Valeura Energy Inc. (VLE) Earnings Call Transcript & Summary

Ladies and gentlemen, thanks for joining us for the Valeura Energy webcast, where we'll provide a little more color on the acquisition we announced earlier today. I'm Robin Martin, Investor Relations Manager. And here with me at the Calgary office is Sean Guest, President and CEO; Heather Campbell, our CFO; and also joining the call from his home office is Gor Begg, our VP, Commercial. This event is being streamed live and is being recorded today, April 28, 2022. We'll make a replay available through our website later today. [Operator Instructions] So we'll provide some prepared remarks on the deal, and we'll reference some slides that we'll be showing on screen in just a moment, if you're joining through the MS Teams call, or they are available on the website if you're joining by dial-in. After that, we'll take any questions you might have. Questions will be submitted through the Teams app that can be done at any time by clicking on the Q&A button or you can e-mail them to us using [email protected]. So I'll start us off by just drawing your attention to the advisories, which is on Slide 2 of our presentation. I'll suggest that you review this at your convenience, noting in particular the cautionary language around forward-looking information that we might use in this call. And with that, I'll hand off to Sean and Heather to walk us through the deal. Sean?

Thanks, Robin. Today, we've announced a major step forward in our M&A strategy by way of a Gulf of Thailand acquisition. Specifically, we are acquiring some of the assets of KrisEnergy out of receivership for an initial price of $3.1 million, plus contingent payments of $7 million. We're also acquiring a key production facility, a mobile offshore production unit, or MOPU, through a separate receivership for $9.2 million. This is an exciting development for us and gives us a new presence in a region which is very familiar to most of our executive team. In addition, I'd note that the structure of the acquisition also provides us with an on-the-ground operating company in Thailand on day 1, as well as a very experienced regional management team. We set out to use M&A as a tool to round out Valeura's portfolio with the objective of adding near-term production and cash flow, but also importantly, medium-term upside opportunities for growth. This acquisition does just that, and it does it at strong deal metrics. We estimate the Wassana oilfield in the G10 block has 4 million barrels of 2P oil reserves which will add near-term oil production of 3,000 barrels a day simply by restarting the suspended field. This is expected to generate cash flow in the order of $9 million per quarter and can pay for the deal in just 6 months of production. At the outset, this means we're paying just over 6,000 per flowing barrel. In addition, we also estimate 13.3 million barrels of oil equivalent of contingent resource, which includes the fully appraised but not yet developed oil field in [indiscernible] Block 6, Rossukon. So including the reserves from the Wassana oilfield plus a resource from Rossukon, the price per recoverable barrel is just over $2. Since this transaction is structured at the corporate level, we also realized the existing tax losses of the seller, which will improve the economics of these projects and potentially give us a leg up on further acquisitions in the country. Given the modest cost, we can fund the acquisition and the restart of production at Wassana through our cash on hand and do not require any equity raise. So importantly, for our shareholders, there is no dilution and we are setting ourselves up with a new platform and team that we can use to grow further. While commodity prices are very high, we still see additional opportunities for M&A at good deal metrics and maintain that this is deal one, further growth can be achieved. Now before I leave this slide, I will comment that all of the reserves and contingent resource numbers quoted in our press release today and in this presentation are management internal estimates as of December 31, 2001. However, please recognize that we have been able to review the existing reserve reports from previous years that have been released publicly by the seller. In addition, we've already commenced an evaluation by an external reserves auditor and expect to release these results around the time that we close the deal. So moving on to the next slide, why we like Thailand. I'll start by saying that this is a very familiar environment for our team. So while Southeast Asia is a new jurisdiction for Valeura, it is where several of the Valeura executives have lived and worked for much of our careers. So in particular, the fact that it's oil production, that it's offshore but in a relatively benign shallow water condition, and has all of the subsea characteristics are similar to basins in the region, this makes it feel very much like at home for us. Looking at Thailand's upstream industry, it is very mature with an established production base of more than 700,000 BOEs per day equivalent. That's good news for us, it means that there's a market for E&P assets coming to the M&A table. We also know that Thailand provides a strong competent workforce and a mature service industry with decades of experience in oil and gas. In fact, given the relatively consistent geology and the marine conditions in the Gulf of Thailand, Thailand has been a global leader in low-cost drilling and field developments. This is very important to us as a small company. The most important consideration is that given all the factors we've noted here, Thailand has historically proven successful for many small and mid-cap companies with successes such as Pearl Energy, Coastal and Salamander, all of which we're able to grow quickly and provide significant wins for their shareholders. Next slide. Looking in a little more detail why this area works for small companies from a subsurface perspective. So first, the Gulf of Thailand is on trend with the Malay Basin, and both are very prolific and have produced 10 billion barrels equivalent to date. The basin is characterized by Miocene fluvial reservoirs. And what that means for non-geoscience folk is that the reservoirs were created by sediments deposited n meandering river channels. On 3D seismic, they kind of look like aerial photos of rivers. And importantly, there are lots of them laterally and they're stacked vertically on top of one another. This creates the situation in the -- with Gulf of Thailand assets. In many cases, they're characterized by small initial field developments that is then followed every year by reserve replacements and growth, as different reservoir levels are added and new near-field structures are drilled. The result is that the original reserve estimates for field in the basin are almost always exceeded over time, and there are numerous examples of fields that are still producing today and have produced more than 10x their initial development plan. This allows small companies to develop the field of modest cost and then continually add reserves and production each year, underpinned by that production-based cash flow. So with that, I'll leave the rocks, and Heather is going to talk us through a little more detail on the fiscal terms. Heather?

Thanks, Sean. So just a little deeper into the fiscal system, the licenses we are acquiring fall into the Thailand III regime, and this regime defines a sliding scale royalty between 5% and 15% tied to production rates. For the Wassana field, we'll be at the lower end of that range and royalties are deductible against petroleum income tax. There's also a special remuneration benefit, or SRB, which applies to windfall profits. The rate is tied to various factors, including drilling activity and complexity, among others, and the regime allows capital expenditure as a deduction in the years spent as well as loss carryforwards. Currently, SRB is not expected to be a material factor for either of these licenses. Petroleum income taxes are 50% on net profits, with expected deductions such as royalties and OpEx and depreciation of assets. Tax losses can be carried forward for up to 10 years. And as Sean said, since we're doing this acquisition as a corporate transaction, the tax loss carryforward position of the company remains in place and will continue to apply to future taxable income. So while the illustration on the graph here, shows taxes at 50% of net profit, in actual fact, for Wassana, we expect this to be nil, and potentially even 0 for the first few years of Rossukon production. Decommissioning requirements are a part of the fiscal regime, and we include these costs in our project economics, of course. Operators are required to have a decommissioning plan in place once fields start nearing the end of their life or when there's 5 years remaining on the lease. As part of that plan, there needs to be a financial guarantee agreed with the regulator to provide for planned decommissioning costs. Also in decommissioning, we feel our cost estimates are currently conservative and we see potential for cost reductions in this area in the near future. Development in the Gulf of Thailand has generally used a standard approach for each field, where platforms are designed for the same operating conditions and with a very similar design even between different operators. What that means is that we expect to see efficiencies with how similar wells and facilities are decommissioned, and it stands to reason that there could be increasing economies of scale developed by the local industry. Back to you, Sean.

Thanks, Heather. The next slide provides more details on G10 and the Wassana oilfield. We're acquiring and operated 89% working interest in the license, and anticipate we will be able to bring the field back on production in Q4 this year. The rig we're anticipating is 3,000 barrels a day net to us, which is consistent with what the field was producing in early 2020 when it was shut in. The field was developed by a way of 16 wells that have been drilled from the MOPU. We estimate that the field has remaining 2P reserves of 4 million barrels of oil, plus 2C contingent resource of an additional 7.4 million barrels of oil, all of that net to the working interest we are acquiring. The fact that the Wassana field was shut in is not related to reservoir or facility performance, it was an economic decision by the seller as a result of very high lease rates on the MOPU and their offloading vessel, compounded by a period of low oil prices seen at the start of COVID. The restart of production is seen as very low risk, with the key components being, first, the readiness of the MOPU; and second, getting a lease for a new floating storage and offloading vessel, which holds the produced oil prior to exporting it for sales. We have now acquired the MOPU and -- which will reduce our OpEx and make a more cost-efficient operation. This summer, we will go through a standard recertification process. It's important to emphasize that since the field was shut in, the MOPU has been continually manned, and the MOPU, the production facilities and the wells have all been maintained. On the FSO, the tendering has been completed and finalizing commercial agreements will be our first order of business. So the production restart plan has been fully developed and progressed by the local team in Bangkok, and we are confident that we can see production in Q4 2022. So going to the next slide. This provides a little more color on the upside potential in the G10 block. Our 2P profile for Wassana field includes a plan to drill 5 infill wells, and this is currently planned for the first half of 2023 and is expected to increase production to a peak of around 5,000 barrels a day. The contingent resources for G10 are roughly split between additional development of the Wassana field and existing nearby discoveries. For the infills, we see potentially as many as 10 more wells and this is relying on longer-reach horizontals predominantly targeting the newly identified reservoir shown in the slide and called the 2.0 Sands down near the bottom. This is a clear example of adding reserves that we discussed earlier. These deeper 2.0 and 2.1 Sands shown on the slide we're not in the original development plan, but have now yielded significant additional production and further growth potential. We believe there can be further upside in near-field exploration, but this will not be our focus given the existing proven oil in place. On the next slide, we get into a little more detail on G6, the other license we are acquiring, which contains the Rossukon oilfield. This is one of the last known but undeveloped oil fields in the Gulf of Thailand, and an opportunity that we see to progress a stalled development project. We're acquiring a 43% operated interest in Rossukon, which has an estimated 6 million barrels of oil equivalent 2C resource. The field has been fully appraised by 6 wells. And while the development plan has been approved by the regulator, the final investment decision has been continually delayed due to the financial challenges of KrisEnergy. So the approved development plan entails a fixed wellhead and production platform plus an FSO for holding the oil, and is estimated to yield a peak production of approximately 12,000 barrels a day gross. As there is a requirement from the regulator for first oil in November 2023, our priority on taking operatorship will be to work with the partners and the regulator to assure the agreed development plan meets these timing needs, while at the same time delivering the best economic results to ourselves and to the government. As such, there are plans for a smaller initial development that could deliver production late next year at a lower CapEx in 2023, but which would yield a lower initial rate that could then be increased to the planned peak production over time. So we'll yield more on this -- we'll give more information on this once we're actually operating the asset. So Slide 10, the next one covers 2 important but related matters. One is our sustainability priorities and how these play into this transaction; and two, is the structure of the deal with regard to the company we've created to make it happen. World-class governance and leadership have always been important across our industry. And to us, this has always meant having an experienced and specialized leadership in place at the country and the executive level. This sets the tone to ensure that we maintain the highest standards of business ethics and continually look for ways to enhance transparency. The diagram on the right explains the corporate structure of how we're doing this transaction. Essentially, we've created and funded a Valeura subsidiary called Panthera Resources, which will do the acquisition itself. Valeura will initially own 85% and the other participants in Panthera, who will show up as a minority interest in the Thailand business, are comprised of 4 key individuals who have multiple decades of experience in the Southeast Asia region and a direct history with the assets being acquired. These individuals become a key component of Valeura's regional management team. Valeura's sustainability priorities have not changed, and the same things that we feel are critical to the success of our operations in Turkey are also critical in Thailand. With regard to the environment, that means minimal flaring and managing produced water to high international standards. For the Wassana field, all produced water is reinjected not to start overboard, and there is virtually no flaring due to the very low gas oil ratio of the production stream. On the social side, people are our priority. This has always been the case and we've always utilized a local workforce relying on knowledge transfer, exposure to international standards and training to ensure the team has the critical skills they need. This is easy in Thailand, given the educated and very experienced workforce. We are acquiring a team of approximately 30 full-time experienced staff in Thailand. And additionally, we have the long-term relationships that come with the Panthera team. We will have a specialized and capable operating company ready to go immediately. So looking at Valeura and the corporate portfolio. Last year, when we sold our gas producing business in Turkey, we acknowledged that we were left with a portfolio that included a potentially very significant blue-sky asset in our deep tight gas play in Turkey. What we were missing was near-term cash flow and the opportunity to reinvest for growth in the medium term. From our 10-year history of operations with our Thrace Basin conventional gas production in Turkey, we did not see that this -- we had the ability to grow production in this asset. With this acquisition, we have built a much more balanced portfolio, with production and cash flow and growth potential. We have essentially taken the cash we received from our 600 barrels a day equivalent of gas production in 2021, and we will use this to acquire and refund the restart of 3,000 barrels a day of production from Wassana, with still significant growth potential from both Wassana and Rossukon commencing in 2023. In the longer term, we maintain that our large tight gas play that's onshore and easily connected to Turkish and international markets. So just to reemphasize the point, our tight gas play in Turkey remains a part of our portfolio, and we have recently seen renewed interest in evaluating this play, given the issues around gas supply security and historically very high prices in Europe. So just summarizing the activity time line going forward. First priority is to close the deal. The conditions are pretty light in this instance. We really just need to have the receiver completed reorganization of the corporate entity we are buying, and we're required to launch a Valeura parent company guarantee with the regulator in Thailand. We expect these to occur this quarter. Obviously, right off the bat, we were focused -- we will focus on everything that needs to restart the production of Wassana and get that cash flow. So as I noted previously, and you can see on here the MOPU recertification and the replacement FSO. We are also eager to get work on planning the development for Rossukon field. That process will start right away with discussions involving partners and the regulators to try and land on the development scenario that meets everyone needs with regard to timing and economics. And on the bottom, as I mentioned, we are continuing to work towards farming down our interest in the tight gas play in Turkey. So just summarizing that. We're adding high-value oil production and cash flow in the near term, and we're doing so at very favorable metrics. We're also including medium-term growth that could more than double the business that we're acquiring thereafter. We're carving out a presence in a new jurisdiction that's proven successful for small-cap companies given the history of its continual reserves and production growth. And at the same time, we continue to pursue the next steps of the appraisal of our larger -- our longer-term value proposition in the tight gas play in Turkey. So thank you very much. And this -- with that, we'll move on to the Q&A session. Robin?

Thanks, Sean. Bear with me for a second here. [Operator Instructions] So just bear with us a moment. So first question that we've got, Sean and Heather is -- on the Rossukon field, how much will it cost to develop the Rossukon field under the existing development plan? And how would you finance it?

Thanks, Robin. So the estimated cost in the -- the large plan that exists now for the 12,000 barrels a day of production is on the order of $180 million gross. So net to us, about $75 million to $80 million, that type of end. Obviously, the cash flows that we see coming in from just Wassana are totally not sufficient from that, but really, the first port of call for us would be more on the debt markets on that and try and look for debt on that. And we -- there have been discussions already starting with debt providers looking at these assets. And while it's not required immediately, that's something that we'll be progressing over the next number of months as we decide, first, which is the development plan we'll go with, the immediate large plan or whether we'll do more of a phased start-up with an early production facility, which is at a much lower cost.

Okay. And you beat me to it. There was another question. If you do an early development plan on Rossukon, what would the CapEx look like for that?

Well, it's going to be much lower now. We don't have the exact numbers on that. The main cost you're going to have on that is really for drilling costs. And that initial just wellhead platform. But you'd be using early production facilities there, which would be leased in the interim period, while you then complete the construction of a wellhead platform. So we expect it to be much lower, but final numbers on that we're not there yet.

Okay. We've got a couple of questions on partners as well. One that asks, for Block G6/48, who are your partners? Previously, this was publicly showing us move Mubadala 40% and Northern Gulf Petroleum 30%, which would leave 30% for you to acquire, but it looks like you're acquiring 43%. Can you explain that?

Yes, it's a good point. So in the block that has existed there historically, those were the partnerships with the split of KrisEnergy as the operator and then Northern Gulf Petroleum and Mubadala is partners. Now Mubadala has not contributed towards the development plan. And as such, their working interest in the Rossukon field has been reduced. They've lost that interest, which has been split between the other partners. So right now, the development plan for Rossukon is between KrisEnergy at 43% and Northern Gulf Petroleum at 57%.

Okay. And a follow-up question on that as well. Is there any opportunity to acquire more of a working interest in either of the blocks from the existing partners?

Quite possibly. You can see there's one other partner referred to as PSL in the G10 block. That's a company that's had a long-term relationship with the Panthera team that we're working with. So we're well known to the team with very good relationships. Obviously, we have discussions on them with the plans for restarting the field there. So they're very enthusiastic about that. And then on G6, we'll just kind of -- we need to first get the development plan sorted a full understanding of the economics before we make any moves related to working interest in that block.

Okay. We've got a couple of questions on the restart of Wassana as well. First off, how complicated will it be to recertify the MOPU that you need for Wassana? Is this a straightforward exercise?

Yes, that's a good question. Because sitting at the outside for people, they may not understand fully whether this is an easy process or there is a lot of complications and risks in this. We see it as quite easy. And that step on the recertification, that's nothing that's required because the field has been suspended or the facility has not been used, it's strictly a time-related matter that this was required at this time. So what we're doing is we'll send divers out there who do an inspection. And because this is still a fairly new facility, we don't expect any issues to come out of that complete review and certification. So it's really more of a review and documenting all of the survey of the vessel.

Okay. Also a question on the wells at Wassana. Since they've been offline for 2 years, is there any risk to starting them up?

Yes. There is always some risk when you're restarting the wells. But what we do like is because the facility has been manned and maintained during this period, they have even gone out to the wells and they've got pumps in those wells, and they actually cycle the pumps and still ensure that they're all working correctly and generating the flow. So we do expect that once we get the floating storage vessel there for the oil that we could start production quite easily. But you could get some small hiccups, but there's no significant work required here. We're not bringing a rig on site. This is really just turning the wells back on.

There's a part B to this question as well, which is, is there any opportunity for above-normal production or flush production when you bring this field back on?

Yes. Reservoir engineers will tell you, you can expect that when you actually do bring a field back on just because it's -- you get this flush production that can be quite a bit higher than was there when you shut in. We really don't like to refer to that because it looks very exciting on day 1, but it does tend to fall off very quickly. So we're quite cautious to try to point to numbers like that.

Okay. And I think just 1 more question, which is you described this as the first deal that you're doing. So if you're looking at further acquisitions, are you looking at other assets in Thailand? Or are there other target countries that you have in mind?

The answer is yes. We are looking at other deals within Thailand at this time, which are quite progressed on some. As we noted, we still see that the environment is right. And while commodity prices are very high, there is still a shift going on in our industry. And this is opening up opportunities to not just acquire small assets, but also assets with like quite significant production and cash flow. So yes, we're very much focused on the next deal as well, Thailand being a country of interest. But we also, given our experience within the region are looking at other countries as well.

Okay. Great. That's all the questions that we've had come in online. Just a reminder to the audience that if you do have any follow-up questions for us, you can reach out to us directly contact directly or in our press release and on our website. And the easiest way to reach us is by e-mail using [email protected].

Thank you very much.

Thank you.