Athabasca Oil Corporation reports a significant increase in bitumen contingent resources and light oil reserves, and assigns 51 million barrels of proved reserves at Hangingstone

CALGARY, March 28, 2013 /CNW/ – Athabasca Oil Corporation (TSX:ATH.TO) announces that it has filed its Annual Information Form dated March 28, 2013, which can be retrieved electronically from the Company’s website (www.atha.com) or from SEDAR (www.sedar.com).

Athabasca is also pleased to report the highlights of an independent reserves and resources evaluation, conducted by GLJ Petroleum Consultants Ltd. and DeGolyer MacNaughton Canada Limited, of the Company’s thermal and light oil assets, at December 31, 2012.

Highlights include:

• Reclassification of 51 million barrels (“bbl”) of Hangingstone’s probable bitumen reserves to the proved reserve category, based upon receipt of regulatory approvals and project sanctioning by the Company’s Board of Directors;
• Contingent bitumen resources (best estimate) increased, year-over-year, by approximately eight percent to 10.6 billion bbl of bitumen;
• Proved plus probable bitumen reserves increased over the previous year’s estimate of 339 million bbl of bitumen (net of the disposition of the MacKay River Joint Venture), to an estimated 342 million bbl; and
• Light oil reserves increased by approximately 139 percent, year-over-year, from 9.2 million barrels of oil equivalent (“boe”) of proved plus probable reserves to 22.0 million boe proved of plus probable reserves.

Thermal Oil Division

In 2012, Athabasca received regulatory approvals to construct the Hangingstone Project 1, a 12,000 bbl/d SAGD project. The Company’s Board of Directors subsequently sanctioned the Hangingstone Project 1, triggering the reclassification of 51 million bbl of Hangingstone’s probable reserves to the proved reserve category, effective December 31, 2012.

The Hangingstone project area is comprised of 136,000 acres of oil sands leases which, based upon an independent engineering estimate, at December 31, 2012, contain 51 million bbl of proved reserves, 66 million bbl of probable reserves and 0.9 billion bbl of contingent resources (best estimate).

Year-over-year additions to the Thermal Oil Division’s reserves and resources reflect the successful results of the 2011-2012 Winter Drilling and Seismic Program which further delineated the bitumen deposits.

In March 2012, Athabasca closed the sale of its remaining 40-percent interest in the MacKay River Joint Venture to Cretaceous Oilsands Holdings Limited, which subsequently amalgamated with Phoenix Energy Holdings Limited, a wholly-owned subsidiary of PetroChina Company International Limited. The sale resulted in the divestiture of a combined 114 million bbl of proved plus probable reserves and 573 million bbl (best estimate) of contingent resources.

At Dover West, Athabasca acquired oil sands leases which contained approximately 1.0 billion bbl of contingent resources (best estimate), at December 31, 2012.

Light Oil Division

At December 31, 2012, the Light Oil Division’s reserves increased, year-over-year, from 9.2 million boe of proved plus probable (“2P”) reserves to 22.0 million boe proved plus probable reserves. This 139-percent, year-over-year increase in Athabasca’s 2P reserves reflects a successful drilling and completion program in 2012 which targeted stacked (or multi-zone) unconventional reservoirs in the Duvernay and Montney formations.

At year-end, the Light Oil Division had established production from 33 horizontal wells in the Fox Creek area (Kaybob East, Kaybob West and Saxon/Placid). Production facilities were commissioned in late 2012, limiting the reporting period for well production histories. Artificial lift has now been installed on the majority of the new wells, which is expected to stabilize production rates.

As production trends and type curves are established in 2013, the Company expects to prove reservoir recoveries and additional 2P reserves. Additional wells were drilled in late 2012, but were not completed or tested prior to year-end – production from these new wells is expected to contribute additional 2P reserves in 2013. At year end 2012, Athabasca had just 30 percent of its proven light oil reserves classified as Proven Undeveloped (PUD) locations.

Athabasca’s strategy has been to secure egress and maximized net backs for its product. As such, the Company invested a significant amount to construct wholly owned infrastructure in the Kaybob and Simonette areas during 2012, thereby reducing future costs, on a boe basis, as production increases. The control of infrastructure is expected to provide the Company with the flexibility to blend and market crude oil and condensate, according to market demands, thereby increasing net backs. Athabasca’s 2012 capital program of $611 million included approximately $189 million for facilities and $27 million for the acquisition of petroleum and natural gas leases. The Company’s 2013 capital budget includes an additional $38 million to construct the infrastructure associated with year-end 2P reserves.

Athabasca expects to realize future cost reductions as it moves down the learning curve, primarily through the drilling of multi-wells from single pads. By leveraging its fixed operating costs – along with the ability to blend oil with Duvernay condensate – the Company expects to receive a premium netback for its product. These factors should provide for a very competitive finding and development and recycle ratio for future development plans at Fox Creek.

Athabasca’s resources and reserves are situated within a land base that is comprised of greater than 1.5 million acres (net) of oil sands leases and permits held by the Thermal Light Oil Division and greater than 2.8 million acres (net) of petroleum and natural gas leases held by the Light Oil Division. During the past year, the Company’s combined Thermal Oil and Light Oil land base increased by approximately 19 percent, from 3.6 to approximately 4.3 million acres (net).

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. 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.”

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; the estimated quantity of the Company’s and Proved and Probable 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 commissioning and the receipt of the expected benefits therefrom: 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 rate 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 Light Oil Division’s 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 on March 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.

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  reserves and resources are contained in the reports of GLJ Petroleum Consultants Ltd. and DeGolyer and MacNaughton Canada Limited, each dated effective December 31, 2012. 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 estimates of reserves and future net revenue for individual properties in this New Release may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. “Contingent Resources” has the meaning given to that term 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.

SOURCE: Athabasca Oil Corporation