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 construction. -- 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. Financials 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 (www.sedar.com). 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 2017. 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 firstname.lastname@example.org Financial Community Andre De Leebeeck Vice President, Investor Relations (403) 817-8048 email@example.com Tracy Robinson Manager, Investor Relations (403) 532-7446 firstname.lastname@example.org SOURCE: Athabasca Oil Corporation To view this news release in HTML formatting, please use the following URL: http://www.newswire.ca/en/releases/archive/March2013/21/c6940.html CO: Athabasca Oil Corporation ST: Alberta NI: OIL ERN CONF -0- Mar/21/2013 16:05 GMT
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