IVANHOE ENERGY INC - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - FORM 8-K - IVANHOE ENERGY INC	eh1100543_form8k.htm
EX-99.3 - EXHIBIT 99.3 - IVANHOE ENERGY INC	eh1100543_ex9903.htm
EX-99.2 - EXHIBIT 99.2 - IVANHOE ENERGY INC	eh1100543_ex9902.htm

EXHIBIT 99.1

Ivanhoe Energy Inc.

Form 51-101F1

Statement of Reserves Data and

Other Oil and Gas Information

For the Year Ended December 31, 2010

June 2, 2011

TABLE OF CONTENTS

ABBREVIATIONS		1
SPECIAL NOTE AND DEFINITIONS		1
PART 1: DATE OF STATEMENT		3
PART 2: DISCLOSURE OF RESERVES DATA
	ITEM 2.1: Reserves Data.	4
PART 3: PRICING ASSUMPTIONS
	ITEM 3.1: Forecast Prices Used in Estimates	6
PART 4: RECONCILIATION OF CHANGES IN RESERVES		6
PART 5: ADDITIONAL INFORMATION RELATING TO RESERVES DATA
	ITEM 5.1: Undeveloped Reserves	7
	ITEM 5.2: Significant Factors or Uncertainties Affecting Reserves Data	7
	ITEM 5.3: Future Development Costs	8
PART 6: OTHER OIL AND GAS INFORMATION
	ITEM 6.1: Oil and Gas Properties and Wells	8
	ITEM 6.2: Property with No Attributed Reserves	10
	ITEM 6.4: Additional Information Concerning Abandonment and Reclamation Costs	11
	ITEM 6.5: Tax Horizon	11
	ITEM 6.6: Costs Incurred	12
	ITEM 6.7: Exploration and Development Activities	12
	ITEM 6.8: Production Estimates	12
	ITEM 6.9: Production History	12

ABBREVIATIONS

In this statement of Reserves Data and Other Oil and Gas information (the “Statement”), the abbreviations and definitions set forth below have the following meanings:

bbl	= barrel
bbls/d	= barrels per day
mmbbls	= million barrels
mmbbls/d	= million barrels per day

SPECIAL NOTE AND DEFINITIONS

Special Note Regarding Differences in Canadian and US Reserves Disclosure

Ivanhoe Energy Inc. (“Ivanhoe”, “the Company”, “our” or “we”) is an SEC registrant. In prior years Ivanhoe applied for and was granted by the Canadian Securities Administrators an exemption from certain of the provisions of National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities” ("NI 51-101"), which permitted the Company to present oil and gas reserves disclosure in accordance with oil and gas disclosure standards applicable in the United States (the “U.S. Rules”). This exemption is no longer available for the Company’s reserves reporting in Canada, although the Company has received an exemption from the Canadian Securities Administrators which allows, among other things, the Company to disclose its reserves in accordance with the U.S. Rules provided that the reserves and oil and gas activities disclosure required by NI 51-101 (excluding certain items) is also provided (the “Exemption Order”). The reserves and oil and gas activities disclosure required by NI 51-101 is provided in this Form 51-101F1, Statement of Reserves Data and Other Oil and Gas Information. The Company has disclosed reserves information in accordance with the U.S. Rules in the Company’s Form 10-K Annual Report for the year ended December 31, 2010, which is available at www.sec.gov or www.sedar.com.

The following is a summary of some of the fundamental differences between reserves estimates and related disclosures prepared in accordance with the US Rules and those prepared in accordance with NI 51-101:

—

SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US, whereas NI 51-101 requires adherence to the definitions and standards promulgated by the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”);

—

the SEC mandates disclosure of proved reserves calculated using an average, first-day-of-the-month price during the 12 month period preceding and existing costs only, whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecasted prices, with additional constant pricing disclosure being optional;

—

the SEC mandates disclosure of reserves by geographic area only, whereas NI 51-101 requires disclosure of more reserve categories and product types; and

—

the SEC leaves the engagement of independent qualified reserves evaluators to the discretion of a company’s board of directors, whereas NI 51-101 requires issuers to engage such evaluators.

The foregoing is a general and non-exhaustive description of the principal differences between SEC disclosure requirements and NI 51-101 requirements. Please note that the differences between SEC and NI 51-101 requirements may be material.

Definitions

The following terms, when used in this statement, have the following meanings and, where applicable, are as set forth in NI 51-101.

1.	"Gross" means:

in relation to our interest in production or reserves, our "company gross reserves", which are our working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest to us;

in relation to wells, the total number of wells in which we have an interest; and

in relation to properties, the total area of properties in which we have an interest.

2.	"Net" means:

in relation to our interest in production or reserves, our working interest (operating and non-operating) share after deduction of royalty obligations, plus our royalty interests in production or reserves;

in relation to our interest in wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we own.

The crude oil reserves estimates presented in this Statement are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

3.	Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on:

analysis of drilling, geological, geophysical and engineering data;

the use of established technology; and

specified economic conditions, which are generally accepted as being reasonable.

Reserves are classified according to the degree of certainty associated with the estimates.

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities revered will exceed the sum of the estimated proved plus probable plus possible reserves.

Other criteria that must also be met for the classification of reserves are provided in the COGE Handbook.

4.	Development and Production Status

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories.

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

ii.

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in and the date of resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable) to which they are assigned.

5.	Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

PART 1: DATE OF STATEMENT

The estimates and disclosures in this Statement have been prepared in accordance with NI 51-101 and have a preparation date of June 2, 2011 with an effective date of December 31, 2010.

PART 2: DISCLOSURE OF RESERVE DATA

The reserves data set forth below summarizes the crude oil reserves of Ivanhoe and the net present value of the future net revenue for the reserves using forecast prices and costs and is prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101. All reserve estimates have been independently evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”).

Item 2.1: Reserves Data

The recovery and reserves estimates of crude oil provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in the "Special Note and Definitions" section of this statement in conjunction with the following tables and notes. For more information as to the risks involved, see "Risk Factors" found in the Company’s 2010 Form 10-K.

Summary of Oil Reserves as of December 31, 2010

Forecast Prices and Costs

	China
	Light and Medium Oil				Canada Bitumen				Total Company
Reserve category	Gross (Mbbl)		Net(1) (Mbbl)		Gross (Mbbl)		Net (Mbbl)		Gross (Mbbl)		Net (Mbbl)

Proved
Developed producing		1,248		1,265		-		-		1,248		1,265
Developed non-producing		-		-		-		-		-		-
Undeveloped		492		468		-		-		492		468
Total proved		1,740		1,733		-		-		1,740		1,733

Probable		828		787		175,684		134,950		176,512		135,737
Total proved plus probable		2,568		2,520		175,684		134,950		178,252		137,470

(1)

Includes royalty interest volumes.

Net Present Value of Future Net Revenue

It should not be assumed that the estimates of future net revenues presented in the following tables represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material.

Future net revenue includes estimated future abandonment costs related to wells and production facilities required to produce the reserves which have been developed or are anticipated to be developed.

Net Present Values of Future Net Revenue as of December 31, 2010

Forecast Prices and Costs

($US000s)

	Before income taxes discounted at					After income taxes discounted at					Net unit value before tax, discounted at
Reserve category	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%	10%/year ($/bbl)

China
Proved
Developed producing	59,434	49,419	42,233	36,892	32,800	51,807	43,697	37,803	33,368	29,928	33.39
Developed non-producing	-	-	-	-	-	-	-	-	-	-	-
Undeveloped	19,326	15,833	13,261	11,313	9,802	14,622	11,665	9,513	7,901	6,666	28.34
Total proved	78,760	65,252	55,494	48,205	42,602	66,429	55,362	47,316	41,269	36,594	32.03

Probable	42,561	28,684	20,450	15,269	11,837	30,498	20,224	14,612	10,375	7,888	26.00
Total proved plus probable	121,321	93,936	75,944	63,474	54,439	96,927	75,586	61,478	51,644	44,482	30.15


Canada
Proved
Developed producing	-	-	-	-	-	-	-	-	-	-	-
Developed non-producing	-	-	-	-	-	-	-	-	-	-	-
Undeveloped	-	-	-	-	-	-	-	-	-	-	-
Total proved	-	-	-	-	-	-	-	-	-	-	-

Probable	4,940,474	2,058,416	906,291	381,056	115,236	3,725,635	1,509,394	622,234	217,436	13,077	6.72
Total proved plus probable	4,940,474	2,058,416	906,291	381,056	115,236	3,725,635	1,509,394	622,234	217,436	13,077	6.72

Total Company
Proved
Developed producing	59,434	49,419	42,233	36,892	32,800	51,807	43,697	37,803	33,368	29,928	33.39
Developed non-producing	-	-	-	-	-	-	-	-	-	-
Undeveloped	19,326	15,833	13,261	11,313	9,802	14,622	11,665	9,513	7,901	6,666	28.34
Total proved	78,760	65,252	55,494	48,205	42,602	66,429	55,362	47,316	41,269	36,594	32.03

Probable	4,983,035	2,087,100	926,741	396,325	127,073	3,756,133	1,529,618	636,846	227,881	20,965	6.83
Total proved plus probable	5,061,795	2,152,352	982,235	444,530	169,675	3,822,562	1,584,980	683,712	269,080	57,559	7.13

Total Future Net Revenue (Undiscounted) as of December 31, 2010

Forecast Prices and Costs

($US000s)

Reserve category	Revenue		Royalties		Operating costs		Development costs		Well abandonment costs		Future net revenue before income taxes		Income taxes		Future net revenue after income taxes

China
Total proved		166,142		37,948		41,160		7,274		-		78,760		12,331		66,429
Total proved plus probable		248,837		59,315		55,241		12,961		-		121,321		24,394		96,927

Canada
Total proved		-		-		-		-		-		-		-		-
Total proved plus probable		13,610,431		3,254,339		3,442,778		1,931,843		40,996		4,940,474		1,214,840		3,725,635

Total company
Total proved		166,428		7,790		72,424		7,274		-		78,760		12,331		66,429
Total proved plus probable		13,860,555		3,266,494		3,546,465		1,944,804		40,996		5,061,795		1,239,234		3,822,562

Future Net Revenue by Production Group as of December 31, 2010

Forecast Prices and Costs

($US000s)

Reserves category	Production group	Future net revenue before income taxes (discounted at 10% per year)		Net unit value ($/bbl)

Total proved	Light and Medium oil		55,494		32.03
Total proved plus probable	Light and Medium oil		75,944		30.15
Total proved plus probable	Bitumen		906,291		6.72

PART 3: PRICING ASSUMPTIONS

Item 3.1: Forecast Prices and Costs Used in Estimates

The pricing assumptions used by the Company’s independent reserve evaluator, GLJ, in the preparation of reserve estimates are summarized in the following table:

Summary of Pricing and Inflation Rate Assumptions as of December 31, 2010

Forecast Prices and Costs

	Light and medium oil			Heavy oil
Year	WTI NYMEX (US$/bbl)			Hardisty heavy (Cdn$/bbl)			Inflation rate (%)			Exchange rate ($US/$Cdn)

Historical
2010		75.52			-			-			-
Forecast
2011		88.00			68.79			2	%		0.98
2012		89.00			68.33			2	%		0.98
2013		90.00			67.03			2	%		0.98
2014		92.00			67.84			2	%		0.98
2015		95.17			70.23			2	%		0.98
2016		97.55			72.03			2	%		0.98
2017		100.26			74.08			2	%		0.98
2018		102.74			75.95			2	%		0.98
2019		105.45			78.00			2	%		0.98
2020		107.56			79.59			2	%		0.98
Thereafter		2	%		2	%		2	%		0.98

The forecast price assumptions assume the continuance of current laws and regulations. There is no assurance that the forecast prices assumptions will be attained and variances could be material. These assumptions may differ from internal assumptions that are used for project economics and planning purposes.

Ivanhoe’s 2010 weighted average realized price was $75.52/bbl of oil.

PART 4: RECONCILIATION OF CHANGES IN RESERVES

The Exemption Order permits the Company to not provide a reconciliation of December 31, 2010 reserve estimates and related disclosures to those in prior years.

PART 5: ADDITIONAL INFORMATION RELATED TO RESERVES DATA

Item 5.1: Undeveloped Reserves

The following table sets out the volumes of gross proved undeveloped reserves and gross probable undeveloped reserves that were first attributed for each of the Company’s product types for each of three most recent financial years and in the aggregate before that time using forecast prices and costs:

	China				Canada
	Proved (Mbbl)		Probable (Mbbl)		Proved (Mbbl)		Probable (Mbbl)

December 31, 2010		292		399		-		175,684
December 31, 2009		98		24		-		-
December 31, 2008		-		-		-		-
Aggregate prior to December 31, 2008		210		98		-		-

Undeveloped reserves are reserves expected to be recovered from known accumulations and require significant expenditure to develop and make capable of production. Proved and probable undeveloped reserves were estimated by GLJ in accordance with the procedures and standards contained in the COGE Handbook.

Undeveloped reserves in China are scheduled to be developed over the next ten years. The Company continually reviews the economic viability and ranking of these undeveloped reserves within the total portfolio of its development projects. Development opportunities are then pursued based on capital availability and allocation.

Item 5.2: Significant Factors or Uncertainties Affecting Reserves Data

The development plan for the Company’s undeveloped reserves is based on forecast price and cost assumptions. The actual prices that occur may be higher or lower resulting in certain projects being advanced or delayed.

The evaluation of reserves is a process that can be significantly affected by a number of internal and external factors. Revisions are often necessary resulting in changes in technical data acquired, historical performance, fluctuations in operating costs, development costs and product pricing, economic conditions, changes in royalty regimes and environmental regulations, and future technology improvements. See "Risk Factors" found in the Company’s 2010 Form 10-K for further information.

Item 5.3: Future Development Costs

The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserve categories noted below.

Summary of Oil and Gas Future Development Costs as at December 31, 2010

Forecast Prices and Costs

($US000s)

	China				Canada		Total Company
	Total proved reserves		Total proved plus probable reserves		Total proved plus probable reserves		Total proved reserves		Total proved plus probable reserves

2011		5,049		5,049		20,745		5,049		25,794
2012		1,102		3,917		256,409		1,102		260,326
2013		1,124		3,995		530,710		1,124		534,705
2014		-		-		41,964		-		41,964
2015		-		-		10,060		-		10,060
Remainder		-		-		1,071,956		-		1,071,956
Total (undiscounted)		7,275		12,961		1,931,843		7,275		1,944,804
Total, discounted at 10%		6,654		11,357		945,019		6,654		956,376

Ivanhoe intends to use its cash and cash equivalent balance to partially fund development costs in 2011. Cash flow from current operating activities will be insufficient to meet future development costs and additional sources of funding, either at a parent company level or at a project level, will be required to grow the Company’s major projects and fully develop its oil and gas properties. Historically, Ivanhoe has used external sources of funding, such as public and private equity and debt financing. There is no assurance that we will be able to obtain additional financing on favorable terms, if at all. If we cannot secure additional financing, we may have to delay or cancel one or more of our capital programs and forfeit or dilute our rights in existing oil and gas property interests.

PART 6: OTHER OIL AND GAS INFORMATION

Item 6.1: Oil and Natural Gas Properties and Wells

Our oil and gas operations are broken down into three geographic areas: Canada, Ecuador and Asia.

Canada

Tamarack, acquired in 2008, is a 6,880 acre block located approximately 10 miles northeast of Fort McMurray, Alberta, Canada. Ivanhoe holds a 100% working interest in the property, subject only to a 20% back-in right held by Talisman Energy Canada (“Talisman”), which expires in mid-2011.

Our independent reserve evaluator, GLJ, has assigned total possible reserves of 220 mmbbls of bitumen to Tamarack. It is anticipated that the reserves will be developed utilizing steam assisted gravity drainage (“SAGD”) technology. The Company expects that 12 well pads and approximately 160 SAGD well pairs will be required to fully develop and produce the targeted resource base. No proved reserves have been assigned, pending regulatory approval.

In March 2010, a 28 well winter delineation program was completed, which provided information necessary for regulatory filings. In November 2010, Ivanhoe filed a comprehensive Environmental Impact Assessment with the Government of Alberta. In support of the application, Basic Engineering and Design and Front End Engineering and Design were completed to generate a Class III (+25/-20%) capital cost estimate. Subject to regulatory approvals from the Alberta Energy Resources Conservation Board and Alberta Environment, construction at Tamarack could commence in mid-2012, with commissioning and start-up of the production facilities expected in the fourth quarter of 2013.

Ecuador

In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary of Ivanhoe, signed a 30 year contract with the Ecuador state oil companies Petroecuador and Petroproduccion. The contract gives us the right to explore and develop the Pungarayacu heavy oil field in Block 20, an area of 426 square miles, approximately 125 miles southeast of Quito, Ecuador’s capital. We anticipate using the Company’s Heavy-to-light or HTL™ technology, as well as providing advanced oilfield technology, expertise and capital to develop, produce and upgrade heavy oil from the Pungarayacu field. The Company may also explore for lighter oil in the contract area and use any light oil discoveries to blend with the heavy oil for delivery to Petroproduccion.

In 2010, the IP-5b well was successfully drilled, cored and logged to a total depth of 1,080 feet. The well was perforated in the Hollin oil sands and steam was successfully injected into the reservoir resulting in production of heated heavy oil. The Company’s IP-15 well, drilled in 2010, encountered certain cementing and completion problems during steam injection operations and testing and the well was suspended without recovering oil. Ivanhoe sees significant variability between the two well locations, supporting the view that geological faulting is prevalent in Block 20 due to the close proximity of the Andes, directly to the west of the block. We plan to commence a seismic program following testing operations at IP-5b to increase our understanding of the geological faulting and to help determine locations for our next appraisal wells.

Asia

China

Zitong

In November 2002, we entered into a 30 year production sharing contract with China National Petroleum Corporation (“CNPC”) for the Zitong block, which covers an area of approximately 658,000 gross acres after contractual relinquishments in the Sichuan basin. The parties will jointly participate in the development and production of any commercially viable deposits, with production rights limited to the later of 2032 or 20 years of continuous production. In 2006, we farmed out 10% of our working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan for US$4.0 million.

In Phase I of the contract, Ivanhoe reprocessed 1,649 miles of existing 2D seismic data and acquired 705 miles of new 2D seismic data. Two wells were drilled and although both wells encountered expected reservoirs and gas was tested on the second well, neither well demonstrated commercially viable flow rates and both wells were suspended.

In Phase II, two wells were drilled in 2010 at the Zitong block, both resulting in gas discoveries. The Yixin-2 well was tested in December 2010 with gas flowing from the Xu-4 Formation. Following initial flow and pressure tests, the well was shut-in for pressure build-up. The Zitong-1 well reached total depth in December 2010 and was tested in January 2011, with gas flowing from the Xu-4 Formation. The well was subsequently shut-in to record reservoir pressure build-up and allow testing of the shallower, Xu-5 formation.

Following the drilling of the Zitong-1 and Yixin-2 wells, areas excluding those identified for development and future production were to be relinquished. In January 2011, Ivanhoe received notice that the exploration period has been extended for an additional six months to the end of June 2011.

Dagang

Ivanhoe’s oil production originates in the Kongnan oilfield in Dagang, Hebei Province, China (the “Dagang field”). We have a 30 year production sharing contract with the Chinese National Petroleum Company (“CNPC”), covering an area of 10,255 gross acres. From 2001 to 2007, we drilled 44 wells and commercial production commenced on January 1, 2009. The project reached cost recovery in September 2009 and our working interest decreased to 49%. Operations in the Dagang field will revert to CNPC at the end of the 20 year production phase of the contract or earlier if the field is abandoned.

In 2010, quotas restricted production to 1,400 bbls/d gross. Actual production in 2010 averaged 788 bbls/d net. Production quotas in 2011 are set at approximately 1,600 bbls/d gross.

Mongolia

Through a merger with PanAsian Petroleum Inc. in November 2009, we acquired a production sharing contract for the Nyalga Block XVI in the Khenti and Tov provinces in Mongolia. The block covers an area of approximately 3.1 million gross acres, after a 25% relinquishment in 2010. The five year exploration period is divided into three consecutive phases, consisting of two years (“Phase I”), one year (“Phase II”) and two years (“Phase III”), with the ability to nominate a two year extension following Phase I or Phase II.

During the initial seismic program, approximately 16% of the block in the Delgerkhaan area was declared by the Mongolian government to be a historical site and operations in this area were suspended. A letter from the Mineral Resources and Petroleum Authority of Mongolia (“MRPAM”) stated that the obligations under year one of Phase I would be extended for one year from the time the Company is allowed to re-enter the suspended area. To date, access has not been granted and discussions with MRPAM are ongoing. As a result, the government has adjusted the dates in which the project year begins. Phase II is now considered to have commenced on July 20, 2010.

From late 2009 through the first quarter of 2010, the Company acquired an additional 465 kilometres of 2-D seismic across Block XVI, for a total of 925 kilometres of 2-D seismic data over the Kherulen sub-basin. In 2010, preparations commenced for a five well drilling program and a seismic acquisition program. The first exploratory location has been identified and we expect to initiate drilling operations in Mongolia in the first half of 2011.

Producing Oil Wells

At December 31, 2010, Ivanhoe had 44.0 gross (21.6 net) producing oil wells in China. The Company does not have any producing gas wells or any non-producing wells.

Item 6.2: Properties With No Attributed Reserves

The following table sets out the unproved properties in which we have an interest for which we have no attributed reserves, as at December 31, 2010.

Acres	Gross		Net
Canada		7,520		7,520
Ecuador		272,639		272,639
Asia – China(1)		664,314		595,338
Asia – Mongolia		3,107,907		3,107,907

(1)

The number of developed acres disclosed in respect of our China properties relates only to those portions of the field covered by our producing operations and does not include the remaining portions of the field previously developed by CNPC.

The Tamarack leases in Canada will expire in October 2016, but Ivanhoe has sufficient drill density to be granted a continuation by the Alberta Department of Energy one year prior to expiry or upon first

production, whichever comes first. Although production activities from the Tamarack leases are anticipated to commence in 2013, we plan to apply for a continuation of the leases prior to their expiration if the project is delayed. Talisman retains a back-in right (the “Back-in Right”), exercisable once per each of the two leases until July 11, 2011, to re-acquire up to a 20% undivided interest in each lease. If the Back-in Right is exercised, the cost to Talisman would be 20% of 200% of Ivanhoe’s acquisition cost and certain expenses incurred since acquisition in respect of the relevant lease.

Ivanhoe signed a specific services contract with affiliated entities of the State of Ecuador in October 2008 that allows the Company to develop Block 20 for a term of 30 years, extendable by mutual agreement of the parties, for two additional periods of five years each, depending on the interests of the State and in conformity with local laws.

Acreage in the Dagang field will return to CNPC in 2027. Following the completion of Phase II of the Zitong Contract, the remaining acreage must be relinquished to CNPC except for areas identified for development and future production, which will be relinquished upon termination of the production sharing contract in 2032.

Acreage in Mongolia is subject to periodic relinquishments up to the end of the exploration period and the remaining acreage designated for appraisal and development will expire 20 years after the final commercial discovery on the Nyalga block.

The Company has approximately 620,000 net acres in Mongolia that will be relinquished before December 31, 2011, upon the end of the second exploration period.

Item 6.4: Additional Information Concerning Abandonment and Reclamation Costs

The Company is required to remedy the effect of our activities on the environment at our operating sites by dismantling and removing production facilities and remediating any damage caused. Costs are expected to be incurred between 2013 and 2058. Ivanhoe does not make such a provision for asset retirement costs in connection with its oil and gas operations in China as dry holes are abandoned as occurred and the Company is under no obligation to contribute to the future costs to restore well sites or abandon the field.

In estimating our future abandonment and reclamation costs ("A&R costs"), we make estimates and judgments on activities that will occur many years from now. In estimating A&R costs we consider many factors including existing contracts, regulations, A&R techniques, industry conditions and past experience. As such, factors are constantly changing and our estimates are uncertain.

As of December 31, 2010, our expected undiscounted A&R costs are $40.8 million ($5.6 million, discounted at 10%) for proved and probable reserves, including $0.3 million of costs to be incurred in within the next three years. These costs relate to approximately 14 existing and 222 additional wells planned to be drilled in the future to access proved and probable reserves.

The total amount of A&R costs reacted to our proved and probable reserves estimate is higher than the asset retirement obligation on our balance sheet primarily due to retirement costs related to planned future capital expenditures. These future obligations are relevant for determining the economic viability of our reserves but do not constitute an existing liability in our financial statements as the wells or facilities potentially giving rise to these costs have not yet been undertaken.

Item 6.5: Tax Horizon

The Company is not currently taxable as at December 31, 2010, and we estimate our tax horizon is beyond ten years; however, for the purposes of the future net revenues disclosed herein a horizon of five years was used.

Item 6.6: Costs Incurred

Costs incurred in oil and gas property acquisition, exploration, and development activities for the Company’s oil and gas properties for the fiscal year 2010 were as follows:

US$000s	Canada		China		Ecuador		Total Company

Property acquisition costs
Unproved		649		-		1,237		1,886
Exploration		29,634		31,326		18,257		79,219
Development		-		5,057		-		5,057
Total costs incurred		30,283		36,383		19,494		86,162

Item 6.7 Exploration and Development Activities

At December 31, 2010, we were actively drilling the Zitong-1 and Yixin-2 wells in our Zitong project and one well in our Dagang field. No wells were completed in 2010. The Company did not drill any exploration or development wells in 2009 or 2008.

Item 6.8 Production Estimates

The Company’s oil production is solely from the Kongnan oilfield in Dagang, Hebei Province, China. The volume of production estimated for the first year reflected in the estimates of gross proved reserves and gross probable reserves described under Item 2.1 herein was 891 bbls/d.

Item 6.9 Production History

The Company’s production and net operating revenue in China for the fiscal year ended December 31, 2010 is presented below by quarter and in total.

	Q1		Q2		Q3		Q4		Total

Average daily production (bbls/d)	804		869		610		870			788

Net operating revenue ($/bbl)
Oil revenue	73.63		76.47		74.41		77.06			75.52
Less operating costs
Field operating	(18.45	)	(17.31	)	(22.15	)	(22.40	)		(19.96	)
Windfall Levy	(11.20	)	(11.00	)	(11.34	)	(12.70	)		(11.59	)
Engineering and support costs	(1.77	)	(1.12	)	(1.69	)	(1.48	)		(1.50	)
Net operating revenue	42.21		47.04		39.23		40.48			42.47

Total production (bbls light and medium oil)	72,396		79,071		56,131		80,021			287,619

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