Baytex Energy: The Business of Oil & Gas - [Business Breakdowns, EP. 57]

1. [First question] - The journey of producing a barrel of oil and how Baytex fits into the oil production ecosystem

All right, Josh, thank you for joining us on Business Breakdowns.

Josh

Thank you for having me.

We don’t cover too many oil and gas names on Business Breakdowns, so I thought we could start at a high level with Baytex within the energy value chain. Could you describe the production of a barrel of oil, how it makes its way out of the ground to end users, and how Baytex, as an oil producer, fits into that equation?

Baytex is an upstream oil and gas company, which means it has the rights to produce on land it doesn’t own. It has leases and other sorts of arrangements with mineral owners and landowners to access the minerals, and it pays oil services companies to develop them. Those companies provide rigs and other services.

Wells are drilled on the land Baytex has purchased the right to access. The oil and natural gas are then gathered, sometimes using Baytex’s own infrastructure and sometimes third-party infrastructure. They’re brought to processing plants and refineries and turned into gasoline, diesel, and other products used across the economy.

It almost sounds like the oil producer is the general contractor of the energy production stage. They don’t actually own a lot of assets, but there’s a lot of coordination involved in getting those barrels out of the ground. Is that a fair analogy?

Kind of, except they’re the ones providing the money as well. They provide the capital to develop the assets or acquire producing assets, and then they’re essentially trying to earn a profit by putting money into the ground, through services and time, and by acquiring the rights to the resource. They hope to get all that money back and then some.

It’s like general contractors that risk pretty much all of the money and hope to earn a speculative profit on the activity.

2. How $100 is dispersed amongst the value chain when a barrel of oil is purchased

Maybe the spec home builder is the better comparison. Could we go through the economics of the value chain as well? If we use a reasonable round number today of $100 per barrel of oil, how much would Baytex, as an oil producer, keep? What are some of the rules of thumb for how much goes to a rig operator, how much goes to midstream pipelines, and how much goes to refineries? What’s the best way to think about the distribution of value in that $100?

What’s interesting about oil and gas is that there are so many different kinds of oil fields and so many different activities among companies in the space that the answers for Baytex might not be as generalizable as we’d like. Baytex has fields in the U.S. and Canada, ranging from more unconventional shale, like the Eagle Ford shale, where it owns a non-operated interest, to relatively conventional heavy oil that it’s developing in Alberta and Saskatchewan.

The economics Baytex realizes, the activities involved, and who else benefits vary. In Texas, where most of the land is privately owned, private mineral owners benefit substantially from royalties on activity at Baytex’s wells. In this case, it’s actually Marathon Oil that’s drilling the wells, and Baytex is participating—essentially funding them. It’s like there’s another general contractor managing the work and owning most of it, while Baytex owns some of it. Baytex writes checks to participate in its interest, and the other general contractor—in this case, Marathon—produces and sells the oil. Baytex gets its share.

The activity ranges from that, where the highest single expense is fracking—the pressure pumping and related activities associated with unconventional shale development—to heavy oil, where almost 100% of the expenditures are related to drilling and then trucking the oil or tying it into a pipeline. We can go through each of those, or we can look at the company holistically. One of the reasons Baytex is so interesting is that it spans this range of activity, different hydrocarbons, and some of the different property ownership setups in the oil and gas industry.

3. A broad overview of Baytex today and its history

I think we should definitely revisit the economics, and the best way to do that is probably to look at it on a basin-by-basin or geographical basis. Maybe this is a good opportunity to transition to Baytex itself and go over the history of the business and how it got to where it is today. Could you give us a broad overview of the business, how it was formed, and how it developed into what it is today?

Baytex has spanned a few different business models. I started my career doing management consulting, and the firm I was at had this idea of “profit models”: ultimately, many different sorts of businesses could be boiled down to relatively few mechanisms for turning business activity into profit. That’s really what business is about: generating profit and then distributing it.

The first activity Baytex was involved in was, when it was founded and taken public in 1993, essentially rolling up assets that were producing in Canada. A roll-up is when you take a public company and issue stock. In Baytex’s case, it issued its initial shares at 40 cents and then at a dollar a share. You try to find assets you can buy that are worth more in your control than they are in the seller’s control. Another way to describe it is “acquire and exploit.” That’s a more oil-and-gas-specific term, but generally, Baytex was a roll-up of assets. It acted in that capacity, in a kind of normal U.S. C-corp structure, from 1993 through 2003.

After operating that way for a number of years and going through a number of different transactions, it turned into what’s called a royalty trust or an energy trust. At the time in Canada, there were significant laws that favored energy trusts from a tax perspective. Baytex spun out some of its unconventional assets, which are now a different company, Crew Energy. It issued additional shares and created an energy trust, so it re-IPO’d.

That structure was even more favorably aligned with its acquire-and-exploit strategy, with an extra aspect: it would pay out nearly 100%, or in some cases more than 100%, of the cash flow it was generating from the business.

It was less about buying and doing better, and more about buying, doing better, and paying out absolutely the maximum they could. Royalty trusts at the time were valued based on how much they paid out, not necessarily how sustainable that was. There was a whole game to try to pay out as much as possible and acquire as much as they could, and they engaged in that for a number of years.

Then that trust structure broke down. There was a change in the tax law, I believe around 2006, where these royalty trusts were forced to restructure because the tax exemption they were relying on was closed. It was apparently too favorable for the companies, and too many companies in Canada were becoming trusts. They switched over to a less dividend-oriented, or distribution-oriented, company and went back to the acquire-and-exploit model. They did a number of other transactions through the downturn in 2014, including a large debt-financing transaction that year.

I’m skipping forward a little, but if you think about the history of the business, it’s been about finding interesting assets, acquiring them using stock, debt, and cash from operations, and then having this view that a bigger company with more assets would end up being worth more than it would have been if they hadn’t assumed the debt necessary to acquire those additional assets. What does that asset base look like today in terms of where they’re located and how much they’re producing?

Today, they’re producing just under 85,000 barrels of oil equivalent a day. About 75% is oil. They’re producing about 30,000 barrels a day in South Texas, in the Eagle Ford Shale. The rest breaks down pretty cleanly between heavy oil production on the border of Alberta and Saskatchewan, heavy oil production in this new area that makes them particularly interesting to talk about—the Clearwater in Alberta, which is a new oil discovery they were involved with—and some more conventional oil and gas production in Central Alberta.

4. The production of a barrel of shale oil and unique characteristics of shale

Maybe a good way to work through this is to go one by one: shale wells and the economics in the Eagle Ford, then one of the more established heavy oil plays they have exposure to, and then the Clearwater. Starting with shale, can you walk us through what producing a barrel of oil from a shale basin looks like, and describe what got investors so excited about the U.S. shale boom in the late 2000s and early 2010s, before the eventual downturn we’ve seen? Maybe you can level-set expectations in terms of what shale means relative to heavy oil, what the break-even costs for a shale barrel of oil are, and some of the other considerations that go into that.

These are great questions and thoughts. This is really important relative to the overall oil and gas industry, as well as the topic of inflation, which has become so central to economic discussions and investments. The shale boom in the U.S. and then in Canada helped keep energy costs in the U.S. down through a surplus of natural gas production. It also helped keep global oil costs down over the last number of years, through unexpectedly high production from individual wells. Many of those wells got drilled to the point where the world actually had a glut of oil for several years, purely from drilling wells in South Texas, West Texas, and a few other places.

The Eagle Ford is remarkable because Baytex and the predecessor company it acquired in 2014 have been actively drilling wells there since, I think, 2010. Despite that, they show over 200 remaining drillable locations on their land, which is pretty remarkable given how many wells have already been drilled there—several hundred, I think. The story for shale, as seen through this Eagle Ford asset for Baytex and others, is that there’s been almost continual downspacing: the ability to get more wells on a given amount of land, along with increasing recoveries from those wells, so you end up with more oil than initially expected.

Until recently, the general trend was falling costs on an absolute basis. As oil well productivity rose from 2010 to, I think, its peak around 2018, and well costs fell, the marginal cost of production for oil and natural gas went down. For natural gas, that was a North American phenomenon because natural gas is mostly landlocked here, with relatively little export capacity. Oil has a global market.

It’s remarkable that the industry was able to stack up enough individual wells, each producing roughly 1,000 barrels a day on initial production and then declining quite fast, and drill enough of them over time to glut the global oil market, which produces roughly 100 million barrels a day worldwide.

5. The main drivers of increased productivity and optimization in oil production

It sounds like, in the shale plays, there was an ability to identify where oil was in the ground and actually produce more—or take more out of that rock—than was previously expected. Was that a major breakthrough in technology? Was it better identification of where exactly the oil was? What was the main driver of increasing productivity on a well-by-well basis?

There were a few factors that coincided. One was the ability to do a lot of reps: essentially, to drill many wells and experiment with them. By the 1,000th well, you might be much more efficient at drilling and have figured out a lot better where to place sand. There were lots of opportunities for optimization.

Because there was so much activity and so much money being spent, there were lots of opportunities for scientists and inventors to come up with new equipment and processes. They were strongly economically incentivized to do that because they could save oil and gas companies and service providers lots of money while also making a lot of money themselves.

The mineral rights arrangement in the U.S. in particular is somewhat unique, with private mineral ownership. That’s different from Canada, where almost all the minerals are held by the Crown, by the government of Canada. In other countries as well, minerals are generally owned by governments, not by private landowners or citizens. That opened up an alignment of interest between the people who controlled access to the resource—the mineral rights owners, the surface owners, and so on—and the companies that wanted to extract the oil.

There was the ability to do a lot of reps, to invent a lot, and to access the land. Finally, to get to the point where there was an oil glut, there was a boom in low-cost financing: very low interest rates, the search for yield, and a private equity boom. There was a wash of capital looking to go somewhere. Shale was identified as a place where, as you deployed more money, your wells got more efficient and reached a lower required oil-price break-even. Hundreds of billions of dollars were invested there. Ironically, much of that money ended up getting lost because too much came in—a case of too much of a good thing.

6. What breaking even looks like today on a barrel of oil

What does that break-even look like today in the Eagle Ford?

It’s actually a more complicated question than you’d think. After years of underinvestment, all that activity hit a crescendo in 2018 and started to slow down. During COVID, a lot of activity fell off, and the industry is in the process of rebuilding activity levels.

As that happens, service costs are rising rapidly in real time. That includes the cost to rent a rig and access the labor and equipment necessary to drill a well, as well as the cost to acquire or rent pressure-pumping equipment, labor, and related equipment. What companies thought things would cost, let’s say, 6 months ago is quite different from what they’ll cost today.

For example, in the Eagle Ford, Baytex’s land and activities are pretty much in the core of the play. A year ago, their wells were costing, in some cases, under $5 million. They were coming on with average production for the year of about 700 barrels of oil equivalent a day, and they were expected to realize about 800,000 barrels of oil equivalent over the life of the well. For that math to work, wells came on at an average of around 1,000 barrels a day, then declined to maybe 300 barrels a day by the end of the year. After a few years, production stabilizes at, let’s say, 50 barrels a day, where it stops declining quite so much. Over 30 years, the wells might get to 800,000 barrels or so.

That was the cost last year. Right now, it might cost as much as $7 million to drill, complete, equip, and tie in that same well. That number isn’t static; it’s moving and may move significantly higher.

Those numbers are all great, and I should probably be able to do the math on the back of an envelope. But in terms of where they think about the oil price break-even being—whether that’s $40 a barrel, $50 a barrel, or $60 a barrel—with the understanding that it’s going to move around a lot and there’s going to be inflation, is there a general rule of thumb or barometer for what they think of as the break-even price in that region?

I try to stay away from that because there were a lot of claims by oil company executives during the shale boom, as well as by private equity funds and private companies that sold assets for huge valuations.

They would make various claims: “Hey, our break-even is $25 a barrel or $30 a barrel.” Many of those claims were unrealistic, and potentially worse than that. I think the better way to look at it, or the way I’m more comfortable looking at it, is to ask what the return is at some substantial discount to the current price of oil.

If you look at Baytex’s corporate presentation, they claim that at $65 oil, with lower well costs than they’re probably seeing right now—but higher than they saw a year ago—they’re getting 500%-plus rates of return on their Eagle Ford assets. Is it that? Probably not. Various costs get excluded, and some expenses are much higher now that oil prices are higher and activity levels are rising. But are they earning a greater than 100% rate of return on that, excluding the cost of acquiring the asset in the first place? They’re probably making a lot of money on these wells.

In my assessment of companies like this and Baytex’s assets, my approach is to be directionally correct rather than precisely wrong. If you really wanted to estimate the break-even here, assuming static service costs—and those costs are probably lower at lower prices—it’s probably in the $30 to $35 a barrel range. But those metrics often exclude a lot of costs and may not be the best way to think about it.

7. Describing the decline rate of a shale well compared to conventional plays

You mentioned something earlier in that answer that I want to unpack a little, and I think it’ll play into how we talk about some of the other regions as well. You mentioned that a well might come on at 1,000 barrels a day, and then, by the end of year 1, it might be producing around 300 barrels a day. That’s a pretty steep decline in the well’s production profile.

I assume that also means you get a faster payback on the well, because most of the production comes up front in its life. How would you describe the production profile of a shale well and its decline rate relative to some of the other conventional or unconventional plays? To me, that screams, “Okay, if I need to keep my production profile up, I’m going to need to keep drilling.” Is that the right way to think about shale players? You spend up front, but you have to repeat that spending continually to maintain production?

Absolutely. The right way to think about unconventional producers—shale producers—is that they need to reinvest a substantial portion of their cash flow to sustain production. Obviously, that changes at different oil prices. The percentage that Baytex needs to reinvest at $50 oil is different from what it needs to reinvest at $100, because the well’s decline rate doesn’t really care if oil is at $10 or $100. It just produces and declines.

There are things companies can do to change that, but generally, the production decline rate is what it is. There’s some leverage to higher oil prices, but there’s also negative leverage to higher service costs in that business model. The right way to think about an unconventional business is in terms of the free cash flow generated over mid-cycle oil prices, rather than EBITDA or operating cash flow without factoring in the maintenance capital needed to sustain production.

8. Overview of the differences of oil blends and quality coming out of Texas versus Canada

If we take a barrel of shale oil, which I think we’d consider light, sweet crude, and compare it with a barrel of oil produced in Canada—I’m going to talk a little about the heavier side of things—what are some of the differences in the quality of the oil and its uses? We tend to think of oil as a commodity, and the definition of a commodity is something very substitutable, but there are differences. Could you give us a quick overview of the differences between what comes out of Texas and what comes out of Canada?

At a very high level, different oil blends have different gravities. Very dense oil has lower gravity, while less dense, almost gaseous oil has much higher gravity. They go through refining processes and end up yielding different amounts of diesel or jet fuel versus gasoline and other oil products. Given certain standard refining processes, heavier oil might yield more diesel, whereas light oil might yield more gasoline and other products.

I don’t track the refining spreads for these different products to make sure they’re economic, or track those trends to make sure they’re not about to become a lot less economic. The specifics around the chemistry matter to a company like Baytex only insofar as it doesn’t want to be on the wrong side of a long-term trend.

It’s an interesting, perhaps nerdier point: the chemistry and exactly what’s burned off and what goes through the refinery. The point is that there’s a different demand case for some of those barrels relative to the ones down in Texas. Maybe we can transition to Baytex’s Canadian assets. Since the company is listed in Canada, could you give us an overview of where it operates there, its production profile, and how that might differ from U.S. shale plays?

There’s one last thing on the oil-quality question that’s worth talking about for a second. One benefit Baytex gets from having so much of its production in Canada, rather than being a full U.S. unconventional shale producer, is that U.S. shale grew so much, so unexpectedly, that the U.S. refining slate—mostly along the Gulf Coast—isn’t really oriented to process the oil coming out of unconventional shale, primarily in South Texas and West Texas.

A lot of the oil produced from these shale plays ends up being exported to foreign refineries that are better suited to refine it. Heavier oil is imported to refineries along the Gulf Coast and elsewhere that are oriented toward that heavy product. One thing that’s really interesting about Canadian heavy oil is that it actually meets a lot of the criteria for U.S. Gulf Coast refiners.

When you look at Baytex’s production in South Texas and where it ends up, especially on the oil side, the natural gas is likely used within Texas, but the oil is likely exported and refined in Asian refineries or elsewhere. It may also be brought down surreptitiously to Venezuela and blended with their heavy oil to transport it elsewhere. In some cases, the oil Baytex produces in Canada is brought down to the Gulf Coast and refined not that far from where its Eagle Ford production is. A lot of its production travels quite far, even though some of it is quite close to active refineries.

Where, beyond Canada, does the U.S. import that heavier oil from?

We still get it from Venezuela, even though we pretend we don’t. We used to get it from Russia, and there are various other producing regions that produce heavy oil that we import. But the reality is that a lot of it still comes from Venezuela and other places we try to pretend aren’t supplying it.

There’s a joke now, with Russian exports being limited and in some cases either sanctioned or self-sanctioned, about—I think it’s—a Latvian blend. It’s funny because there’s no oil in Latvia. They’re essentially importing oil from Russia, blending it with oil from elsewhere, and then pretending it isn’t Russian oil. I think a lot of that happens with oil imports to the U.S.

That’s one reason it’s important, from an energy independence and national security perspective, that this oil is produced in the U.S. and Canada. People used to think a lot about energy independence and national security in relation to oil and gas, and they’ve thought about it less until very recently. Canadian oil production is actually very strategic to U.S. energy security because it’s so useful for U.S. refining slates.

9. A snapshot of what Baytex’s Canadian operations look like

Great point. I was speaking to someone on a call about that last week. It’s not part of the narrative with everything going on in Europe right now, which is somewhat amazing considering that 15 years ago it felt like everything revolved around our energy dependence on other countries. It’s really interesting how much can change when a large amount of capital goes into a sector and necessity breeds innovation.

That’s a good opportunity to transition to the Canadian side of things. A snapshot of what Baytex’s Canadian operations look like would be a good place to start.

Baytex has a few assets in Canada that are worth focusing on. One is its Viking asset. Ironically, the biggest transaction Baytex ever did in terms of dilution to acquire assets was its merger with Raging River, where it issued about 50% of its outstanding shares. So it issued about as many shares as it had before to merge with Raging River, which had just one asset: Viking oil production. There was some other stuff that came with it, but from a production perspective, it was almost all Viking oil, which is light oil similar to U.S. shale, except each well costs a fraction as much and produces a fraction of the oil.

It was an interesting transaction because, on one hand, it really changed the nature of the company by dramatically increasing the shares outstanding, as well as increasing the decline rate, because unconventional oil declines so much faster than conventional oil. On the other hand, because of the timing of the transaction, Baytex was able to survive multiple oil crashes. Since the transaction, the asset has declined a lot.

On the other hand, it may be the reason why Baytex exists in its current form and didn’t have to go bankrupt when heavy oil prices in Canada went to almost zero in 2018, and then again when oil prices actually went negative very briefly in 2020. To recap, the benefit there was a diversification of the oil production quality. Raging River also had relatively little debt.

Baytex was able to issue equity through the acquisition or merger with Raging River, get enough production and enough cash flow, and survive the downturn in 2018. That positioned them to do some things that looked a little funny to outsiders but actually allowed them to survive the 2020 downturn as well.

It makes sense to start with the Viking because it took so many shares and became such a big part of the business, even though, on a production basis, I think they’re only producing about 10,000 barrels a day from the Viking currently. It’s an interesting thing: They used 50% of their shares to end up with, I think, a little over 17,000 barrels a day of production in the Viking when they bought it. That production has declined, and now you have an 80,000-something-barrel-a-day producer. About 50% of their current shares are attributable to only 17,000 barrels a day.

It makes the Viking noteworthy. It’s actually not a huge asset for them anymore. It generates some free cash flow, and the returns are decent, but not remarkable. They’re actually on the lower side versus some of the other things Baytex does. But it’s worth mentioning first because of the history of the business and how many shares went out versus what the business looks like today.

From a return perspective, before going to the other assets, just using their numbers and then sanity-checking them, they claim that at $65 oil these wells pay out in a little more than a year with an 82% IRR. Realistically, they probably pay out in a year and a half at $65 oil, but that’s still not bad. You don’t get much profit beyond that at that sort of price. You really need higher prices, and they have a huge amount of inventory there because it’s a little less economic than some of their other stuff.

So they’re able to slow-play it, allow production to decline a little, generate a lot of free cash flow from the asset, and then redeploy it into some of their higher-return core assets. In addition to their Viking oil play, they have heavy-oil-oriented lands across a few different places, and they have a more U.S.-style shale play that they’re incubating. That makes them a very interesting business. There’s an aspect of the business that I think people don’t fully understand, and it offers one of the more interesting aspects of oil and gas—or really of any sector—after a long downturn, when many people don’t even know where to look to find giant assets that aren’t being attributed any value by the market for various reasons.

10. The other major Canadian assets Baytex has

The capital allocation points there are particularly interesting when talking about the economics of those wells at $65. I think you referenced what the Eagle Ford wells were, and we’ll get to the Clearwater as well and the excitement around that asset. Beyond Viking, what are the major assets that you would point to in Canada, or what else is worth speaking about for Baytex?

Their historic heavy oil at Lloydminster and Peace River is great. These are the assets they built their company on over many years, and it’s funny that they’ve almost become a side note. They’re the largest producing asset set after the Eagle Ford, but they’re just not the focus of the business anymore. They’ve also essentially become cash cows, even though their returns are phenomenal as well.

For their Peace River multilaterals outside of the Clearwater, they cited a 120% rate of return. Again, you sanity-check that and sandbag it by 50%, and it’s still pretty good. Same idea with Lloydminster: Those returns are actually very high. I think one of the things happening there is that they were quite low—they were actually the lowest of all their assets—and then they’ve been applying some of the new technology being used in the Clearwater to this legacy asset. They show 300%-type rates of return.

Honestly, I would toss that. I don’t think that’s a real return that’s applicable to that whole asset base. But if you got a 75% or 100% rate of return at $65 oil, that’s still quite noteworthy and doesn’t require a lot of hand-waving. It probably reflects the full cost, including acquiring the land, building infrastructure, and all these other factors that are often overlooked. It probably also factors in higher services costs.

So you have these base businesses at Baytex. You have their Eagle Ford back in the U.S., where it’s generating a lot of free cash flow. They don’t even operate it; they have this long runway there to just sit on it, generate free cash flow, and participate. They have their Viking, which they’re also sitting on, allowing it to decline a little and generate a lot of free cash flow even at much lower prices.

You have their heavy oil, which is a similar idea. It’s not really something they’re focusing on or ramping up. Then you have their Clearwater, which is very sexy and a reason a lot of people, I think, own their stock today. And then you have their Duvernay, which is this shale play that I think is one of the keys to a potential re-rate for their company. I think that’s one of the value adds we can bring here: talking about how to find hidden assets and evaluate them, especially if a company won’t really talk about or emphasize them.

11. The heavy oil decline rate of Canadian oil wells compared to US shale wells

Before we jump, I think we should hit on the Clearwater next. For the heavy oil assets at Lloydminster, what does the decline rate look like, again comparing it back to U.S. shale wells?

It varies a little bit, but I think the right way to think about these sorts of assets is that they’re actually most similar to Gulf of Mexico offshore wells. A traditional offshore well would produce pretty strongly for a few years with roughly a 25% or 30% decline rate. Maybe the initial year of production might have a higher decline rate. It would produce for a few years and then water out.

With shale, the idea is that you could potentially have a well that declines a lot rapidly and then flattens out and produces for a long time. With conventional wells, in some cases you basically get flat production for a long time, and in other cases you get pretty good production for a few years and then nothing. It’s not that all of the wells go to zero after a few years, but many of them do.

I think the right way to think about the Lloydminster side of Baytex’s business is as wells that have great initial returns and decline much less quickly than shale wells, but never slow down to a stable, low production rate for a long time. Many of the wells just die.

12. What makes Clearwater such an exciting and interesting opportunity for Baytex

Good opportunity to transition over to Clearwater. In doing some basic research on the business, it was popping up quite frequently as the most exciting asset, the most interesting asset, and perhaps just a little less well known. Maybe you can go through what that looks like for Baytex, what it represents today in terms of production and size, and how you think about framing that opportunity for the business.

What’s interesting about the Clearwater is that it’s important for illustrating the different business models in upstream oil and gas. Again, one of the reasons Baytex is so interesting is that it spans so many of these different business models.

After the highly dilutive deal they did to survive—I can’t criticize it, because they likely wouldn’t exist without having gone through bankruptcy if they hadn’t done that deal—they lost their appetite for the acquire-and-exploit strategy that they had started and grown the business through. One thing Baytex did that’s actually quite rare in oil and gas today, and was even rarer when they were doing it over the last couple of years, is identify a trend that was working. They acquired land for almost no upfront cost and explored on that land to see if their geologic theory would translate to economic oil reservoirs that they could further explore, delineate, and develop.

Baytex’s main Clearwater asset is on the Peavine Métis Settlement, which is the equivalent of an American Indian reservation. They came in and paid, I think, a few million dollars in a lease bonus to acquire the rights to produce oil and gas on that settlement, on that land. The minerals are still owned by the Crown, so they’re still owned by the government of Canada. But they’re also paying the settlement, I think, a 6% override—something along those lines—as a royalty.

That might sound like a lot, but in the U.S., the typical royalty is 25%, and in Canada on Crown lands, it’s a sliding scale, from, I think, 3% on the low end up to 30% or so at really high oil prices, after wells have paid out. Paying 6% in addition to the initial 3% or whatever for the Crown royalty is actually not a very high royalty, but it aligned Baytex with the local people.

This is especially relevant because it’s a settlement and not raw land governed by Alberta. It’s a very intelligent way to go about things, and it was a deviation from the trend for the business, which has mostly been—especially among public oil and gas companies—to either develop existing assets or acquire assets that have been explored and already delineated and somewhat developed. Baytex is an E&P company, so exploration and production, and they actually do some of the exploration.

13. Identifying where oil might be and what that process looks like

Other companies do this, right? They’re not alone, but this is probably one of the best success cases of exploration activity by companies like Baytex in many years. Maybe we can talk just really quickly about what that exploration phase actually looks like. It’s not somebody on the beach with a metal detector scanning around and getting some bounce that tells them there’s oil down there. What does the process look like in terms of identifying where oil might be? I think this is often miles below ground level, so what does that process look like for any of these businesses?

It really varies depending on who’s looking, where they’re looking, and what activity there’s been in the area. In an area where there’s been no oil drilling activity—or no drilling activity at all—there are various signposts people would have looked for 100 years ago when searching for an oil field. Is there oil seepage that makes it to the ground, where one of the reservoirs has essentially a leak that somehow makes its way to the surface? Are there certain geologic features that make it likely there’s a trap, indicating that there might be a geological structure underground that could hold a conventional oil pool?

In this case, because there’s been a lot of activity in the general area historically, I believe there were several vertical wells drilled either on the land or in the general area that would have indicated oil was present in this formation. It was probably a combination of seismic maps over the general area, identifying a zone that could hold this oil, and old well logs showing what it looked like to drill down through the area historically. Then they could combine those and compare them to other wells in the region that were or weren’t productive to calibrate the likelihood of success.

I’m saying this with some speculation because they haven’t fully shared how they approached it, partly because they’ve been acquiring additional land in other areas, likely using the same strategy. A lot of this is generalizable, which is why I can talk about it; I’m not giving away any of their secrets. But there may be certain geologic keys they figured out for this particular thing that they’re better off not telling people about, so they can go buy more land elsewhere and potentially replicate their success.

It’s an interesting piece of the business. I remember reading about Aubrey McClendon and Tom Ward in their early days of acquiring assets and figuring out where to drill. They were literally going into libraries and going through some of the drilling history in the region. This was way back when a lot of the industry took off in the Oklahoma City area, I think.

There are all different ways to do it. Then you have the opposite end of the spectrum. When I first started my career at Goldman, we brought a deal for a business that had a bunch of acreage off the coast of West Africa. The idea was that when you looked back at Pangaea, it was lined up with Brazil, and that same plate along the coast of Brazil produced a ton of oil. So, in their mind, it would make sense if they produced a lot of oil in West Africa. There are all different methodologies you can use. I don’t think those wells off the coast of West Africa turned out to be too profitable, but nonetheless.

14. His process as an investor in evaluating new projects like Clearwater

So, for you as an analyst looking at the Clearwater project and deciding what’s an attractive opportunity, how do you approach this? How much capital is going into the project, and what are you initially looking for? Maybe you can talk about the process for you as an investor to evaluate initial well returns—what they look like and how you think about them as an investment.

It’s tough, partly because there hasn’t really been this sort of activity at scale in a while. Generally, I don’t like to invest in exploratory-stage companies because there’s too much of a chance of failure. Historically, especially among public companies, the expected value of exploration activity through a public company structure is obviously less than the dollars it would cost to participate. I don’t like participating in activities that aren’t high expected value, especially when there’s a lower likelihood of a return of capital.

In this case, it was interesting because there were some initial indications of success in the Clearwater, and that wasn’t valued in their stock when I ended up sizing up my investment in the company. Ahead of time, I probably would have attributed zero value to this. I might even have attributed negative value to the spending necessary to explore it, but it wasn’t really expensive for the company to do most of the exploration activity. The land cost was very low. I think they spent a few million dollars on the land, a few million dollars on the science around it, and a few million dollars on drilling the first wells. It wasn’t a free look, but it was a very cheap look, and it was easy to be comfortable with.

I already owned some of the stock before these initial results came out. From my perspective, it was pretty hard to assess, especially given how little information they wanted to provide. To the extent this was successful—and it was—they wanted to be able to replicate the process they used elsewhere if they could find anything similar. There really wasn’t enough information for an outside public investor or potential investor in the company to vet it and figure out if there was significant upside.

Once the results came out for their first couple of wells, they were actually available through the Alberta Energy Regulator’s website before the company announced them, which was amazing. Any way you can get public information about companies and effectively utilize it, more power to you. They had a couple of wells that were very small in the Clearwater. It’s different from other shale plays or unconventional plays because they drill multiple laterals. They’re essentially drilling multiple horizontal wells from the same wellbore. These initial wells had 2 laterals, and newer wells they’ve drilled have 8 laterals from one wellbore.

It was interesting because those initial wells came on at approximately 175 barrels a day each, based on the data that was out. When I tried to explain this to some people, they thought that was a very low number and couldn’t understand why I was so excited about it. Their reaction made it more exciting to go buy even more because people just didn’t get it. There was some linear extrapolation, with an appropriate amount of discount: if they produced 175 from 2, they would reasonably produce, let’s say, 3 times that if they got 8. It wouldn’t be 4 times as much, but it would be some degree of extrapolation up, and it turned out that was a reasonable assessment.

Obviously, the costs for the wells are higher when you drill 8 laterals instead of 2. But on a development basis, if you drill a single well or 2 wells, it costs a lot to move a rig and arrange for all the various other services. Your cost for 1 or 2 wells could actually be quite high. Their cost to go from 2-lateral wells to 8-lateral wells didn’t actually go up that much when they started drilling them in a steady, continuous program instead of just drilling 1 or 2 wells at a time.

Is this all tapping into the same reservoir? I’m picturing it as having your initial vertical well, which goes down, and then your offshoots, where eventually it makes that 90-degree angle and starts going horizontally. Is it all tapping into essentially one layer of the rock underneath?

It depends. In this case, it’s not. It’s actually not even in the Clearwater formation. It’s in the Spirit River formation, which is similar to the Clearwater, but not the same. I think that’s one of the ways this particular field was missed: it was not the same depth, not the same zone. Other companies looking just for the same Clearwater zone might have missed this, whereas Baytex was looking throughout the Spirit River formation, which includes multiple different zones, including the Clearwater.

There’s an excellent graphic of a jelly donut and then a layer cake. I don’t know if you’ve seen this one before. It uses them as an analogy for the advancements in drilling: old vertical drilling was just plugging right down into the jelly donut and trying to capture as much as possible. With new horizontal drilling, you really get down into those layers of the cake and the different zones.

It’s always interesting to talk about, and I think it’s something a generalist often misses: there could be Eagle Ford in the same area as the Permian because they’re different zones in different layers of the earth, and these could be located in different states. It’s an interesting dynamic that I always appreciate.

I think it’s interesting because, for example, with Baytex’s Clearwater, I don’t think the actual Clearwater zone is productive for oil where they are, but their Spirit River is. You have this interesting dynamic where, as you’re saying, you can have the same zone in a different place, and it’s just not productive. In some cases, you actually have that layer-cake phenomenon, where multiple zones can be productive, and that can get confusing too.

One zone might be highly productive in one spot, and then, even a few miles away, it might be much less productive. It’s a sort of complexity you’ve picked up on that makes valuation quite complicated and requires a lot of technical expertise.

One of the things I skipped over, which is extremely important in understanding this and made me a lot more comfortable with it, was this: I’m not a geologist and I’m not an engineer. I think there’s a lot of humility that goes into these things, and there’s a lot of benefit in recognizing what you don’t know. There’s also a lot of history that you don’t have if you’re not a geologist or an engineer, and so on. So many people who looked at this particular area didn’t like it for various reasons based on their prior knowledge, either their activity in the area or their personal conception of what the geology or the oil would be like.

There was concern that the oil would be too heavy. There was concern that there would be too much H₂S, essentially poisonous gas that could make operations more expensive, as well as lower the quality and sale price of the oil. There were various other concerns that people had. One of the things I did, and I think it’s relevant for evaluating similar things in other places, was find people who were experts in this sort of thing without a lot of prior negative or positive history with this particular field.

Finding multiple people with different perspectives on this particular asset and discovery was helpful. Knowing those people right away and being able to get feedback within a couple of hours was a huge advantage, because once this information ended up on the Alberta Energy Regulator’s website, the stock started to go vertical. Being able to accurately and rapidly assess the thing without bias, and being able to find the right set of experts to evaluate something, makes a big difference.

I think it’s a generalizable lesson for oil and gas evaluation, where there are risks on both sides. If you don’t know anything and you think you can evaluate it, it’s probably a mistake. If you’re an expert in it, you probably don’t want to be the person evaluating it either, because there’s a big risk that your prior personal experience may bias your evaluation as well.

15. How to ascribe value to a project like Duvernay compared to Clearwater

You described that opportunity almost like it was an option value embedded in the equity price, and a very cheap option if you’re paying anything for it at all. How would you describe the Duvernay in that same category? How do you go about describing value for something that sounds like they’ve disclosed very little about, and that the market gives little attention to today?

The Duvernay is actually different from the Clearwater, because Clearwater went from essentially zero to 60. It went from no one attributing any value to it, and no one even really knowing the company had it, to suddenly having highly productive, extraordinarily economic wells in the hottest play in Canada, possibly one of the hottest plays in North America for oil and gas. Suddenly, they went from being a nobody to having 3 of the top 5 wells, ironically competing with Neil Roszell’s new company. The guy who was CEO of Raging River, who sold them their last company, now has another very similar company in the Clearwater.

This time, Baytex is already there, and they have the top 2 wells and 3 of the top 5, and many of the top 20. That’s different because they’ve already ramped it up to the development stage. They have thousands of barrels a day of production, and they’re on track to maybe get to 10,000 barrels a day over the next year or so from an asset that had zero production. It took relatively little capital to get it there because the wells pay back in 1 or 2 months. You put $10 million or $20 million into a program like that, and you don’t really need to inject more; you just recycle that capital repeatedly.

The Duvernay is different because the wells are very big and, until recently, even with $100 oil, it took a while for them to pay back. Unlike some of the other fields we talked about, these wells are getting drilled 1 or 2 at a time, and they have the high decline rate you see with shale. Until recently, with higher oil prices, they also had a several-year payback. You’re going from an initial 30-day production rate of more than 1,000 barrels a day way down pretty fast. So, there are first-year decline rates of 70% or more, but you’re not getting all your money back in the first year—or you weren’t at lower prices—and you may not get your money back in the first 2 years at $50 or $60 oil.

The company has intentionally slow-played this because the idea is to focus on assets that generate a lot of free cash flow in order to fix the biggest problem the company had, which was existential risk from high debt levels. That activity has paid off as they’ve paid off a lot of their debt. They’ve maintained enough activity to have a couple thousand barrels a day of production, and they invest $10 million to $20 million a year to sustain the asset.

They have this giant asset that, in a sustainable high-oil-price environment and with the ability to deploy meaningful capital into something other than paying down debt, they’ve essentially preserved as a right-tail oil option. Because they’ve done this small amount of activity and maintained a small amount of production, the market isn’t really attributing a lot of value to it. Given how volatile the world is and how volatile oil prices have been, there’s this “pay me now” sort of approach, and anything that’s not really relevant within a couple of years, or that doesn’t have good line of sight, is being awarded very little value. But looking at the world, how much oil inventory is remaining, and what other projects look like, this thing starts looking increasingly attractive from a holistic perspective, as well as from a sustained, higher-oil-price, highly economic perspective.

16. Baytex’s approach to hedging and how it differs from the rest of the industry

With the slower payback period, I think about that as a higher cost of production, so a higher break-even cost. At these higher oil prices, that changes the equation a bit. You’re essentially able to pay back those wells much faster. Something that comes into play here is the visibility of the oil price. How do management teams, and Baytex in particular, think about a scenario where they could hedge out $100 oil for the next 12 months and make sure that production is hedged at $100 to ensure they’re locking in the profitability on those wells? That’s the overly simplistic approach to this. How do they go about their hedging strategy, and how does it differ from or compare to the rest of the industry?

First of all, they can’t hedge at that price. The forward curve for oil is a lot lower than the spot price. So, the amount you can lock in if you want to guarantee your oil price for the next year is maybe $85 or $90 a barrel, versus the current $100. You can’t really lock in the full current price for oil, and that reflects a tight inventory environment where storage providers and companies that have access to oil are being economically incentivized to provide their oil now instead of later. That’s the reason the forward curve for oil prices is structured the way it is.

17. How the management team at Baytex manages capital allocation

Because they can’t do that with this sort of asset, and because this isn’t their only asset, they’re able to hedge on a corporate basis. They’ve typically been hedging 40% or 50% of their overall production, and they include the Duvernay as part of their capital expenditure mix. They take advantage of being a reasonably large company and being able to incorporate this longer-life, longer-duration asset into the mix with other assets that are spectacularly high-return and really call for most of their capital. They preserve the option value of that asset while investing in the highest-return assets.

Maybe you can talk a little bit about the capital allocation strategy in general and give us an overview of the management team. We haven’t talked much about this management team, or whether it’s been the same since the 2014 acquisition of Raging River. The industry as a whole has a reputation for taking every dollar of operating cash flow and putting it back into the ground, regardless of where the oil price is. That has changed somewhat over the past couple of years, but maybe you can level-set expectations on how Baytex compares to the industry and how this management team approaches capital allocation.

The current CEO, Ed LaFehr, joined the company in 2016. That was before the merger with Raging River. He had been a senior executive at several other oil and gas companies, where he had effectively navigated them through multiple cycles. I think it’s important to note that he wasn’t involved so much in leveraging up the business, and he’s been a steady hand in terms of deleveraging and doing things that people maybe didn’t want from a leveraged producer.

Generally, if you lever up, you’re more risk-loving, and your investors might be more risk-loving. So, he came in with a mandate of deleveraging and turning Baytex into a less interesting company as a bet on oil prices, and a more interesting company as a bet on the assets and cash flows from a medium- to longer-term perspective. He’s been a very contentious figure among prior shareholders who may have been betting more on higher oil prices.

Fortunately for the business, he came in when he did, because he took necessary steps that were painful but allowed the business to survive and, ironically, preserved value for many shareholders who were quite upset about things like the Raging River merger, which was so dilutive. He could be the CEO of a 300,000-barrel-a-day company, and they’re producing less than 100,000 barrels a day.

He’s allocated a lot of capital since he’s been in the business toward debt paydown, even before that was popular. If you look at how the business did last year, they spent less than half of their available cash flow on capital expenditures and more than half on debt paydown, while keeping production relatively flat. Now they’re doing even more of that, along with starting to return capital through share buybacks. That’s actually become more in line with the general industry. At the time Baytex started doing that, it wasn’t the norm. This is a case where the industry has come around to what they’re doing, rather than Baytex adopting something that happens to be popular right now.

18. Why return capital to shareholders

The other thing to note is that in 2020, their leverage was 6 times debt to cash flow at the end of the year. Take a business like that, and they’re on track to be at zero debt by the end of 2023, maybe even with a little net cash. You completely change the profile of the business, the risk profile, and the appropriate valuation. It does beg the question: if you have wells that will produce at 500% IRRs and oil prices are where they are today, why not drill more? Why return that capital to shareholders if there’s such an attractive opportunity set for capital investment?

That’s a great question, and I think that’s something that frustrates their shareholders. I think they’d been resistant to that at higher debt levels and more interested in just paying off their absolute amount of debt. But it does look like we’re seeing the early indications that they’re ramping up production and activity.

The interesting thing about 500% rates of return—and again, discount those heavily; maybe they’re 200% rates of return—is that even at 200%, you’re getting your money back in 6 months. Some of their wells are legitimately a lot better than that. If you can do that, you’re essentially putting money into a flywheel and amplifying it rapidly. It does look like they’re in the early stages of doing that a little.

The nice thing about it from an industry perspective is that there are very few fields in North America and in the world where you can earn returns anywhere close to the returns Baytex is earning. Baytex is doing this, but many other companies aren’t able to because capital efficiency is so much better in the Clearwater, and specifically in Baytex’s Clearwater, than in most of the other places where companies are active.

It does look likely that they’re going to be able to grow out of their debt problem to some extent, in addition to paying off a lot of their debt. So, I think they are doing it. I think it’s been frustrating for investors who were betting on higher oil prices that they hadn’t grown faster. I think it’s happening organically, as these wells are so productive that they almost can’t not drill more and produce more. As they pay down their absolute debt levels quite a bit, they’re also freer to put a little more capital into the business and accelerate that process.

19. Metrics he uses to value an oil production company or adjacent business

Interesting inflection point. As an investor, how do you approach these businesses? What metrics do you use to value an E&P and oil producer?

I generally triangulate because I’ve found that relying on any one metric can end up exposing the capital to loss. Frankly, it’s been such a tough business to invest in the oil and gas industry for so many years that I think it’s really necessary to take a careful approach to evaluating every individual opportunity to avoid being blindsided. Unfortunately, I think we learn these things by making mistakes and learning what to look for.

The easy one to point to is production versus enterprise value and production versus debt, to get a high-level idea of how much cash-flow-generating activity is happening within the business without requiring additional capital, versus how much you’re essentially paying for it. That’s from a debt perspective, because the debt absolutely has to get paid back over time for these companies, as well as from an enterprise value perspective, to understand what you’re paying for it and hopefully get a return on your capital in addition to a return of the capital.

There’s a production question and a reserve question. These companies all have assessed reserves from their external reserve auditors, as required by the SEC in the U.S. or the Canadian SEC up in Canada. There are various methodologies for using these reserve reports. They’re kind of as informative as real estate assessments: interesting and helpful, but definitely not something to rely on exclusively.

There’s also a cash flow measure. Cash flow is interesting because it’s really subject to your assessment of their likely costs, as well as the likely price for oil, natural gas, and natural gas liquids. An important factor there is the local price for production. It’s not just about the price of oil at NYMEX for WTI; the question is how much the oil you produce in any particular spot sells for.

This is very relevant for Baytex because there was a point in time when heavy oil went down in 2018, I think to $8 a barrel. At that time, it was really helpful for them to have all the South Texas production in the Eagle Ford. Right now, interestingly, with the Canadian dollar at a low value, Baytex is getting extra money from its Canadian oil production because oil is denominated in U.S. dollars and a lot of its costs are in Canadian dollars. Its revenue is actually higher partly because of a weak Canadian dollar.

It’s a pretty interesting setup, but it’s also worth reminding yourself when evaluating these things that local factors can change quite a bit. It requires quite a bit of evaluation to make sure you’re on the right side of that trend, or, if you’re on the wrong side, that you factor it into a discounted valuation.

While returns are important, understanding inventory is helpful as well. Understanding capital efficiency is partly about well returns, but also about whether production is falling off a cliff. Does it go away to some extent, like some of the Lloydminster production, or does it stabilize and stay around for a long time, like certain shale production? There’s this whole set of factors, and building out almost like a matrix to figure out the right valuation and the return profile for the equity seems necessary to identify the best opportunities.

20. Rules of thumb to consider when it comes to evaluating the asset base

You talked a bit about the reserve reports they include in their annual and other filings. When you look at one of these producers, what do you look for in a reserve base? How many years do they have remaining? Are there rules of thumb you consider when thinking about the asset base? Ultimately, the production base today means very little beyond this year’s revenue, and what matters is the reserve base. How do you go about interpreting and evaluating that?

Baytex is actually an exception for me to some extent. I’ve tended to avoid companies that are more active on the unconventional side because they typically have higher decline rates. When you own the public equity, you typically have to pay quite a bit for future production that isn’t yet booked as existing production.

Historically, shale-oriented and unconventional-oriented companies traded at a significant multiple to the assessed value of their current production. The idea, I guess, is that public equity investors are betting on the companies’ ability to replace existing production from identified inventory.

In looking at Baytex’s reserves and reserve value, it took a little humility and getting comfortable with the inventory Baytex has, as well as these multiple sources of upside potential—free options. They’re not free for me exactly, because I consider that I’m paying for them: I’m paying a premium to the pre-developed producing value of Baytex’s reserves. But they are free in the context of comparable companies being valued similarly without having those sorts of upside. So, they’re relatively free rather than absolutely free, depending on the underwriting approach.

In this case, it’s somewhat easy because you have this ultra-low-cost discovery in the Clearwater and this high-cost asset that people know about but seem to attribute little or no value to, the Duvernay. Between the two, it’s not necessary to look very far to see how to make up for a gap in Baytex’s reserves. Again, they’re fine relative to many of their unconventional competitors, but they’re not at the sort of discount I would typically look for. They’re made up for by these multiple assets that the market doesn’t seem interested in valuing yet.

21. Main risks that could drive stock underperformance

That’s a good explanation of why this stock would be a good opportunity in the bull case, in the bull thesis. If something were to go wrong or this business were to re-rate lower, what do you think are the main risks that could drive the stock and the business to underperform?

There’s asset risk and there’s balance sheet risk. The nice thing, and what got me comfortable on the producing value side, is the amount of data that makes those risks unlikely. But there is a risk that the next wells drilled in the Clearwater are terrible and that it takes a little while for the company to figure that out. That would reduce a lot of the upside and could cause the stock to fall quite a bit, because even though it’s not fully priced in, some success is priced in there. So, that’s an operational risk. It could be true for other assets for Baytex.

It just gets harder to imagine with some of the other assets because there’s so much history. It’s possible Eagle Ford wells could start getting worse, but again, there’s so much history on that asset and on some of the others. The benefit of this acquire-and-exploit model, especially years into it, is that you have a long track record of operational success or failure. At least you have a long history, and you can see it in the financial statements, not just in claims by companies. You can also see it in the well engineering, field engineering, and other things like that.

Clearwater, I think, would be a big potential risk. Again, so far it’s been a risk to the upside, not the downside. The wells keep being better than people expected, and better than I expected.

There’s also a financial risk, which is getting mitigated over time as they pay off their debt. But if oil went to $20 tomorrow, Baytex might suffer more than some of its peers because it still has relatively high debt versus its peers. There’s an implicit bet in owning or considering owning Baytex stock that oil prices will stay relatively high compared with where they’ve been over the last 3 or 4 years, for long enough to give them room to pay off debt. At $65 oil, they were paying off debt, but at $40 or $30 oil, they would be in trouble.

But again, if you think about it as a relatively low-cost producer across the assets they’re deploying capital into, they’re somewhat of a good proxy for the oil prices required by the industry. That risk is there, and it’s important to consider and incorporate in any investment decision, including the decision to just hold the stock and not buy or sell it. It’s really important to understand the local breakevens for the company, as well as the impact of financial and operating leverage like they have.

22. Lessons and takeaways from his time investing and working with Baytex

We like to wrap these conversations up with lessons learned throughout the investing process, or when talking to the operators. What are the key lessons you’ve taken away from the Baytex investment?

Things sometimes take years to play out. If you look at Ed LaFehr joining Baytex in 2016, things looked terrible a couple of different times for Baytex. There have been multiple times when many, if not most, of the company’s shareholders were deeply frustrated by his strategy and the choices the board and management were making.

They took a longer-term orientation: not drilling wells to get out of debt, but paying off debt from free cash flow; not accelerating development in assets like the Duvernay, which had lots of upside potential but also the risk of bankrupting the company; and not diluting the stock. Once they had to, they did it. But once they didn’t have to anymore, they didn’t issue a lot more shares to acquire assets when there was an opportunity to explore using internal resources and find upside they otherwise would have had to pay quite a bit for through dilution.

I think a big part of it is patience. Track records really matter, too. The management team at Baytex has created value over time, and I think that matters quite a bit. It was one of the ways to get comfortable with the opportunity: you had these very conservative people in this leveraged structure with this great discovery. It made it a little bit easier for me, at least, to get comfortable.

I also think there were lessons in acknowledging who they are, being able to see what they’ve done in past roles, and getting comfortable that they would do what they’d done previously at this company.

Well, Josh, it’s been a great conversation. Thanks so much for joining us today.

Thanks a lot, Matt. I appreciate it.