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

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8-K - FORM 8-K - IVANHOE ENERGY INC	eh1200410_8k.htm
EX-99.3 - EXHIBIT 99.3 - IVANHOE ENERGY INC	eh1200410_8k-ex9903.htm
EX-99.2 - EXHIBIT 99.2 - IVANHOE ENERGY INC	eh1200410_8k-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, 2011

February 10, 2012

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	3
PART 3: PRICING ASSUMPTIONS
	ITEM 3.2: Forecast Prices and Costs Used in Estimates	5
PART 4: RECONCILIATION OF CHANGES IN RESERVES
	ITEM 4.1: Reserves Reconciliation	6
PART 5: ADDITIONAL INFORMATION RELATING TO RESERVES DATA
	ITEM 5.1: Undeveloped Reserves	6
	ITEM 5.2: Significant Factors or Uncertainties Affecting Reserves Data	7
	ITEM 5.3: Future Development Costs	7
PART 6: OTHER OIL AND GAS INFORMATION
	ITEM 6.1: Property Descriptions	7
	ITEM 6.2: Properties with no Attributed Reserves	9
	ITEM 6.4: Abandonment and Reclamation Costs	10
	ITEM 6.5: Tax Horizon	10
	ITEM 6.6: Costs Incurred	10
	ITEM 6.7: Exploration and Development Activities	10
	ITEM 6.8: Production Estimates	10
	ITEM 6.9: Production History	11

⁠

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
mmbl	= thousand barrels
mmbbl	= 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 (“CSA”) 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 “US Rules”). This exemption is no longer available for the Company’s reserves reporting in Canada, although the Company has received an exemption from the CSA which allows, among other things, the Company to disclose its reserves in accordance with the US 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 US Rules in the Company’s Form 10-K Annual Report for the year ended December 31, 2011, 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 the 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 is 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 recovered 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 the Statement have been prepared in accordance with NI 51-101 and have a preparation date of February 10, 2012 with an effective date of December 31, 2011.

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 the 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 2011 Form 10-K.

Summary of Oil Reserves as of December 31, 2011

Forecast Prices and Costs

	China				Canada				Total
	Light and medium oil				Bitumen				Company
(mbbl)	Gross		Net(1)		Gross		Net		Gross		Net
Proved
Developed producing		1,221		1,235		–		–		1,221		1,235
Undeveloped		414		393		–		–		414		393
Total proved		1,636		1,629		–		–		1,636		1,629
Probable		841		799		175,684		136,163		176,525		136,962
Total proved plus probable		2,476		2,428		175,684		136,163		178,160		138,591

(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 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, 2011

Forecast Prices and Costs

	Future net revenue ($US000s) Before income taxes discounted at					Future net revenue ($US000s) After income taxes discounted at						Net unit value before tax, discounted at 10%/year ($/bbl)
	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
China
Proved
Developed producing	67,833	57,621	50,138	44,469	40,051	58,717	50,245	43,986	39,210	35,463		40.58
Undeveloped	11,561	9,842	8,432	7,274	6,316	8,780	7,037	5,661	4,565	3,683		21.43
Total proved	79,394	67,463	58,570	51,743	46,367	67,498	57,283	49,647	43,775	39,146		35.95

Probable	44,455	30,370	21,797	16,303	12,618	33,342	22,454	15,836	11,609	8,792		27.28
Total proved plus probable	123,849	97,833	80,368	68,045	58,985	100,840	79,737	65,483	55,384	47,938		33.10

Canada
Probable	4,710,458	1,968,976	847,848	332,793	73,562	3,549,446	1,439,031	576,007	179,585	(19,375	)	6.23
Total proved plus probable	4,710,458	1,968,976	847,848	332,793	73,562	3,549,446	1,439,031	576,007	179,585	(19,375	)	6.23

Total Company
Proved
Developed producing	67,833	57,621	50,138	44,469	40,051	58,717	50,245	43,986	39,210	35,463		40.60
Undeveloped	11,561	9,842	8,432	7,274	6,316	8,780	7,037	5,661	4,565	3,683		21.46
Total proved	79,394	67,463	58,570	51,743	46,367	67,498	57,283	49,647	43,775	39,146		35.95
Probable	4,754,913	1,999,346	869,645	349,096	86,180	3,582,788	1,461,485	591,843	191,194	(10,583	)	6.35
Total proved plus probable	4,834,307	2,066,809	928,215	400,839	132,547	3,650,286	1,518,768	641,490	234,969	28,563		6.70

Total Future Net Revenue (Undiscounted) as of December 31, 2011

Forecast Prices and Costs

($US000s)	Revenue		Royalties		Operating costs		Develop- ment costs		Well abandon- ment costs		Future net revenue before income taxes		Income taxes		Future net revenue after income taxes
China
Total proved		172,191		33,262		47,229		12,306		–		79,394		11,896		67,498
Total proved plus probable		260,618		51,653		63,285		21,831		–		123,849		23,009		100,840

Canada
Total proved plus probable		13,571,644		3,141,608		3,407,368		2,271,460		40,751		4,710,458		1,161,012		3,549,446

Total Company
Total proved		172,191		33,262		47,229		12,306		–		79,394		11,896		67,498
Total proved plus probable		13,832,262		3,193,261		3,470,653		2,293,291		40,751		4,834,307		1,184,021		3,650,286

Future Net Revenue by Production Group as of December 31, 2011

Forecast Prices and Costs

Reserves category	Production group	Future net revenue before income taxes (discounted at 10% per year) ($US000s)	Net unit value ($/bbl)
Total proved	Light and medium oil	58,570	35.96
Total proved plus probable	Light and medium oil	80,368	33.10
Total proved plus probable	Heavy oil	847,848	6.23

PART 3: PRICING ASSUMPTIONS

Item 3.2: 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, 2011

Forecast Prices and Costs

	Light and medium oil	Heavy oil
Year	ICE Brent FOB (US$/bbl)	Hardisty heavy (Cdn$/bbl)	Inflation rate (%)	Exchange rate ($US/$Cdn)
Historical
2011	110.63	–	–	–
Forecast
2012	105.00	72.37	2%	0.98
2013	105.00	73.60	2%	0.98
2014	102.00	74.51	2%	0.98
2015	100.00	74.51	2%	0.98
2016	100.00	74.51	2%	0.98
2017	100.00	74.51	2%	0.98
2018	101.35	75.54	2%	0.98
2019	103.38	77.09	2%	0.98
2020	105.45	78.67	2%	0.98
2021	107.56	80.28	2%	0.98
Thereafter	+2%/yr	+2%/yr	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 weighted average realized price of oil was $105.93/bbl in 2011.

PART 4: RECONCILIATION OF CHANGES IN RESERVES

Item 4.1: Reserves Reconciliation

The following table provides a summary of the changes in the Company’s reserves in China and Canada, based upon forecast price and cost assumptions.

Reconciliation of Reserves

Forecast Prices and Costs

	China Light and medium oil									Canada Heavy oil
(mbbl)	Gross proved			Gross probable			Gross proved plus probable			Gross probable
December 31, 2010		1,741			828			2,569			175,684
Extensions		147			44			191			–
Technical revisions		107			(31	)		76			–
Production		(359	)		–			(359	)		–
December 31, 2011		1,636			841			2,476			175,684

Reserve extensions of 191 mbbl were added in China due to the four wells drilled in Dagang in 2011. Technical revisions of 76 mbbl resulted from production improvements and increased recovery factors. In Canada, no additional reserves were assigned as further reserve development is subject to regulatory approval of the Company’s application for the Tamarack project and availability of financing.

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:

	Light and medium oil				Heavy oil
(mbbl)	Proved undeveloped		Probable undeveloped		Probable undeveloped
December 31, 2011		45		149		–
December 31, 2010		292		399		175,684
December 31, 2009		98		24		–
Aggregate prior to December 31, 2009		210		98		–

Undeveloped reserves are reserves expected to be recovered from known accumulations and require significant expenditures to develop. Proved undeveloped reserves are generally those reserves related to wells that have been tested and not yet tied-in, wells drilled near the end of the fiscal year, or wells further away from gathering systems. In addition, such reserves may relate to planned infill drilling locations. Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive infill drilling locations and lands contiguous to 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 timing of undeveloped reserve development in Canada is dependent upon approval of the Company’s Tamarack application for the project and availability of financing.

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 2011 Form 10-K for further information.

Item 5.3: Future Development Costs

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

Future Development Costs as at December 31, 2011

Forecast Prices and Costs

	China				Canada		Total
($US000s)	Total proved reserves		Total proved plus probable reserves		Total proved plus probable reserves		Total proved reserves		Total proved plus probable reserves

2012		9,960		9,960		18,988		9,960		28,948
2013		2,346		4,692		165,926		2,346		170,618
2014		–		7,179		663,563		–		670,742
2015		–		–		141,935		–		141,935
2016		–		–		12,736		–		12,736
Remainder		–		–		1,268,312		–		1,268,312
Total (undiscounted)		12,306		21,831		2,271,460		12,306		2,293,291
Total, discounted at 10%		11,530		19,220		1,106,957		11,530		1,126,177

Ivanhoe intends to use its cash and cash equivalent balance to partially fund development costs in 2012. 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 the Company will be able to obtain additional financing or obtain it on favorable terms. If the Company cannot secure additional financing, the Company may have to delay or cancel one or more of the Company capital programs and forfeit or dilute the Company’s rights in existing oil and gas property interests.

PART 6: OTHER OIL AND GAS INFORMATION

Item 6.1: Property Descriptions

The Company’s oil and gas operations may be found in three geographic areas: Asia, Canada and Ecuador.

Asia

China

Zitong

In November 2002, we entered into a 30 year production sharing contract (“PSC”) with China National Petroleum Corporation (“CNPC”) for the Zitong block, which covers an area of approximately 248,000 gross acres after contractual relinquishments in the Sichuan basin. In 2006, we farmed out 10% of our working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan (“MGC”) for $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 of the contract, the Yixin-2 and Zitong-1 gas wells were drilled in late 2010 and completed in early 2011. Both wells encountered gas in the Xu-4 Formation and were shut-in for pressure build-up following initial flow and pressure tests.

On December 30, 2011, the Company entered into a supplementary agreement to the Contract for Exploration, Development and Production in Zitong Block, Sichuan Basin with CNPC for the Zitong block (“Supplementary Agreement”). The Supplementary Agreement effectively extends the exploration period under the PSC by creating a 36 month evaluation phase beginning July 1, 2011, for the performance of additional work. The Supplementary Agreement is subject to ratification by the Ministry of Commerce of the People’s Republic of China.

On January 11, 2012, Ivanhoe signed a binding Memorandum of Understanding which contemplates a transaction (the “Zitong Transaction”) whereby Ivanhoe will assign its entire working interest in the Zitong PSC to Shell China Exploration and Production Company Limited (“Shell”). Completion of the Zitong Transaction is subject to government approvals and other prescribed conditions, including rights of first refusal by both CNPC and Ivanhoe’s working interest partner, MGC.

Dagang

Ivanhoe’s oil production originates in the Kongnan oilfield in Dagang, Hebei Province, China (the “Dagang field”). We have a 30 year PSC with CNPC, covering an area of 10,255 gross acres. From 2000 to 2007, we drilled 46 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 2011, quotas restricted production to 80,000 gross tonnes or 1,600 bbls/d gross. Actual production in 2011 averaged 967 bbls/d net. The production quota in 2012 remains set at 80,000 gross tonnes.

Mongolia

Through a merger with PanAsian Petroleum Inc. in November 2009, we acquired a PSC 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 adjusted the dates on 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. The seismic was used to drill two wells in 2011. The first exploration well, N16-1E-1A, was drilled and abandoned as the well did not encounter oil shows in the reservoir. The Company observed oil staining, fluorescence and increases in background gas at its second exploration well site at N16-2E-B.

Canada

Tamarack, acquired from Talisman in 2008, is a 6,880 acre lease located approximately 10 miles northeast of Fort McMurray, Alberta, Canada. The Tamarack integrated oil sands project (“Tamarack” or the “Tamarack Project”) is comprised of a two-phased 40,000 bbl/d steam-assisted gravity drainage thermal recovery (“SAGD”) and HTL™ facility. Our independent reserve evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), has assigned total 3P reserves of 219 mmbbls of bitumen to Tamarack. Talisman held a 20% back-in right which expired in July 2011. Additionally, in 2011, Ivanhoe repaid a $40 million promissory note to Talisman that was part of the initial purchase price.

Ivanhoe filed an Environmental Impact Assessment for the Tamarack Project in November 2010. Regulators completed their initial review of the Company’s application and, as is customary, provided an initial set of Supplemental Information Requests in the third quarter of 2011. The Company submitted the supplemental information to the regulators in the fourth quarter of 2011.

As the regulatory process unfolds, Ivanhoe continues to engage and consult with numerous local and aboriginal stakeholders to identify potential project impacts and mitigations and economic and employment opportunities for residents of area communities. It is anticipated that the regulatory approval process will be completed later in 2012. Project advancement, as currently envisaged, is subject to regulatory approval, financing and board sanction.

Ecuador

In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary, signed a 30 year contract with the Ecuador state oil companies Petroecuador and Petroproduccion. The contract gives the Ivanhoe 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. The Company anticipates using 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, Ivanhoe drilled its first two appraisal wells in the Pungarayacu field. The second, 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. In 2011, the heavy crude oil extracted from the IP-5B well was successfully upgraded to local pipeline specifications using Ivanhoe’s proprietary HTL™ upgrading process. Later in 2011, the Company completed a 190-kilometre 2-D seismic survey over the southern portion of Block 20. Following the analysis of the seismic program, Ivanhoe began preparing to drill one exploration well into the deeper Hollin and pre-cretaceous horizons in the southern part of the Pungarayacu Block to test the potential of lighter oil resources, which would prove beneficial for blending purposes and overall project economics.

Producing Oil Wells

The Company does not have any producing gas wells. The Company had 49.0 gross (24.0 net) productive oil wells in Asia, as at December 31, 2011.

Item 6.2: Properties with no Attributed Reserves

Developed Acres

Undeveloped Acres(1)

Gross

Net

Gross

Net

Asia – China(2)

1,724

845

253,496

225,683

Asia – Mongolia

–

3,107,907

Canada

–

7,520

Latin America

–

272,639

(1)

Undeveloped acreage is considered to be those acres on which wells have not been drilled or completed to a point that would permit production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

(2)

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 lease 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.

Ivanhoe signed a specific services contract with affiliated entities of the State of Ecuador in October 2008 that allows us 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.

Subsequent to the completion of Phase II of the Zitong Contract, acreage not identified for development and future production was relinquished to CNPC in 2011. The remaining Zitong acreage will be assigned to Shell upon closing of the Zitong Transaction and receipt of the requisite government approvals, or relinquished upon termination of the production sharing contract in 2032.

According to the existing contract, acreage in the Dagang field will return to CNPC upon contract termination in 2027, at the latest, unless Ivanhoe abandons the field before then.

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.

Item 6.4: 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.

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 ($5.5 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 216 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, 2011, and the Company estimates its 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 2011 were as follows:

(US$000s)	Canada		China		Ecuador		Total
Property acquisition costs
Unproved		–		–		767		767
Exploration		9,697		23,094		11,536		44,327
Development		–		12,923		–		12,923
Total costs incurred		9,697		36,017		12,303		58,017

Item 6.7: Exploration and Development Activities

At December 31, 2011, the Company was not actively drilling any wells; seven wells were completed in 2011. At December 31, 2010, Ivanhoe was 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.

Refer to Item 6.1, Property Descriptions, for a description of the Company’s most important current and likely exploration and development activities, by country.

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 994 bbls/d.

Item 6.9 Production History

Ivanhoe’s oil production originates in Asia, specifically the Dagang and Daqing fields in China. Production from Dagang and Daqing in 2011 was 341,258 bbls and 11,842 bbls, respectively.

The Company’s production and net operating revenue in China for the fiscal year ended December 31, 2011 is presented below by quarter and in total.

	Q1		Q2		Q3		Q4		Total
Average daily production (bbls/d)	1,007		940		1,029		894			967

Net operating revenue ($/bbl)
Oil revenue	89.62		109.71		113.74		110.97			105.93
Less operating costs
Field operating	(17.92	)	(19.76	)	(17.91	)	(23.56	)		(19.68	)
Windfall Levy	(17.39	)	(25.51	)	(27.30	)	(22.39	)		(23.18	)
Engineering and support costs	(1.21	)	(1.20	)	(1.34	)	(1.20	)		(1.24	)
Net operating revenue	53.10		63.24		67.19		63.82			61.83

Total production (bbls light and medium oil)	90,599		85,581		94,674		82,246			353,100

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