Ivanhoe Energy issues operational update on major development and exploration projects

June 15, 2011

Focus on execution remains key priority

CALGARY, June 15, 2011 /PRNewswire/ – 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

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

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

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 9(o) 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 17(o), 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(TM)). 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

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
“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.

SOURCE Ivanhoe Energy Inc.

Source: newswire

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