CALGARY, Oct. 31, 2012 /CNW/ - Athabasca Oil Corporation (TSX: ATH) today reported third quarter 2012 operational results.
Athabasca achieved several significant milestones, delivering value to its shareholders:
- The Energy Resources Conservation Board approved the development of the Thermal Oil Division's 12,000 barrels per day (bbl/d) Hangingstone Project 1, and Alberta Environment and Sustainable Resource Development Department approved its construction under the Environmental Protection and Enhancement Act;
- The Light Oil Division completed construction and tie-in of its production facility at Kaybob West, bringing total Light Oil production to over 3,500 barrels of oil equivalent per day (boe/d). Behind-pipe production sits at more than 7,000 boe/d. The Light Oil Division expects to achieve its year-end exit rate of 10,000 to 11,000 boe/d;
- The Light Oil Division drilled and completed its second horizontal Duvernay well located at Saxon (06-10-62-23W5M). The well is currently shut-in pending completion of the Saxon battery.
"The Government of Alberta's approvals of Hangingstone Project 1 represent a significant milestone in the Company's history and a value-added event for its shareholders," says Sveinung Svarte, president and CEO. "Athabasca's Thermal Oil projects contain considerable bitumen resources, and are tracking on schedule and within budget."
"Furthermore, our decision, two years ago, to diversify the Company's exploration and development portfolio - adding the liquids-rich light oil play in the Western Canadian Sedimentary Basin - is reaping benefits today." Added Sveinung, "The Athabasca-operated Light Oil Division expects to exit the year with production in the range of 10,000 to 11,000 boe/d."
Athabasca has filed its financial statements and management's discussion and analysis (MD&A) for the three and nine month periods ended September 30, 2012. These documents can be retrieved electronically from Athabasca's website (www.atha.com) and, later this morning, from SEDAR (www.sedar.com).
Thermal Oil Division
Hangingstone — Steam Assisted Gravity Drainage (SAGD)
Summer activities were focused on conducting engineering and procurement activities. Front-end engineering and design (FEED) for Hangingstone Project 1, a 12,000 bbl/d SAGD (or steam assisted gravity drainage) project was completed during Q3 2012.
Athabasca awarded a $36-million contract, to an Alberta company based near Calgary, for the fabrication of its production modules. The Company's in-house design and management teams continue to control costs by managing construction timelines for long-lead equipment.
Athabasca achieved a corporate milestone when the Energy Resources Conservation Board (ERCB) approved the development of its 12,000 bbl/d Hangingstone Project 1 and the Alberta Environment and Sustainable Resource Development Department approved the Project 1 construction under the Environmental Protection and Enhancement Act.
In November 2012, the Hangingstone Project 1 budget will be presented, for sanctioning, to Athabasca's Board of Directors.
Hangingstone Project 1 is progressing, as scheduled, and the Company is fully staffed for the project's execution. Project start-up is expected in Q4 2014.
The Company plans to follow the Hangingstone Project 1 with two consecutive, 35,000 bbl/d SAGD projects, bringing the area's potential production to more than 80,000 bbl/d.
Dover West Carbonates — Thermal Assisted Gravity Drainage (TAGD)
Production from the Company's bitumen-rich Leduc carbonates at Dover West will utilize the TAGD production process. During Q2 2012, a "proof of concept" Field Test confirmed that Athabasca could effectively heat the reservoir and mobilize bitumen to a production well, paving the way to initiating the TAGD Pilot/Demonstration Project. Athabasca anticipates commencing the third flow cycle of the TAGD Field Test in November 2012.
Data obtained during previous Field Tests have enabled Athabasca to model its TAGD proprietary production technology, simulating the performance of a commercial TAGD project in the Leduc carbonates.
Work continues on the development at an innovative Heater Assembly Facility (HAF) which Athabasca constructed near Strathmore, Alberta. During Q3 2012, at the HAF, Athabasca successfully drilled a vertical well and used it to assemble a prototype heater for the Pilot Project's wells. Athabasca also drilled a horizontal well that will be used to test the pilot heater assembly.
Light Oil Division
Q3 2012 was an active period from a drilling, completions and construction point of view. Athabasca continued with the construction of three batteries in its 100%-operated Kaybob West, Kayob East and Saxon areas.
Athabasca's facilities were designed to deliver a processing capacity of up to 36,000 bbl/d of oil production and 43 mmcf/d of gas production by year-end. During Q1 2013, the Company plans to extend the Simonette-Kaybob West trunk pipeline into the Kaybob East and Placid areas.
In early October 2012, Athabasca commissioned the Kaybob West Battery, bringing total Light Oil production to over 3,500 boe/d. Behind-pipe production is currently estimated at greater than 7,000 boe/d.
The Kaybob East battery will be commissioned in late November, and the Saxon battery in early December, enabling Athabasca to achieve its year-end guidance of between 10,000 to 11,000 boe/d.
During Q3, Athabasca rig released eight horizontal wells — targeting unconventional reservoirs in the Montney and Duvernay formations — and completed eleven horizontal wells. All of the wells were successful and have met or exceeded the Company's type curve.
Athabasca has drilled and completed its second horizontal Duvernay well located at Saxon (06-10-62-23 W5M). The 06-10 well was shut-in to allow absorption of the load fluid by the under-saturated formation and to enhance production performance. The well will be put on production when the Saxon battery is commissioned in December.
Athabasca expects to achieve its year-end exit rate of 10,000 to 11,000 boe/d.
Athabasca is a dynamic, Canadian company focused on the development of oil resource plays in Alberta, Canada. The Company has accumulated an extensive, high quality resource base suitable for the extraction of thermal crude oil (bitumen) and light oil. Well financed and well endowed with quality assets and talented people, Athabasca is poised to become a major Canadian oil producer. It aspires to produce more than 200,000 boe/d by 2020, comprised of a 50/50 weighting of thermal and light oil. Athabasca is traded on the TSX under the symbol ATH.
Conference Call and Webcast Today October 31, 2012
9:00 am Mountain Time (11:00 am Eastern Time)
A conference call and webcast to discuss the third quarter will be held for the investment community and media on October 31, 2012 at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 888-231-8191 (toll-free in North America) or 647-427-7450 approximately 15 minutes prior to the conference call. An archived recording of the call will be available from approximately 1:00 pm ET on October 31 until midnight on November 14, 2012 by dialing 855-859-2056 (toll-free in North America) or 416-849-0833 and entering conference password 21106173.
This conference call is being webcast and the webcast link is available via Athabasca's website, www.atha.com or via the following URL:http://www.newswire.ca/en/webcast/detail/1056935/1148961
Please note this is a listen only audio webcast.
This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words "anticipate," "plan," "continue," "estimate," "expect," "may," "will," "project," "should," "believe," "predict," "pursue" and "potential" and similar expressions are intended to identify forward-looking information. The forward-looking information is not historical fact, but rather is based on the Company's current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company's industry, business and future financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release. In particular, this News Release may contain forward-looking information pertaining to the following: expected timing of receipt of first significant revenues from the Company's assets; the Company's capital expenditure programs; the estimated quantity of the Company's Probable and Possible Reserves and Contingent Resources; the Company's drilling plans; the Company's plans for, and results of, exploration and development activities; the Company's estimated future commitments; business plans; development of the Company's Thermal Oil Division and Conventional Oil and Gas Division projects; timing of facilities construction and timing of production; the use of in-situ recovery methods such as Steam Assisted Gravity Drainage (SAGD) and Thermal Assisted Gravity Drainage (TAGD) for production of recoverable bitumen, including the potential benefits of such methods; targeted exit rates production for 2012 and beyond, and long term production goals; timing of submission of project regulatory applications; estimated timing of first steaming, selection of equipment manufactures and internal sanction, as applicable, of the Company's projects; estimated initial and full production of the Company's projects; Athabasca's plans with respect to the Conventional Oil and Gas Divisions assets and the expected benefits to be received by Athabasca from such assets; expectations regarding the Company's Light Oil Division development areas including anticipated production levels and timing of receipt of significant revenues and operating results therefrom; and expected increase to number of staff members in 2012.
With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business; the applicability of technologies for the recovery and production of the Company's reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company's capital programs; the Company's future debt levels; geological and engineering estimates in respect of the Company's reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities; the impact that the agreements relating to the PetroChina Transaction (the "PetroChina Transaction Agreements") will have on the Company, including on the Company's financial condition and results of operations; and the Company's ability to obtain financing on acceptable terms.
Actual results could differ materially from those anticipated in this forward-looking information as a result of the risk factors set forth in the Company's most recent Annual Information Form filed on March 27, 2012 ("AIF") that is available on SEDAR at www.sedar.com, including, but not limited to: fluctuations in market prices for crude oil, natural gas and bitumen blend; general economic, market and business conditions; dependence on Phoenix Energy Holdings Limited (" Phoenix") as the joint venture participant in the Dover oil sands projects; variations in foreign exchange and interest rates; factors affecting potential profitability; factors affecting funding, including the development of new business opportunities, the availability of financing, developments in technology, the priorities of the Company and of its current and future joint venture partners and general economic conditions; uncertainties inherent in estimating quantities of reserves and resources; uncertainties inherent in SAGD and TAGD; the potential impact of the exercise of the Dover put/call options on the Company; failure to meet the conditions precedent to the exercise by the Company of the Dover put option, including failure to obtain necessary regulatory approvals for completion of the Dover put/call option transaction by the second quarter of 2013 or at all; failure to obtain regulatory approval for the Dover West Sands project, Dover West TAGD Pilot project or other oil sands projects when anticipated or at all; failure to meet development schedules and potential cost overruns; increases in operating costs making projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; gas over bitumen issues affecting operational results; the potential for adverse consequences in the event that the Company defaults under certain of the PetroChina Transaction Agreements; environmental risks and hazards and the cost of compliance with environmental regulations; failure to obtain or retain key personnel; the substantial capital requirements of the Company's projects; the need to obtain regulatory approvals and maintain compliance with regulatory requirements; changes to royalty regimes; political risks; failure to accurately estimate abandonment and reclamation costs; risks inherent in the Company's operations, including those related to exploration, development and production of oil sands, crude oil and natural gas reserves and resources, including the production of oil sands reserves and resources using SAGD and TAGD and the production of crude oil and natural gas using multi-stage fracture and other stimulation technologies; the potential for management estimates and assumptions to be inaccurate; reliance on third party infrastructure for project facilities; failure by counterparties (including without limitation Phoenix) to comply with contractual arrangements between the Company and such counterparties; the potential lack of available drilling equipment and limitations on access to the Company's assets; Aboriginal claims; seasonality; hedging risks; insurance risks; claims made in respect of the Company's operations, properties or assets; the potential for adverse consequences as a result of the change of control provisions in the PetroChina Transaction Agreements; competition for, among other things, capital, the acquisition of reserves and resources, export pipeline capacity and skilled personnel; the failure of the Company or the holder of certain licenses or leases to meet specific requirements of such licenses or leases; risk of reassessments of the Company's tax filings by taxation authorities; risks arising from future acquisition and joint venture activities; risks that joint venture arrangements will not perform as expected; volatility in the market price of the common shares; and the effect that the issuance of additional securities by the Company could have on the market price of the common shares. In addition, information and statements in this News Release relating to "reserves" and "resources" are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. The assumptions relating to the Company's Hangingstone reserves and resources are contained in the reports of GLJ Petroleum Consultants Ltd. and DeGolyer and MacNaughton, each dated effective April 30, 2012. See the Company's News Release dated July 26, 2012 available on SEDAR. For additional information regarding the specific contingencies which prevent the classification of the Company's Contingent Resources as Reserves see "Independent Reserve and Resource Evaluations - Contingent Resources Estimates" in the AIF. The forward-looking statements included in this News Release are expressly qualified by this cautionary statement. Athabasca does not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities laws.
Oil and Gas Information:
"BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Test Results and Initial Production Rates:
A pressure transient analysis or well-test interpretation has not been carried out and thus the test results provided in this News Release should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.
SOURCE: Athabasca Oil Corporation
For further information:
Vice President, Communications & External Affairs