Australis Oil & Gas Limited (ATS.AX) Earnings Call Transcript & Summary

Thank you very much, Jon, and good morning to all of those who've joined us for this live webcast of the AGM. I'll pause briefly on this slide, just to remind those listening to the presentation that these disclaimers apply to both the content and the commentary provided during the course of this presentation. As this is an AGM, it feels appropriate to start by briefly reviewing some of the major events over the last 12 months. The key activity for us has been our initial drilling program, which had a number of positives and some challenges. I will cover this off in more detail later in the presentation, but we managed to prove rock productivity, and we demonstrated that wells could be delivered at a cost which makes for a very attractive economics. Unfortunately, we weren't able to complete all of the wells as full laterals with the desired repeatability, although we can now clearly identify the root causes that prevented us from doing so, and we believe that they can be addressed and managed. Obviously, as well, the last 4 months have created market mayhem. It's affected us as it has the entire industry. Australis is in a relatively strong position compared to most. We've got high netbacks, we've got control of our production, and we have a healthy hedge book. In addition, we promptly engaged with our lender, and we've aggressively addressed costs. The presentation, as I run through it, will provide some details of the asset, will provide some context for the asset by analysis and comparisons to some of the well-known premium unconventional plays, and I'll talk a little bit about the COVID-19 impact on us and the industry. At the end, I plan to circle back to what I think is the key question for us as a Board, as employees, as shareholders and as prospective investors. If you accept the premise that the company has an exciting asset with key attributes that are highly attractive for a new unconventional play, then how do the present market conditions impact on our corporate strategy of finding a partner to help develop it or even potentially take it off our hands? Is this strategy still valid? We firmly believe that it is, and this presentation will explain why. I'd like to start with a short description of what we set out to do as a team and what progress we've made. Our corporate strategy has largely remained the same since the company was formed in late 2014. We felt that there was an opportunity to secure a material unconventional oil asset at highly accretive entry price that had certain required characteristics. We identified the TMS as a valid target. And by the time we got to the IPO, we'd secured our initial position in the play. Over the subsequent 3 years through acquisitions and a patient leasing program, we've built a material position. And practically, all of the attributes we were seeking have now been unequivocally demonstrated and, where possible, independently verified. This includes reservoir performance, materiality, pricing benefits, entry cost and control, et cetera. Approximately 18 months ago, Australis kicked off the next phase of our plans with the initial drilling program. Whilst we had a large amount of historical empirical data that showed the well performance, with the history of the play, we felt it necessary to provide a refresh of that productivity data, and we also wanted to demonstrate what the early development economics would look like at today's cost base. The program was largely successful in a sense, but we did have the operational difficulties I referred to earlier that we weren't fully expecting. And I think we recognize and acknowledge the impact this did have on our share price. In addition to all this, as a backdrop to our activities, the U.S. unconventional market is going through a bit of a transition at the moment as most of the oil plays are reaching a level of maturity where Tier 1 inventory is becoming limited and then, for the very first time, growth projections are being questioned, and this was all starting to happen even before the dramatic pullbacks associated with the recent price collapse, which broadly brings us up to date. As we do believe we have an asset that under the right market conditions has significant value, our focus in these more recent turbulent times has been around asset preservation. This means safeguarding the balance sheet, reducing corporate costs significantly, all the while continuing the process of seeking a partner to participate in the asset. So why do we like the TMS? There's a number of attributes about the TMS in general and about our position specifically, which we feel are increasingly rare in the U.S. unconventional market. We've got that proven rock productivity, which is on par or better than premium other plays that are much more mature, where drilling and completion designs have been refined over thousands of wells. We've got a significant acreage position with conservative spacing assumptions. We're still got a large inventory of future locations, each one with compelling economics. It translates to an independently verified recoverable estimate that is material for any midsized U.S. oil and gas company. The acreage position is highly contiguous. We're designated operator over the majority of it. The leases have long tenure, and about 1/3 of our acreage is actually held by production. And moreover, the local field rules in Mississippi allow us to efficiently HBP the remainder. We've got a low royalty rate at about 20%, which obviously helps the economics. The wells we use to generate our projected performance have now all been on production for 5 years. And as such, we've got a high degree of confidence in the decline profile, and that's unusual in the U.S. for an undeveloped play. The wells produce 95% oil, and it enjoys a premium to WTI, and we've got abundant local infrastructure in close proximity. To have all of these attributes in a single delineated but undeveloped play simply doesn't exist elsewhere in the U.S., and as such, we believe that in time, appropriate value will be recognized for the assets that we hold. So what do they look like? The map shows the acreage position, and the blue oval, you can see, represents the area we believe where the subsurface characteristics come together to create that Tier 1 rock. In dark blue, you can see the acreage position the company holds, a little over 110,000 net acres, and the TMS wells are shown on the map as well. Those in red are producing wells operated by Australis; in orange are the 6 locations we've drilled; and in green, the wells that are operated by others, but within which Australis has an interest. In total, we operate 38 wells, and we have a non-operated interest in a further 18, which means we actually participate in more than 60% of all of the TMS wells that are being drilled. The existing production meets our lease obligations and holds our acreage by production. As I said earlier, that's about 1/3 of our acreage. And because we've been taking largely long life leases with modest royalty rates, then you can see from the pie chart that 85% of our acreage is either HBP-ed or has a lease expiry beyond January 2022. This long lease life means there's little pressure on the company to deploy capital in the short term to meet those lease obligations, and that's a distinct advantage, particularly in this environment. We're designated operator for over 100,000 gross acres, which again, means we have a high degree of control. Now Australis has long been the only proponent of the TMS. It's largely worked in our favor because we've been in an uncompetitive leasing environment. But last year, another oil and gas company started leasing in our area and has now built out a substantial position to the south and west of us, some of their acreage now extending into our core area. So this slide just touched upon the year-end reserve report that was issued by Ryder Scott. They allocated us a proved reserve of 48.6 million barrels and a total recoverable volume of 200 million barrels. I should point out we can only take credit for a 5-year development window and, as such, most of our acreage, about 69%, sits outside that window and we cannot allocate it at a reserve. As a result of our drilling program and the associated well productivity, Ryder Scott were able to increase our type curve from the previous year for all well categories, and our proved reserves went up by 53%. To try and put these numbers in some context, the bar chart on the bottom right-hand side compares Australis' proved reserves versus the oil and gas condensate proved reserves for some of the largest oil and gas companies in Australia. You can see we sit neatly between Oil Search and Santos. So during 2019, we drilled -- well, a little '18 as well, we drilled out 6 new TMS wells all within the core of the play. We certainly had our challenges. But during that program, we did achieve a number of our goals. The wells provided further proof of rock quality within the core area. The average productivity of those were 9% above our target type curve. Two of the wells were drilled and completed as full-length laterals. These wells averaged a little over $10.5 million to drill, complete time and produce. That's a 35% reduction on the average cost for Encana in 2014. Those wells set new benchmarks for economics of TMS wells. Those wells allowed us to increase the reserves that I touched upon earlier and obviously, added to the HBP position. However, we did have challenges during the program. And ultimately, we weren't able to complete the 6 wells to the full planned horizontal length. And I want to spend a couple of minutes talking about it. The first 4 wells were drilled with an inherited Encana well design. We used an oil-based mud in the horizontal section. As I say, 2 went up fully according to plan. One was drilled to full length, but we actually got stuck while pulling out a hole at the end of the operation. And after a couple of attempts to recover the drill string, we abandoned it in place and completed approximately 40% of the lateral on that well. The drilling of the fourth well was voluntarily abandoned partway through. We are encountering something we weren't expecting in terms of a stress regime, and that manifested itself both during the drilling and the fracture stimulation operations. Now partially in response to our live interpretation of those drilling programs, our problems in the first 4 wells and particularly the one where we became stuck when pulling out of the hole, we made a decision to trial a water-based mud system in the horizontal well section for the last 2 wells. Now that different mud system, it addressed the specific operational issues it was designed for but introduced additional challenges and new learning curves on wells 5 and 6. When we finished the program, we carried out a detailed post-operational review. We're able to revisit the basis for trialing that water-based mud. And it was clear with that sort of forensic hindsight analysis that the identified root causes meant that ultimately, we didn't need to switch the mud systems. We could also see that improvements to operational procedures will allow us to avoid those root causes in the future. So whilst we couldn't achieve all of our objectives with the program, we can now clearly show that the wells can be drilled on a highly economic basis. And the difficulties that we did encounter have now been identified, addressed and can be managed. The company has always managed its balance sheet throughout our Australis journey. Events of the last few months have obviously led to further proactive steps as we seek to manage our business in these present economic conditions. Specifically, activities fell into 4 categories. We've worked proactively with Macquarie, our debt provider, and we used available cash to pay down the existing debt position by $10 million during this quarter. This reduced our interest payments, and Macquarie agreed to waive certain covenants relating to oil price and amortization payments through to the end of 2020. We did this to remove any uncertainty on our debt obligations during this period of high volatility in the oil price. Additionally, as the likelihood of us drilling in this price environment we felt was to be low, we agreed to cancel the remaining undrawn capacity under the facility, which reduced costs further by removing the standby costs. The company has got the strong hedge book, which obviously provides revenue protection in this low oil price environment. And in the field, we'll be managing production levels to maximize the net revenue to the company. We operate 98% of our production, which gives us the control to do this. All discretionary CapEx is on hold. And as operator, again, we have the control to do this. And we've made substantive reductions in field operating costs, in overheads and KMP remuneration. We estimate at the moment, we've reduced G&A by 50% from our 2019 figures. I said earlier that our focus at the moment was on safeguarding our asset, and we're doing everything we can to achieve this. So I've said several times in this presentation that the TMS is on par with other plays in the U.S., and I'd like to address that over the next couple of slides. But first of all, I just need to briefly explain what our TMS type curve is. It was constructed using the data from 15 wells drilled by Encana in 2014. These 15 wells demonstrated a step change in performance in the play as a result of the drilling and the completion design, but also, they were all drilled within our designated core area. To generate our type curve, we simply take the arithmetic average of each calendar month's production and then we history match that cumulative profile. This is simply the average performance of the wells. There's no correction for downtime. There's no normalization. It's just the average. If you're interested, there's more details in the appendices slides to this presentation. Now 2 weeks ago, one of the shale analytics companies that operate in the U.S. released a report that caught our eye. It sought to identify the best producing counties in the 4 main oil shale plays in the U.S. They picked a 2-year cumulative oil volume as the comparator point, and they required that in order to qualify, the counties had to have been -- had to have at least 200 producing wells within them. The data is actually shown on the left-hand side in the bar chart. And you can see from top to bottom, the top counties within the 4 plays in the U.S. Now we've taken the same data from the 15 wells that Encana drilled in 2014, and we plotted it on the same basis. You can see there, it sits at #2 on the list. Now patently, there haven't been 200 wells drilled in the entire TMS, let alone within 1 county, but the 15 wells that we've used had a range of performance. They weren't cherry-picked. They weren't all good wells. And everybody, I think, will understand that results will only improve as we optimize the drilling and completion design over time. Now the same report then went on to question how the longer-term decline profile behaved, in this case over 60 months. ShaleProfile, they took the best county in each of the 4 unconventional plays, and they plotted the cumulative oil curve for a 5-year period on the right-hand side. Again, we're able to overlay the actual data from the TMS wells in red, and you can see the result. Sometimes when we talk to third parties, we often hear the comment that the TMS declines quickly. You can see very well that it actually compares to the very best of the other U.S. unconventional plays. Now the previous slide talked about oil productivity. This slide, we've tried to provide a comparison against case studies for 2 transactions within the Permian Basin. They were announced in Q4 of 2019 and closed in the first quarter of this year. The first was WPX that acquired Felix for stock and cash. The second was Parsley who purchased Jagged Peak stock. Now both of these deals were considered accretive by the market because Felix and Jagged Peak were considered good operators, and they were in the core parts of the Permian play in the Delaware Basin. The bullet points on this slide in the first 2 there give you the basic deal parameters. Now in both cases, the purchasers provided production details on a subset of new wells that they selected that demonstrated the asset quality and the underlying economics. For Felix, there were 21; and for Jagged Peak, there were 35. And the buyers provided 12-month cumulative oil production volumes. Now we're looking to understand how productive the rock is. So if we average the net production for those wells on a per foot basis, Felix came out at 17.6 barrels per foot and Jagged Peak at 16.8. If we did the same work for the TMS wells in 2014 that make our type curve up, it comes out at 16.9. In other words, when we compare 2014 productivity in the TMS to 2018 productivity from the best operators in the best part of the Permian, they're basically the same. Now of course, this is just part of the story. What about costs? In 2018, Jagged Peak advised that their well costs were running at $1,500 per horizontal foot. By comparison, Stewart was $1,500 and -- $1,519 and Taylor was a little bit higher at $1,632 per horizontal foot. It's worth pointing out that there were hundreds of rigs running at this point in time in the Delaware Basin. These were the first 4 wells that Australis had drilled in the play. And again, they get better as we get more practice and more wells are put in the ground. Now Delaware Basin actually produced a lot of water as well. Only Parsley provided the details on that, but their numbers came out at 61.6 barrels per foot in that same 12-month period. Compare that back to our type curve, 10.5 barrels per foot, i.e., 6x as much water comes out. That water needs to be produced, processed and disposed of, which is a significant cost and an operational challenge, and it's not one that the TMS faces. What about pricing differentials? The last data we had for Jagged Peak prior to the acquisition was Q3 2019, $53.55 a barrel; same period, Australis, $59.60, 11% higher. So we've got the same productivity, same cost, higher achieved price and 1/6 of the water volumes. Just out of interest, if I take those deal metrics and apply it to our production and our acreage, we come out with a valuation north of USD 1 billion. Look, I've spent some time talking about Australis. I've talked about our strategy, the asset and the recent results. But I think before we close the loop house, I just need to talk a little bit about how the industry is performing in general as well. There is no doubt U.S. unconventional oil production has been a game changer, as Jon referred to. The U.S. has added 7 million or 8 million barrels a day to world markets and has moved that country close to self-sufficiency. Analyst projections have remained robust, talking about annual increases of 1 million barrels a year for the next -- 1 million barrels a day each year for the next few years. And that's all been readily accepted by the market, to be fair, often driven by statements by the companies themselves on well performance, single well of returns, depth of inventory, et cetera. But it has always been difficult for Australis to marry this with the more technical discussions in which take place. They center on things like decreasing well performance, infrastructure limitations, diminishing Tier 1 inventory, wells being crowded too close together and interfering. Plus, of course, there's the well-documented shareholder pressure for these companies to avoid growth for growth's sake and start to deliver on real returns. We actually believe that the reality was starting to appear in the data even before the recent dramatic changes. The slide you're looking at is actually from the 3 largest oil shale plays in the U.S. They account for 85% of the production. The chart actually show monthly changes in production volumes: 20 months below the line indicate contraction; and any lines -- any points above the 0 there, yes, obviously, there is additional production within the play. To start on the top left, the Eagle Ford actually shows declining production through to early 2017, and that was following the 2014 price drop. Between 2017 and '19, there are occasional periods of growth, but largely, the production remained static. During Q4 of '19 and Q1 of '20, before the dramatic drop, you can clearly see the downward trend was developing. And actual fact, volumes out of the Eagle Ford were decreasing. The Bakken on the top right follows a similar trend, although there were a few more net gains during that period of '17 to '19. And of course, the main contributor to U.S. growth was the Permian in the bottom left. During 2018, that play was increasing by 100,000 barrels a day every month, but there was a step-down in 2019. And if you look at the monthly figures, you can actually see that they were trending down in the same way as the others during the last 6 months. In fact, if you look at the top -- at the bottom right-hand side, which is U.S. production growth as a whole, U.S. production had actually practically stalled to 0 during the Q1 of 2020. So why has this occurred? What are the headwinds that the industry's faced that were perhaps coming to bear? Well, look, we've been saying this for some time, but high-quality Tier 1 oil inventory is finite. In the Eagle Ford and the Bakken, that was largely consumed during that period of 2013 through to 2017. That first to play was delineated. And then during the low oil price, companies had to drill their best acreage simply to survive. A quick fact. There were 12,000 wells drilled in the Eagle Ford in the first 5 years, and that grew production to 2.5 million BOEs a day. In the next 5 years, another 10,000 wells were drilled, but production actually reduced by 20%; basically, all the good stuff had already being drilled. Another key point and that's become clear over time that the industry has overestimated the density with which wells can be fitted into a given area. The impact of cramming wells too close together is a reduction in production performance that's become known as the parent-child relationship. So this means that future development needs need to be planned on wider spacing, and the existing booked infill locations that had been considered Tier 1 now need to be reevaluated, further reducing the inventory available for operators in a given area. Another point to understand is that a lot of these oil shales actually produce a lot of gas. The Permian, for instance, is only around about 60% oil. The gas is less valuable. It has to be processed and it has to be dealt with. To make matters worse, as the wells start to decline and pressures drop downhole, the gas typically moves more easily through the reservoir and is preferentially produced. This reduces the oil ratio even further. So as wells get older, this can have a material impact on economics. As I've already alluded to, a lot of these plays also have a high water cut. We talked about the Delaware where it certainly is an issue. That water needs to be produced, separated, disposed of or treated for recycling. Today, the Permian produces nearly 12 million barrels of water a day. That's 550 Olympic swimming pools every day. Most of that's presently reinjected. That has a cost. It also has operational issues as well. A study released by the University of Texas in November 2019 concluded that between 2009 and 2017, the number of low-level earthquakes in the Delaware Basin increased from 19 to 1,600 a year. And of course, even once this oil and gas has got to surface, you get the other price differentiators that affect economics. It's influenced by geographic location, infrastructure for oil, water and gas and of course, the speed of growth of the play. It's fair to say that the drive by shareholders for companies to deliver on their promised returns has highlighted a lot of these secondary issues, which are real and they affect field and company economics. So my last couple of slides before I close the loop here is -- and discuss this in the context of the TMS is a quick word about the overall impact of the last few months on production. The top chart actually shows you the often quoted rig count and oil price. You can clearly see the rig count was dropping steadily for some of the reasons I outlined previously, but then it took a steep drop in April, and I can tell you that as of last week, there were only 284 horizontal rigs running in the U.S. We believe actually that the frac fleet utilization figures is a much better lead indicator for production, as shown on the bottom right-hand side. Again, you can see this was on a steep downward trajectory, but it accelerated in the last quarter. Recent estimates indicate there are only 50 active fleets in the U.S. If I compare that number back to the beginning of the year, and you recall that's when production had effectively -- production growth had effectively stalled, there were 230 fleets running at that time. The EIA estimates that the depletion rate of the existing inventory of wells is about 600,000 barrels a day every month. So the frac fleet is running at 20% of what's needed to maintain production levels, then the underlying decline is starting to come to bear. And then, of course, there was the temporary shut-in that occurred. Estimates from the EIA range between 1.5 million and 2.5 million barrels a day. A lot of this volume can obviously be switched back on, but the older wells with limited pressure or high water cuts may struggle. The combination of steep decline curves, limited Tier 1 inventory and temporary shut-in means there's probably going to be quite some time before shale declines stabilize and certainly before any growth going forward may ultimately be limited. So I promised in the first slide that I'll bring us back to the TMS, to our company and our strategy. There are a number of macro issues that we think are already driving a transformation in terms of the U.S. industry. We've got that diminishing Tier 1 inventory that I talked to, and we've got these multiple secondary, but relevant headwinds that are limiting performance and returns, honestly, further exacerbating shareholder frustration. The U.S. shale oil production was already slowing but has dropped dramatically in the last quarter, and it will be difficult for it to recover to a point of maintaining levels, let alone seeing future growth. There's no better spotlight on some of these issues I've discussed than a low oil price. We feel that will help accelerate the delineation of the remaining large play, the Permian. The TMS Core is one of the very few Tier 1 oil plays that's been delineated, appraised, but not yet developed. We've clearly shown its productivity. We hold a large contiguous acreage position as development ready. Limited drilling thus far has demonstrated the value, but the low well numbers mean we avoid those parent-child issues that have played up the plays. The slow development of the TMS means we understand the correct spacing now, and we can develop it with confidence. That's not something you normally find out until after the play's been developed. The relatively low water cut we have, the high oil content at 95% and the steady gas cut means that we avoid some of those other issues I was referring to earlier. And our proximity to markets and infrastructure prevents local discounting, and our high-quality light sweet crude ensures a premium to market. So what does all this mean? Please don't get me wrong. Even with all these challenges, the U.S. unconventional industry will produce vast amounts of oil for many years to come. However, as the general environment improves, the options for new Tier 1 oil development in the U.S. will be limited. What is available in existing plays will be tightly held and other emerging plays have largely fallen short of expectation. So with the unique characteristics and status of the TMS and as the only drill-ready undeveloped Tier 1 oil play in the U.S., the TMS will have its day in the sun. And our job is to ensure we're here to realize value for shareholders as those events unfold. So in summary, as a team, we've done this before. There were some dark days in the Aurora story in the depths of the GFC, but we saw them through as we will now for Australis. We are very much aligned with our shareholders. All of the Board and the executive have invested considerable sums of money at much higher prices, and we're all aligned in terms of achieving our common outcome. We firmly believe we've got an exciting and valuable asset that has a number of strategic advantages, and we believe that the market is moving to a space where that value will be recognized. And finally, we've taken all possible steps to safeguard the asset in these difficult times and ensure it's preserved for when the market is ready. So that concludes the presentation. I'd now like to open the meeting up for questions.