. 115)”. The proposed statement would create a fair value option under which an entity may irrevocably elect fair value as the initial and subsequent measurement attribute for certain financial assets and financial liabilities on a contract-by-contract basis, with changes in fair value recognized in earnings as those changes occur. Management is in the process of reviewing the requirements of this recent exposure draft.

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

Forward-Looking Statements

With the exception of historical information, certain matters discussed in this Form 10-Q, including in this Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward looking statements that involve risks and uncertainties. Certain statements contained in this Form 10-Q, including statements which may contain words such as “could”, “propose”, “should”, “intend”, “expect”, “believe”, “will” and similar expressions and statements relating to matters that are not historical facts are forward-looking statements. Forward-looking statements can also include discussions relating to future production associated with our RTP^TM Technology and our Peach and North Yowlumne prospects. Such statements involve known and unknown risks and uncertainties which may cause our actual results, performances or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, our ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of heavy-to–light and gas-to-liquids development technologies, the prices of goods and services, the availability of drilling rigs and other support services, legislative and government regulations, political and economic factors in countries in which we operate and implementation of our capital investment program.

The above items and their possible impact are discussed more fully in the section entitled “Risk Factors” in Item 1 and “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of our 2005 Annual Report on Form 10-K.

The following should be read in conjunction with the Company’s consolidated financial statements contained herein, and the consolidated financial statements, and the Management’s Discussion and Analysis of Financial Condition and Results of Operations, contained in the Form 10-Q for the quarter ended June 30, 2006 and in the Form 10-K for the year ended December 31, 2005. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K. The unaudited condensed consolidated financial statements in this Quarterly Report filed on Form 10-Q have been prepared in accordance with GAAP in Canada. The impact of significant differences between Canadian GAAP and U.S. GAAP on the unaudited condensed consolidated financial statements is disclosed in Note 15.

SPECIAL NOTE TO CANADIAN INVESTORS

The Company is a registrant under the Securities Exchange Act of 1934 and voluntarily files reports with the U.S. Securities and Exchange Commission (“SEC”) on Form 10-K, Form 10-Q and other forms used by registrants that are U.S. domestic issuers. Therefore, our reserves estimates and securities regulatory disclosures generally follow SEC requirements. In 2004, the Canadian Securities Administrators (“CSA”) adopted National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) which prescribes certain standards for the preparation and disclosure of reserves and related information by Canadian issuers. We have been granted certain exemptions from NI 51-101. Please refer to the Special Note to Canadian Investors on page 14 of our 2005 Annual Report on Form 10-K.

Unless we indicate otherwise, all dollar amounts ($) are in U.S. dollars, and oil and gas volumes, reserves and related performance measures are presented on a working-interest, after-royalties basis.

As generally used in the oil and gas business and in this throughout the Form 10-Q, 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 to express these different commodities in a common unit. In calculating Bbl equivalents, 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.

Electronic copies of our filings with the SEC and the CSA are available, free of charge, through our web site (www.ivanhoeenergy.com) or, upon request, by contacting our investor relations department at (604) 688-8323. Alternatively, the SEC and the CSA each maintains a website (www.sec.gov and www.sedar.com) that contains our periodic reports and other public filings with the SEC and the CSA.

Executive Overview of 2006 Results

Ivanhoe Energy is an independent, international energy development and production company focused on pursuing long-term growth in its reserves and production using advanced technologies. In particular, we have sharpened our focus during the past quarter on our heavy oil business activities, including advancing the development of the HTL technology.

Ivanhoe Energy’s proprietary HTL technology, using the patented RTP^TM process, 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 technology has the potential to substantially improve the economics of heavy oil development by addressing the main challenges of heavy oil production in relatively small minimum scale, field-located upgraders: the need for onsite energy, the transportation challenge of heavy oil, and wide heavy-light oil price differentials.

In order to build a substantial reserve base from our technologies, the Company has been working on six fronts:

	1.		*Increased focus of the company’s resources on building an HTL business*. We will continue to shift our people and our financial resources in support of our goal, and we will continue to take corporate actions that demonstrate an ever-increasing focus on the commercialization and implementation of the HTL technology. For example, the sale of LAK Ranch in Wyoming was pursued in part because the field was determined to not be of sufficient size to support an HTL plant.

	2.		*Advancing the technology*. The RTP^TM CDF has been an area of significant focus for us over the past few quarters, but is only one tool in the HTL development program. We have a number of tools available as we move towards the commercial implementation of HTL. Considerable data has also been derived from the operation of the 20-barrel-per-day petroleum pilot plant that was used to complete the original

			petroleum development work, as well as the extensive experience that exists within Ensyn as a result of operating the core technology commercially for over 15 years in the biomass business.

			Additional development work will continue as we advance the technology through the first commercial application and beyond.

	3.		*Advancing our business development to find and reach agreements where our technologies can be used.* Although we are focusing more of our resources on our HTL opportunities, we continue our effort around a GTL project. To accelerate the pace of reaching commercial agreements, we have solicited the expertise of our outstanding Board of Directors to support our business development activities.

	4.		*Enhancing our financial position in anticipation of major projects*. Implementation of large projects requires significant capital outlays. We are refining our financing plans and establishing the relationships required for the development activities ahead. Some of our initial activities have included the $15 million LaSalle facility and revisions to our capital budget for the remainder of 2006 and the development of our 2007 budget.

	5.		*Building the relationships that we will need for the future.* Implementation of our technologies demands close alignment with partners, suppliers, host governments and financiers. The initiatives that we have just announced with AMEC and LaSalle are solid steps in establishing those relationships we need for future success.

	6.		*Building internal capabilities in advance of major projects.* The HTL technical team, which includes our own staff, specialized consultants including the inventors of the technology from Ensyn, and our EOR team will be supplemented and expanded to add additional expertise in areas such as project management. During the third quarter, we added process engineering expertise to our HTL team and have pending agreements with other engineering talent.

A current strategy of the Company is to produce operating cash flows from oil and gas properties in China and the U.S. to help the Company position itself for substantial gains in the commercial application of its technologies, particularly its HTL technology. In the pursuit of that strategy, the exchange of Company shares for the re-acquisition of the 40% working interest in the China Dagang operation completed earlier in the year resulted in a quarterly increase in our China production that, together with price increases, brought quarterly revenues to a level 97% higher than in the same period of 2005. Our cash flow from operations improved significantly to $5.6 million this quarter compared to $2.5 million in the same three month period a year ago, although our net losses increased due to significant increases in depletion and depreciation expense.

The following table sets forth certain selected consolidated data for the three-month and nine-month periods ended September 30, 2006 and 2005:


	Three-Month Periods Ended						Nine-Month Periods Ended
	September 30,						September 30,
(stated in thousands of U.S. dollars, except per share and production amounts)	2006			2005			2006			2005
Oil and gas revenue	$	13,745		$	8,883		$	36,385		$	21,193
Net loss	$	(4,388	)	$	(2,113	)	$	(14,169	)	$	(4,627	)
Net loss per share	$	(0.02	)	$	(0.01	)	$	(0.06	)	$	(0.02	)
Average production (Boe/d)		2,306			1,902			2,192			1,741
Net operating revenue per Boe	$	42.99		$	40.87		$	41.91		$	33.51
Capital investments	$	5,019		$	9,789		$	13,622		$	34,144
Cash flow from operating activities	$	5,643		$	2,524		$	11,345		$	5,189

Financial Results – Change in Net Loss

The following provides an analysis of our changes in net losses for the three-month and nine-month periods ended September 30, 2006 when compared to the same period for 2005:


	Three-Months			Nine-Months
	Ended			Ended
(stated in thousands of U.S. Dollars)	September 30,			September 30,
Net Losses for 2005	$	(2,113	)	$	(4,627	)
				,

Favorable (unfavorable) variances:
Cash Items:
Net Operating Revenues:
Production volumes		2,144			6,527
Oil and gas prices		2,718			8,665
Less: Operating costs		(2,993	)		(6,034	)

		1,869			9,158

General and administrative		(20	)		(703	)
Business and product development		(518	)		(1,625	)
Acquisition costs		(230	)		(732	)
Net interest		690			1,099

Total Cash Variances		1,791			7,197


Non-Cash Items:
Depletion and depreciation		(3,296	)		(15,558	)
Stock based compensation		(511	)		(750	)
Write off of deferred acquisition costs		(502	)		—
Write-downs of HTL and GTL investments		357			636
Impairment of China oil and gas properties		—			(750	)
Other		(114	)		(317	)

Total Non-Cash Variances		(4,066	)		(16,739	)


Net Losses for 2006	$	(4,388	)	$	(14,169	)

Our net loss for the three-month period ended September 30, 2006 was $4.4 million ($0.02 per share) compared to our net loss for the same period in 2005 of $2.1 million ($0.01 per share). The increase in our net loss from 2005 to 2006 of $2.3 million is mainly due to a $3.3 million increase in depletion and depreciation, and a $1.3 million increase in general and administrative, business and product development expenses and CMA related acquisition costs, partially offset by a $1.9 million increase in net operating revenues and a $0.7 million decrease in net interest.

Our net loss for the nine-month period ended September 30, 2006 was $14.2 million ($0.06 per share) compared to our net loss for the same period in 2005 of $4.6 million ($0.02 per share). The increase in our net loss from 2005 to 2006 of $9.6 million is mainly due to a $15.6 million increase in depletion and depreciation, and a $3.1 million increase in general and administrative, business and product development expenses and CMA related acquisition costs, partially offset by a $9.2 million increase in net operating revenues and a $1.1 million decrease in net interest.

Significant variances are explained in the sections that follow.

Net Operating Revenues

The following is a comparison of changes in production volumes for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005:


	Three-Month Periods Ended							Nine-Month Periods Ended
	September 30,							September 30,
	Net Boe’s				Percentage			Net Boe’s				Percentage
	2006		2005		Change			2006		2005		Change
China:
Dagang		147,571		80,799		83	%		414,660		199,320		108	%
Daqing		5,196		6,087		-15	%		17,189		25,935		-34	%

		152,767		86,886		76	%		431,849		225,255		92	%


U.S.:
South Midway		49,901		46,994		6	%		141,113		148,314		-5	%
Spraberry		6,200		7,232		-14	%		18,167		21,496		-15	%
Citrus		212		8,463		-97	%		4,631		26,807		-83	%
Knights Landing		29		24,559		-100	%		175		52,482		-100	%
Others		716		870		-18	%		2,570		880		192	%

		57,058		88,118		-35	%		166,656		249,979		-33	%

		209,825		175,004		20	%		598,505		475,234		26	%

Net production volumes for the three-month period ended September 30, 2006 increased 20% when compared to the same period in 2005 due to a 76% increase in production volumes in our China properties offset by a 35% decrease in our U.S. properties, resulting in increased revenues of $2.1 million. The increase in production volumes for the nine-month period ended September 30, 2006 of 26% was due to a 92% increase in production volumes in our China properties offset by a 33% decrease in our U.S. properties, resulting in increased revenues of $6.5 million.

Oil and gas prices increased 29% and 36% per Boe for the three-month and nine-month periods ended September 30, 2006 generating $2.7 million and $8.7 million in additional revenue as compared to the same periods in 2005.

For the three-month and nine-month periods ended September 30, 2006, operating costs, including production taxes and engineering support, increased 287% and 136% per Boe or $3.0 million and $6.0 million compared to the same periods in 2005.

China

Net production volumes at the Dagang field increased 83% and 108% for the three-month and nine-month periods ended September 30, 2006 compared to the same periods in 2005. As a result of the 2005 development program, oil production volume increased by 10% or by 7.8 Mboe and 31% or 61.2 Mboe for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005. During 2005 we placed 22 new wells on production and fracture stimulated 13 wells in the northern block of this project and in the first nine months of 2006 we completed one well, fracture stimulated 12 wells and re-completed 13 wells. Additionally,

volumes at the Dagang field increased for the three-month and nine-month periods ended September 30, 2006 compared to the same periods in 2005 by 73% or 59.0 Mboe and 77% or 154.1 Mboe due to the re-acquisition of Richfirst’s 40% working interest in this project in February 2006.

Our share of production volumes from the Daqing field decreased 15% and 34% for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005. These decreases were mainly due to our royalty percentage from the Daqing field being reduced from 4% to 2% in May 2005 when the operator of the properties reached payout of its investment.

Operating costs in China increased by $18.19 per Boe and $10.94 per Boe for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005. Field operating costs increased due to higher power costs, increased workover and maintenance costs and increased treatment and processing fees attributable to higher water production rates. With the suspension of our drilling activity at our Dagang field in December 2005, a major portion of our Dagang field office costs, which were previously being capitalized, are now being expensed as part of our operating activities. Engineering support for the three-month period ended September 30, 2006 increased due to a higher allocation of support to production as we reduced our capital activity in the Dagang field during the three-month period ended September 30, 2006 when compared to the same period in 2005. The increase in production volume in 2006 due to the 2005 drilling program at the Dagang field, in relation to the level of support required to operate the field, results in the per Boe decrease for the nine-month period ended September 30, 2006 compared to the same 2005 period. As more fully described in Note 10 to the September 30, 2006 Unaudited Condensed Consolidated Financial Statements, beginning March 26, 2006 enterprises exploiting and selling crude oil in China are subject to the Windfall Levy if the monthly weighted average price received for crude oil is above $40 per barrel. For financial statement presentation the Windfall Levy is included in operating costs.

U.S.

The 35% and 33% decreases in U.S. production volumes for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005 were mainly due to the decline in production from the Knights Landing field which had been depleted to minimal levels at the end of 2005 and the sale of our Citrus property effective February 1. 2006.

For the three-month and nine-month periods ended September 30, 2006, operating costs in the U.S., including production taxes and engineering support, increased by $3.71 per Boe and $4.76 per Boe from the same periods in 2005 primarily as a result of several maintenance projects related to the processing facilities at South Midway and as a result of an increase in ad valorem taxes at South Midway and our Spraberry field in West Texas.

* * *

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


	Three-Month Periods Ended September 30,
	2006						2005
	U.S.		China		Total		U.S.		China		Total
Net Production:
Boe		57,058		152,767		209,825		88,118		86,886		175,004
Boe/day for the period		627		1,679		2,306		958		944		1,902

	Per Boe						Per Boe

Oil and gas revenue	$	59.51	$	67.74	$	65.50	$	49.21	$	52.33	$	50.76

Field operating costs		12.66		15.02		14.38		9.85		5.82		7.85
Production tax and Windfall Levy		0.97		8.84		6.70		0.70		—		0.35
Engineering support		3.47		0.67		1.43		2.84		0.52		1.69

		17.10		24.53		22.51		13.39		6.34		9.89

Net operating revenue		42.41		43.21		42.99		35.82		45.99		40.87
Depletion		25.32		38.68		35.05		14.38		36.63		25.43

Net revenue from operations	$	17.09	$	4.53	$	7.94	$	21.44	$	9.36	$	15.44


	Nine-Month Periods Ended September 30,
	2006						2005
	U.S.		China		Total		U.S.		China		Total
Net Production:
Boe		166,656		431,849		598,505		249,979		225,255		475,234
Boe/day for the period		610		1,582		2,192		916		825		1,741

	Per Boe						Per Boe

Oil and gas revenue	$	56.74	$	62.36	$	60.79	$	42.00	$	47.47	$	44.59

Field operating costs		13.63		12.81		13.04		10.23		7.13		8.76
Production tax and Windfall Levy		1.24		5.49		4.31		0.58		—		0.31
Engineering support		3.68		0.70		1.53		2.98		0.93		2.01

		18.55		19.00		18.88		13.79		8.06		11.08

Net operating revenue		38.19		43.36		41.91		28.21		39.41		33.51
Depletion		23.21		40.69		35.82		14.84		24.21		19.28

Net revenue from operations	$	14.98	$	2.67	$	6.09	$	13.37	$	15.20	$	14.23

General and Administrative

Our changes in general and administrative expenses, before and after considering increases in non-cash stock based compensation, by segment for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods for 2005 were as follows:


	Three-Months			Nine-Months
	Ended			Ended
	September 30,			September 30,
	2006 vs.			2006 vs.
	2005			2005
Favorable (unfavorable) variances:
Oil and Gas Activities:
China	$	691		$	374
U.S.		(221	)		(729	)
Corporate		(981	)		(965	)

		(511	)		(1,320	)
Less: stock based compensation		491			617

	$	(20	)	$	(703	)

Including increases for stock based compensation, general and administrative expenses after allocations increased by $0.5 million and $1.3 million for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005.

China

General and administrative costs for China decreased for the three-month and nine-month periods by $0.9 million due to a one time charge in 2005 for the write off of deferred financing costs. The decrease for the three-month period was offset by an increase in foreign currency loss of $0.1 million and the increase for the nine-month period was offset by an increase in foreign currency loss of $0.3 million and an increase in rent of $0.1 million.

U.S.

General and administrative costs in the U.S. increased $0.2 million and $0.7 million as allocations to capital investments decreased as a result of less capital activity for the three-month and nine-month periods ended September 30, 2006 when compared to the same period in 2005.

Corporate

General and administrative costs related to Corporate activities increased by $1.0 million for the three-month period ended September 30, 2006 when compared to the same periods in 2005 mainly as a result of a $0.5 million increase in stock based compensation, a $0.3 million increase in outside legal fees and financial consulting fees and a $0.2 million increase in corporate governance costs. The increase in these same costs for the nine-month period of $1.3 million was due to a $0.8 million increase in stock based compensation, a $0.4 million increase in outside legal fees and financial consulting fees, a $0.3 million increase 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 and a $0.3 million increase in corporate governance costs. These increases were offset by a $0.6 million decrease in reduced professional fees incurred to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”) as most of the 2004 SOX review was performed in the first quarter of 2005. In addition, the current year costs for SOX are lower as there are no start up costs that we experienced in 2005.

Business and Product Development

Changes in business and product development expenses, before and after considering increases in non-cash stock based compensation, by segment for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods for 2005 were as follows:


	Three-Months			Nine-Months
	Ended			Ended
	September 30,			September 30,
	2006 vs.			2006 vs.
	2005			2005
Favorable (unfavorable) variances:
HTL		(451	)		(1,624	)
GTL	$	(87	)	$	(134	)

		(538	)		(1,758	)
Less: stock based compensation		20			133

	$	(518	)	$	(1,625	)

Business and product development expenses increased $0.5 million and $1.8 million for the three-month and nine-month periods ended September 30, 2006 compared to the same periods in 2005 as we continued to focus on

business and product development activities related to heavy oil processing opportunities. Operating expenses of the RTP^TM CDF to develop and identify improvements in the application of the RTP^TM Technology are a part of our business and product development activities and contributed $0.5 million and $1.4 million to the increase in business and product development expense for the three-month and nine-month periods ended September 30, 2006. These increases included the costs of hiring of additional personnel to manage additional and extended test runs of the RTP^TM CDF.

Depletion and Depreciation

Depletion and depreciation increased $3.3 million and $15.6 million for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005 primarily due to an increase in depletion rates of $9.62 and $16.54 per Boe resulting in additional depletion expense of $0.9 million and $8.5 million for the three-month and nine-month periods ended September 30, 2006. Additionally, higher production rates resulted in increases in depletion of $2.0 million and $3.8 million for the three-month and nine-month periods ended September 30, 2006 compared to the same periods in 2005. We began depreciating the CDF RTP^TM in 2006 which also contributed to the overall increase in depletion and depreciation for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005.

China

China’s depletion rate increased $2.05 and $16.48 per Boe for the three-month and nine-month periods ended September 30, 2006 compared to the same periods in 2005. This resulted in a $0.3 million and $7.1 million increase in depletion expense for the three-month and nine-month periods ended September 30, 2006. These increases were mainly due to the suspension of new drilling activity in December 2005 at our Dagang field in order that we may assess production decline performances on recently drilled wells, as well as maximizing cash flow from these operations. As a result, we reduced our estimate of the overall development program. In addition, in the second quarter of 2005, we impaired the cost of our first Zitong block exploration well, Dingyuan 1, resulting in $12.5 million of those and other associated costs being included with our proved properties and therefore subject to depletion.

Additionally, increases in production volumes in China accounted for $2.4 million and $5.0 million of the increases in depletion expense for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005.

U.S.

The U.S. depletion rate increased $10.94 and $8.37 per Boe for the three-month and nine-month periods ended September 30, 2006 compared to the same periods in 2005, resulting in a $0.6 million and $1.4 million increase in depletion expense compared to these same periods in 2005. This increase was mainly due to the impairment of the remaining cost of our Northwest Lost Hills #1-22 exploration well as at December 31, 2005, resulting in $8.9 million of those costs being included with our proved properties and therefore subject to depletion in the first quarter of 2006. In addition, revisions to reserve estimates at Knights Landing and the sale of Citrus also contributed to the increased rate. Production volume decreases in the U.S. resulted in a $0.4 million and $1.2 decrease in our depletion expense for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005.

HTL

The RTP^TM CDF was in a commissioning phase as at December 31, 2005 and, as such, had not been depreciated as at December 31, 2005. The commissioning phase ended in January 2006 and the RTP^TM CDF was placed into service. For the three-month and nine month periods ended September 30, 2006, $0.4 million and $3.3 million of depreciation was recorded for the RTP^TM CDF. There was no revenue associated with the RTP^TM CDF operations for the three-month and nine-month periods ended September 30, 2006 and 2005. For the three-month and nine-month periods ended September 30, 2006, $0.4 million and $3.3 million of depreciation were recorded for the

RTP^TM CDF. Depreciation of the RTP^TM 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 RTP^TM 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.

Impairment of Oil and Gas Properties

As more fully described in our financial statements in Item 8 of our 2005 Annual Report filed on Form 10-K, we evaluate each of 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.

We impaired our China oil and gas properties by nil and $0.8 million for the three-month and nine-month periods ended September 30, 2006 compared to no impairment for the same periods in 2005. This impairment is mainly due to the Windfall Levy established in March 2006 that impacts the amount of future oil revenues from the Company’s China operations.

Capital Investments

The following provides an analysis of our capital investment activities for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods for 2005:


	Three-Month Periods Ended							Nine-Month Periods Ended
	September 30,							September 30,
					(Increase)							(Increase)
(stated in thousands of U.S. Dollars)	2006		2005		Decrease			2006		2005		Decrease
Oil and Gas Activities:
China	$	1,630	$	5,860	$	4,230		$	6,292	$	24,120	$	17,828
U.S.		2,929		2,789		(140	)		4,982		5,309		327
HTL		393		894		501			1,909		3,738		1,829
GTL		67		246		179			439		977		538

	$	5,019	$	9,789	$	4,770		$	13,622	$	34,144	$	20,522

Oil and Gas Activities — China

Capital investment in China for the three-month and nine-month periods ending September 30, 2006 was $1.6 million and $6.3 million, a $4.2 million and $17.8 million decrease compared to the same periods in 2005.

Expenditures at Dagang decreased $3.5 million to $1.6 million and $12.3 million to $5.7 million during the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005. The suspension of new drilling at Dagang accounts for the majority of this decrease. We continue to assess prior fracture stimulations and related production decline rates in order to choose additional wells for this program and to assist in making critical decisions on resuming our drilling program. We presented our Modified Overall Development Program to our Chinese partner, PetroChina, in August 2006 in which we proposed an additional five wells to be drilled in the project. We will evaluate the production results of these new wells and will review on an economic well-by-well basis whether we feel additional development wells are justified. Although our current Overall Development Program period expired October 31, 2006, PetroChina has advised that an extension until October 31, 2007 would be forthcoming.

In February 2006, the Company re-acquired Richfirst’s 40% working interest in the Dagang oil project for a purchase price of $28.3 million, paid through a combination of common shares of the Company, a non-interest bearing promissory note and forgiveness of unpaid joint venture receivables.

Our capital investment in our Zitong block was nil and $0.6 million for the three-month and nine-month periods ended September 30, 2006 compared to $0.8 million and $6.1 million for the same periods in 2005. The decreases are due mainly to the completion of our 700-mile seismic acquisition program in the first quarter 2005 and to the commencement of drilling our first exploration well which spudded in April 2005.

In May 2006, we received final approval from the Chinese authorities for our farm-out of 10% of the Zitong block to Mitsubishi. Subsequent to the approval, Mitsubishi paid the Company $4.0 million which will be used to drill the Yixin #1 well to a specified depth, at which time Mitsubishi will have earned their 10% working interest in the block.

During the nine-month period ended September 30, 2006, we continued prospect development in this block and selected our second exploration well location. Drilling on the second exploration well commenced in October 2006, but it is not expected to be completed and tested by November 30, 2006, the current deadline for completing the Phase 1 exploration program. In September 2006 we submitted a letter to PetroChina requesting that a further extension be granted to the Phase 1 exploration program, to a date 90 days following the completion of testing of the second well. Testing is estimated to be completed in April 2007. PetroChina replied to the letter and asked for further documentation regarding the adjustment to the work schedule. We submitted this data and have received preliminary approval of the revised timetable. We are awaiting PetroChina’s formal written approval of the extension.

Oil and Gas Activities — U.S.

The following provides an analysis of our U.S. Oil and Gas capital investment activities for the three-month and nine-month periods ended 2006 when compared to the same periods for 2005:


	Three-Month Periods Ended							Nine-Month Periods Ended
	September 30,							September 30,
					(Increase)							(Increase)
(stated in thousands of U.S. Dollars)	2006		2005		Decrease			2006		2005		Decrease
U.S. Oil and Gas Activities:
South Midway	$	2,632	$	426	$	(2,206	)	$	2,742	$	890	$	(1,852	)
Yowlumne		129		117		(12	)		903		308		(595	)
Knights Landing		92		144		52			738		619		(119	)
Northwest Lost Hills		—		935		935			5		1,019		1,014
LAK Ranch		15		471		456			82		868		786
Other California Exploration		61		696		635			512		1,605		1,093

	$	2,929	$	2,789	$	(140	)	$	4,982	$	5,309	$	327

South Midway

We drilled and completed ten wells in the third quarter of 2006. The wells are in various stages of either primary production or enhanced steam production. Indications are that the production rates are as expected. One additional well should be drilled and completed in the fourth quarter of this year. We drilled one successful delineation well and two temperature observation wells in the second quarter of 2005 and one successful exploration well in the third quarter of 2005.

North Yowlumne

In December 2005, drilling commenced on the North Yowlumne prospect to a total depth of 13,000 feet to test the Stevens sand that have produced over 110 million barrels of oil at the nearby Yowlumne field. We hold a 12.5% working interest in this prospect and have farmed out an 87.5% interest in the initial well and prospect. In the event of a discovery, we will own a 56.25% working interest in the well after payout. The test program is proceeding from the lowest zone to the highest zone in the well. The lower zones tested a small amount of light oil and associated gas. The operator has installed artificial lift and has attempted to produce the well to establish a commercial production rate. Flow rates from the lower zones were established and were sub-economic. Additional testing of upper intervals are on-going and final results of the entire testing of the well will be made when known.

LAK Ranch

We drilled one data collection well and three steam injection wells during 2005. We commenced continuous steaming operations in the fourth quarter of 2005 and through the third quarter of 2006. Although, the initial oil production has increased in response, we have determined that this project is not large enough to support a heavy oil upgrading facility based on the RTP^TM Technology and does not fit with our principal strategy of deploying our capital to further the development of our HTL technology. As noted elsewhere in this report, we have sold our interest in the project for cash of $0.6 million and a 5% gross overriding royalty.

Knights Landing and Northwest Lost Hills

We finalized the existing development program of our Knights Landing field in early 2005. The final interpretation of our 3-D seismic acquisition program was complete in the third quarter of 2006. Based on this interpretation many potential locations have been identified. We are planning on drilling four of these well locations in 2007. The Northwest Lost Hills #1-22 deep well was tested in January 2006 and in two tests flowed a non-commercial rate of 400 Mcf/d and 5,000 Bbls/d of water. We have received a formal abandonment plan from the operator. Specific timing of the abandonment is not currently known. We have no further plans to explore in this prospect.

Heavy-To-Light Oil Activities

We incurred $0.5 million and $1.8 million less in capital investment activities on HTL projects for the three-month and nine-month periods ended September 30, 2006 compared to the same periods in 2005.

RTP^TM Commercial Demonstration Facility

The RTP^TM CDF was constructed on Aera’s property in the Belridge Field for the purpose of demonstrating the RTP^TM Technology on a larger scale, and to test various HTL related processes.

During the three-month and nine-month periods ended September 30, 2006, we incurred $0.3 million and $1.3 million more on technical and operational enhancements to the RTP^TM CDF when compared to those same periods in 2005. In order to carry out additional test runs with very difficult feedstocks (further runs with vacuum tower bottoms (“VTBs”) and runs with Athabasca bitumen), a number of additional upgrades and enhancements to the RTP^TM CDF were carried out. In the first half of 2006, this work included the rerouting of piping and peripheral vessels, the addition of back-up peripheral equipment and the expansion of control systems. In the third quarter, additional work was identified in order to prepare the RTP^TM CDF for High Quality test runs. This included improvements to the distillation tower, which is used for upgraded product fractionation. Other upgrades which had been previously identified as necessary for extended operation were also undertaken.

Our priority will continue to be the testing of crude oil from potential resource partners with an initial focus on heavy crude oil from California and Western Canada, including bitumen from Canada’s Athabasca tar sands region. The RTP^TM CDF runs to date have successfully demonstrated that product upgraded by the RTP^TM CDF

compares favorably to test runs carried out at Ensyn’s pilot facility. In addition, a number of process enhancements have been validated during the RTP^TM CDF test program including flue gas de-sulphurization, heavy metals capture and crude acidity reduction.

The High Yield application, fully demonstrated in March 2006, is suited for “stranded” heavy oil resources that cannot be developed due to the inability to transport the heavy crude from the field to market, and where viscosity reduction and maximization of liquid product yield are the key goals. The High Quality application, appropriate for opportunities where a more fully upgraded product and significant onsite energy are required such as the tar sands in Athabasca, will be one of the key areas of focus in upcoming tests. Athabasca bitumen has been delivered from Western Canada and is currently in onsite storage ready for processing.

Iraq

In October 2004, we signed a memorandum of understanding with the Ministry of Oil of Iraq to prepare a study to evaluate the shallow Qaiyarah oil field in Iraq. The reservoir assessment has been completed and various recovery methods have been evaluated. Facility design work is complete and an economic evaluation was completed in the third quarter of 2006. Based on this evaluation we submitted a technical proposal to the Iraq Oil Ministry. When we are invited to make a presentation on this technical proposal we will offer a commercial proposal for the Qaiyarah oil field. The Iraq Ministry of Oil is under no obligation to execute the project or to enter into formal commercial negotiations.

The Qaiyarah heavy oil field project resulted in a $0.5 million and $1.1 million decrease in capital investments for the three-month and nine-month periods ended September 30, 2006 when compared to the same periods in 2005. In addition, we invested $0.2 million and $0.9 million during the three-month and nine-month periods ended September 30, 2005 and nil during those same periods in 2006 on other projects in Iraq including submission of four bids for the engineering, design and procurement of oil production facilities development projects.

Other

For the three-month and nine-month periods ended September 30, 2006, we incurred $0.1 million and $0.7 million less on design packages for commercial RTP™ facilities (“RTP^TM Plant”). We incurred nil and $0.4 million in costs related to a memorandum of understanding related to a study of heavy crudes from large oil fields in Colombia during the three-month and nine-month periods ended September 30, 2005 compared to nil during those same periods in 2006.

Gas-To-Liquids Activities

In 2005, we signed a memorandum of understanding with Egyptian Natural Gas Holding Company (“EGAS”), the state organization responsible for managing Egypt’s natural gas resources, to prepare a feasibility study to construct and operate a GTL plant that would convert natural gas to ultra-clean liquid fuels in Egypt. We completed an engineering design of a GTL plant to incorporate the latest advances in Syntroleum GTL technology and have completed market and pricing analysis for GTL products to reflect changes since the original evaluation was completed several years ago. Plant capacity options of 47,000 and 94,000 Bbls/d were evaluated and in May 2006, we presented the feasibility study report to EGAS along with three commercial proposals. Based on EGAS’ review of, and response to, these proposals we submitted a revised proposal in October 2006. Subject to EGAS internal analysis indicating that a GTL project is economically feasible for Egypt, the negotiation and signature of a mutually agreeable definitive agreement and approval by the Company’s Board of Directors and the appropriate authorities in Egypt, EGAS will agree to commit, at no cost to the project, up to 4.2 trillion cubic feet of natural gas, or approximately 600 MMcf/d for the anticipated 20-year operating life of the project. At the present time, the EGAS project is the only significant GTL project that the Company has under development.

Financial Condition, Liquidity and Capital Resources

Sources and Uses of Cash

Our net cash and cash equivalents decreased for the three-month period ended September 30, 2006 by $6.3 million compared to no increase for the same period in 2005. Our net cash and cash equivalents increased for the nine-month period ended September 30, 2006 by $12.8 million compared to a decrease of $5.6 million for the same period in 2005.

Operating Activities

Our operating activities provided $5.6 million in cash for the three-month period ended September 30, 2006 compared to $2.5 million for the same period in 2005. Our operating activities provided $11.3 million in cash for the nine-month period ended September 30, 2006 compared to $5.2 million for the same period in 2005. The increases in cash from operating activities for the three-month and nine-month periods ended September 30, 2006 were mainly due to increases in net production volumes of 20% and 26% and increases in oil and gas prices of 29% and 36% when compared to the same periods in 2005. The increases in net revenues for the three-month and nine-month periods ended September 30, 2006 were partially offset by increases in general and administrative and business and product development expenses, excluding stock based compensation.

Investing Activities

Our investing activities used $10.9 million in cash for the three-month period ended September 30, 2006 compared to $8.9 million for the same period in 2005. We spent $1.9 million more on capital investments, after changes in working capital, in the three-month period ended September 30, 2006, compared to the same period in 2005. Our investing activities used $17.6 million in cash for the nine-month period ended September 30, 2006 compared to $35.6 million for the same period in 2005 for an $18.0 million decrease in cash used in investing activities. This decrease was primarily due to a decrease of $11.0 million of cash used in merger and acquisition related activities. In addition, $5.4 million in proceeds from sale of assets and a $2.2 million net inflow from a project advance from a partner in the nine-month period ended September 30, 2006 contributed to the reduction in the use of cash.

Financing Activities

Our financing activities used $1.0 million in cash for the three-month period ended September 30, 2006 compared to $6.4 million of cash provided by financing activities for the comparable period in 2005. The $7.4 million increase in cash from financing activities is mainly due to a $6.9 million increase in cash from private placements and exercises of warrants and options plus a $0.6 million increase in net debt financing. Our financing activities provided $19.1 million in cash for the nine-month period ended September 30, 2006 compared to $24.9 million of cash provided by financing activities for the comparable period in 2005. The $5.8 million decrease in cash from financing activities is mainly due to a $7.1 million increase in cash from private placements and exercises of warrants and options offset by a $13.4 million decrease in net debt financing.

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 entitles 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 entitles the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing. Of the proceeds, $4.0 million has been used to pay down long-term debt and the balance will be used to pursue opportunities for the commercial deployment of the Company’s heavy oil upgrading technology, to advance its oil and gas operations and for general corporate purposes.

Outlook for 2006

As noted earlier, the Company completed a private placement of special warrants, $4 million of which was used to repay long-term debt and the balance of $21.4 million has been added to working capital to enable us to continue to develop our oil and gas reserves, particularly through the deployment of our proprietary heavy oil upgrading technology. In addition, in October 2006 the Company obtained a $15 million Senior Secured Revolving/Term Credit Facility, with an initial borrower base of $8 million from LaSalle Bank N.A., a wholly owned subsidiary of ABN AMRO Bank N.V. The facility will be available for the development of oil and gas properties, general corporate purposes and for the commencement of engineering of HTL commercial activities.

Management’s plans also include alliances or other partnership agreements with entities who we believe will provide additional resources to support the Company’s projects as well as the sale of additional equity securities, loans and debt financing in order to generate sufficient funds to assure continuation of the Company’s operations and achieve its capital investment objectives.

Contractual Obligations

The table below summarizes the contractual obligations that are reflected in our Unaudited Condensed Consolidated Balance Sheet as at September 30, 2006 and/or disclosed in the accompanying Notes:


	Payments Due by Year
	(stated in thousands of U.S. dollars)
	Total		2006		2007		2008		2009		After 2009
Consolidated Balance Sheets:
Note payable – current portion	$	3,493	$	927	$	2,566	$	—	$	—	$	—
Long term debt		3,290		—		553		2,325		412		—
Asset retirement obligation		2,046		—		—		831		492		723
Long term obligation		1,900		—		—		—		1,900		—
Other Commitments:												—
Interest payable		610		131		340		135		4		—
Lease commitments		1,759		202		622		481		287		167
Zitong exploration commitment		3,870		3,870		—		—		—		—

Total	$	16,968	$	5,130	$	4,081	$	3,772	$	3,095	$	890

Off Balance Sheet Arrangements

As at September 30, 2006 and December 31, 2005, 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.

Outstanding Share Data

As at October 27, 2006, there were 241,195,798 common shares of the Company issued and outstanding. Additionally, the Company had 29,696,330 share purchase warrants outstanding and exercisable to purchase 29,696,330 common shares. As at October 27, 2006, there were 12,551,543 incentive stock options outstanding to purchase the Company’s common shares.

Quarterly Financial Data In Accordance With Canadian and U.S. GAAP (Unaudited)


	QUARTER ENDED
	2006									2005												2004
	3rd Qtr			2nd Qtr			1st Qtr			4th Qtr			3rd Qtr			2nd Qtr			1st Qtr			4th Qtr
Total revenue	$	14,015		$	13,084		$	9,864		$	8,651		$	8,907		$	6,645		$	5,736		$	6,212
Net loss:
Canadian GAAP	$	(4,388	)	$	(4,405	)	$	(5,376	)	$	(8,885	)	$	(2,113	)	$	(1,031	)	$	(1,483	)	$	(17,184	)
U.S. GAAP	$	(7,117	)	$	(3,982	)	$	(12,112	)	$	(8,557	)	$	(1,843	)	$	(1,564	)	$	(3,008	)	$	(15,736	)
Net loss per share:
Canadian GAAP	$	(0.02	)	$	(0.02	)	$	(0.02	)	$	(0.04	)	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.09	)
U.S. GAAP	$	(0.03	)	$	(0.02	)	$	(0.05	)	$	(0.03	)	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.09	)

The net losses in the fourth quarter of 2004, for Canadian and U.S. GAAP, were primarily due to impairment provisions of $16.3 million and $15.0 million for U.S. oil and gas properties. The differences in the net loss and net loss per share for the first quarter of 2005 was due mainly to HTL and GTL investments, which are capitalized for Canadian GAAP but expensed as incurred for U.S. GAAP. The Canadian GAAP net loss in the fourth quarter of 2005 was primarily due to an impairment provision of $5.0 million for the China oil and gas properties, compared to the combined impairment provision calculated for U.S. GAAP for the China and U.S. oil and gas properties of $5.5 million. The differences in the net loss and net loss per share for the first quarter of 2006 were due mainly to the impairment charged for the China oil and gas properties for U.S. GAAP purposes of $7.2 million when compared to $0.8 million calculated for Canadian GAAP. The differences in the net loss and net loss per share for the third quarter of 2006 were due mainly to the impairment charged for the U.S. oil and gas properties for U.S. GAAP purposes of $3.1 million when compared to nil calculated for Canadian GAAP.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

No material changes since December 31, 2005.

Item 4. Controls and Procedures

The Company’s management, including our President and Chief Operating Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2006. Based upon this evaluation, management concluded that these controls and procedures were (1) designed to ensure that material information relating to the Company is made known to the Company’s President and Chief Operating Officer and Chief Financial Officer and (2) effective, in that they provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

It should be noted that while the Company’s principal executive officer and principal financial officer believe that the Company’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Company’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

During the period ended September 30, 2006, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II – Other Information

Item 1. Legal Proceedings: None

Item 1A. Risk Factors:

As at September 30, 2006, there were no additional material risks and no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2005.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds: None

Item 3. Defaults Upon Senior Securities: None

Item 4. Submission of Matters To a Vote of Security Holders: None

Item 5. Other Information: None

Item 6. Exhibits


EXHIBIT
NUMBER		DESCRIPTION

31.1		Certification by the Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification by the Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

IVANHOE ENERGY INC.


By:		/s/ W. Gordon Lancaster
Name:		W. Gordon Lancaster
Title:		Chief Financial Officer

Dated: November 2, 2006

INDEX TO EXHIBITS


Exhibit
Number		Description

31.1		Certification by the Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification by the Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002