Description

Athabasca Oil Corp (ATH.TO)

Link to the PDF of this write-up:  https://www.dropbox.com/sh/b3ix96a5s4jr8kj/AAA4pb7ebfTu7GF5k-KG9jUca?dl=0

• 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

Global

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.

Figure 3: WTI-WCS differential since 2014. Normalized range is US$ 10-15/bbl.

2)      ATH Overview and Valuation Summary

Athabasca currently produces 40,000 boe/d (~90% liquids), of which 30,000 bbl/d is heavy oil from its oil sands plays in northeastern Alberta (Leismer and Hangingstone) and 10,000 boe/d is from its liquids rich plays in central Alberta (Montney and Duvernay). The company expects to grow its production at a 15% CAGR into 2020, largely stemming from a ramp up of its light oil plays and secondarily, from improvement in Hangingstone. Importantly, this growth will be self-funded at current commodity pricing.

ATH’s thermal oil assets produce a stable base cash flow. The capex for ATH’s thermal oil assets has largely been sunk. Only minimal sustaining capex ($5-10/bbl) is required to maintain a stable 30,000 boe/d base production over a long 2P resource life (Leismer: 85 yrs.; Hangingstone: 45 yrs.).

In the near-term, Athabasca plans to hold Leismer production flat between 20,000-22,000 bbl/d, with quick-pay out opportunities such as gas injection and flow control devices on the table. Operational improvements will come by way of a tie-in to the Norlite diluent pipeline in Q2 2018, resulting in ~$20MM annual savings. Meanwhile, Athabasca is working on ramping its Hangingstone production to ~10,000 bbl/d from ~9,000 currently, with a potential to ramp to 12,000 bbl/d longer term. At US$ 65 WTI and US$ 20 WTI-WCS differential, the company expects $130M of operating income in 2018 and $70 M of CAPEX, equating to $60 M of fund flow. Notably, this guidance includes negative $(7) M Q1 thermal oil operating income resulting from the WTI-WCS blowout in Q1 and 3 weeks of scheduled maintenance at Lesimer in Q2.

Longer-term, Athabasca has regulatory approval to expand Leismer to 40,000 bbl/d and build a greenfield project on the Corner acreage (AER approval for 40,000 bbl/d), which the company believes to have better geology than Leismer. The company would look for sustained WTI prices above US$65/bbl, stable WCS differentials, and a contango futures curve before proceeding with thermal expansions.

Light oil will continue to be the short-term growth driver. Athabasca sees light oil production doubling to 20,000 boe/d by 2020. Montney economics are driven by high netbacks from strong initial condensate yields of 200-300 bbl/mmcf. Well costs, currently $8 million/well, have benefited from pad drilling and evolution of completion technology. Duvernay remains largely self-funded through the end of 2019, with key delineation wells in the oil window expected in H2 ‘18. Through a JV with Murray Oil, ATH only needs to pay 7.5% of the CAPEX for 30% working interest in the Duvernay acreage, effectively de-risking the greenfield stages of this project at minimal cost. At US$ 65 WTI, the company expects $125M of operating income from its light oil assets in 2018 and $70 M of CAPEX, equating to $55 M of fund flow.

Depending on commodity pricing and desired payback period, ATH can toggle between growth options in light and heavy oil. We believe the sale of the midstream assets, for which a sales process has already commenced, could fetch between $200-400M. We believe that proceeds will be used accretively for growth initiatives, debt reduction, or share buybacks.

We value ATH by a PV-10 NAV of its 2P reserves. We value all its assets and liabilities separately to reach a final valuation using our base case price deck (Figure 4). We assume heavy and light oil differentials remain at current levels until 2021, at which point differentials narrow to historical norms as new pipeline capacity comes on-line. In our base case, which assumes a $300M midstream asset sale, we value ATH at $2.37/sh. (Figure 5), with potential upside to $2.93 if certain operating improvements and expansion projects occur. Our blue-sky scenario of $4.59, gives ATH credit for un-booked well inventory (i.e. not in 2P reserves) per management’s commentary. Importantly, we highlight ATH’s sensitivity to oil prices and the narrowing of the WCS-WTI differential (Figure 6). Given our positive macro view of oil, we view ATH as a cheap call option on higher LT oil prices.

Compared to other Canadian E&P’s (Figure 7), we believe ATH is the cheapest way to play improved oil pricing and the narrowing of the WTI-WCS differential.

•         ATH is the cheapest on a flowing barrel basis (EV/BOED).

•         ATH is cheapest on EV/Reserves basis (EV/1P Reserves and EV/2P Reserves) due to its long 2P reserve life.

•         ATH has the second highest production growth rate from 2017 to 2019.

•         Compared to Canadian E&P’s with >50% heavy oil exposure, ATH screens the cheapest on an EV/EBITDA basis. ATH trades ~2 turns lower than that subset.

•         While ATH has average 2018/2019 EV/EBITDA multiples compared to oily Canadian E&P’s, we believe near term trading multiples do not adequately price in the upside from the WCS-WTI differential narrowing post-2020, which is a core driver of our investment thesis.

Figure 4: Base case commodity price deck

Figure 5: Base case valuation

Figure 6: Sensitivity of NAV to LT commodity pricing

Figure 7: Comparison of ATH to oil weighted Canadian E&P’s

3)      Midstream Monetization:

ATH launched a process for its Leismer infrastructure assets in March. This was likely spurred by recent transactions, including the sale of MEG's (MEG.TO) Access Pipeline/Stonefell Terminal to Wolf Midstream for 13.4x EBITDA. ATH’s infrastructure assets include:

•         300 mmbl (150mbbl Dilbit & 150 mbbl) Diluent tank farm at Cheecham

•         12” Dilbit and 8” diluent pipelines to Leismer

•         110 mmbl (100 mbbl Dilbit & 10 mbbl) Diluent tank farm at Leismer

•         46 mmbl (40 mbbl Dilbit & 6 mbbl) Diluent tank farm at Hangingstone

Figure 8: Map of ATH’s infrastructure assets

We believe these assets could fetch between $200-400M in a sale.  While we note a range of outcomes is possible, our base case assumes a $300M asset sale at 12x EV/EBITDA. This transaction would be $0.23/sh. accretive to equity value (Figure 9). We believe that ATH will be able to use the sale proceeds to for a variety of accretive projects:

•         Growth Projects: Leismer expansion, Corner greenfield project, or accelerated development of light oil assets

•         Debt reduction: ATH has US$ 450M 9.875% of 2022 Notes. ATH may redeem the notes at 104.9% of principal in 2019, 102.5% of principal in 2020 and 100% of principal in 2021.

•         Share buybacks

Figure 9: Incremental value/sh. of midstream sale and sensitivity to EV/EBITDA multiple

4)      Heavy Oil Asset Overview

Leismer

Leismer, which commenced production in 2010, is a top tier oil sands project. It has 650 mmbbl of 2P reserves and ~85-year 2P life. At current commodity pricing, Leismer is highly cash generative.

Modeling Assumptions:

•         Production: ATH intends to keep bitumen production at Leismer in the rage of 20,000 -22,000 bbl/d. We model production at 21,000 bbl/d bitumen.

•         Oil Price Realization: ATH realizes $(3) -(4) differential to the WCS benchmark due to higher sulfur content.

•         Cost of Diluent: On average, bitumen is upgraded by adding 0.42 bbl of diluent (Edmonton C5+) for every 1 bbl WCS sold, with higher quantities needed in the winter than the summer.  The cost of diluent per bbl has averaged $17/bbl above the Edmonton C5+ benchmark, primarily due to transport costs. ATH intends complete a tie-in to the Norlite pipeline by the end of Q2 ‘18, reducing diluent cost by $6/bbl or $20M annually. We model this transport cost going forward as a variable cost of 5% Edmonton C5+ plus a fixed cost of $7/bbl of diluent.

•         OPEX: While we estimate that OPEX/bbl would remain flat at $13.75/bbl absent the midstream asset sale, we increase OPEX by $3.26/bbl to account for our base case assumptions for this transaction.

•         Royalty: ATH pays a royalty to the Alberta government and to Burgess Energy.

â—¦Royalties to the Alberta government are indexed to Canadian dollar WTI price. ATH expects to pay royalties under the pre-payback formula until 2035 and under the post- payback formula thereafter. At US$ 65 WTI, we believe that ATH pays 4.3% of gross realization to the government.

â—¦ATH’s royalty to Burgess Energy is indexed to US$ WTI price.  At $65 WTI this royalty will be 2.6% of gross revenue less transport costs.

•         Sustaining Capex: The company estimates sustaining capex to be $5-10/bbl.

Figure 10: Summary of Leismer assumptions

Valuation

At US$ 65/bbl WTI and a US$ 20.00 WCS-WTI differential, Leismer should produce $98M in pre-tax cash flow or $13/bbl produced. As the WCS-differential narrows to US$15/bbl, pre-tax cash flow will increase to $157M or $21/bbl produced. We value this asset using a DCF of post-tax cash flows over the life of the asset (10% discount rate and 26.5% tax rate). We value the NOL’s as a separate asset. Based on the previous assumptions, we value Leismer at $1.93/sh. Figure 11 highlights the sensitivity of Leismer’s valuation to commodity pricing.

Figure 11: Sensitivity of Leismer Value to oil pricing

Upside

Leismer is upgradable to 40,000 bbl/d. While we don’t give ATH credit for any expansion project in our base case, we note that a 15,000 bbl/d expansion at a cost of $25k/bbld (company’s estimated range is $20-30k/bbld) would cost $375M and be $0.32/share accretive at US$65 WTI. The project would likely take 2 years to complete and would ramp up to full capacity 1-year post start up. Although this project becomes value accretive above US$ 55 WTI, sustained WTI pricing above US$ 65 would likely be necessary for the project to reach FID.

Figure 12: Upside from Leismer project expansion

Hangingstone

Hangingstone, which commenced production in 2015, is a higher cost oil sands project than Leismer. Compared to Leismer, Hangingstone has worse quality rock, less scale, and a smaller percentage of owned infrastructure. Hangingstone has 180 mmbbl of 2P reserves and ~50-year 2P life

Modeling Assumptions:

•         Production: We estimate production will ramp up from 9,000 bbl/d to 10,000 bbl/d of bitumen. While the company maintains that it can ramp up production to 12,000 bbl/d, it hasn’t been able to do so over the 4 years Hangingstone has been in service, presumably due to the geology and a higher SOR ratio. We do not give ATH credit for a full ramp in production.

•         Oil Price Realization: ATH realizes $(3) -(4) differential to the WCS benchmark due to higher sulfur content.

•         Cost of Diluent: On average, bitumen is upgraded by adding 0.42 bbl of diluent (Edmonton C5+) for every 1 bbl WCS sold, with higher quantities needed in the winter than the summer.   The cost of diluent per bbl has averaged $15/bbl above the Edmonton C5+ benchmark, primarily due to transport costs. We model this transport cost going forward as a variable cost of 5% Edmonton C5+ plus a fixed cost of $11/bbl of diluent.

•         OPEX: We estimate that OPEX/bbl will remain flat at $32/bbl.

•         Royalty: ATH pays a royalty to the Alberta government and to Burgess Energy.

â—¦Royalties to the Alberta government are indexed to Canadian dollar WTI price. ATH expects to pay royalties under the pre-payback formula indefinitely. At US$ 65 WTI, we believe that ATH pays 4.3% of gross realization to the government.

â—¦ATH’s royalty to Burgess Energy is indexed to US$ WTI price.  At $65 WTI this royalty will be 2.6% of gross revenue less transport costs.

•         Sustaining CAPEX: The company estimates low near-term sustaining CAPEX, which we estimate to be $5/bbl over the next 3 years, increasing to the midpoint of the $5-10/bbl long term range thereafter.

Figure 13: Summary of Hangingstone assumptions

Valuation

At US$ 65/bbl WTI and a US$ 20.00 WCS-WTI differential, Hangingstone should produce $(3) M in pre-tax cash flow or $(1)/bbl produced. As the WCS-differential narrows to US$15/bbl, pre-tax cash flow will increase to $15M or $4/bbl produced. We value this asset using a DCF of post-tax cash flows over the life of the asset (10% discount rate and 26.5% tax rate). We value the NOL’s as a separate asset. Based on the previous assumptions, we value Hangingstone at $0.15/Sh. Figure 14 highlights the sensitivity of Hangingstone’s valuation to commodity pricing.

Figure 14: Sensitivity of Hangingstone value to oil pricing

Corner

Corner is undeveloped oil sands acreage in Alberta, Canada. Corner is a potential greenfield project and is not included in our base case valuation of ATH. The company believes Corner is a top tier lease with a superior reservoir to Leismer. While the company believes Corner should have similar unit costs/bbl to Leismer, it will have a substantially higher capex intensity than a brownfield Leismer expansion project. Assuming capex intensity of $50,000/bbld production, a 20,000 bbl/d project would cost $1,000 M. A project of this size would likely require a JV partner. At 331 mmbbl of 2P reserves, Corner would have a ~45-year 2P life based on fully ramped up production levels. We believe this project would likely take 4-5 years to complete and another 1 to 1.5 years to ramp to full capacity. Consequently, we believe this project would not be accretive at our assumed long-term pricing, US$ 65/bbl WTI and US$ 15/bbl WCS-WTI differential (Figure 15). We estimate that this project becomes accretive above US$ 70/bbl WTI (Figure 16). There are opportunities for remote steam generation from Leismer that could lower initial capital outlay; however, the company has not done a detailed cost estimate.

Figure 15: Summary of Corner assumptions

Figure 16: Sensitivity of Corner value to oil pricing and CAPEX

5)      Light Oil Asset Overview

Montney:

In Greater Placid, Athabasca has an operated position in approximately 80,000 gross Montney acres, of which 48,000 are developed. ATH has a prospective inventory of over 200 high graded gross drilling locations (140 net at 70% working interest). Infrastructure is in place for 10,000 bbl/d liquids and ~50 mmcf/d of gas. This basin will be an area of multi-year growth for ATH. The company plans to run a flexible program with 1-3 rigs in operation depending on commodity pricing.

Modeling Assumptions:

•         CAPEX/well: D&C costs are $8 M/well. We grossed the D&C costs up by 25% to arrive at a full cycle CAPEX cost of $10 M/well. Full-cycle costs, which may prove to be conservative, should account for land and infrastructure costs.

•         Production: ATH’s Montney type curve has an EUR of 675 mbbl, of which 45% is liquids. We model approximate decline rates given by the company. While production mix skews to a higher oil mix initially, we chose to model a constant production mix equal to the EUR mix over the life of the well (i.e. we model the same decline rate for all three energy streams).

•         Realization: In-line with ATH’s historical light oil results, we model oil realization at a $(2) differential to Edmonton Par, NGL realization at 65% Edmonton Par and gas realization at a $(0.50) discount to AECO.

•         Costs: We model Montney wells using the blended OPEX/bbl seen in the light oil segment, $9/bbl. Over time these costs should drop to $6.50/bbl as production in this basin scales. We account for unit cost improvement as an additional source of upside to our base case.

•         Royalties: The Alberta government’s royalty formula depends on if a well has achieved payback. At US$ 65 WTI, we calculate the royalty to be 4% of the gross realization during the pre-payback period (first 4 years at our price deck) and 31% of realization less OPEX during the post-payback period.

Figure 17: Summary of Montney assumptions

Valuation

Given that 2P reserves are 43 mmboe and EUR/well is 675 mboe, 2P reserve estimates imply 64 net wells at the Montney type curve. We value the post-tax, full cycle value of the a Montney well at $0.7 M (10% discount rate and 26.5% tax rate). We value the NOL’s as a separate asset. We value ATH’s Montney asset at $43 M or $0.08/sh. Figure 18 highlights the sensitivity of Montney’s valuation to commodity pricing.

Figure 18: Sensitivity of Montney value to oil pricing

Upside

While higher commodity prices, including a narrowing of the Edmonton Par-WTI differential, are the biggest sources of upside, there are additional operating sources of upside. Improving unit OPEX costs from $9.00/bbl to $6.50, as the company suggests, would result in $0.08/sh. of additional upside. We believe this is likely as ATH’s position within the basin scales. There is also upside from 76 perspectives well locations that do not appear in the 2P reserves. As ATH’s Montney acreage gets developed there is potential for these wells to be added to ATH’s 2P reserves. Un-risked, these perspective wells could provide $0.10/sh. in upside. While this source of upside likely deserves a risk factor, we include the un-risked value in the blue-sky scenario only to highlight the un-booked resource potential of ATH’s Montney assets.

Figure 19: Montney upside from un-booked well locations

Duvernay

In Greater Kaybob, ATH has a 30% non-operated interest in over 200,000 gross Duvernay acres. There are approximately 1,000 gross potential drilling locations on this acreage. 156,000 gross acres and 800 perspective locations are in the volatile oil delineation while 41,000 acres and 200 perspective locations are in the condensate rich gas delineation.  In May 2016, ATH Partnered with Murphy Oil to develop this acreage though a cash/carry structure JV structure. This JV structure helps ATH de-risk the Duvernay acreage and minimizes financial exposure in the greenfield stages of production. ATH pays 7.5% of the CAPEX for 30% working interest over the first 4 years of this agreement, after which time ATH pays 30% of the CAPEX for 30% of the working interest. To date ATH has received $267M of upfront cash and $219M of CAPEX reimbursement from this agreement. ATH has $138M remaining capital carry commitment from Murphy Oil.

Modeling Assumptions:

•         CAPEX/well: D&C costs are $10M/well. We grossed the D&C costs up by 25% to arrive at a full cycle CAPEX cost of $12.5M/well. Full-cycle costs, which may prove to be conservative, should account for land and infrastructure costs. Management believes that they can bring down half-cycle well costs to $8.5M over the next 2-3 years and we view this as an additional source of upside to our base case value.

•         Production: Duvernay has ~5 regional type curves for the phase windows (ranges from liquids rich: 150 bbl/mmcf gas to volatile oil 1,000 bbl/mmcf). Each area has different IP, EUR, gas/liquids decline profiles. Duvernay liquids yields stabilize at a higher level compared to the Montney and in turn, drive superior netbacks. Absent more granular information from the company, we model the Duvernay acreage as a single type curve, with an EUR of 460 mbbl, of which 67% is liquids. While production mix skews to a higher oil mix initially, we chose to model a constant production mix, equal to the EUR mix, over the life of the well (i.e. we model the same decline rate for all three energy streams).

•         Realization: In-line with ATH’s historical light oil results, we model oil realization at a $(2) differential to Edmonton Par, NGL realization at 65% Edmonton Par and gas realization at a $(0.50) discount to AECO. Given that Duvernay’s oil production is benchmarked to Condensate (Edmonton C5+), our differential assumptions are likely conservative.

•         Costs: We model Duvernay wells using the blended OPEX/bbl seen in the light oil segment, $9/bbl. Over time these costs should drop to $6.50/bbl as production in this basin scales. We account for unit cost improvement as an additional source of upside to our base case.

•         Royalties: The Alberta government’s royalty formula depends on if a well has achieved payback. At US$ 65 WTI, we calculate the royalty to be 4% of the gross realization during the pre-payback period (first 3 years at our price deck) and 31% of gross realization less OPEX during the post-payback period.

Figure 20: Summary of Duvernay assumptions

Valuation

Given that 2P reserves are 25 mmboe and EUR/well is 700 mboe, 2P reserve estimates imply 36 net wells at the Duvernay type curve. We value the post-tax, full cycle value of the a Duvernay well at $3.0 M (10% discount rate and 26.5% tax rate). We value the NOL’s and  the remaining capital carry commitment from Murphy Oil as separate assets. This implies ATH’s Duvernay value is $107 M or $0.21/sh. Figure 21 highlights the sensitivity of Duvernay’s valuation to commodity pricing.

Figure 21: Sensitivity Duvernay valuation to oil prices

Upside

While higher commodity prices are the biggest sources of upside, there are additional operating sources of upside. Improving unit OPEX costs from $9.00/bbl to $6.50, as the company suggests, would result in $0.06/sh. additional upside. We believe this is likely as ATH’s position within the basin scales. Reducing Capex/Well from $10M to $8.5M would result in $0.10/sh. of additional upside.  There is additional upside from 264 perspectives net well locations that do not appear in the 2P reserves. We believe that as ATH’s Duvernay acreage gets developed there is potential for these wells to be added to ATH’s 2P reserves. Un-risked, these perspective wells could provide $1.55/sh. in upside. While this source of upside likely deserves a risk factor, we include the un-risked value in the blue-sky scenario only to highlight the un-booked resource potential of ATH’s Duvernay assets.

Figure 22: Duvernay upside from un-booked well locations

PDP

ATH has 8.1 MMBOE of PDP reserves. Based on mrq production, we estimate that 78% of those reserves are from the Montney. Most of this production is new, and thus we estimate a high initial decline rate. We value the PDP at $0.23/sh. (Figure 23).

Figure 23: PDP Assumptions

Balance Sheet

•         Hedge: ATH’s portfolio is largely unhedged. For Q2 and Q3 ’18, ATH has roughly half of its total oil production and half of its heavy oil production basis hedged. After Q4 2018, ATH has no commodity hedges in place. We value the hedge portfolio by NPV at a $(0.03)/sh. liability.

•         Debt: Athabasca issued US$450.0 million of Senior Secured Second Lien Notes due in 2022. The notes bear interest at a rate of 9.875% per annum. We value the debt as a $(1.16)/sh. liability.

•         Cash: ATH has $129M or $0.25/sh. in cash.

•         Restricted Cash: ATH has $111M or $0.22/sh. of restricted cash that is cash collateral for the letter of credit, which is for ATH’s long-term transportation agreements (primarily the Hangingstone/Enbridge transportation agreement). Since we do not know under what circumstances the restricted cash obligation would be released or restructured, we value it at its NPV at the time of 2P reserve depletion. Effectively, this values restricted cash at $0.00/sh. in our base case.

•         ARO: We value the ARO at the discounted book value of 114M or a $(0.22)/sh. liability

•         Leismer Contingent Payment: ATH is required to pay to Statoil a contingent payment of 33% of the difference between the price of US$ WTI and US$ 65 for each barrel of Leismer production until 2020. While the discounted book value of this liability, valued by a call option model that accounts for time value and oil price volatility, is $52M or ($0.10)/sh., we chose to value it as an NPV of cash flows. At $65 WTI, the NPV of this payment is $0.00.

•         Capitalized Carry: We value the Capitalized Carry commitment form Murphy oil at the discounted book value of $133M or a $0.26/sh. asset

•         G&A: We capitalize the after-tax value of $46M annual G&A ($36M cash G&A plus $10M of SBC) at 10%, which equates to a $(0.66)/sh. Liability.

•         NOL: ATH has a $3B tax pool (i.e. NOL). At a tax rate of 26.5% this has the potential to shield $795M in future taxes. We value the NOL at $372M or $0.73/sh. based on a DCF of asset level cash flows.

Risks

•         On October 27, 2016, the International Maritime Organization (IMO) announced that beginning on January 1, 2020, the maximum sulfur content allowed in marine bunker fuel will be reduced from 3.50% by mass (m/m) to 0.50% m/m. Changing bunker fuel regulations could provide additional headwinds to the narrowing of the WTI-WCS differential. This could provide headwinds to heavy oil in Canada, which is higher in Sulphur content as compared to some of the medium grades supplied by the Middle East. Canadian heavy crudes compete favorably against Venezuelan crudes on Sulphur content (3.50% vs. Venezuelan and Maya benchmark at 2.01% and 3.50%, respectively). If egress is available, differential impacts should be minimized. We estimate the US has ~17 MMBbl/d of hydrotreating (or Sulphur treating) capacity, which suggests an availability to process higher Sulphur content feedstocks. Refineries lacking de-sulphurization equipment may choose to either purchase expensive de-sulphurization equipment or potentially alter feedstock mix.

•         Pipeline takeaway projects fail to be completed, resulting in wider oil differentials, both WTI-WCS and WTI-Edmonton Par.

•         Lower oil prices

Appendix

•         Alberta Government Royalty:  During the pre-payout period, a project pays a royalty based on a percentage of its gross revenues (oil sales less cost of diluent), ranging from 1% to 9%, depending on the price of WTI converted to Canadian dollars. During the post-payout period, a project pays a royalty based on a percentage of its net revenues (oil sales less cost of diluent less allowable costs), ranging from 25% to 40%, depending on the price of WTI Canadian dollars.

Figure 24: Pre-payback and post-payback oil formulas

•         Burgess Royalty: In 2016 and 2017, Athabasca granted Contingent Bitumen Royalties on its Thermal Oil assets to Burgess Energy Holdings for gross cash proceeds of $397.0 million. Under the terms of the royalty, Athabasca will pay Burgess a linear-scale royalty of 0% - 12% relative to a WCS benchmark price applied to Athabasca’s realized bitumen price net of diluent, transportation and storage costs.

Figure 25: Pre-payback and post-payback oil formulas

Catalyst

• Higher oil prices

• Narrowing of WCS-WTI differential

• Midstream Asset Sale

• Accretive Growth Projects