Yahoo Finance

Operations Update

Light Oil

Production averaged 6,319 boe/d (50% liquids) in the first quarter of 2016. Field capital expenditures totaled $31 million and included the completion and tie-in of a three well Montney pad, completing drilling operations on a four well Duvernay pad at Kaybob West and the construction of the Placid inter-connect to the Company's owned and operated infrastructure at Saxon.

Greater Placid - April ~3,500 boe/d gross

In the Montney play at Placid, the Company has established a scalable and operated position which it believes has top quartile returns potential relative to other North American plays.

In the first quarter of 2016, Athabasca completed three new Montney wells off a pad at Placid to follow up on two successful wells drilled in the winter of 2014/15. Drilling and completion ("D&C") costs averaged $6.9 million per well. Drilling costs averaged approximately $4 million per well with spud to rig release times averaging 23 days for extended reach laterals (~2,500 meters). Completions operations concluded in March with frac costs averaging $2.9 million per well (~785 lbs/ft proppant loading).

Placid is now pipeline connected to Athabasca's extensive greater Kaybob infrastructure allowing flexibility to market liquid and gas products at various regional processing plants and mainlines. The pipeline inter-connect to Saxon was commissioned on-time and under budget. Athabasca recently tied in a four well pad and the 8-20-60-23W5 well through this new infrastructure. Three of the wells have produced for 30 days and the average IP30 on these wells is 771 boe/d (59% liquids). Rates remain restricted as the wells clean-up post completion. Initial well performance is meeting expectations and the Company remains encouraged by liquids yields which are supportive of the 8-20 well which had a restricted IP30 of 900 boe/d (65% liquids, 270 bbl/mmcf free liquids), cumulative production to date of 200 mboe (52% liquids) and current production of ~600 boe/d (43% liquids).

With no near-term land expiries and operated egress, the asset is set up with significant flexibility to control the pace of development going forward. Athabasca has exposure to approximately 25,000 gross acres of prospective Montney land with two separately defined Montney intervals.

Greater Kaybob - April ~4,800 boe/d gross

Athabasca and industry continue to de-risk the Duvernay play at Kaybob with select areas progressing to pad drilling operations. The Company's core objectives for the winter Duvernay program included demonstrating pad drilling cost efficiencies and ongoing appraisal and delineation of the volatile oil window.

At Kaybob East, the Company completed a two well proppant loading test in the volatile oil window. Industry has seen a positive trend in productivity and ultimate recoveries by increasing proppant loading in both the Duvernay and other leading North American shale plays. The higher proppant completion resulted in a 40% improvement in its IP30 rate (758 boe/d vs. 541 boe/d). The Company remains encouraged by the initial production from these wells and continues to monitor extended rates and evaluate the potential for higher proppant loading across the play.

At Kaybob West, in the condensate rich gas window, the Company completed drilling operations on a four well cost demonstration pad. Average drilling costs for the pad were $4 million per well with spud to rig release times averaging less than 18 days. The Company intends to complete the four wells after break-up, with a planned on-stream date in Q3 2016. D&C costs are expected to be within $8 - $10 million per well depending on completion intensity.

Light Oil Joint Venture Update

In January 2016, Athabasca entered into an agreement to form a strategic joint venture with Murphy to develop the Duvernay and Montney Formations in the Greater Kaybob and Greater Placid areas. As part of the transaction, Athabasca is selling 70% of its interest in its Greater Kaybob area assets and 30% of its interest in Greater Placid area assets for gross proceeds of $475 million. Murphy will assume operatorship of the Greater Kaybob area assets and Athabasca will retain operatorship of the Greater Placid area assets under separate joint development agreements. Athabasca will also retain operatorship of the regional midstream infrastructure in the near term.

Murphy will pay approximately $250 million in cash to Athabasca on closing. Additional consideration of $225 million will be in the form of a capital carry whereby Murphy will fund 75% of Athabasca's share of Duvernay development capital up to a maximum five year period. The carry supports up to approximately $1 billion of investment of which Athabasca's financial exposure is limited to $75 million to retain a 30% working interest in 200,000 gross acres. The effective date of the transaction is January 1, 2016. The Company is progressing towards closing in Q2 2016.

The joint venture with Murphy will leverage both partners' extensive shale play expertise and ensure capital is directed towards de-risking the volatile oil window in the Duvernay. Athabasca is now positioned with a capital risk profile appropriate to its size while maintaining significant upside in the Duvernay shale play and a funded growth profile. Athabasca's operated Montney position at Placid provides a material platform for future economic growth with over 100 high quality locations.

Thermal Oil - Hangingstone

In the Thermal Division, Hangingstone Project 1 is now 10 months into its production ramp-up with 23 well pairs converted to SAGD production. Bitumen production averaged 7,029 bbl/d in the first quarter of 2016, representing 23% growth over Q4 2015. Volumes for the quarter were partially impacted by operations maintenance. Cash flow for the quarter was impacted by lower than expected realized bitumen pricing with ongoing volatility in the oil price benchmarks. Western Canadian Select heavy crude averaged US$26.30/bbl in the first quarter.

Hangingstone was shut down yesterday due the regional Fort McMurray wildfires. At this time, there is no damage to the facility, field pipelines or well sites. Timing for a restart of operations will be contingent on containment of the regional fires and ensuring safe operating conditions. Prior to the shut-in production reached approximately 9,000 bbl/d.

2016 Budget and Outlook

In December, Athabasca released its 2016 capital budget. Pro forma guidance incorporates the pending Murphy transaction, current operations and strip commodity prices is outlined in the tables below.

At this time no additional Light Oil capital has been approved for the second half of 2016. Athabasca has operational readiness to increase development in both the Montney and Duvernay.

Pro forma Murphy Transaction, Athabasca will have approximately $880 million of liquidity and a net cash position of approximately $60 million. Liquidity will be further bolstered by the $225 million Duvernay capital carry commitment. The Company continues to evaluate alternatives to enhance its capital structure and remains committed to reducing total leverage by $300 to $400 million during 2016.

Board Renewal Update

Athabasca is pleased to announce further steps in its ongoing commitment to Board renewal and strong governance. The Board has appointed Mr. Bob Rooney as an independent director. Mr. Rooney was previously Executive Vice President and General Counsel at Talisman Energy Inc. prior to its acquisition by Repsol S.A. Prior thereto, Mr. Rooney was a partner at Bennett Jones LLP in Calgary with over 20 years of experience in corporate M&A and international oil and gas law. He is currently active in the oil and gas sector and is a Managing Director of RimRock Oil and Gas, a private Calgary based company. Mr. Rooney's diverse background will be an asset to the Board's composition and skill set.

In conjunction with this appointment, Mr. Paul Haggis and Mr. Peter Sametz will not be seeking re-election for Board positions at the next annual meeting. Athabasca would like to thank both directors for their valuable contributions to the Company and wishes them well on future endeavors.

Since announcing the Board renewal process in September 2014, the Company has made significant changes that will better position the Company for the future. Changes made include the appointment of a new independent Chair, four new independent directors and the rotation of four legacy directors.

Annual General Meeting

Athabasca's annual general meeting is scheduled for June 21, 2016 at 9:00AM MST at the Metropolitan Center in Calgary.

About Athabasca Oil Corporation

Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and light oil assets. Situated in Alberta's Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabasca's common shares trade on the TSX under the symbol "ATH". For more information, visit www.atha.com.

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", "target", "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 expected timing of the closing of the Murphy Transaction; the benefits expected to be realized by the Company from the Murphy Transaction, including the impact on the Company's financial position and balance sheet strength; the Company's forecasted liquidity and net cash position upon closing of the Murphy Transaction; the timing of receipt of regulatory approvals; Athabasca's plans to retire a portion of its debt in 2016; the expected potential of the Duvernay volatile oil window; the growth potential of and the economic returns expected to be realized from, the Company's Montney lands in the Placid area; the improvements in Duvernay well drilling and completion costs expected to be realized by the Company, including from employing pad drilling; the timing of completion and commissioning operations in the Company's Light Oil division; the timing of the on-stream date the Company's Kaybob West area wells; the benefits expected to be realized from the use of recovery technologies in the Company's Light Oil division, including multi-stage, energized hybrid completion technology and the utilization of a high proppant loading completion design; the Company's expected flexibility in its pace of development; the Company's drilling plans, in particular, with respect to the Duvernay and Montney formations and the costs of such drilling operations; the timing of the ramp-up of production and of achieving plateau production from Hangingstone Project 1; the Company's expectation that Hangingstone Project 1 will have a flat production profile for its initial 5 to 7 years of production after achieving nameplate production (12,000 bbl/d); the Company's estimated future commitments; the Company's business and financing strategies and plans; expectations regarding the Company's 2016 capital budget; and the future allocation of capital.

With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity prices for petroleum and natural gas; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business and the effects that such regulatory framework will have on the Company, including on the Company's financial condition and results of operations; the impact that the Murphy Transaction will have on the Company, including on the Company's financial condition and results of operations; the Company's ability to meet its re-financing objectives; the Company's ability to accelerate development when prices recover; Athabasca's cash-flow break-even commodity price; geological and engineering estimates in respect of Athabasca's reserves and resources; the applicability of technologies for the recovery and production of the Company's reserves and resources; the Company's ability to demonstrate the quality of its asset base and to build large-scale projects; 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; the Company's ability to obtain equipment in a timely and cost-efficient manner; the geography of the areas in which the Company is conducting exploration and development activities; and the Company's ability to obtain equipment in a timely and cost-efficient manner.

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 Annual Information Form ("AIF") dated March 10, 2016 that is available on SEDAR at www.sedar.com, including, but not limited to: risks associated with regional forest fires and other events of force majeure affecting Athabasca's operations, fluctuations in market prices for crude oil, natural gas and bitumen blend; political and general economic, market and business conditions in Alberta, Canada, the United States and globally; compliance with greenhouse gas regulations; changes to royalty regimes, environmental risks and hazards; alternatives to and changing demand for petroleum products; failure to meet the conditions precedent to closing of the Murphy Transaction; dependence on Murphy as the Company's joint venture participant in the Company's Duvernay and Montney assets; dependence on Murphy as the operator of the Company's Duvernay assets; the substantial capital requirements of Athabasca's projects and the ability to obtain financing for Athabasca's capital requirements; operational and business interruption risks associated with the Company's facilities; failure by counterparties to make payments or perform their operational or other obligations to Athabasca in compliance with the terms of contractual arrangements between Athabasca and such counterparties, including in respect of the Murphy Transaction, and the possible consequences thereof; the potential for adverse consequences in the event that the Company defaults under certain of the agreements in respect of the Murphy Transaction; long term reliance on third parties; aboriginal claims; failure to obtain regulatory approvals or maintain compliance with regulatory requirements; failure to meet development schedules and potential cost overruns; variations in foreign exchange and interest rates; factors affecting potential profitability; risks related to future acquisition and joint venture activities; reliance on, competition for, loss of, and failure to attract key personnel; uncertainties inherent in estimating quantities of reserves and resources; changes to Athabasca's status given the current stage of development; litigation risk; risks and uncertainties inherent in SAGD and other bitumen recovery processes; risks related to hydraulic fracturing, including those related to induced seismicity; expiration of leases and permits; risks inherent in Athabasca's operations, including those related to exploration, development and production of petroleum, natural gas and oil sands reserves and resources; risks related to gathering and processing facilities and pipeline systems; availability of drilling and related equipment and limitations on access to Athabasca's assets; increases in costs could make Athabasca's projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; environmental risks and hazards; failure to accurately estimate abandonment and reclamation costs; the potential for management estimates and assumptions to be inaccurate; reliance on third party infrastructure; seasonality; hedging risks; risks associated with maintaining systems of internal controls; insurance risks; claims made in respect of Athabasca's operations, properties or assets; competition for, among other things, capital, export pipeline capacity and skilled personnel; the failure of Athabasca or the holder of certain licenses, leases or permits to meet specific requirements of such licenses, leases or permits; risks related to Athabasca's amended credit facilities; senior secured notes and term loans; and risks related to Athabasca's common shares.

For important additional information regarding Athabasca's reserves and resources estimates and the evaluations that were conducted by GLJ and D&M, please see "Independent Reserve and Resource Evaluations" in the Company's AIF available on SEDAR at www.sedar.com. 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.

Test Results and Initial Production Rates:

The well test results and initial production rates provided in this News Release should be considered to be preliminary. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.