Athabasca Oil Corporation Provides Light Oil Operations Update

CALGARY, March 6, 2013 /CNW/ – Athabasca Oil Corporation (TSX:ATH.TO) is pleased to provide an update of its light oil operations in the Fox Creek area of the Alberta Deep Basin.

In December 2012, the Light Oil Division achieved its goal with production rates of greater than 10,000 barrels of oil equivalent per day (boe/d) comprised of approximately 50 percent oil and condensate.

Daily oil and gas production ramped up during Q4 2012, as the Company constructed and commissioned its wholly-owned infrastructure with a capacity of 36,000 barrels per day (bbl/d) and 48 million cubic feet per day (mmcf/d) of natural gas.

In October 2012, Athabasca commissioned a 63-kilometre-long, 12-inch-diameter trunk pipeline with a capacity of up to 180 mmcf/d. The Kaybob West Battery was commissioned in October 2012, followed by the Kaybob East and Saxon/Placid batteries in mid-December 2012.

In 2012, the Company drilled 46 horizontal wells targeting stacked unconventional reservoirs in the Duvernay, Montney and Nordegg formations — by the start of January, 44 wells had been completed and 33 were on production, including Athabasca’s first three horizontal Duvernay wells.

Athabasca is particularly encouraged by the strong initial performance of its three Duvernay wells — in particular, the 2-34-62-20W5M well produced about 50,000 barrels of 55°-plus API liquids and 0.2 billion cubic feet of gas during its first 80 days of production. Producing at a restricted flow in February, the 2-34 well averaged 840 boe/d (63-percent liquids) at a flowing surface pressure greater than 20 megaPascals gauge (mPag). Athabasca intends to capture the premium value of the produced condensate as a sales product.

“As one of the largest Duvernay land holders in the Deep Basin where the company owns 340,000 acres of high-graded Duvernay rights, Athabasca is excited about the results from its three horizontal wells, drilled and completed to date,” said Sveinung Svarte, chief executive officer. “Athabasca is also pleased to see other positive industry test results in the Duvernay. These results, along with recent industry transactions, support Athabasca’s view of the strong value of the Duvernay play.”

During the first half of 2013, Athabasca will monitor production and decline rates of the horizontal wells, establishing type curves by formation (Duvernay, Montney and Nordegg) and by area. The type curves will be used to create a development plan to produce these stacked unconventional reservoirs.

Athabasca’s Kaybob acreage lies in the heart of the Duvernay Fairway where the Company holds 200,000 acres (net) with greater than 20 metres of Duvernay pay. Athabasca has high-graded more than 2,000 drilling locations (targeting the stacked Duvernay and Montney formations) to develop the Kaybob and Saxon/Placid areas.

At December 31, 2012, Athabasca’s Fox Creek area well inventory included 22 horizontal wells (completed with multi-stage hydraulic fracturing) awaiting tie-in and seven horizontal wells awaiting multi-stage completions.

Athabasca’s Q1 2013 winter development drilling program involved contracting six rigs to drill 16 horizontal wells targeting the liquids-rich Montney Formation. During Q2 2013, Athabasca intends to drill four additional horizontal wells targeting the Montney.

In late February 2013, Athabasca completed construction, ahead of schedule and below budget, of a 35-kilometre-long, 8-inch-diametre dual pipeline interconnect between the Kaybob East and Kaybob West batteries. The interconnect represents the final step in configuring the Company’s wholly-owned infrastructure at Fox Creek.

During January and February 2013, production averaged between 7,500 and 8,000 boe/d comprised of greater than 50 percent oil and condensate. The reduction in production rates, from those reported in December 2012, is related to throughput capacity constraints in a third-party high pressure sour gas transmission line in the Kaybob East area. Once the pipeline interconnect from Kaybob East to Kaybob West is commissioned, Athabasca can bypass this third-party bottleneck by switching to its wholly-owned infrastructure, adding 2,500 to 3,000 boe/d of curtailed production to come to market.

“The recent third-party pipeline capacity constraint has demonstrated the importance of the Company’s decision to build and control our own light oil gathering and production facilities, enabling us to optimize production rates and operational costs,” said Sveinung Svarte. “As production ramps up, Athabasca will deliver incremental, low cost reserves and improved finding and development costs.”

Building upon a successful Q4 2012 and Q1 2013, Athabasca is poised to increase its light oil production. The Company confirms that it is tracking its mid-year guidance of 11,000 to 13,000 boe/d comprised of approximately 50 percent oil and condensate.

About Athabasca Oil Corporation
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.”

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: 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; the Company’s business plans for, and development of, the Company’s Light Oil Division business; timing of facilities construction and production; targeted exit production rates by the end of the second quarter of 2013 and beyond and long term production goals; selection of and effectiveness of drilling rigs and equipment; 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, including the use of multi-stage fracture and other stimulation technologies; 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 and natural gas; general economic, market and business conditions; dependence on Phoenix Energy Holdings Limited (” Phoenix”) as the joint venture participant in the Dover oil sands project; 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; 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 project 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 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 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