/C O R R E C T I O N from Source -- Athabasca Oil Corporation/

In c6940 transmitted at 06:00e today, there were 3 errors in the release. 
Under the heading "Light Oil", second bullet, "2013" should have read "2012". 
Under the heading "2013 First Quarter Activity - Thermal Oil Division", third 
paragraph, the second sentence should have read "in 2011" instead of "in 
2012". Under the heading "2013 First Quarter Activity - Light Oil Division", 
first paragraph, the third sentence should have read "February 2013" instead 
of "February 2012". Corrected copy as follows: 
Athabasca Oil Corporation Announces 2012 Year-End Results 
CALGARY, March 21, 2013 /CNW/ - Athabasca Oil Corporation (TSX: ATH) is 
pleased to announce its 2012 Year End Results. The Company achieved numerous 
corporate milestones and transitioned from a pure exploration company to an 
exploration and production (E&P) company with a balanced portfolio of light 
oil production and a wholly-owned thermal oil project under construction. 
Some of the 2012 highlights include: 
Light Oil 

    --  Completion of infrastructure, including a 63-kilometre-long,
        12-inch-diameter trunk pipeline from Kaybob West to the Keyera
        Simonette Gas Plant and oil batteries at Kaybob West, Kaybob
        East and Saxon/Placid with a capacity of 36,000 bbl/d of oil
        and 48 mmcf/d of natural gas;
    --  Production ramp-up in the Kaybob area, during Q4 2012, as the
        wholly-owned infrastructure was commissioned. On December 17,
        2012, the Company achieved peak production rates of 10,700
        boe/d with 57 percent liquids;
    --  In 2012, Athabasca drilled 46 horizontal wells (and completed
        44 horizontal wells) targeting unconventional reservoirs in the
        Duvernay, Montney and Nordegg formations. At December 31, 2012,
        33 wells were on production, 22 wells were awaiting tie-in and
        seven wells were awaiting completions;
    --  Athabasca completed three very good Duvernay wells of which the
        best, the 2-34-62-20W5M well, while producing on restricted
        flow, in February and March 2013, has averaged greater than 800
        boe/d (63-percent liquids) at a flowing surface pressure of
        greater than 20 megaPascals gauge (mPag).

Thermal Oil
    --  Receipt of regulatory approvals, in October, for the
        Hangingstone Project 1, a 12,000 bbl/d SAGD project. In
        November, the Board of Directors sanctioned the $536-million
        construction of the Hangingstone Project 1 and $27 million for
        associated infrastructure. The project is currently under
    --  Demonstration of "Proof of Concept" for the Thermal Assisted
        Gravity Drainage ("TAGD") production technology during two
        field test phases at Dover West, effectively heating the
        reservoir rock in the Leduc carbonates.

With the ramp-up of production through its wholly-owned infrastructure, 
Athabasca embarked on the path of significant growth in revenues from its 
Light Oil Division, earning a netback of $10.8 million in Q4 2012 from 
production of greater than 4,000 barrels of oil equivalent per day (boe/d) 
which was comprised of 43 percent liquids, as compared to $1.0 million in Q4 
2011 from production of approximately 400 boe/d which was comprised of 35 
percent liquids.

Total capital spending in 2012 was $1.1 billion compared to $621.9 million in 
2011. Spending was comprised of $478 million in Thermal Oil Division and $611 
million in the Light Oil Division, with the remainder allocated to Corporate.

On November 19, 2012, Athabasca issued $550 million in Senior Secured Second 
Lien Notes bearing interest at 7.5% per annum, maturing in 2017. At December 
31, 2012 the Company had approximately $1.0 billion of cash, cash equivalents 
and short-term investments on hand. Athabasca also has a $200 million 
revolving credit facility available.

The company has filed its financial statements for the 12 month period and 
management's discussion and analysis (MD&A) for the three and 12 month periods 
ended December 31, 2012. These documents can be retrieved electronically 
from Athabasca's website (www.atha.com) and later this morning from SEDAR 

2013 First Quarter Activity - Thermal Oil Division
During Q1 2013, Athabasca continued with the site preparation for Hangingstone 
Project 1. Detailed engineering is now over 70 percent complete. The project 
is proceeding on time and on budget.

Athabasca has entered into an agreement with Enbridge Pipelines (Athabasca) 
Inc. for the transportation and terminaling of dilbit produced from 
Hangingstone Project 1, a 12,000 bbl/d dry bitumen project. The new 
16-inch-diameter, 50-kilometre-long pipeline from Athabasca's Hangingstone 
Central Plant Facility to the existing Enbridge Cheecham Terminal is 
anticipated to be in service in the latter half of 2015, concurrent with the 
ramp-up of Hangingstone Project 1 production. The new 16-inch Enbridge 
pipeline has sufficient capacity to handle the additional and anticipated 
40,000 bbl/d which will come from the Hangingstone Project 2 commencing in 

Utilizing the innovative TAGD technology, Athabasca successfully completed a 
third production phase in the Dover West Leduc carbonates, confirming the 
production of bitumen from between the two horizontal well bores indicating 
good mobilization at temperatures around 90 degrees Celsius. In 2011, the 
Company submitted a TAGD Pilot/Demonstration Project application, to the 
Energy Resources Conservation Board. Very encouraged by the results of the 
third production phase at Dover West, the Company will seek sanctioning, from 
its Board of Directors, upon receipt of regulatory approvals which are 
expected in 2013.

2013 First Quarter Activity - Light Oil Division
As previously mentioned, on December 17, 2012, the Light Oil Division achieved 
peak production rates of approximately 10,700 boe/d with 57 percent liquids. 
Subsequently, the Company experienced throughput capacity constraints in a 
third-party transmission line in the Kaybob East area, curtailing Athabasca's 
production by approximately 2,500 to 3,000 boe/d. Despite this capacity 
constraint, during January and February 2013, the Company's production 
averaged approximately 7,500 boe/d which was comprised of more than 54 percent 
liquids. In late February 2013, Athabasca completed the construction of a 
35-kilometre-long pipeline interconnect between the Kaybob East and Kaybob 
West batteries.

However, at the end of February, Athabasca experienced additional throughput 
constraints due to unexpected downtime at the Keyera Simonette Gas Plant. 
Although the unexpected operational issues at the Keyera Gas Plant have been 
resolved, the facility is not expected to be fully functioning until early 
April. The Kaybob inter-connect pipeline will be commissioned in conjunction 
with the resumption of full operations at the Keyera plant. Pipeline start-up 
will enable the Company to switch to its wholly-owned infrastructure, 
lessening the impacts of this third-party facility constraints and bringing 
its currently curtailed production and additional wells on stream. Until then, 
Athabasca expects a production in the range of 4,000 to 5,000 boe/d.

2013 Outlook
In December 2012, Athabasca's Board of Directors approved the 2013 capital 
budget of $798 million, and set a mid-year production guidance of 11,000 to 
13,000 boe/d. Athabasca intends to conduct a mid-year review of its 2013 
capital budget. Final 2013 capital budget and year end production guidance 
will be based on well performance, commodity prices and corporate events.

Building on success, the 2013 capital investment includes $236 million for 
organically driven E&P activities in the Light Oil Division and $533 million 
to advance Athabasca's various Thermal Oil assets, including the construction 
of Hangingstone Project 1. Capital expenditures in 2013 are anticipated to be 
financed from cash on-hand, available credit facilities and cash flow from 
light oil production.

Athabasca anticipates that the Dover SAGD Joint Venture will receive 
regulatory approval in 2013. Receipt of regulatory approvals provides 
Athabasca with the opportunity to exercise the Dover Put Option for a price of 
$1.32 billion.

Joint venture arrangements continue to represent excellent vehicles for 
Athabasca to develop its 4.3-million acres (net) of thermal and light oil 
assets, tapping into third-party capital and technical expertise. To that end, 
the Company continues joint venture discussions with world class E&P companies.

Athabasca will continue to allocate financial and human resources - in 
parallel and at a similar pace - to grow these complementary businesses, 
enabling the Company to balance the high returns and flexibility inherent in 
the light oil business with the attractive and stable returns and production 
characteristic of the thermal oil business.

Conference Call and Webcast, March 21, 2013 7:30 am Mountain Time (9:30 am 
Eastern Time)

A conference call and webcast to discuss the 2012 year-end results will be 
held for the investment community and media on March 21, 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 
12:30 pm ET on March 21 until midnight on April 4, 2013 by dialing 
855-859-2056 (toll-free in North America) or 416-849-0833 and entering 
conference password 22540188.

This conference call is also available by webcast for listening purposes only. 
The webcast link can be found on Athabasca's website (www.atha.com) or via the 
following URL: http://www.newswire.ca/en/webcast/detail/1113311/1213559.

About Athabasca Oil Corporation
Athabasca is a dynamic, Canadian exploration and production (E&P) 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 execution of the 
transportation agreement with Enbridge Pipelines (Athabasca) Inc.; 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; sanctioning of 
projects; 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 production exit rates for the second quarter 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 Company's Light Oil Division and Thermal Oil 
assets and the expected benefits to be received by Athabasca from such assets; 
and 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; failure to satisfy certain conditions in connection with 
the Company's debt and credit facilities; 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 in 2013 or at all; failure 
to obtain regulatory approval for the Dover West Sands project, Dover West 
TAGD Pilot/Demonstration 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. As the value ratio between natural gas and crude 
oil based on the current prices of natural gas and crude oil is significantly 
different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 
basis may be misleading as an indication of value.

Media Heather Douglas Vice President, Communications & External 
Affairs (403) 532-7408 hdouglas@atha.com  Financial Community Andre De 
Leebeeck Vice President, Investor Relations (403) 817-8048 
adeleebeeck@atha.com  Tracy Robinson Manager, Investor Relations (403) 
532-7446 trobinson@atha.com

SOURCE: Athabasca Oil Corporation

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CO: Athabasca Oil Corporation
ST: Alberta

-0- Mar/21/2013 16:05 GMT

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