Athabasca Oil Corporation is pleased to announce its 2013 capital budget and production guidance. The Company plans to invest $798 million to develop its Light Oil and Thermal Oil assets in Alberta. Capital expenditures will be financed from cash-on-hand, low-interest debt and cash flow from production. Athabasca reaffirms that it is on track to exit 2012 with 10,000 to 11,000 barrels of oil equivalent per day (boe/d) from its assets in the liquids-rich Deep Basin.
Positioning the Company for growth, the 2013 capital investment includes $236 million for organically driven exploration and production (E&P) activities in the Light Oil Division and $533 million to advance Athabasca’s various Thermal Oil assets, including the construction of its wholly-owned Hangingstone Project 1, a 12,000 barrel per day (bbl/d) SAGD project near Fort McMurray.
“Athabasca exits 2012 as an E&P company with a balanced portfolio of Light Oil production and a Thermal Oil project that’s been sanctioned by our board of directors,” says Sveinung Svarte, chief executive officer. “Our Light Oil Division is poised to increase production, targeting an exit rate of 11,000 to 13,000 boe/d by the end the first half of 2013. At the same time, we continue to advance our Thermal Oil assets, and expect the Hangingstone Project 1 to be on stream before year-end 2014.”
Maintaining capital discipline, Athabasca is well funded to support its 2013 capital budget, with over $900 million of cash and short-term investments on hand, and a $200-million undrawn revolving credit facility. Athabasca will conduct a mid-year review of its 2013 capital budget and production guidance, assessing well performance, commodity prices and corporate events.
Light Oil Division
The Kaybob West and East production facilities are operational and the Saxon facility is currently being commissioned, enabling Athabasca to achieve a significant corporate milestone by exiting 2012 with 10,000 to 11,000 boe/d. It currently produces in excess of 10,000 boe/d with more than 5,000 barrels per day of oil and condensate.
Athabasca plans to invest $236 million in 2013, as the Company advances the development of its Light Oil fairway. The Company has allocated sixty percent of its annual Light Oil budget (or $137 million) for adevelopment drilling program targeting the liquids-rich Montney Formation. Athabasca will utilize four to six drilling rigs during its winter 2012/2013 program.
An additional $15 million has been allocated for a 2-D exploration seismic survey and a three-well drilling program at Caribou, the Company’s newest property which is situated in northwestern Alberta. Athabasca has 680,000 contiguous acres with Slave Point oil potential in the Caribou area.
Athabasca has moved swiftly up the learning curve, in terms of understanding the fracture characteristics of the liquids-rich Duvernay reservoir, and innovative completion techniques have yielded strong production test results. All three of the Company’s Duvernay wells will be on production by year-end. Athabasca will monitor these wells’ production performance and decline rates, during the next six to nine months, before establishing a development strategy for this unconventional play.
Athabasca’s Duvernay land base is comprised of more than 350,000 of high-graded net acres, of which approximately 200,000 acres are located at Kaybob, in the heart of the fairway.
“As one of the industry’s largest Duvernay land holders, Athabasca is very encouraged by its recent well results and by production rates from other wells producing in the Duvernay fairway,” said Sveinung Svarte. “We are also pleased to see recent industry transactions, supporting our view of the economic value of the Duvernay.”
In 2012, Athabasca invested $179 million in facilities and infrastructure in its Light Oil Division. The 2013 capital investment, for the Light Oil Division’s facilities and infrastructure, will be $63 million. “We’ve done most of the heavy lifting, with respect to constructing our 100-percent-owned production facilities and infrastructure,” says Sveinung Svarte. “As we transition from exploration to development drilling, particularly in the Montney play in the Deep Basin, our new production will be accretive to the bottom line.”
Athabasca’s Light Oil Division expects to continue its growth next year and to exit the first six months of 2013 with a production rate of 11,000 to 13,000 boe/d. The Company’s production facilities are capable of up to 36,000 boe/d and 48 mmcf/d of natural gas, enabling flexibility with respect to changing commodity prices and market conditions.
Thermal Oil Division
Athabasca plans to invest$533 million, in 2013, to develop its various Thermal Oil assets near Fort McMurray, including the Hangingstone Projects 1 and 2 and Dover West.
By effectively managing the project execution process, Athabasca’s in-house design and management teams have contractually committed 60 percent of the forecasted capital expenditures for the Hangingstone Project 1, a 12,000 bbl/d SAGD (or steam assisted gravity drainage) project comprised of a central processing facility and four well pads with five SAGD well pairs per pad.
Drilling of the SAGD well pairs is planned to commence in mid-2013 at the Hangingstone Project 1 and facility commissioning is scheduled for Q4 2014.
The Company plans to follow the Hangingstone Project 1 with two consecutive SAGD projects (Hangingstone 2 and 3), bringing the area’s potential production to more than 80,000 bbl/d. During 2013, Athabasca will construct infrastructure in the Hangingstone area, and will undertake an appraisal drilling program to further evaluate the bitumen resources that will supply the Hangingstone 2 Project.
At Dover West, Athabasca plans to invest $42 million during 2013, comprised of building roads and other infrastructure. The Company continues to advance its in-house geoscientific evaluation of its sand and carbonate plays. The TAGD (Thermal Assisted Gravity Drainage) Heater and Development Project work continues, in 2013, and is aimed at unlocking the significant bitumen potential of the Dover West Carbonates.
“The development of Athabasca’s substantial Thermal Oil assets continues on time and on budget,” says Bryan Gould, president. “Our teams are working diligently to add value to these properties, and we’re scheduled to be on stream, at Hangingstone, in late 2014.”
|Athabasca Oil Corporation|
|2013 Capital Budget|
|Project/Activity (million CAD)|
|Thermal Oil Division||502|
|Light Oil Division||236|
|Facilities & Infrastucture||63|
|Dover OpCo (40% share)||31|
Conference Call and Webcast, December 17, 2012
7:30 am Mountain Time (9:30 am Eastern Time)
CALGARY – Athabasca Oil Corporation will issue its 2013 capital budget and production guidance on Monday, December 17, 2012 before the market opens.
A conference call and webcast to discuss the 2013 capital budget will be held for the investment community and media on December 17, 2012 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 1:00 pm ET on December 17 until midnight on December 31, 2012 by dialing 855-859-2056 (toll-free in North America) or 416-849-0833 and entering conference password 79499422.
This conference call is being webcast and the webcast link is available via Athabasca’s website (www.atha.com) or via the following URL:
Please note this is a listen only audio webcast.
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 barrels of oil equivalent per day by 2020, comprised of a 50/50 weighting of thermal and light oil. Athabasca is traded on the TSX under the symbol ATH. For further information please visit www.atha.com.
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 “will”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “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 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 projects; timing of facilities construction and 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 2012 and second quarter 2013 exit production rates 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 Light Oil 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.
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; failure to receive regulatory approval for the Dover, Hangingstone, Dover West Sands or other oil sands projects when anticipated or at all; failure to obtain necessary regulatory approvals for completion of the Dover put/call option transaction, if any; 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; defaults under certain debt 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 and in certain debt 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; 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