Athabasca Oil Corporation (ATH) Earnings Call Transcript & Summary

And good morning, ladies and gentlemen. Thank you for dialing in to our virtual AGM this morning. My name is Rob Broen, and I'm the CEO of Athabasca Oil. As we are all well aware, 2020 was an incredibly challenging year due to COVID 19. Over the next few minutes, I want to give you an overview of how our company is emerging strong from this pandemic and outline our plans for the future. As our investors on this call know, Athabasca has a diverse asset base. We have light oil assets in West Central Alberta. These include our Placid area where we have been developing liquid-rich Montney resource and our Duvernay acreage at Kaybob where we now have derisked a very large development fairway with some outstanding results. We also have a significant thermal asset base, including our high-quality producing property at Leismer corner where we also -- where we have focused high-value capital this year. We also have a producing property at Hangingstone that is now fully recovered from a self curtailed shutdown in 2020 during the pandemic. Our asset base is complementary. We produce gas and condensate and light oil, and we utilize those products in thermal oil. We have a low decline, long-life reserve base, and we also have short-cycle time growth assets. These are the basis for a long period of cash flow generation, and I'll provide more details on all of this in the upcoming slides. Yesterday, after market close, we released our Q1 results. Some highlights included: production of approximately 34,400 BOE per day with 89% liquids. This was supported by strong performance in thermal oil of about 26,000 barrels a day. Our Light Oil division demonstrated excellent resilience, still producing about 8,500 BOE per day after a year of very little capital investment. Based on asset performance in Q1, we have increased our corporate production guidance to 32,000 to 34,000 BOE per day for 2021. Our capital program in the quarter of $36 million was predominantly at Leismer where we drilled 2 infill wells and 1 additional well pair, with first oil expected in July this year. We also are currently drilling 5 well pairs that will sustain production in 2022 and beyond. These projects add incredible value to the company and will help sustain our production and add significant lending value in coming years. Our capital guidance remains at $100 million for 2021. Our operating income on the quarter was $66 million. That's an amazing improvement from a year ago where it was about a $20 million loss, demonstrating the incredible cash flow potential from our asset base when we are not impacted by macro events. We retained about $141 million of cash after our Q1 capital program and expect now to build to over $200 million by the end of this year at today's strip prices. These are -- this is very important as we prepare to refinance our balance sheet in the coming months. Now before I specifically talk about our refinancing plan and our assets, I want to spend a moment to describe the transformation that the company has been undertaking. Over the last 5 years, we've done a series of transactions and completed many development programs in order to generate significant value. These are shown on the time line on this slide. All of these transactions were done to transform the company to one that has disciplined operations and is underpinned by a strong balance sheet and compelling free cash flow. You can see in the graphs, we've been able to maintain our production base despite periods with very low capital spend and also drive down our cost structure. Our primary objective is to maximize our cash flow, and you can see after some macro setbacks with differential loads due to a lack of egress in 2018 and then COVID in 2020, we are now on track to generate significant free cash. That is our strategic objective. In March of 2020, the outbreak of COVID-19 created a material disruption to the global economy. Commodity prices declined dramatically as an unprecedented decrease in oil demand took hold while countries reacted to the global pandemic. Athabasca reacted swiftly in 2020 and undertook many initiatives to protect the company, including reducing its capital program, temporary production curtailments, finding ways to reduce operating costs and the addition of a $70 million contingent bitumen royalty at an extremely low-cost of capital. In the second half of 2020, commodity prices began to improve significantly. Economies were reopening, and they are reopening as vaccines are implemented and the world recovers from COVID. Oil storage has been declining globally, and demand is returning to pre-pandemic levels. In fact, Goldman Sachs is now predicting a very large jump in oil demand of over 5 million barrels a day in the coming 6 months. The question on where is the supply going to come from seems imminent. Meanwhile, Canadian pipeline egress constraints have been alleviated through tempered growth of production and the implementation of capacity projects, including Enbridge Line 3, which is expected to add another 270,000 barrels a day in the second half of this year; and the Trans Mountain pipeline that will be completed in late 2022. These things position for a strong demand for responsible Canadian oil. The demand for refineries in the U.S. and as a feedstock worldwide, is particularly strong for heavy barrels as Venezuelan and Mexican exports continued to decline. Given our asset portfolio is 90% liquids and predominantly heavy barrels, Athabasca is very well positioned for an improving oil futures market. The financial position of the company is top of mind for our investors, and refinancing of our balance sheet is our top priority. I would like to spend a few minutes outlining our financial position and the objectives for refinancing our $450 million second lien notes over the coming months. Our goal is to provide multiyear funding certainty while lowering the quantum and the cost of our debt. Through the efforts undertaken in 2020, we've been able to preserve a strong financial position. As I already mentioned, at the end of Q1, we held $141 million of unrestricted cash. We have an additional $135 million of restricted cash that is backstopping long-term agreements, and we are working hard to optimize those financial assurances. [ $38 million ] was recently extended to November 30. We also have intentionally streamlined the number of banks in our syndicate to 4 long-term partners. Our capital program has been held to $100 million this year and that will provide production support through 2022. As mentioned previously, the capital is only being spent on production and maintenance projects including the high-value drilling at Leismer that will support the company's lending value into the future. We have just increased our production guidance this year to 32,000 to 34,000 barrels a day, and we are fortunate to have a low decline rate that keeps our capital requirements very low. Our outlook at $60 WTI and $11 WCS differential, which is currently well below 2021 strip prices, is that we will generate over $210 million of EBITDA and $155 million of funds flow. That will result in approximately $55 million plus of free cash, and we expect our unrestricted balance to be over $200 million by year-end. This results in a 2x net debt-to-EBITDA level using our current debt levels. Our target is less than 1.5x net debt-to-EBITDA at $55 WTI as we reduced the quantum and the cost of our debt. Our large low-risk reserve base has over $500 million of PDP and $1.6 billion of total proved reserves under very conservative year-end 2020 evaluator price forecast relative to current strip prices. We have the potential to support a strong first lien credit facility that can provide additional liquidity concurrent with our note refinancing. Finally, we were able to mitigate volatility risk through an active hedging program. Our hedging is designed to protect cash flow against a predictable capital spend. We will hedge up to 50% of our production, including WCS differentials, in particular to avoid seasonal volatility. For the balance of 2021, the company has hedged approximately 45% of its production at prices between $55 and $63 WTI. That includes 11,500 barrels per day of WCS differentials at $12. So even though COVID-19 impacted our intended time line of refinancing, the company is now in a strong position as energy credit markets continue to improve with more constructive commodity pricing. Now I'd like to spend just some brief minutes on each of our assets. Starting with Leismer. Leismer is a top-quality oil sands project and a cornerstone asset for Athabasca. We currently produce approximately 17,000 barrels a day, although we have regulatory approval for up to 40,000 barrels a day index of approximately 90 years. The asset has a $28 per barrel netback in March, and this competes with the very best light oil assets. The operating breakeven is approximately $27 a barrel WCS, and that assumes an $11 WCS differential. This winter, we drilled 2 infill wells on our L6 pad and an additional well pair on our L7 pad that we had developed in 2019. All of these wells will expect first oil in July of this year. We also commenced drilling a 5-well pad in the northern part of the field at L8. We have finished drilling the producer wells, and we are currently finishing drilling the associated steam injector wells. I'm very pleased to report that we have seen the highest quality reservoir drilled to date in our entire Leismer field. We are expecting the wells to be ready for first steam later this year and will ramp up production to over 5,000 barrels a day in 2022 from this pad. The capital cost of this project was approximately $50 million in 2021, resulting in an NPV10 of about $270 million at $55 oil. We drilled this pad clearly because of the tremendous value it adds to the company by maintaining our production through 2022. I'd also like to make mention of the tremendous improvements we've made on this cornerstone asset. You can see we've drilled longer lateral wells, we've reduced our drilling costs and we've established very competitive operating costs over the past several years. All of this has translated into better overall performance. Additionally, we have recently implemented natural gas co-injection on our mature well pairs. This has reduced our SORs at these well pairs by up to 50% and kept our overall asset SOR at close to 3x, consistent with top-tier results for an asset this size. These efforts have also resulted in lower greenhouse gas emissions at the asset and helping establish the company on a path to a lower carbon future. On to Hangingstone. Our Hangingstone asset is an asset with a production capacity of approximately 9,500 barrels per day and slightly higher SORs of about 4.5x. And in 2020, at the peak of the oil price crash due to COVID-19, we made the decision to suspend production from this asset for a total of 4 months. This decision was made to reduce costs during the crisis period. We had confidence in our production history from the asset and also ensure that we could monitor pressures and temperatures to keep the option open to reestablish production when prices improve. At the same time, we were able to complete our scheduled turnaround activities during the shutdown over the course of 4 months instead of a typical 3-week period. That allowed us to complete all scheduled work in a manner that was significantly more cost effective. In September of 2020, we resumed production from the asset. The field restart has exceeded expectations, and the asset has now fully recovered from the shut-in. In March, the field averaged 9,500 barrels a day with very stable operations. Hangingstone has no capital requirements to maintain production for the next several years. We're also implementing many additional cost savings measures at Hangingstone, and this includes: we've successfully field-tested natural gas co-injection now to reduce energy usage and lower SORs, we are in the process of implementing natural gas co-injection field-wide, we've started steaming an additional well pair in April with first oil expected in Q3 this year and we announced yesterday that we've initiated the construction of a trucking terminal at the site in partnership with a leading industry marketing company. This project is being built by Athabasca with no required capital contribution. The partnership has secured up to 5,000 barrels a day of third-party trucked-in volumes that will generate up to $5 million in annual savings through a processing fee and by leveraging existing volume commitments under Athabasca's transportation agreements. In March, Hangingstone had an operating netback of $21 per barrel, and the asset is forecasted to generate about $55 million of operating income in 2021 at today's strip prices. It now has an estimated breakeven cost of about $33 per barrel WCS, and that again assumes $11 differential. Switching to Light Oil. Placid is our operated Montney asset. The asset produced approximately 4,600 BOE per day with 43% liquids and had an excellent netback of $29 per BOE in March. Declines have moderated significantly, and the asset is very flexible for future capital development plan and has about 150 future locations on over 80,000 prospective acres. In the Duvernay at Kaybob, we have approximately 220,000 acres of resource and an estimated 700 future locations. Our Q1 production was 3,850 BOE per day with 74% liquids, and we had an exceptional $40 per BOE operating netback in March. We have now drilled approximately 80 locations and largely derisked the land base through more than $1 billion of investment, and that's at a net cost to Athabasca of only $75 million over the last 4 years. Importantly, I'm happy to report that we are seeing some of the best results over the last year. In the eastern part of the play, at Kaybob East and Two Creeks, we have several wells that have demonstrated longer-term production results with IPs of 725 BOE per day, and those are IP180s; and IP365s of 550 BOE per day. And that's with about 83% liquids. These are exceeding our type curves in the field. This area is particularly exciting as it is in the shallower part of the reservoir where we've seen D&C costs of $7.5 million with line of sight to reduce costs longer term. We believe that this play competes very well against other plays in North America. And the Kaybob area is supported by a strong joint development agreement. And has no near-term land retention requirement. The area infrastructure is well established, and Athabasca is the designated operator of all this infrastructure. These assets have excellent potential for the future. Now I talked about cost improvements in our thermal assets, but I want to mention several of the outstanding attributes of our light oil properties. You can see on this slide that we have made many improvements in capital, operating costs and well results over the last several years. All of this culminates in a top-tier netback. In fact, our Light Oil division has consistently had the best operating netback relative to our peer group for the last 2 years. This quarter, our netback was $31 per BOE, once again ahead of our peer group, which contains companies that are much larger than us. This can be attributed to our low-cost structure, our high liquids yield and our operated infrastructure that is well connected to an active industry corridor. And excellent well results have been realized to ensure we have maintained this position. So this morning, I'm very pleased to present our inaugural ESG report. Our company believes that we produce energy to make people's lives better. The world needs Canada's energy to improve environmental performance and provide a better quality of life across the globe. Our inaugural ESG report is an opportunity to showcase the positive impacts we have made and explain how sustainability and responsibility are being embedded into every decision we make. We are committed to sustainability and constant improvement as part of our strategy, and we have a long history of measuring and reporting on ESG metrics. Our 2020 highlights include: we've demonstrated a 20% decrease in greenhouse gas intensity emissions since 2015; we have an industry-leading total recordable injury frequency of 0.1 per 200,000 man hours; we had 0 reportable hydrocarbon spills in 2020; we've contributed 235,000 acres of mineral interest land to partner with the Alberta government and the Mikisew Cree First Nation to establish the world's largest contiguous protected area of boreal forest; and we have many examples in the report of meaningful contributions to the communities where we live. We have a strong culture of diversity, authenticity and inclusion. So looking to the future, we plan to reduce our emission intensity to a total of 30% by 2025. And we are developing a technology road map to a lower carbon future, and that will include the evaluation of carbon capture use in storage, cogeneration, solvent injection and renewables in our analysis. Our entire Board will have governance by continuing to incorporate ESG goals in annual compensation, ensuring ESG considerations are always considered in capital allocation approvals and by providing oversight to the company's ESG performance. We take our responsibility seriously. We ensure we can deliver on the goals that we're going to set out, and I really encourage you to visit our website and review our ESG report. We are very proud of it. So I'd like to conclude the presentation today with this slide, Athabasca's value proposition. We have a very strong combination of assets. We have low decline, long reserve life thermal assets. We have high-margin, short-cycle time light oil assets. Our company has unparalleled torque to oil prices. We now have approximately a $43 WTI corporate breakeven, operating breakeven, and our company generates -- a $5 move in WTI at our company generates $70 million of EBITDA unhedged. We believe and are confident we have the financial capacity to refinance our second lien notes. I've described that in some detail. We've got $141 million unrestricted cash position. We've got a strong EBITDA profile of over $200 million this year at $60 oil. And we have plenty of asset coverage, very significant, in fact, for a company our size. And the economics on our sustaining projects are outstanding. So this results in a very flexible asset base with low breakeven costs. We have unparalleled free cash flow generation and intend to have a very strong balance sheet and competitive debt-to-EBITDA metrics. Ultimately, this translates into a premium oil-weighted investment. That concludes my presentation this morning. I want to say a very special thank you to the staff of Athabasca who worked very hard and continue to work very hard to make this company great. And I also want to thank our Board for being in support of all the things that we're doing at this company. We would now be happy to take any questions from shareholders or guests. Once again, we'll wait a few minutes and see if anybody has any questions. It looks like there are no questions this morning. So we will conclude the meeting. Thank you, everyone, for attending.

Before I do that, there is a question that came in. Sorry, there is a bit of a delay for us to see the questions that come in. The question is, what is the anticipated time frame for refinancing the senior notes? And as I said in the presentation, we worked really hard to position both the assets and their performance and also our financial position in an improving energy price environment. I anticipate in the coming months that we will be refinancing the senior notes. And I'll just leave it at that. The next question is on our earnings for the past quarter. And I can just repeat what I said at the very beginning of the presentation in terms of our Q1 results. Our production was 34,400 BOE per day, high liquids yield. Capital in the program was $36 million. Our operating income was $66 million. And we retained a cash balance at the end of our Q1 capital program which, by the way, is heavily weighted to a winter program of $141 million. We have another question. I see your questions are coming in now, so that's good. If oil prices stay high, what are your priorities with the free cash flow you will be generating? Well, I can tell you, in the short term, our #1 priority is refinancing our debt. And I mentioned the targets that we have for our debt, and that will continue to be a priority. So we have to get that taken care of first. We're not intending to allocate any additional capital until our debt is refinanced. And I think beyond that, the company is positioned to be -- to have free cash flow, and it will be significant free cash flow. And our intention will be -- we'll have to evaluate it when we get there, but we'll make sure that we get our debt targets down to the level that I mentioned. And then beyond that, we have several options that include giving money back to shareholders. And we have a tremendous portfolio of assets to invest in, in our company. So -- but I want to emphasize the priority right now is refinancing our debt. Next question is, what is the philosophy behind selling WTI call options? So as we were starting up Hangingstone just coming out of the worst part of the oil price crash last year during COVID, we felt strongly that we needed to bring the asset back on, both from a technical standpoint and an economic standpoint, and we wanted to protect the company as we did that over the course of the winter. So what we ended up doing is we hedged a portion of our production over the winter months. And in order to make sure we got an adequate price on that, we sold the call option at a much higher price for the back half of this year, and that's why we have it in place. I will also mention that we still -- our objective is to make sure that we hedge to protect cash flow for our capital program. and that would be up to 50% of our production. So we're about 45% to the end of the year. So we have a really good exposure to the price environment that we see in front of us that looks very constructive. Looks like that's the conclusion of the questions. Thank you for your questions, and thank you for attending the meeting this morning, and we'll adjourn.