Ivanhoe announced summary financial results and operating highlights for the year ended December 31, 2010. All figures reported are in US dollars unless otherwise noted. Ivanhoe Energy has filed its annual report on Form 10-K for the year ended December 31, 2010.
"During 2010, Ivanhoe Energy made tremendous progress on several fronts across each of our core assets, setting the stage for our team to continue executing within each of our geographical regions," said David Dyck, President and Chief Operating Officer. "In 2011, we will build on the successes and achievements of the past year, and our efforts to accelerate various discussions and due diligence activities to establish strategic partnerships and financing arrangements continues to be a key focus of our management team."
Tamarack Project - Canada
Ivanhoe Energy completed its winter delineation drilling program at Tamarack in early 2010 and, in November 2010, the Company marked a major milestone towards commercial production with the submission of its regulatory application to the Government of Alberta for the Tamarack Project. Ivanhoe Energy holds a 100 percent working interest in this Project which is expected to produce approximately 40,000 barrels per day for at least 30 years.
Subsequent to year end, Ivanhoe Energy announced that an independent reserve evaluator had recognized probable (2P) and probable plus possible (3P) reserves for the Tamarack Project. The reclassification of a portion of the contingent resources to 2P and 3P reserves is a result of the successful completion of the Company's 2010 drilling program on the Tamarack lands, further technical evaluation, and the submission of its regulatory application. GLJ Petroleum Consultants of Calgary (GLJ) assigned estimated 2P bitumen reserves of 176 million barrels and 3P bitumen reserves of 220 million barrels to Tamarack. Along with the reserves classifications, the independent 2010 evaluation recognized 345 million barrels of best estimate contingent resource. On a combined basis, the 2P reserves plus best estimate contingent resource rose 18 percent compared with GLJ's previous report for 2009.
In addition to the submission of the regulatory application for the Tamarack Project, Basic Engineering and Design was completed to support the generation of a Class III (+20/-15%) capital cost estimate. For Phase 1 (20,000 barrels per day) of a fully integrated project, the Class III estimate is $1,370 million compared to the Class IV (+25%/-20%) estimate of $1,166 million. Certain contingencies and scope changes, including capital for infrastructure, cogeneration facilities and pipelines, were included in this estimate. It is anticipated that these scope changes will contribute to lower operating expenses over the life of the project and enhance overall project economics.
Ivanhoe Energy retains flexibility regarding the timing for deployment of HTL upgrading capacity in order to maximize economic returns. Based on current market conditions in Western Canada, including narrow heavy-light price differentials and low natural gas prices, a stand-alone upstream project provides a superior economic return than does a project integrating upstream operations with an upgrading facility. Ivanhoe Energy will continue to monitor market conditions to capitalize on changing markets by adjusting project scope and timing in order to maximize project returns over the life of the project.
Based on the Class III estimate, a stand-alone upstream project would cost approximately $820 million or $40,000 per flowing barrel for Phase 1 (20,000 barrels per day) which is in line with similar in-situ oil sands projects in the Athabasca region given the current pricing environment. Based on a detailed review of the project timetable, Ivanhoe Energy believes the timeframe to receive regulatory approval for the Tamarack Project could take up to 24 months from application submittal. Subject to regulatory approval, Ivanhoe Energy has reviewed its construction and commissioning schedule for the Project and first bitumen production is anticipated in 2014. Given the significant long-term value of this asset, this development schedule is not expected to impact project economics in any significant manner.
Zitong - China
In 2010, Sunwing Energy successfully drilled two wells, Yixin-2 and Zitong-1, to total depth. These wells are located on Sunwing's 659,840-acre (1,031-square-mile) Zitong Block in Sichuan Province, the oldest and one of the most productive gas producing regions in China.
In December 2010, Sunwing Energy announced a significant natural gas discovery at Yixin-2 where gas flowed from the Xu-4 Formation at initial rates of up to 13 million cubic feet per day. Subsequently, after a short shut-in period, the Yixin-2 well was flow tested for a 48-hour period at rates of 1.5 million cubic feet per day declining to 0.667 million cubic feet per day with a tubing pressure of 2,380 psi. The flow rates of the Xu-4 Formation at the Yixin-2 well were higher than what was expected from these tight, fractured sandstones that rely on stimulation to generate commercial flow rates.
Design work is being completed and equipment has been scheduled to carry out a vertical fracture stimulation of the Xu-4 Formation in the Yixin-2 well. It is expected that stimulation equipment will be available and on location at the end of March, at which time the well will be fracture stimulated.
Subsequent to year end, the Company announced its second natural gas discovery in the Xu-4 Formation at the Zitong-1 well, located on the 70-square-kilometer Guan structure. The well was tested with a small three millimetre choke and flowed at a restricted rate of approximately 750,000 cubic feet per day at a flowing tubing pressure of 3,150 psi. Subsequently, the well was shut-in and the Xu-4 Formation was isolated to test the shallower, Xu-5 Formation. Testing of the Xu-5 Formation is continuing and the Company will provide an update when this activity is completed.
Sunwing Energy is preparing a Provisional Development Plan for the Zitong block which will be submitted to PetroChina in mid-2011. The plan will provide PetroChina with a conceptual overview of the development activity Sunwing Energy plans to undertake across the block, and will be modified as longer-term testing and data evaluation continues on the Block.
Following the drilling of the Zitong-1 and Yixin-2 wells, areas excluding those identified for development and future production were to be relinquished. In January 2011, Sunwing Energy received advice from PetroChina that the exploration period has been extended for an additional six months.
Dagang - China
At the Dagang field, production after royalties was 750 net barrels of oil per day in 2010 compared to 1,240 net barrels of oil per day in 2009. No development wells were completed in 2010, however, the Company conducted five fracture stimulations during the year. After 2010 production, total proved and probable reserves increased 76 percent to 2,530 mbbls at December 31, 2010 from 1,435 mbbls December 31, 2009, mainly due to in-field performance improvements from continued water injections and an ongoing fracture stimulation program in the Dagang field. This program will continue in 2011 in order to offset normal field decline.
In 2010, quotas restricted production to 70,000 gross tonnes or approximately 1,400 gross barrels of oil per day. In 2011, production quotas are set at 80,000 gross tonnes or approximately 1,600 gross barrels of oil per day.
Mongolia - Block XVI
In late 2009 and early 2010, the Company acquired 465 kilometers of 2-D seismic over the Kherulen sub-basin within the Nyalga basin, resulting in a total of 925 kilometers of 2-D seismic data over Block XVI in Mongolia. This data was processed and interpreted during 2010 and several drilling locations have been identified within a targeted area. Following spring break-up, the Company expects to initiate drilling operations in Mongolia in mid-2011.
During the initial seismic program, approximately 16 percent of the block was declared to be an historical site and operations in this area were suspended. A letter from the Mineral Resources and Petroleum Authority of Mongolia ("MRPAM") states that the Company's year one of "Phase I" of its contract would be extended for one year from the time the Company is allowed to re-enter this particular area. To date, access has not been granted to this area and discussions with MRPAM are ongoing. As a result, the government has adjusted the dates in which the project year begins. Phase II is now considered to have commenced on July 20, 2010.
In 2010, in line with the terms of its Production Sharing Contract, the Company completed a 25 percent relinquishment of the lands within its contract area. With this relinquishment, the Company continues to hold a significant acreage position in Mongolia representing 12,679 square kilometers (3.1 million acres).
Pungarayacu Project - Ecuador
Ivanhoe Energy drilled two appraisal wells on Block 20 in Ecuador in 2010. The first appraisal well, IP-15, encountered certain cementing and completion problems prior to steam injection operations and testing was suspended without recovering oil.
The second appraisal well, IP-5b, was successfully drilled, cored and logged. The well was perforated in the Hollin Formation and steam was injected into the reservoir resulting in the production of heavy oil to the surface. These were the first barrels of oil ever to be produced from the Pungarayacu oil field.
Independent lab analysis of the oil produced from the IP-5b well indicates an API gravity of approximately 9 to 10 degrees. The oil demonstrated very favourable viscosity reduction at elevated steaming temperatures and contained dissolved gas, which further enhances its mobility in the reservoir and will positively impact thermal recovery potential. Oil produced from the IP-5b well was transported to Ivanhoe Energy's Feedstock Test Facility (FTF) in San Antonio, Texas and successfully tested using the Company's propriety HTL process. The final data is currently being analyzed.
The Hollin formation has exhibited favourable reservoir permeabilities. This is the primary sandstone reservoir and principal producing formation in the Oriente Basin, one of the most productive of the South American Sub-Andean Basins. Ivanhoe Energy sees variability between the two well locations, supporting the view that geological faulting is prevalent in Block 20 due to the close proximity to the Andes, directly west of the block.
In 2011, the Company plans to commence a seismic program starting in the southern portion of Block to increase understanding of the geological faulting and to determine locations for future appraisal wells.
During 2010, Ivanhoe Energy continued to make technical improvements related to its proprietary HTL technology. The improvements were achieved through a new process configuration developed by an in-house technical team at the FTF. These improvements enable conversion of residual content to synthetic crude oil through a simplified operation that delivers lower per-barrel capital and operating costs, and allows for larger volumes of crude to be processed in any given sized facility.
Ivanhoe Energy continues to pursue HTL business development opportunities globally, with an emphasis on creating value from stranded resources or resource accumulations considered too small to be economically viable using other technologies.
Summary of Fourth Quarter
Oil revenue totalled $6.2 million in the fourth quarter of 2010 compared to $4.2 million in the third quarter of 2010, mainly due to increased sales volumes. Cash flow used in operating activities was $4.0 million during the fourth quarter of 2010 compared to $5.4 million in the third quarter of 2010. Capital investments during the fourth quarter increased to $25.3 million compared to $20.4 million in the third quarter of 2010.
Liquidity and Capital Resources
Ivanhoe Energy's cash and cash equivalents were $67.8 million at December 31, 2010, compared to $90.2 million at September 30, 2010. This decrease was primarily due to cash used in operating and drilling activities for the Company's business in China and, to a lesser extent in Canada, Mongolia and Ecuador.
Ivanhoe Energy's two initial heavy oil projects, in Canada and Ecuador, will require significant capital for full development. The Company's strategy is to finance the development of these two projects primarily with funding from strategic partners. Ivanhoe Energy is engaged in various discussions and due diligence efforts to establish key strategic and financing arrangements. The pace of the development of the Company's projects will be determined in conjunction with these strategic partnership discussions.
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