Highlights include:
Athabasca has filed its financial statements and management’s discussion and analysis for the three month period ended March 31, 2013. These documents can be retrieved electronically on the Company’s website www.atha.com and later this morning from SEDAR www.sedar.com.
Thermal Oil Division
Athabasca continued to advance the development of its various thermal oil assets during the first quarter of 2013.
At Hangingstone Project 1, the Company’s wholly-owned 12,000 barrels per day (bbl/d) steam assisted gravity drainage (“SAGD”) project near Fort McMurray, 66 percent of the earthworks required for the construction of the central processing facility and the SAGD well pads has been completed. Detailed engineering for the project is now 83 percent complete. Athabasca anticipates commencing drilling of the SAGD well pairs by mid-year 2013.
During the first quarter of 2013, Athabasca drilled 23 appraisal wells at Hangingstone Project 2 to further delineate bitumen resources. In the second quarter of 2013, the Company anticipates submitting regulatory applications for Hangingstone Projects 2 and 3, two consecutive SAGD projects which are expected to increase overall production to greater than 80,000 bbl/d.
During the first quarter of 2013, Athabasca entered into an agreement with Enbridge Pipelines (Athabasca) Inc. for the transportation and terminaling of diluted bitumen (“dilbit”), which will be produced from Hangingstone Project 1. The new 16-inch-diameter, 50-kilometre-long pipeline is expected to be in service during the latter half of 2015, concurrent with the planned production ramp-up of Hangingstone Project 1. The pipeline is expected to have sufficient capacity to transport the Company’s additional 40,000 bbl/d of dilbit which is anticipated to be produced from Hangingstone Project 2.
At Dover West, the Company drilled and cased three delineation wells to further evaluate bitumen resources in the oil sands reservoirs. The drilling results further validate the resources required to develop the initial 12,000 bbl/d SAGD Dover West Sands Project 1.
Utilizing the innovative TAGD technology, Athabasca successfully completed its third production phase in the Dover West Leduc carbonates. The Company concludes that it is feasible to produce bitumen through gravity drainage at temperatures considerably lower than those used in SAGD operations.
On April 23, 2013, a regulatory hearing commenced for the Dover Commercial Project, a 250,000 bbl/d SAGD Joint Venture (“JV”) project. Closing arguments were presented April 29, 2013. Regulatory approval of this project is expected later this year which would trigger rights under the Company’s Put/Call Option Agreement.
Light Oil Division
In the first quarter of 2013, Athabasca advanced the development of its light oil assets in the Kaybob area, and continued exploration activities on its newest light oil assets in the Caribou and Muskwa areas of northwestern Alberta. Athabasca’s wholly-owned pipeline interconnect from Kaybob East to Kaybob West was commissioned in early April, allowing previously curtailed production and additional new wells on stream.
During the first quarter of 2013, production averaged 6,100 boe/d and was comprised of 56 percent liquids. As previously reported, Athabasca’s daily production was curtailed during the first quarter of 2013 by constraints in a third-party transmission line in the Kaybob East area and significant service interruptions at the Keyera Simonette Gas Plant.
Keyera completed repairs to the sulphur facilities at its Simonette gas plant in early April. However, the plant has continued to be restricted with respect to sour gas processing and liquids handling. This has reduced its ability to handle higher than expected liquid content in the gas stream feedstock from Athabasca’s liquids-rich Montney and Duvernay formations. Athabasca has been working closely with Keyera to resolve the situation. Keyera recently made several upgrades at its Simonette plant and plans additional modifications throughout the second and third quarter, including during its scheduled shut-down in September 2013.
Athabasca continues to estimate maximum production capability of greater than 11,000 boe/d, based on new well tests and production performance data. Athabasca may face near-term production constraints until the planned modifications at the Simonette plant have been completed and the plant is better able to handle the composition of the natural gas currently being delivered. As a result of these interruptions, Athabasca’s production in April has ranged from 300 boe/d to 9,800 boe/d with an average production rate of approximately 5,800 boe/d. Athabasca expects continued production variability until the above mentioned issues are resolved.
During the first quarter of 2013, Athabasca drilled 16 horizontal development wells in the Kaybob area, targeting the Montney Formation. An additional three Montney horizontal wells are scheduled to be drilled in the second quarter of 2013. A total of 18 Montney horizontal wells were completed during the first quarter of 2013, with an additional seven wells scheduled for completion during the second quarter of 2013. All of the Montney wells from the winter development drilling program are expected to be tied-in and producing by the end of the second quarter of 2013. One successful water injection well was drilled and completed during the first quarter of 2013 in the Kaybob East area.
Athabasca continues to be encouraged by the strong performance of its three Duvernay horizontal wells. The Company is also encouraged by Duvernay production results reported by other industry operators. Athabasca holds 350,000 high-graded acres (net) of liquids-rich Duvernay potential, including 200,000 acres (net) near Kaybob which contain greater than 20 meters of net pay and lie in the heart of the Duvernay Fairway.
Athabasca believes it has more than 2,000 potential drilling locations in the Montney and Duvernay formations. The Company intends to conduct a mid-year review of its 2013 capital budget directed towards these opportunities.
Conference Call and AGM, April 30, 2013
7:30 am Mountain Time (9:30 am Eastern Time)
A conference call to discuss the first quarter will be held for the investment community and media on April 30, 2013 at 7:30 a.m. MT (9:30 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 10:30 a.m. ET on April 30 until midnight on May 14, 2013 by dialing 855-859-2056 (toll-free in North America) or 416-849-0833 and entering conference password 22540188.
An audio webcast of the conference call will also be available via Athabasca’s website,www.atha.com or via the following URL:
http://www.newswire.ca/en/webcast/detail/1127495/1229783.
Athabasca’s Annual General Meeting of Shareholders will be held the same day in Calgary at The Metropolitan Centre, Metropolitan Ballroom, 333 – 4th Avenue SW at 10:00 am MT. William Gallacher, chairman of the board, will conduct the business of the meeting and Sveinung Svarte, chief executive officer, will provide an overview of 2012 and discuss the company’s future outlook.
To view the video-stream webcast and presentation slides please visit Athabasca’s website,www.atha.com or the link below:
http://event.on24.com/r.htm?e=610061&s=1&k=8BA97B305057C4694040E324784DE289.
About Athabasca Oil Corporation
Athabasca is a dynamic, Canadian exploration and production 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. Athabasca is poised to become a major Canadian oil producer. Athabasca is traded on the TSX under the symbol “ATH.”
Reader Advisory:
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; production capabilities of the Company’s wells; 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; the timing of resolution of third party facility constraints; the 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 the first half of 2013 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 2013.
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 onMarch 28, 2013 (“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; risk of reassessments of the Company’s tax filings by taxation authorities; failure to satisfy certain conditions in connection with the Company’s debt and credit facilities; 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 in 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.
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.
SOURCE: Athabasca Oil Corporation
Media and Financial Community
Andre De Leebeeck
Vice President, Investor Relations and External Communications
(403) 817-8048
adeleebeeck@atha.com
Financial Community
Tracy Robinson
Manager, Investor Relations
External Communications
(403) 532-7446
trobinson@atha.com