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

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8-K - FORM 8-K - IVANHOE ENERGY INC	eh1400462_8k.htm
EX-99.3 - EXHIBIT 99.3 - IVANHOE ENERGY INC	eh1400462_ex9903.htm
EX-99.2 - EXHIBIT 99.2 - IVANHOE ENERGY INC	eh1400462_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, 2013

March 17, 2014

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	5

PART 5: ADDITIONAL INFORMATION RELATING TO RESERVES DATA

	ITEM 5.1: Undeveloped Reserves	6

	ITEM 5.2: Significant Factors or Uncertainties Affecting Reserves Data	6

	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	10

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, 2013, 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; 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 date of this Statement is March 17, 2014. The estimates and disclosures in the Statement have been prepared in accordance with NI 51-101 and have a preparation date of February 5, 2014 with an effective date of December 31, 2013.

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 2013 Form 10-K.

Summary of Oil Reserves as of December 31, 2013

Forecast Prices and Costs

	Canada
	Bitumen
(mbbl)	Gross		Net
Proved
Developed producing		–		–
Undeveloped		–		–
Total proved		–		–
Probable		171,827		135,710
Total proved plus probable		171,827		135,710

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, 2013

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
		0	%	5	%	10	%	15	%	20	%	0	%	5	%	10	%	15	%	20	%	($/bbl)
Canada
Probable		4,418,978		1,654,949		617,296		183,767		(10,957	)	3,331,055		1,194,860		396,802		66,841		(78,082	)		4.55
Total probable		4,418,978		1,654,949		617,296		183,767		(10,957	)	3,331,055		1,194,860		396,802		66,841		(78,082	)		4.55

Total Future Net Revenue (Undiscounted) as of December 31, 2013

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
Canada
Total proved plus probable		12,989,591		2,737,041		3,415,703		2,377,346		40,522		4,418,978		1,087,923		3,331,055

Future Net Revenue by Production Group as of December 31, 2013

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 plus probable	Heavy oil			617,296				4.55

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, 2013

Forecast Prices and Costs

	Heavy oil
Year	Hardisty heavy (Cdn$/bbl)		Inflation rate (%)		Exchange rate ($US/$Cdn)
Historical
2013		65.07		1.0		0.971
Forecast
2014		65.72		2.0		0.950
2015		70.03		2.0		0.950
2016		72.85		2.0		0.950
2017		72.85		2.0		0.950
2018		72.85		2.0		0.950
2019		72.85		2.0		0.950
2020		73.42		2.0		0.950
2021		74.90		2.0		0.950
2022		76.42		2.0		0.950
2023		77.97		2.0		0.950
Thereafter	+2.0%/yr			2.0		0.950

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.

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 Canada, based upon forecast price and cost assumptions.

Reconciliation of Reserves

Forecast Prices and Costs

	Canada Heavy oil
(mbbl)	Gross probable
December 31, 2012		175,684
Extensions		–
Technical revisions		(3,857	)
Production		–
Dispositions		–
December 31, 2013		171,827

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 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:

	Heavy oil
(mbbl)	Probable undeveloped

December 31, 2013		–
December 31, 2012		–
December 31, 2011		–
Aggregate prior to December 31, 2011		175,684

Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive infill drilling locations and lands contiguous to production. Probable undeveloped reserves were estimated by GLJ in accordance with the procedures and standards contained in the COGE Handbook.

The timing of undeveloped reserve development in Canada is dependent upon approval of the Company’s regulatory application to develop the Tamarack 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 as a result of 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" in the Company’s 2013 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, 2013

Forecast Prices and Costs

		Canada
($US000s)		Total proved plus probable reserves

2014		9,975
2015		12,355
2016		72,992
2017		439,502
2018		477,388
Remainder		1,365,134
Total (undiscounted)		2,377,346
Total, discounted at 10%		1,024,737

Additional sources of funding 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 markets. However, there is no assurance that these sources of funding will be available to the Company in the future or available on acceptable terms, and any future equity issuances may be dilutive to current investors. If Ivanhoe cannot secure additional financing, the Company may have to delay its capital programs and forfeit or dilute its rights in existing oil and gas property interests.

PART 6: OTHER OIL AND GAS INFORMATION

Item 6.1: Property Descriptions

The Company conducts its oil and gas operations in three geographic areas: Canada, Ecuador, and Mongolia.

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 Project envisages 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 net probable reserves after royalties of 136 mmbbls of bitumen to Tamarack.

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 (“SIRs”) in the third quarter of 2011. The Company submitted the supplemental information to the regulators in the fourth quarter of 2011.

The Company received additional SIRs in the second and fourth quarters of 2012 and responded to the SIRs in July and November 2012, respectively. On January 21, 2013, the Company received a Completeness Determination from Alberta Environment and Sustainable Resource Development pursuant to Section 53 of the Environmental Protection Act following its review of the Tamarack Environmental Impact Assessment. In August 2013, the Company enhanced its application by submitting an addendum. The addendum included results acquired in the first quarter of 2013 from the testing and coring of three additional wells and 3D seismic data from a portion of the project's area.

In December 2013, the Company learned that the Alberta Energy Regulator (“AER”) intends to conduct a thorough technical review of the factors that affect reservoir containment of shallow SAGD projects and will be consulting with stakeholders to develop formal regulatory requirements. Following discussions with each affected industry applicant, the AER issued a bulletin with interim guidelines. The AER now indicates that they will develop the new requirements following extensive industry and stakeholder engagement. This decision and process affects all shallow SAGD projects, including Ivanhoe's Tamarack Project.

Ivanhoe met with the AER in December 2013 and was advised that, per the interim guidelines, the Tamarack application would not continue to be processed until (a) 3D seismic has been collected and interpreted over the entire initial development area and (b) the maximum operating pressure meets the interim guidelines.

The Company then prepared to launch a seismic program over the remaining portion of the initial development area for which seismic had not been shot, and continued to discuss with the AER the validity of the Company’s methodology for its proposed maximum operating pressure. The Company was given an indication that the AER might consider assessing and ruling on the validity of its methodology, but in a letter dated February 6, 2014 and received by the Company on February 24, 2014 the AER said that it would not do so. At that point the Company cancelled the costly seismic program for this winter.

The Company is continuing its discussions with the AER and is exploring its alternatives for moving the Tamarack Project forward. In addition, the Company continues its discussions with local stakeholders to address any statements of concern as part of the regulatory process. Ivanhoe continues to believe that its proposed development plan for Tamarack is safe and economically viable and expects the project will be approved. However, until the new formal regulatory requirements are known, Ivanhoe cannot determine whether the Tamarack Project, as currently proposed, will ultimately fit within those requirements.

The Company has suspended activity, including capital investment, on its current Tamarack oil sands project application, except for essential items, pending clarity from the AER on the final regulatory requirements for shallow SAGD projects and/or any continuing discussions the Company might have with the AER.

Ecuador

In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary, signed a 30 year specific services contract with the Ecuadorian state oil companies Petroecuador and Petroproduccion. The contract (which was subsequently assigned to another Ecuadorian state oil company, Petroamazonas) gives 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 city. The specific services contract provides for the Ecuadorian Government to pay a fee for each barrel of oil produced from the field. This fee fluctuates based on three published producer price indices and, in the Company’s opinion, tracks West Texas Intermediate benchmark oil price movements. 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 blend any light oil discoveries with the heavy oil for delivery to Petroamazonas.

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 at its test facility in San Antonio. 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.

In 2012, the Company drilled well IP-17 in the pre-cretaceous zone in the Southern portion of the Block to test the formations in this area. It was successfully drilled to a depth of 13,594 feet, where it was cased and suspended. The well confirmed the presence of hydrocarbons in the Hollin and Napo formations and evaluated the potential of the deeper, pre-cretaceous structures. While hydrocarbons were found in the Hollin and Napo formations, the reservoir in the immediate vicinity of the well was not suitable for commercial exploitation.

During 2013, the Company drilled well IP-14b to a total depth of 1,150 feet and encountered hydrocarbons in the Hollin formation. On December 31, 2013, the first phase of the Specific Services Contract between Ivanhoe and the Ecuadorian Government, representing the evaluation phase, ended. The next steps in the contract would be the pilot and exploitation phases. However during 2013, the Company has been engaged in discussions with a large international oil company regarding the concept of jointly investing and participating in the development and operation of Block 20. During the course of these discussions, the parties have developed a framework of commercial terms which has been used in separate discussions with the Government of Ecuador. The ultimate objective of these discussions with the Ecuadorian Government has been the establishment of mutually acceptable terms and conditions allowing for the formation of a consortium between the Company and the third party to jointly develop Block 20. The formation of the consortium is contingent upon the successful negotiation of definitive and legally binding agreements that reflect the achievement of this

objective. Although Ivanhoe remains optimistic, there is no assurance that this objective will be achieved or achieved in a timely manner. The outcome of these discussions is likely to have a significant impact on the Company’s continuing participation in the Block 20 project.

Asia

Mongolia

Through a merger with PanAsian Petroleum Inc. in November 2009, we acquired a production sharing contract (“PSC”) for the Nyalga Block XVI in the Khenti, Govi Sumber and Tov provinces in Mongolia. The project is operated by a Mongolian registered company Shaman LLC (“Shaman”) which is an indirect wholly-owned subsidiary of Panasian Energy Ltd. The block currently covers an area of approximately 9,239 square kilometers. 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 elect 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. After extensive laboratory testing of the drill cuttings from the second well it was determined that the oil was not of a mobile nature and the decision was made to forego any completion operations. Well site reclamation work has been completed and the local government has signed off on the acceptance of the reclamation works.

In early 2013, the Company completed the acquisition of a 106 kilometer 2-D seismic program and completed processing of the results. This new seismic data has been incorporated with the recent drilling results by independent consultants and an up-to-date prospects report has been finalized as of the third quarter of 2013. The report has recommended potential for 3 drill sites to be evaluated based on this review result.

The five year initial term of the exploration license was to expire July 19, 2013. The Company applied for, and was granted a two year extension to the PSC after meeting the minimum expenditure requirement, extending the term to July 19, 2015 providing additional time to find a partner or buyer.

The PSC permits an additional two year extension from July 2015.

Producing Oil Wells

The Company does not have any producing wells at December 31, 2013.

Item 6.2: Properties with no Attributed Reserves

Developed Acres

Undeveloped Acres(1)

Gross

Net

Gross

Net

Asia – Mongolia

–

2,283,234

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.

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 filed the Tamarack Project application in 2010 and the application has been under regulatory review since this that time. Recent regulatory changes have required additional information to continue to process the application. The impact of these changes could affect the approval or timing of the project.

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.

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 2014 and 2038.

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, 2013, our expected undiscounted A&R costs are $40.5 million ($4.3 million, discounted at 10%) for proved and probable reserves, including $nil 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 associated with 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, 2013, 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 2013 were as follows:

(US$000s)	Asia		Canada		Ecuador		Total
Exploration		722		11,196		7,982		19,900
Development		–		–		–		–
Total costs incurred		722		11,196		7,982		19,900

Item 6.7: Exploration and Development Activities

At December 31, 2013, the Company was not actively drilling any wells; no wells were completed in 2013.

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

In 2012, the Company sold its interest in its sole oil production from the Kongnan oilfield in Dagang, Hebei Province, China and has no current production.

Item 6.9: Production History

In 2012, the Company sold its interest in its sole oil production from the Kongnan oilfield in Dagang, Hebei Province, China and has no current production.

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