Athabasca Oil Corp. reported its Q2 2019 results.

2019 Second Quarter Highlights

Light Oil – Strong Duvernay Results

• Production of ~10,200 boe/d (51% liquids)

• Operating income of ~$26 million with a top decile netback of ~$27.50/boe

• Strong initial Two Creeks Duvernay results unlock significant inventory within a shallower window of the Kaybob play; IP60 of ~725 bbl/d per well 16‐29 pad and IP30 of ~725 bbl/d 5‐19 pad

• Simonette Duvernay pad on‐stream with initial rates >2,000 boe/d per well (~90% liquids)

Thermal Oil – Low Decline Production

• Production of ~23,800 bbl/d including downtime for maintenance at both assets

• Operating income of ~$56 million; record division netback of ~$27/bbl (~$31/bbl at Leismer) oLeismer L7 sustaining pad commenced circulation with first production expected in Q4 2019

Q2 Summary

• Production of ~34,000 boe/d (85% liquids)

• Operating income of ~$82 million (excluding hedging) oAdjusted funds flow of ~$48 million ($0.09/share)

• Free cash flow of ~$21 million with positive contributions from both Light Oil and Thermal Oil

2019 Outlook

• Annual capital guidance of ~$135 million focused on sustaining production for 2020

• Low annual sustaining capital advantage of ~$9.50/boe; balanced H2 2019 activity includes drilling a four well Montney pad at Placid, drilling 13 Duvernay wells, a steam debottleneck project and NCG co‐injection expansion at Leismer

• Annual adjusted funds flow forecast of $155 million (US$60 WTI & US$17.50 WCS differentials)

Operations Update

Light Oil

Q2 2019 production averaged 10,210 boe/d (51% liquids). The division generated operating income of $25.6 million and maintained a top decile netback of $27.59/boe. Capital expenditures for the quarter were $5.0 million (net of capital carry).

The liquids rich Montney at Greater Placid (70% operated working interest) is positioned for flexible and efficient development. Robust project economics are supported by strong initial liquids yields (200 – 300 bbl/mmcf), low lifting costs and a ~200 well high graded inventory. Drilling will recommence this fall on a four well pad at 2‐5‐61‐23W5 (“2‐5”). The Company retains flexibility for completion timing and tie‐in of two pads (11 wells).

The Greater Kaybob Duvernay program (30% non‐operated working interest) remains robust and the partnership is executing a jointly approved 2019 budget of C$256 million gross (~C$20 million net of capital carry). Activity is focused on delineation at Two Creeks, Kaybob East and Kaybob West. Athabasca remains encouraged by continued strong production results across the volatile oil window.

At Two Creeks, two multi‐well pads were recently brought on‐stream with strong initial rates and high quality liquids (~41⁰API). 16‐29‐64‐16‐W5 (two well pad) had an IP30 of ~750 bbl/d and an IP60 of ~725 bbl/d per well. 5‐19‐64‐16W5 (two well pad) had an IP30 of ~725 bbl/d per well. The Company sees significant long term potential at Two Creeks with exposure to approximately 45,000 acres in a shallower window of the play (~2,700m vertical depth) which is expected to drive lower well costs. The partnership recently completed a strategic land swap with an industry major, capturing 31 sections of consolidated acreage between Kaybob East and Two Creeks in exchange for nine non‐core sections.

At Kaybob West, a significant northern step‐out 16‐25‐65‐20W5 had a facility restricted IP30 of ~800 bbl/d with an IP120 of ~700 bbl/d.

At Simonette, a three well pad 8‐3‐64‐24W5 was recently tied into third party infrastructure. The first two wells had an average IP14 of ~2,050 boe/d (91% liquids) per well and the third well is expected to be placed on production during Q3 2019.

By the end of this year Athabasca believes the majority of the Duvernay acreage (six areas across ~210,000 gross acres) will be de‐risked from a resource appraisal perspective and the partnership will be in a position to high‐grade development opportunities thereafter. Athabasca remains protected into 2020 with a current capital carry balance of $53.6 million ($238 million gross expenditures).

Thermal Oil

Q2 2019 production averaged 23,748 bbl/d. Production was impacted by facility maintenance activities and recovery from curtailed production in Q4 2018 and Q1 2019 as a response to the unprecedented WCS differential environment (~1,000 bbl/d impact to annual average). As such, the Company anticipates Thermal Oil production to trend on the lower end of its annual guidance.

The division generated operating income of $56.5 million with a record operating netback of $26.97/bbl ($31.07/bbl at Leismer and $18.04/bbl at Hangingstone). The Company’s realized bitumen price averaged $55.58/bbl, supported by a US$10.67 WCS differential during the quarter and lower seasonal blending requirements. Capital expenditures for the quarter were $21.9 million.

At Leismer, Athabasca rig released the L7 sustaining pad earlier in the year. L7 is the first sustaining pad drilled since acquiring the asset in early 2017 and includes five well pairs with ~1,250m laterals (50% longer than prior wells). The Company commenced well pair circulation in June with first production expected in Q4 2019. The upcoming winter program will include completion of a steam debottleneck project, expansion of non‐condensable gas co‐injection across the field and long lead initiatives aimed at maintaining base production.

Business Environment

In December, the Alberta Government announced mandatory industry production curtailments starting in January 2019 to alleviate the high differential situation until additional egress is added. Following the announcement, the Western Canadian Select (“WCS”) heavy oil pricing outlook has significantly improved. WCS prices have averaged C$61.18 in H1 2019, a ~140% increase from C$25.36 in Q4 2018. Athabasca remains supportive of these actions and views them as a necessary step to normalize pricing and provide a bridge to permanent market access initiatives.

Industry crude by rail remains an important factor in managing differentials and Alberta inventories. Rail capacity continues to increase and base line utilization is expected to build through 2019 as long term contracts are operationalized.

The global heavy oil market continues to tighten with supply declines in Venezuela and Mexico, OPEC cuts and growing petrochemical demand. These changing dynamics are supporting heavy oil pricing benchmarks with US refineries in the PADD II and III regions requiring a heavier feedstock. The majority of onshore North American liquids production growth is light or condensate spec and slated for export to the international market. Athabasca is well positioned for this changing global supply dynamic with its Thermal Oil weighted production and long life reserve base.

Risk Management and Balance Sheet

Athabasca has protected a base level of capital activity through its risk management program while maintaining cash flow upside to the current pricing environment. For H2 2019, the Company has hedged 14,000 bbl/d of apportionment protected volumes with a WCS floor price of ~C$52.50 and an additional 2,000 bbl/d of WCS differentials at ~US$20. The Company has also secured 8,000 bbl/d of direct refinery sales for 2020. The hedging program targets up to 50% of near term corporate production and Athabasca will layer on additional protection to support its 2020 capital plans through the fall.

The Company has access to 130,000 bbl of storage at Edmonton to manage and optimize product sales. Athabasca has secured long term egress to multiple end markets with 25,000 bbl/d of capacity on TC Energy Keystone XL and 20,000 bbl/d of capacity on the Trans Mountain Expansion Project.

Athabasca maintains a strong financial position with liquidity of $424 million (cash and available credit facilities) and a Duvernay capital carry balance of $53.6 million. The Company’s term debt is in place until

2022 with no maintenance covenant and the $120 million undrawn reserve based credit facility was recently reaffirmed by the banking syndicate.

Outlook and Drive to Free Cash Flow

Athabasca’s 2019 capital guidance of ~$135 million is focused on sustaining production for 2020. The Company maintains a low annual sustaining capital advantage of ~$9.50/boe. Balanced H2 2019 activity includes drilling a four well Montney pad at Placid, drilling 13 Duvernay wells, a steam debottleneck project and NCG co‐injection expansion at Leismer. Annual adjusted funds flow is forecast at $155 million (US$60 WTI & US$17.50 WCS differential for the balance of 2019). The Company has flexibility to direct sustainable free cash flow to debt reduction, share buy backs or capital projects.