Ivanhoe Energy issues operational update on major development and exploration projects

Focus on execution remains key priority

CALGARY, June 15, 2011 /CNW/ - David Dyck, President and Chief Operating Officer of Ivanhoe Energy Inc. (TSX: IE, NASDAQ: IVAN), today issued an operational update on the company's major initiatives and outlined the company's priorities to advance domestic and international projects toward production.

"Ivanhoe Energy is well positioned to take advantage of current economic conditions and continue to advance the development of our heavy oil and conventional oil and gas projects in key resource regions around the world," Mr. Dyck said.

"We have a diverse portfolio of high-quality assets and can report some very positive developments. Our primary approach to financing our ongoing activities is focussed on identifying and securing joint-venture partners to join us in our projects. Where applicable, we also are considering financing at the subsidiary company level for specific projects, which would establish a significant level of self-sufficiency within the subsidiaries for financing and to fund ongoing capital expenditures."

Notable gas exploration achievements in China's Zitong Block

Sunwing Energy, Ivanhoe Energy's 100%-owned Asia-focussed subsidiary, successfully completed two hydraulic-fracture stimulation programs on the Yixin-2 and Zitong-1 wells in China's Sichuan Province. The results of these treatments, and subsequent flow testing, have confirmed that stimulation of these high-pressure reservoirs can be achieved and that multi-stage stimulation technology, combined with horizontal drilling technology, can be applied in the Zitong Block.

The company's drilling and stimulation activities have resulted in positive achievements in the evaluation of the reservoirs in the Zitong Block. The company has successfully produced gas at measurable rates in both the Xu-4 and the Xu-5 formations. We have demonstrated our ability to successfully conduct a high-pressure hydraulic fracture in both reservoirs and place proppant in these fractures, providing valuable information for the design and execution of future fracture treatments in horizontal wellbores. The data recorded to date in the vertical wellbores provide sufficient information to model expected production performance in a horizontal wellbore. While permeabilities of the reservoirs result in rapidly declining flow rates and pressures in the pre-stimulation testing, these rates of decline are consistent with pre-stimulation flows in most tight sands. In fact, the actual recovery of gas in all of Sunwing's tests exceeded results of pre-stimulation testing in many tight-gas projects in North America. The company is confident that the results of the current testing will allow successful design and implementation of horizontal wellbores with subsequent stimulation using the latest technology for multi-stage fracture stimulations.

Sunwing is planning a 150-square-kilometre, 3-D seismic program to cover certain areas of the Guan Structure, the Guan East Structure and part of the Wen Structure to help plan and design a horizontal well-path for two horizontal wells - one each in the Guan and Wen structures. The company also will review the potential to drill a Guan East well with a horizontal leg as a first-stage test of the regional gas play, or re-enter the Zitong-1 wellbore to complete a horizontal section in the Xu-4 Zone. This program will be carried out over the next 24 months and will provide the groundwork for development of the Zitong Block.

Results of the work carried out to date have reinforced Sunwing's original resource estimates for the Zitong Block and the company is working toward implementing its onward program as soon as possible.

Gerald Moench, President of Sunwing, said the company believes that the Zitong Block contains between 0.3 (P90) and 1.7 (P10) trillion cubic feet of total gas initially-in-place, with a best estimate (P50) of 0.75 trillion cubic feet. "The successful development of this block will have a dramatic impact on the value attributable to Ivanhoe Energy and we are working towards implementing a development program as soon as possible."

Sunwing is the operator of the 659,840-acre (1,031-square-mile) Zitong exploration block in Sichuan and holds a 90% contractor interest in a Petroleum Contract with PetroChina Company Limited. Mitsubishi Gas Chemical Company, of Japan, holds the remaining 10% interest. Sunwing is currently conducting further evaluation to permit classification of the resource numbers quoted into more specific categories pursuant to National Instrument 51-101, to estimate the recoverable portion of these in-place volumes and to determine their commerciality. In the meantime, there is no certainty that it will be commercially viable to produce any portion of these resources

Yixin-2 well

On December 21, 2010, Sunwing announced a natural-gas discovery at its Yixin-2 well, which tested at initial pre-stimulation flow rates of up to 13,000 Mcf/d. The well was drilled to a vertical depth of 4,165 metres (13,660 feet) into the Xu-4 reservoir and was the first of two wells drilled in Phase II of the exploration period to satisfy certain contractual commitments on the block.

Following the post-perforation clean-up flow, and a short shut-in period, the Yixin-2 well was flow tested at a controlled rate of between 1,250 to 1,500 Mcf/d for a 48-hour period, then shut-in for a 21-day pressure build-up period to obtain critical pressure data and to organize high-pressure pumping equipment to carry out a fracture stimulation of the Xu-4. A 100-ton hydraulic-fracture stimulation utilizing high strength proppant was later successfully conducted on the Xu-4 formation.

The well was flow tested for a 30-day period through a test separator and currently is shut-in on a 60-day final pressure build up. During this flow period, 47% of the frac fluid used to stimulate the well was recovered. The initial gas flow rate after fracturing was approximately 800 Mcf/d at a flowing pressure of 7,100 psi. The final flow rate before shut-in was 73 Mcf/d at a flowing pressure of 86 psi. Following the post-frac flow test, down hole electronic recorders were run with the current shut-in period to extend to mid- to late-July. Results of the build-up, as well as the flow-test data, will provide critical reservoir information necessary for forward planning and in discussions with our partner, PetroChina.

The post-fracture stimulation results observed are not uncommon in tight-gas sand reservoirs; the rate declines the longer the well is flowed as more of the tighter formation matrix is tested. The key to unlocking the potential of tight-gas reservoirs is to generate induced fractures to provide sufficient surface flow area to maintain a constant commercial inflow of gas. The fracture operation on Yixin-2 was pumped as planned and, from initial indications, the well has an effective induced fracture system. Preliminary indications are that the permeability of the Xu-4 in this particular part of the Zitong Block may be lower than originally estimated. Initially, Ivanhoe had hoped the Xu-4 could be effectively stimulated in a vertical wellbore; however, these initial post-frac results suggest horizontal wells with multi-staged fracture stimulations are the preferred exploitation strategy to not only access sufficient natural fractures but also to create additional fractures to achieve the desired, stabilized inflow rate.

Zitong-1 well

The Zitong-1 well was drilled in the Guan Structure to a vertical depth of 4,294 metres (14,084 feet). It originally was designed to test the potential of the deeper Xu-2 through a horizontal wellbore. Sunwing perforated and evaluated the Xu-2 Zone. After a brief flow and build-up test, it was determined that this zone was very tight in this particular location. As a result, Sunwing chose to concentrate on other up-hole zones. Since the well intersected the Xu-5 reservoir section and also the Xu-4 at shallow depths, Sunwing proceeded to test both zones in the vertical wellbore. Early in 2011, Sunwing perforated the Xu-4 formation and allowed the well to flow at a final rate of 680 Mcf/d, with a flowing wellhead pressure of 2,196 psi. The flow and build-up test indicated low permeability away from the wellbore and Sunwing decided to isolate the Xu-4 and move up-hole to test the Xu-5 Zone.

The Xu5 Zone was perforated, acidized and flowed, with a final flow rate of 510 Mcf/d at a flowing tubing pressure of 1,214 psi. A post-perforation/acidization flow and build-up test on the Xu-5 Zone showed an effective permeability estimated at 0.0075 mD, well within the acceptable parameters for successful tight-gas plays in other regions, such as North America and the Middle East. The initial recorded reservoir pressure was 10,636 psi which would be considered to be over-pressured.

In May 2011, Sunwing stimulated the Xu-5 Zone with a 200-tonne fracture treatment using high-strength proppant. The zone has been on flow test since then. The well flowed to a test separator and recovered approximately 62% of the frac fluid before any measurable gas rates were recorded. Initial gas flow rates after fracturing measured up to 287 Mcf/d at pressures of up to 1,682 psi. The well was completed with 114.3-mm (4½-inch) tubing to conduct the high-rate fracture treatment; however, due to the larger tubing, the well encountered liquid unloading problems. Sunwing utilized coil tubing and nitrogen to clean the water from the wellbore to allow continued flow testing of the well. At present, the well may have a "water block" in the reservoir that has been preventing the in-flow of gas into the wellbore. Preparations are underway to inject a sufficient volume of nitrogen into the formation in an attempt to remove or reduce the effect of the apparent water block. Water blocks in low-permeability formations can occur following stimulation. Following the nitrogen injection and following blow down, the well will be flow tested and then shut-in for an extended pressure build up.

Preparations for first well on Mongolia's Nyalga Block

Sunwing has recently instructed its drilling contractor to mobilize the drilling rig and associated equipment to the first selected location in the Nyalga Basin in Mongolia. Mobilization activities will take approximately one month to complete. Sunwing will spud its first Mongolian oil well on a 15 sq km structure identified by 2D seismic in late July. The second drilling location will be centered on an adjacent structure with follow-on locations contingent on progressive drilling success. The current focus of exploration represents just a small portion of the total basin area. Detailed evaluation and testing, as required, will be conducted on our initial wells following drilling.

While existing seismic data has assisted in the selection of the first two locations, Sunwing intends to acquire additional 2D seismic on other portions of the block, and if necessary, acquire 3D seismic to better assess future drilling locations and trapping systems. The drilling rig has been contracted for two initial locations, with an option for three additional wells in 2011, weather permitting. Drilling on these two structures should provide a reasonable assessment on the overall potential of the Block which is over 12,000 sq. km in size with very little seismic detail. Given the main Mongolia to China railway and highway crosses through the eastern side of Block XVI, logistical activities can leverage off this proximity to existing infrastructure.

Tamarack heavy-oil project progressing through Alberta's regulatory approval process

The Tamarack Project is continuing to progress through the Province of Alberta's regulatory approval process. The application was submitted to the government in October 2010 for the development of an integrated in-situ heavy-oil project to be built in two phases, each of 20,000 barrels per day, with an ultimate production capacity of approximately 40,000 barrels per day (bitumen basis).

Regulators completed their initial reviews of the Tamarack submission and, as is customary, provided the company with an initial set of Supplemental Information Requests (SIRs) in May 2011. Ivanhoe Energy is preparing responses that it plans to submit to the regulators in Q3, 2011. The company is continuing to work with numerous local and aboriginal stakeholders and identify economic and employment opportunities for residents of area communities. Progress to date indicates that the Tamarack Project remains on track for approval expected in the second-half of 2012.

Tamarack is a 6,880-acre contiguous block located approximately 10 miles (16 kilometres) northeast of Fort McMurray. Ivanhoe Energy holds a 100% working interest in the project, subject only to a 20% back-in right held by Talisman Energy, which expires in July 2011. Ivanhoe recently completed a $50 million public offering, a portion of which will be used to repay Talisman's convertible promissory note.

Tamarack engineering update

Tamarack project engineering and execution plans continue to progress smoothly in anticipation of regulatory approval. Design of the surface facilities is ongoing with AMEC-BDR, with completion of the Front-End Engineering and Design (FEED) anticipated in the fall of 2011. Detailed engineering will begin in the fourth quarter of 2011 once the FEED has been completed. The project execution plan is being developed and will use best-in-class construction methodologies.

Infrastructure and HTL considerations

The company is pursuing the option of providing for a co-generation facility to supply the project's initial power needs. This power plant will be integrated into the design of the central processing facility to take advantage of process efficiencies - an approach that improves the project economics, removes a large scheduling risk beyond the control of the company and has positive environmental benefits. The project eventually will be tied into the regional power grid, further improving the production facility on-stream factor and project economics by taking advantage of excess power sales.

Alternatives to access markets for the sale of whole or blended bitumen and HTL Synthetic Crude Oil (SCO) produced from Tamarack continue to be assessed. Maintaining the option to sell a variety of products is important for the company to take advantage of changing market conditions over the life of the project.

Ivanhoe Energy also maintains complete optionality on the deployment of HTL technology for Tamarack. The application now being reviewed by regulatory authorities consists of an integrated project. However, key economic and commodity indicators impact the decision to warrant the capital investment, which is continually assessed by the company's management. For Ivanhoe Energy, investment returns are robust under either a stand-alone upstream model or an integrated upstream/HTL model. This flexibility is a competitive advantage for Ivanhoe as HTL addresses downside economic conditions associated with a wider, heavy-to-light price differential. Tamarack's detailed engineering and design incorporates applicable components that would facilitate the commissioning of a HTL facility but in any event would take approximately 36 months from the decision point to proceed with detailed engineering for a HTL facility. The company believes that the longer term North American heavy-oil differential will widen to the point that the economics of upstream-only operations are challenged. HTL provides a unique solution that can be built on much lower capital intensity than other existing methodologies and, due to this modest scale, allows Ivanhoe Energy to act quickly in response to fundamental economic drivers and take advantage of corporate and/or asset opportunities in the future.

To maximize flexibility to reach markets that will provide the highest netbacks, both pipeline and rail options are being investigated. Natural gas and diluent supply points and providers are being considered and these will be connected to Tamarack to provide start-up and ongoing operational flexibility.

Sub-surface engineering and geology update

Since the submission of the application for the Tamarack Project, Ivanhoe's sub-surface engineering and geological team has continued to support the project application and refine the understanding of the resources. Incorporation of information from the past winter's drilling program contributed to the previously announced increases in independently assessed, probable reserves to 176 million barrels and the best-estimate contingent resource to 345 million barrels.

New information has been incorporated into an updated 3-D geologic model to further refine the understanding of reservoir quality and the implications for project performance. This updated model continues to confirm that high-quality pay targets for SAGD development are present in the Tamarack development area. This 3-D geological model will be used in conjunction with reservoir simulation to optimize the reservoir development plan. The company currently expects that 12 well pads and approximately 160 SAGD well pairs will be required to fully develop and produce the targeted resource base.

Additionally, Ivanhoe Energy has identified high-quality expansion opportunities on the Tamarack lease, beyond the Phases 1 and 2 areas identified in the application. These will be delineated in a drilling program expected during the coming winter.

Successful upgrading of Pungarayacu oil creates Ecuador JV interest

Ivanhoe's Pungarayacu Project is located on the eastern foothills of the Andes Mountains. It is easily accessible via a network of existing infrastructure. An oil pipeline with spare capacity runs through the lease block. Block 20 is one of only a few that has been classified as strategically important by the Ecuadorian government for full field development. The presence of hydrocarbons has been known since the 1980s; however, up until now, viable extraction and upgrading solutions that address environmental concerns have been elusive. Ivanhoe Energy's HTL process has the potential to address these sensitivities and, in doing so, provide economic development for the people of Ecuador.

The Pungarayacu field has been independently estimated to contain between 4 to 12 billion barrels of Original Oil in Place (OOIP), which according to the Canadian Oil and Gas Evaluation Handbook are classified as Undiscovered Resources. This potentially significant resource has attracted interest by multi-national corporate entities, as well as national energy companies. Interests of all key stakeholders are being respected as development work proceeds. In early development work, Ivanhoe Energy successfully recovered 9o API heavy oil during 2010 that was taken to the company's Feedstock Test Facility in San Antonio, Texas, for testing. Ivanhoe Energy successfully upgraded the Pungarayacu heavy crude to 17o, which meets local pipeline specifications. This represented a significant milestone for the project and created a renewed interest among potential joint-venture partners.

Ivanhoe Energy also plans to assess the southern border of the existing field. A geologic interpretation suggests the heavy-oil field may extend southward to a far greater extent than previously expected. Geologic evidence suggests that a deeper, lighter oil play exists on the block. The objective of Ivanhoe's currently 2-D seismic program is to determine the likelihood of geological trapping systems that would support these views.

Ivanhoe is continuing to make good progress on its previously disclosed 190-kilometre 2-D seismic program and expects the initial phase of shooting and processing will be completed in early July this year. The seismic data will assist in the selection of future appraisal drilling locations. The seismic program fully complies with all Ecuadorian regulatory requirements and has the approval of local stakeholders after extensive consultation.

HTL Business Development

In addition to the known heavy-oil projects in Canada and Ecuador, Ivanhoe Energy also is pursuing a number of prospective HTL projects as business development opportunities. These projects have the potential to provide third-party validations of the HTL process.

Ivanhoe Energy Inc. is an independent, international heavy-oil development and production company focused on pursuing long-term growth in its reserves and production using advanced technologies, including its proprietary, patented heavy-to-light upgrading process (HTL™). Core operations are in Canada, the United States, Ecuador, China and Mongolia, with business development opportunities worldwide. Ivanhoe's shares trade on the Toronto Stock Exchange under the symbol IE and on the NASDAQ Capital Market with the ticker symbol IVAN.

For more information about Ivanhoe Energy Inc., please visit our web site at www.ivanhoeenergy.com.

STATEMENTS CONCERNING RESERVES AND RESOURCES. Cautionary Note to U.S. Investors:  We use certain terms in this news release, such as contingent resources, which the SEC's guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to also consider closely the disclosure in our Form 10-K for the fiscal year ended December 31, 2010, available from the Company's website. You also can obtain this form from the SEC website at www.sec.gov.

The determination of oil and gas resources involves the preparation of estimates that have an inherent degree of associated risk and uncertainty. The estimation and classification of resources requires the application of professional judgment combined with geological and engineering knowledge to assess whether specific classification criteria have been satisfied. Statements in this news release concerning "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, of the ability to produce in the future the resources described. Actual resources and, if commenced, future production will differ from the estimates provided herein, and the difference may be significant. 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 the 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 further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status. [Reserves are further defined below].

          Proved Reserves
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
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
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.

Contingent Resources
Certain of the resource volumes referred to in this news release have been classified as "contingent resources" within the meaning of the COGE Handbook. The term "contingent resources" is defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.

Contingent resources are further classified in accordance with the level of uncertainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. Estimates of resources, which always involve uncertainty, are quoted herein as a range according to the level of confidence associated with the estimates. The "best estimate" is considered to be the best estimate of the quantity of bitumen resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. The "low estimate" is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. The "high estimate" is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. The contingencies that currently prevent the contingent resources referred to herein from being classified as reserves are a lack of regulatory approval, the absence of a firm development plan, and the uncertainty of funding approval for development. There is no certainty that it will be commercially viable to produce any portion of the contingent resources referred to in this press release.

FORWARD-LOOKING STATEMENTS: This document includes forward-looking statements, including forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  Forward-looking statements include, but are not limited to, statements concerning the anticipated timing and results of planned fracture stimulation and further evaluation and testing of the Yixin-2 and Zitong-1 well, the future tie-in of the Zitong Block wells to the local gas-gathering system, the anticipated receipt of regulatory approvals for the Tamarack Project, the achievement of other project development milestones, and other statements which are not historical facts. When used in this document, the words such as "could", "plan", "estimate", "anticipate", "intend", "may", "potential", "should", and similar expressions relating to matters that are not historical facts are forward-looking statements. Although Ivanhoe Energy and Sunwing Energy believe that their expectations reflected in these forward-looking statements are reasonable, such statements involve risks and uncertainties and no assurance can be given that actual results will be consistent with these forward-looking statements. Important factors that could cause actual results to differ from these forward-looking statements include the possibility that the company will be unable to raise financing in the future for any of its projects, the possibility that required regulatory approvals will be denied or delayed, the potential that the company's projects will experience technological and mechanical problems, new product development will not proceed as planned, the HTL technology to upgrade bitumen and heavy oil may not be commercially viable, market acceptance of the HTL technology may not be as anticipated, Ivanhoe Energy's lack of history in developing commercial HTL opportunities, geological conditions in reservoirs may not result in commercial levels of oil and gas production, the availability of drilling rigs and other support services, uncertainties about the estimates of the reserves, the risk associated with doing business in foreign countries, environmental risks, changes in product prices, our availability to generate cash flow and raise capital as and when required, competition and other risks disclosed in Ivanhoe Energy's Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission on EDGAR and the Canadian Securities Commissions on SEDAR.

For further information:

David Dyck
President and Chief Operating Officer

1 (403) 817 1138
            Greg Phaneuf
Executive Vice President, Corporate Development

1 (403) 817 1131


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