July 05, 2018 - 3:51pm EST by
2018 2019
Price: 1.75 EPS 0 0
Shares Out. (in M): 510 P/E 0 0
Market Cap (in $M): 893 P/FCF 0 0
Net Debt (in $M): 591 EBIT 0 0
TEV (in $M): 1,355 TEV/EBIT 0 0

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Athabasca Oil Corp (ATH.TO)


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Overview: Athabasca Oil Corp (ATH.TO) is a Canadian E&P that produces ~90% liquids by volume, with production skewed towards heavy oil from the Athabasca Oil Sands. Compared to other Canadian E&P’s, we believe ATH is the cheapest way to play improved oil pricing and the narrowing of the WTI-WCS differential for the following reasons: high exposure to oil, particularly heavy oil; long life of 2P reserves; no hedges in place beyond 2018; higher than average production growth; and bottom of the range trading multiples. At its current price of $1.75/sh., ATH has a market cap of $900M and an enterprise value of $1.3B. We believe that at flat US$65 WTI and a WTI-WCS differential that narrows to US$ 15 in 2021, ATH has 35% upside to our $2.37 base case PV-10 NAV valuation.

Cheap Call Option on Higher Oil Prices: We view ATH as a cheap call option on higher oil prices. By our estimate, every US$5/bbl increase in WTI price increases our valuation by ~$1.00/sh. Given our expectation for a balanced global oil market going forward, we are bullish on oil pricing.

Narrowing of WCS-WTI differentials: Western Canada lacks sufficient pipeline takeaway capacity to transport oil, particularly heavy oil, to US based refiners. This scenario resulted in the WCS-WTI differential blowing out to a low of US$30/bbl in Q1 2018. Although the proposed pipeline projects (Enbridge: Line 3; Kinder Morgan: Trans Mountain Expansion; TransCanada: Keystone XL) have not reached FID, we are confident that at least 2 of these projects will be built by 2021, resulting in sufficient takeaway capacity to narrow the WCS-WTI differentials to a more normalized level of US$ 10-15 (vs US$ 21.00 today). We take this view because the US is short heavy oil and US refiners need to import heavy oil to optimize refinery production. By our calculation, every US$ 1.00 narrowing in the long term WTI-WCS differential increases our valuation by ~$0.20/sh.

Monetization of midstream assets: We believe ATH is in the process of monetizing $200-400M of midstream assets related to its Leismer acreage. We believe that the monetization will be $0.10-$0.40 accretive to share value depending on the transaction multiple. We believe that these proceeds will be used accretively for growth initiatives, debt reduction, or share buy-backs.

Risk-Free development of Duvernay light oil acreage: Through a JV with Murray Oil, ATH only needs to pay 7.5% of the capex for 30% working interest in the Duvernay acreage. Since this acreage is largely a greenfield development, potential upside will not only come from reductions in cost structure (OPEX and CAPEX), but also from reserve additions as the acreage gets developed. ATH’s ability to un-risk all 1,000 potential gross locations represents a blue-sky scenario. Un-risked, this could unlock an additional $1.55/sh. in value.


*Note: All currency is in Canadian Dollars unless otherwise stated


1)      Outlook for Oil


Renewed enthusiasm for oil related equities for the better part of 2018 has stemmed from both larger than expected supply cuts by OPEC members and improved oil demand. Back in 2016, supply cuts were initially expected to be 1.7 MMbbl/d. In May 2018, they were 2.2 MMbbl/d.  Supply cuts have proven larger than expected because of the precipitous drop in Venezuela production and very strong compliance from OPEC members. In the June 2018 meeting, OPEC’s decision to increase production to a level implied by 100% compliance was not only bullish relative to market expectations, but also reinforced its goal of stabilizing inventories and preventing surplus inventories from forming. That said, it will take time for this net supply to come online, especially in-light of the re-imposition of economic sanctions against Iran and accelerating declines in Venezuela.

Much of the improvement in global balances has been on the back of a very strong period of growth for oil demand. As such, current inventory levels need to be considered in the context of current demand. While overall inventory levels are already trending toward the historical 5-year average on an absolute level, ‘days of demand’ from a global standpoint have already dropped below the historical 5-year average, suggesting there is no need for additional reductions in inventory levels to leave the market relatively balanced. In fact, one could argue that inventory levels may not be sufficient. This leads us to believe that the global market can be supportive of higher oil prices and consequently, the oil market will move from the steep backwardation in forward oil prices that has persisted for the past several years to a flatter curve at higher energy price levels.


N. America/USA

While growth out of US shale, particularly out of the Permian, remains robust, these volumes are predominantly light oil (API>45). Although the US has been importing less oil, heavy oil (<25°API) imports have increased by ~28% to 6.1 MMBbl/d and now represent ~58% of total imports (up from 37% 10 years ago). Refiners still need to blend heavy oil with light oil to optimize refining margins. Heavier crudes, of which the US produces less than 0.5 MMbbl/d, are the preferential feedstock for producing diesel. Thus, as US refinery production continues to ramp, the US will continue to increase heavy oil import volumes.

We believe Canada, as a supplier of heavy oil, is a key cog to US energy independence. Canadian import market share has risen to 40% from 19% over the past ~10 years, taking share from Saudi Arabia, Venezuela and other countries (primarily OPEC nations). Refineries (primarily in the Gulf Coast) have been geared towards accepting diluted bitumen from Canada as a feedstock. As volumes from Venezuela continue to decline because of political turmoil (production down from 789 MBbl/d to 705 MBbl/d over the past three years), Canadian heavy oil will need to fill the gap. Near term; however, Canadian heavy oil export volumes remain constrained by pipeline takeaway capacity. Proposed pipelines represent an incremental capacity of 1,720 Mbbl/d of total egress:

        LR3 (Enbridge)- Capacity: 350 Mbbl/d,

        Trans Mountain Expansion Pipeline (Canadian Government pending purchase from Kinder Morgan)- Capacity: 540 Mbbl/d

        Keystone XL Pipeline (TransCanada)- Capacity: 830 Mbbl/d

Further, Enbridge suggested that it could add as much as 450 Mbbl/d to its current export capacity via system enhancements: drag reducing agents (75 Mbbl/d), flow adjustments (100 Mbbl/d), and system upgrades (275 Mbbl/d). We take the view that at least two of these pipelines will be built by 2020/2021 and that will be sufficient to handle expected Canadian production growth over the next decade (Figure 1).


Figure 1: Canadian pipeline takeaway projects needed to balance production growth forecasts


Pipeline constraints have resulted in the WCS-WTI differential blowing out to US$ 30/bbl in Q1 2018 from a 5-yr. average of ~US$15/bbl. The differential is currently trading around US$ 21.00, in line with rail transportation costs to the gulf coast (US$ 15-22) plus a quality differential from higher sulfur content (US$ 3-6/bbl) (Figure 2). When the Canadian government announced its intent to buy the Trans Mountain Expansion pipeline from Kinder Morgan, assuaging the markets skepticism that the project would built, the differential briefly narrowed to US$ 15/bbl. Though the differential has widened since then, longer term we expect the basis differential to stay in the US$ 10-19/bbl range based on US$ 7-13/bbl pipeline fees to the gulf coast and US$ 3-6/bbl quality differential. At times when pipeline takeaway capacity has not been constrained, the WTI-WCS differential has historically stayed in the US$ 10-15/ bbl range (Figure 3). Importantly, ATH has secured firm transport capacity (Trans Mountain Expansion: 20,000 bbl/d and Keystone XL: 10,000 bbl/d) equal to its current heavy oil production.

Figure 2: Heavy Oil transport costs to US gulf coast are US$ 7-13/bbl by pipeline vs US$ 15-23/bbl by rail.