Good afternoon, and welcome to BHP's 2019 Petroleum Investor Briefing. For those of you that I have not met, I'm Geraldine Slattery, and I'm the President, Operations Petroleum, and a member of BHP's executive leadership team. I've been with BHP for over 25 years in our petroleum assets here in Australia, in the U.K., and in the U.S., and most recently, I was the asset president for our conventional production operations globally. It's a pleasure to be here with you in Sydney, and indeed, with those of you who are dialing in by webcast and by teleconference. You will hear from three presenters today, myself, Michiel Hovers, our Group Sales and Marketing Officer, and Sonia Scarselli, our Vice President, Exploration and Appraisal.
Before I get started, I do want to point you to our disclaimer and to our statement of petroleum resources, and note their importance to this presentation. Today, we're here to talk. Today, we're here to talk about our petroleum business and its place in BHP's portfolio, and to address the questions that are on your mind. I recognize that you have interest in understanding our market outlook and our plans to grow value and to grow returns. We will cover all of this today. There are a few things that I would like you to take away at the end of today's conversation. Firstly, we believe oil and advantage gas are commodities that have the potential to generate strong returns over the long term.
We have the assets and the gross projects to replace and indeed build on the resilient returns we have enjoyed from the petroleum business through the next decade. Our performance track record in exploration through to production gives us confidence in our ability to deliver on these plans. Finally, working in both a sustainable and a capitally disciplined way underpins everything that we do. This is key to our long-term success. Let's begin, and with our purpose, to bring people and resources together to build a better world. As Andrew Mackenzie and Geoff Healy have shared in recent months, we believe that creating social value is an integral part of creating shareholder value. I know that building trust comes from doing the right thing by people and by the environment in how we run the business.
It comes from providing access to employment, to opportunity for local service providers, and having the highest standard of care for our surrounding communities. Without this trust, we cannot hope to access the talent, the most valuable acreage, the service providers, or the approvals that we need to competitively deliver on our plans. Let's now turn to the specifics of the business. Petroleum has delivered strong returns and has an attractive outlook. Our strategy, our BHP strategy, of being the best commodities with the best assets enabled by the best capabilities, has delivered strong financial returns over many years. This strategy is what sets us up to continue such performance. Our commodity analysis tests against a range of potential scenarios, recognizing the inherent uncertainty as we look out several decades. In any plausible future scenario, we believe that oil and advantaged gas will be attractive for decades to come.
We have a pipeline of competitive growth opportunities with average rates of return of around 25%. With our existing assets, these position us to deliver an average return on capital employed of greater than 15% through the next decade. We also have the talent and the track record in safety, in exploration, and in deep water operations that gives confidence in our ability to deliver on our plans. Of course, we will always put the safety of our people and the sustainability of the environment first, and we will be disciplined in our use of BHP's capital under the capital allocation framework. Let's now turn to our assets. Over the past five years, petroleum has had the highest margins in the group at over 65%, and an average return on capital employed of approximately 15%. We take great pride in this performance.
Yet we also recognize the need to focus on the longer term as production from our legacy assets declines over the coming decade. Maintaining our performance relies on us delivering on our growth projects, and in advancing further growth opportunities from recent exploration success. The outlook we share today has the potential to deliver robust EBITDA margins of more than 60%, inclusive of our continued exploration investment, generate average returns of 12% through the mid-2020s, rising to 20% in the latter half of the decade, and increase the base value of the petroleum business by 80%. This outlook is based on the following assumptions. It's an unconstrained case, which assumes execution of all of our unsanctioned projects at current equity and earliest schedule. We've used Wood Mackenzie long-term price forecasts, and we've also indicated the sensitivity of financial metrics to $60 and $80 Brent oil and $6 and $8 LNG.
As you can see, the returns remain resilient across this price range. Many of you may recall, back in October 2016, we presented a plan for the conventional petroleum business across three core areas at the time. Firstly, getting the most from our producing asset base through high availability and low operating costs. Secondly, from delivering and generating high returns from our pipeline of brownfields and greenfield projects. Thirdly, extending our growth options through exploration and early lifecycle assets. I'm pleased to say we have more than delivered on these commitments. To call out just a couple of highlights, we've completed two major projects and have more than $3 billion worth of additional investment in major projects underway. These, having an average rate of return in excess of 20%. Two of these, Atlantis Phase 3 and Project Ruby, were not in the firm plan back in 2016.
We had identified them as potential upside cases to be further de-risked through seismic imaging. In 2016, we successfully acquired the Trion asset in Mexico's first ever deep water bid round, thus demonstrating the value of investing countercyclically. In Trinidad and Tobago, our exploration program has discovered a material gas resource in the northern licenses. You may remember this was a frontier basin with the nearest well tests some 200 km away. Finally, we've extended our option set with potential Tier 1 positions in eastern Canada and in Western GOM. Collectively, our portfolio now has the potential to deliver average annual production growth of 3% over the next decade. We do this while maintaining a competitive return on capital employed and EBITDA margins.
This includes the decline in production from our legacy assets in Australia, which we'll more than replace with high margin bbl from our oil-dominated growth projects in the Gulf of Mexico in the near term. Beyond our current suite of options, we will also continue to increase our pipeline of future growth opportunities through exploration and the acquisition of early-stage discovered resource. This builds on our exploration success over the past three years in adding new resource and providing low-cost options to grow the value of the portfolio. With that, let's turn to CapEx. As you will see, we have many attractive and high-returning projects and opportunities in various stages of development and maturity within the portfolio. As the chart on the right shows, this portfolio would require an average annual CapEx from 2023 to 2025, inclusive of exploration expenditure, of about $4 billion per annum.
This reduces as the major projects are past their peak investment period. As I mentioned at the outset, this is an unconstrained view. All opportunities will compete for capital under the capital allocation framework. This prioritizes maintenance capital, balance sheet strength, and payment of a dividend to shareholder under the payout ratio policy. Excess cash is allocated to maximize value and returns with a rigorous comparison with cash returns to shareholders. There's always fierce competition across the group for capital through the annual prioritization process. Our growth opportunities give us the flexibility to manage that capital in a value-optimized way. Across the group, including the opportunities we'll talk about today, include flexibility to first improve our project economics and capital efficiencies, potentially sell down in our high equity positions to reduce capital and monetize value improvements. Finally, optimizing the phasing of the project execution.
Now let me briefly touch on how petroleum fits in the broader BHP portfolio. As I mentioned earlier, petroleum has been a significant contributor to the group over many years, with strong cash and EBITDA generation. As you'll shortly hear from Michiel, our analysis gives us confidence in the future demand and the ability to generate returns from oil. Our contribution goes well beyond commodity attractiveness and returns. Our group performance demonstrates that a portfolio of diversified commodity exposures reduces the impact on volatility, as you can see from the chart on the slide. We also believe that diversified portfolios enable more rigorous capital allocation, with only the most compelling projects being funded. Having a strong balance sheet allows counter-cyclical investment and in the right project. As our CFO, Peter Beaven, describes it, the holy grail of value creation in our industry.
Finally, petroleum both enhances and benefits from being part of the broader portfolio. We benefit from BHP's strong balance sheet, a prerequisite for deep water operations. We can invest counter-cyclically, which is particularly important in exploration and has underpinned our success in recent years as we maintained our exploration program in Trinidad and Tobago, and in acquiring the Trion resource. We can focus on value over reserve replacement and be patient for the highest returning opportunities. Finally, we benefit from BHP's integrated geoscience and project expertise. With that introductory summary, and consistent with our strategic framework of being in the best commodities, the best assets, with the best capabilities, the agenda for today's briefing will be Michiel will shortly provide detail on the outlook for our commodities. I will then return to describe our suite of assets and opportunities.
We'll then take some time for your questions, and a break, in fact. Following the break, Sonia will come back to take you through the exploration strategy. I will conclude with a summary of our capabilities and the value and the returns that you can expect. There will then be another chance for questions. With that, let me hand you over to Michiel.
Thank you. Good afternoon, ladies and gentlemen, and thank you, Geraldine. My name is Michiel Hovers, and I'm the Group Sales and Marketing Officer. I've been with the company for 16 years in various roles, always in the marketing organization. I started off selling energy coal, followed by uranium. I moved to Singapore to market nickel, followed by about five years of looking after the iron ore marketing. Most recently, before my current role, I was the VP Supply and Marketing based in Houston, looking after petroleum marketing. Worked very closely with Geraldine and the team. I'm now back in Singapore and responsible for the marketing organization of the entire group. It is my great pleasure to share with you today our long-term outlook for oil and gas. Before I do that, I would like to touch on BHP's strategy around commodity attractiveness.
As we shared with you in our strategy briefing earlier this year, we are very deliberate about the commodities we choose and assess them against a strict set of criteria. What are these criteria? Firstly, the current and potential size of the market should be large. We are a large company. This also lessens the potential for single event disruptions that can create significant volatility. Secondly, we look for favorable demand and supply fundamentals over the long term. We can only grow shareholder value for project options if the market actually demands this. We like commodities where the economic rent accrues upstream, near the resource, matching our operational capabilities, and simultaneously creating long-term competitive advantage that cannot be competed away. Fourthly, we like steep cost curves. They offer strong margins for low-cost assets.
Lastly, as Geraldine outlined, we believe that a diversified portfolio enables better capital allocation. I think that clearly lays out kind of what we're looking for. Next step is to do scenario analysis to adjust future uncertainty. Using a set of divergent but plausible scenarios, we create buckets to better understand what the future might bring. We do this for each commodity, also test against a range of strategic themes, we'll touch on some of these later. Now, how does oil and gas fit into this context? Our outlook for oil is attractive. Oil demand will continue to grow, albeit at an increasingly slower pace, until an eventual peak. Perpetual natural field decline creates a structural supply-demand gap, even in our low demand case, which creates a need for inducement economics.
The low-cost supply sources of today, such as core shale, are not large enough to fill this gap. New higher cost supply will be needed to be induced. This creates a reasonable steep cost curve beyond the mid-run. The case for natural gas is somewhat more nuanced. The demand profile for natural gas is actually very healthy. It's diversified and we see consistent growth. The growth in the LNG segment is even better. Supply of gas, however, is more abundant. Asset choice becomes critical. We like gas assets when they're advantaged on the cost curve, either due to proximity to existing infrastructure or access to premium markets. Okay. With that intro, let me now move into our outlook for oil, and I'll start with the demand side. Sorry. Over the last four decades, with the exception of the global financial crisis, oil demand has increased every single year. Sorry.
Population growth, urbanization, and industrialization are the main drivers for this trend. Global growth is therefore not equally distributed across the regions. OECD demand has already peaked and will continue to decline. We see non-OECD demand rise from over 50% today to nearly 70% of total demand by 2050, driven primarily by China and India and other emerging Asian countries. As I mentioned, we tend to think through the future in ranges. In our plausible low demand case, we see demand peaking in the mid-2020s, and in our central case, 10 years later, in the mid-2030s. As the graph on the right illustrates, the sharp decline in light-duty vehicle demands is the main catalyst for this peak. Light-duty vehicles currently account for nearly 30% of total oil demands, falling to 10%-20% by 2050.
In contrast, demand growth comes from other sources of transport, aviation, rail, shipping, medium and heavy-duty vehicles. The greatest source of demand growth, however, comes from industry and petrochemicals. Petrochemical demand is expected to grow at twice the rate of global GDP. This includes products like plastics, fertilizer, clothing, packaging. Demand of these products is closely linked to the key macro trends of urbanization and industrialization. In our low demand case, this includes a much more aggressive rate of EV penetration, well above the vast majority of any of the published mid cases. Significant trend increases in fuel efficiency and low case macro inputs constraining the non-transport demands. We also test our entire portfolio against a set of strategic themes, and how the electrification of transport will evolve is one of them, and I would like to dive a little bit deeper into that.
First, let me give you some round numbers to illustrate why this is such a vital question. The global liquid demand currently stands about 100 million bbl a day. 60 million of those are used in transport. 50 million of those are used in road transport. We're talking roughly about half of the global demand here. We model electric vehicle adoption very aggressively and have been on the green end of the spectrum here for years. We see electrification of the light-duty fleet as a certainty, even in our low adoption case, where it just takes longer. When I spoke to you three years ago at our 2016 petroleum briefing, we shared our view on the electrification of passenger vehicles in great detail. Since then, we have been expanding our analysis and taking a deeper dive into the medium and heavy-duty vehicle sector, trucks and buses.
The short summary is that buses are highly amenable to electrification. However, they only make up 3% of the global demands. The medium and heavy trucking fleet is more relevant. It makes up 14% of the global demands. It's the last frontier of electrification. We believe that battery technology, the weight and cost dynamics of batteries, will impede accelerated adoption. In addition, the average truck's useful life is actually quite long, around 17-18 years. Given these adoption hurdles, we do not expect electrification of the trucking sector to occur until deep into the second half of this century. On top of this, in our central case, we see the number of trucks increase. There are currently around 60 million trucks.
We see that increase in our central case to $100 million in 2050, leading to potential growth in this sector. Hey, a much more detailed look at our latest insights in electrification of transports can be found on our prospects blog that we posted today on the BHP website. Go and have a look. Let me move to the oil and supply story. We model global natural field decline conservatively at 3% per year. At that decline rate, half of today's supply will need to be replaced by 2035 to meet demand in our central case. Where is all of this supply going to come from? U.S. shale has, of course, been the major source of new supply in recent years. However, like most industry observers, we see U.S. shale evolving into a more mature stage of production. Shale will continue to be an important source of supply.
However, issues such as child-parent well interference, well spacing, water handling, steep decline rates, and last but not least, capital disciplines are headwinds that slow the rate of growth. As a result, we see slower growth towards a plateau in the mid-20s when U.S. oil production peaks at around 16 million bbl a day before it starts easing off. On top of this, it is important to note that not all shale is created equal. The low-cost cores are finite. We see core shale move off the margin in the mid-2020s. Conventional oil fields and deep-sea developments will be required to meet the demands. Those bbl will likely come with greater geopolitical complexity and some from sources still yet to be found. That brings me to another important point. On a global basis, the most recent oil investment cycle has lacked the required spend to maintain abundant reserves.
Conventional projects that are coming online over the next year or so are a result of the previous peak in the cycle. The last three years have seen very low levels of conventional oil resources being sanctioned for developments. According to the IEA, we are tracking 60% lower than the previous five years. On top of this, the sharp slowdown in exploration spend has led to record low new discoveries. We could be at a turning point here, as in 2016, we started to see a 20% uptick in exploration spends. For these reasons, we see a long-term market that stimulates inducement of new, higher cost supply, which leads to a reasonable steep cost curve beyond the mid-term. That is why we like oil.
Just to stress the point, I want to highlight again that we think in ranges, and we test all our future plans against this range, including the plausible low. Let's turn to the gas markets. As the world moves to a lower carbon footprint, natural gas increases its share in the global energy markets. In parallel with the rise of renewables, we forecast an incredibly strong renewable power growth, with wind and solar growing by over 7% per annum over the next three decades to meet almost 40% of the global power generation by 2050. If you add hydro, this number increases to 55%. It's also important to note that the global energy consumption continues to rise. We do not see this peaking, i.e., the global energy pie gets bigger. Gas will also increase its market share to the expense of coal.
Gas will see diversified growth in the power and industry sectors and grow at 1.2% CAGR to 2050. In the power sector, gas becomes a complement to renewables, providing an important source of base load flexibility for a market increasingly reliant on intermittent renewables. I should note that we do see a risk for renewables potentially leapfrogging gas as a base load fuel for power in emerging markets that have a relative young fleet of coal-fired power stations. This is built into our low case and only starts to become relevant in the very long term. Think 2030s. Let me pivot to LNG. You'll see in the bottom chart that we're currently experiencing an oversupplied market. This will continue till the mid-'20s, after which point demand will start to outpace supply. The LNG market is currently relatively small. It's modest, 45 Bcf a day.
Relatively small versus the overall large gas market of 370 Bcf a day. We are very positive on the demand outlook for LNG. It is the fastest growing fossil fuel and grows at a healthy 4% CAGR to 2040 and is on track to doubling its share in the global gas market by 2050. We see regional demand growth primarily in Asia, China, and India, but also in Europe. The strong demand outlook, coupled with natural field decline, will require over 50 new LNG trains to be induced in the next 20 years. As the LNG market becomes larger, the impact of a new large project entering the market will be less likely to create an oversupply as it does today. Despite the strong outlook for demands, the overall supply dynamics leave the gas market fundamentally more restrained.
Gas is just more abundant and a more homogeneous resource than oil. As a result, we see a flatter cost curve. On top of this, the LNG market is transitioning. The market will continue to harmonize, growing more and more interconnected. The U.S. export facilities of recent years now connect the U.S., Europe, and Asia into one global energy market. The largest spot market, as well as the liberalization of the power markets in Asia that is driving a need for more contract flexibility, have diminished the appetite for long-term contracts. Even more, contracting is moving away from oil indexation, which is now estimated to be roughly 50% of the market. What does it mean for our view on gas? We like gas, but due to this harmonization, as well as a flatter cost curve, we need to be very selective in the opportunities we pursue.
We like gas assets that are geographically advantaged vis-à-vis existing infrastructure, customer, or both, creating upstream margins. Let me summarize my key messages in closing. We like oil because we see a structural supply and demand gap, even when stress-tested against our most aggressive assumptions for EVs. Even though we call for a peak in demand, natural field decline creates a need for inducement economics. With core shale coming off the margin, this happens at a higher cost than today. Natural gas similarly displays a supply and demand gap. The demand profile for gas is very healthy. It is diversified, and we see consistent growth, with the growth in the LNG sector even stronger. Supply of gas, however, is more abundant, and for this reason, asset choice is critical. It is therefore that we favor oil. We still find gas attractive when advantaged. Thank you for your time today.
I will join you again at the end of the next presentation, and will now hand back to Geraldine.
Thanks, Michiel. Okay. We'll now turn to our asset base in more detail. After which, as Michiel said, we'll get to your turn. Today, we hold nearly 3.2 billion BOEs in resource. We continue to add to this resource base through exploration or acquisition, and we continue to unlock commercialization through technology and strategic partnerships. Our asset base is built around a collection of fields and related infrastructure, concentrated in geographic regions, which we call a heartland. Heartlands provide a competitive advantage through differentiated access opportunities to partnerships, to shared infrastructure, and to talent, through deep technical and operating capabilities that allow us to get the very best out of those assets, and through the ability to impact social value at a larger scale and over an extended period. Before we get to the asset specific, at a portfolio level, we see a strong production outlook through the 2020s.
Our production today stems from three producing heartlands: in Bass Strait, in Western Australia, and in the U.S. Gulf of Mexico. As we progress through the early 2020s, the Gulf of Mexico oil assets grow in contribution, followed by major growth through Scarborough, through Trion, and potentially a Trinidad North gas development. If we turn now to the specifics of the individual regions, our Australian producing assets are highly cash generative. They're resilient to price, and they will continue to generate strong returns through the mid to late 2020s. In Bass Strait, we are focused on understanding and commercializing its contingent resource, whilst also recognizing its limited material upside potential beyond the mid to late 2020s. North West Shelf, equally, a very strong cash generator.
Our focus there is on working with our JV partners to enable the Karratha LNG facility to transition to a third-party tolling facility, given the declining North West Shelf equity gas over the next decade. Turning to Scarborough. Scarborough offers material growth potential to our Australian portfolio. Development planning is now technically very mature, the commercial tolling terms are well advanced to the point where we have increasing confidence in a sanction decision readiness in 2020. As you may have seen this past Friday, Woodside, the operator, has announced a material increase in the 2C resource estimate to 11.1 Tcf. A Scarborough development would also unlock potential future upside through the development of the Thebe and Jupiter gas resources, which contribute an additional two Tcf. We're targeting a final investment decision in the 2020 calendar year, with potential first production from FY 2024.
If we turn now to the Gulf of Mexico. Over the early to mid-2020s, we see the Gulf of Mexico contribution growing from just over 30% of EBITDA today to about 50% in FY 2025. Atlantis is a true Tier 1 asset and continues to yield further high-return growth. The Phase 3 project offers returns of over 40% and is expected to deliver first oil next year in the 2020 calendar year. Beyond this, development planning is underway on multiple further growth projects, including subsea pumping and further infill wells. Mad Dog Phase 2 is on track, and as in Atlantis, development planning is underway on further growth through water injection and through field extensions. Shenzi continues to demonstrate our operating capability in deepwater Gulf of Mexico, where unit costs and uptime remain competitive.
In the early to mid-2020s, we anticipate growth at Shenzi through progressive development of the Wildling discovery to the north. We anticipate a final investment decision on Wildling Phase 1 in early 2021, with potential first oil from early 2022. In addition to the named options just mentioned, we have many further unsanctioned projects with IRRs in excess of 20%, that in large part have been made possible by improvements in technology. Turning to Mexico. At Trion, following the success of the 2DEL appraisal well, we moved on to the second 3DEL appraisal well, that has provided greater confidence around both the scale and the quality of the resource. With these results, we now have sufficient information to underpin advancing the development planning.
Whilst we're still in the early stages, we're targeting a project break-even of below $50 per BOE, and we're confident that the Trion development will compete for capital in BHP's portfolio. Project sanction is possible from the 2022 financial year, with earliest first oil from financial year 2025. In Trinidad and Tobago, we have operated there for nearly 20 years in the shallow water Angostura Field. Earlier this year, we sanctioned the Ruby brownfield project, which was underpinned by continued appraisal and seismic imaging in proximity to the original development. In the deepwater, in our northern licenses, we have declared a 3.5 Tcf growth discovery with further potential upside. Whilst detailed development studies are just getting started, a hub development appears best suited to this play.
The case we share today assumes access through existing LNG infrastructure in Trinidad and Tobago, which has capacity, whilst recognizing there are multiple development concepts being considered at this phase in the project. As operator with high equity interest, we also have scope to optimize the development planning and the development concept. Subject to being competitive for capital, we see an FID from 2022. Coming back now to the strength of the portfolio in aggregate. We start with our suite of producing assets from Bass Strait to Mad Dog. This base delivers strong margins and returns through the next decade. Sanctioned and well-advanced projects bring new high-return oil into production from the 2021 financial year, effectively replacing field decline from our legacy Australia assets. These are highly attractive, with IRRs that range from approximately 20%-45%.
Beyond this, we have multiple high-confidence unsanctioned projects across green and brownfield, as we've discussed. Finally, we have a successful exploration and appraisal program that feeds the front end of the pipeline, with Trinidad and Tobago North transitioning into the development planning phase. We also recognize that acquiring early lifecycle assets, like Trion, can add value and enhance the portfolio. This remains part of how we seek out future options. What I'd like to leave with you is that we have a strong base with near-term, high-return new production from already sanctioned projects, followed by a healthy pipeline of high-confidence opportunities in various stages of maturity. With that, we now have some time for questions, including from over the phone, on what Michiel and I have just presented.
To remind, Sonia and I will come back after these and a short break to discuss exploration capabilities, values and returns. If you can hold questions on those topics until after this Q&A, we will get to those towards the end.
Of course.
Michiel, join me and we'll take the first question. We'll take some from the floor here and then from the phone. Yeah.
Hi, Geraldine. It's Paul Young from Goldman Sachs. Thanks for the presentation. Two questions on your big unsanctioned growth projects. One being Trion and the other Trinidad and Tobago Gas. On Trion, lots of exploration upside there, but questions around the base case scope. Are we looking at a fixed platform here, potentially tieback? Several on Trinidad and Tobago Gas.
First question. You did actually mention there's spare capacity at Atlantic.
LNG, which is about a 15 million ton per annum facility. When does material ullage or capacity open up at that facility? Also, do you actually have enough resource at this point in time to push ahead with this? Or is it contingent on further exploration? I'm going to throw in a third one there, but it's a lot going on in this project. The last one is, BP owns 30% of T&T North. They own 50% odd of Atlantic LNG, and they're the operator. You do mention about potential sell downs of large equity holdings. Is this an example of potentially that? Thanks.
Okay. Thank you, Paul. On Trion, we're in the early stages of development planning where we're pre-FEED and of course, that's the point in the development planning where most value is generated through getting the engineering right. A couple of concepts being considered that take into account the specifics of both the reservoir and the oceanic conditions. Trion will be one of the deepest facilities in the world at 8,000 ft. The nature of the reservoir is such that it's somewhat compartmentalized, so you'll have a high number of wells. With those things in mind, a semi-submersible coupled with a floating storage facility is likely the most appropriate development concept. The reason for that, beyond what I've just said there, it's proven technology, it's well understood, whereas an FPSO is a little bit outside of the proven technology range.
That's what we're tending towards at the moment. The T&T LNG. Again, quite early in the stages. In terms of the resource question, there is sufficient resource in what we have discovered today and booked in our contingent resource. What I would say is that there is upside beyond that. From one of our most recent wells, which isn't actually captured in that, and there's further appraisal that we need to do. For the contingent resource that we've reported, that does support a development. In terms of the access to the LNG facility, we tend to access both the domestic market and the LNG market. The domestic market is a strong market. Ammonia, methanol, and we see increasing demand there. In terms of the LNG facility, there is ullage available.
Certainly, as we look out towards a potential first gas timeline, there are few reported, and that we understand, material gas resources that would compete for that ullage. Of course, at the outset, we did rather kind of purposefully and strategically partner with BP, given that they are involved in the midstream. I think you had a, if you're allowed even another question. A question there on the sell down. Part of our access strategy, whether it's exploration or acquisition, is we seek to have operatorship and a high equity interest, so that we can optimize our development. Ultimately, we're focused on value here, and so whether it's a sell down or operatorship or the many other levers, that's what this front end of the development cycle is focused on. More to come on that, but it's certainly a lever.
Hi, it's Glyn Lawcock at UBS. Geraldine, I think you and your team today have already said you favor oil and you still find gas attractive when it is advantaged. I was wondering if you could sort of elaborate on that a little bit in the context of the North West Shelf and Scarborough. Obviously, you just became 50% bigger overnight, it feels like. Well done to Woodside. You're going to pay twice the tolling fee to go through a new plant versus a plant that sits there with ullage. Could you explain why is that in the best interest of BHP shareholders? Thanks.
Let me start and Michiel may add to the LNG question. I think with particular reference to our resources in Western Australia, the Scarborough Gas Field and our equity interest in the Karratha LNG facility. The optimum case for us is to commercialize the Scarborough Field, the highest possible value, and to secure utilization and a revenue stream from the North West Shelf Facility. That's one piece. Developing those in parallel generates value. The second piece on those two facilities is Scarborough Gas has some part of its composition means you need additional investment in the North West Shelf Facility to cater to nitrogen content and so forth. That doesn't make that an ideal development concept. At the moment, our plan forward looks at taking Scarborough through Pluto, with the balance going through the North West Shelf Facility, particularly speaking to the higher resource.
We are actively working and well advanced in North West Shelf to secure a revenue-generating tolling facility with Browse as the anchor tenant there. That, for us, represents addressing the biggest value drivers in commercializing the resource at a higher return and getting the most out of Karratha. Thanks.
Sorry, just wanted to follow on.
Sorry, Geraldine. I guess, the capital up front for what you say the gas has got nitrogen problems.
The tolling fee, I would've thought you pay through a new plant versus an existing plant that you're in. How do you square those economics? I'm still confused how the economics of what would be a minimal capital up front for pulling nitrogen out versus what will be quite a material uplift in the tolling fee. Thanks.
Again, it kind of comes back to getting the most from our overall resource base. A couple of other things maybe to add to what I've already said. The North West Shelf facility, we recognize the interests of the Browse partners in North West Shelf, and so the commercial complexities, beyond the technical complexities of routing Scarborough. That in itself is not a driver. We recognize that from a pragmatic point of view, in advancing both of those concepts in parallel. Rest assured that the tolling that we're currently negotiating through Pluto, is commensurate with the risks, the exposures, and the value proposition from Scarborough. Ultimately, Glyn, everything comes back through our capital allocation framework, where it is rigorously tested by an independent part of the company, our governance process, that tests the assumptions, be they commercial and technical.
As it stands, we see both of those moving forward in the early to mid-2020s, which is the highest value proposition for us.
Okay.
Yeah, no. I think you described it well there, Glyn. I think we basically look at all these options on the best route to market for any of these gas fields. Yeah.
Thank you.
Yeah.
Tyler Broda from RBC. Two questions from me. One, in terms of the growing concerns around ESG facing the sector, how do you square that off in terms of cost of capital, or how do you look at that from a wider context of its impact on BHP as a group?
Secondly, on page nine, there's the reduction in volatility that comes from petroleum being part of the portfolio. There's a big bump there in 2025. Could you just explain what's going on there? Thank you.
Let me start with the ESG. We look at that from two perspectives. One, back to our strategy and the attractiveness of the commodity. As Michiel explained, under any plausible scenario in a decarbonizing world, throughout several decades, we see strong demand, particularly for oil, owing to the scarcity of supply and parts of the demand sector that there are no readily technologically ready substitutes. We continue to see demand and of course, we think in ranges. We take account of the uncertainty. That, of course, is something that the marketing team do independently. What I and Sonia and the petroleum team are focused on is bringing forward options that recognize that uncertainty. Whether it's Trion, whether it's Trinidad North or otherwise, we test for performance across the range of outcomes.
For what you saw on the new books and on the slides today, you would find that they're very resilient across the price. They pay back in the mid-case in sort of well under 10 years, five, six, seven years. The projects that you would see coming on stream here, we've got our money back from those by the early 2030s. Both from a commodity point of view and from a resilience of the investment, and those two things come together. We square that away in a practical sense through our capital allocation framework, which tests across not just the financial metrics, but also the payback times, the impact on the long-term diversification of the portfolio, and other measures. Think we covered?
Just the volatility on.
Oh, the volatility. That's something I think we test on with and without petroleum. I'll have to maybe come back to you on the specific bump there on 25, which we'll be very happy to take that separately, if that's all right.
Hi, Jack Klapper, Bank of America. If I can just return to Scarborough for a second. On most people's estimates, I think it's relatively lower return than your existing sanctioned projects, which you said were 20%-45%. Can you talk to the economics at all? Secondly, with the option agreement that you have for an additional 10% by the end of this year. Does exercising that option agreement have to go through the same capital allocation framework as a FID?
The Scarborough economics, I can't, as you probably won't be surprised, speak about the very specific details of those. They are tested across the range of outcomes. They are tested on both rate of return metrics, but also their ability to stay to deliver a return on capital, even in a very low case outcome. We do look at their impact on cash flow out over the decades. There's a range of metrics. What I will say is that it is a high-quality resource. That's why we've remained in it and interested in it, both in terms of its scale, but also in terms of its access to the regional infrastructure. Indeed, as you would have heard there from Michiel, its proximity to the growing Asian market. You have an advantaged access point. I think that Scarborough does offer a very good value proposition.
In terms of the 10% option, absolutely. It's, for all intents and purposes, a connected but nevertheless separate investment which comes under the same level of scrutiny as any other investment would. We're clearly already considering that. I think we'll go to the phone lines for a question.
Certainly. Ladies and gentlemen, we will begin that question and answer session. Just once again, if you wish to ask your question, just please press star one. Your first question comes from Lyndon Fagan from JP Morgan. Please ask your question, Lyndon.
Thank you. The first question is just on the Victoria assets which have been put up for sale by Exxon. Just wondering whether you would be a potential purchaser or potential seller of those assets, whether you could make some broader comments on how M&A might fit into the portfolio, given that petroleum is only sort of 7% of EBIT over the next few years. I guess the second question is just on the CapEx sort of going up to $4 billion a year, can you maybe talk a bit about what an unconstrained scenario actually means? What are the constraints, if you like, that might pull that back, how the CapEx would sit more broadly for the group? I imagine in that window that it ratchets up to $4 billion. You've got Jansen coming on at maybe $1 billion a year.
Do we start to see the group hit CapEx levels of over $10 billion? Thanks.
four questions there. Thanks, Lyndon. firstly, Victorian assets, the Bass Strait assets. As I said during the briefing and just very briefly reiterating, very valuable to us, lots of cash, and we continue to invest on the contingent resource because of its access to such a strong market. In terms of the Exxon process, clearly, it's a complex asset. Exxon are operator, and the Bass Strait has big importance to the security of Eastern Australia gas market. of course, that does give us pause for thought. We're considering all of our options within that. In my view, it's a complex transaction. It's not something that will play out very quickly. I would anticipate that will take a couple of years. we're considering our options and what that might mean to us. Our core strategy is still continue to get the most from that asset.
Beyond the mid-2020s, at this point, we don't see material upside, but we continue to test it because that's some of the highest returns that we'd likely see from any of our assets. Watching it, but certainly at the moment, very focused and just continuing to get the value from it. M&A in the portfolio. We'll continue to see that as a mechanism that we could grow value in the portfolio. We see exploration as the most value accretive and highest returning way to bring new resource into the portfolio. However, when you think of assets like Trion or an asset that has similar characteristics to that, which speaks very strongly to the same set of criteria that informs our exploration strategy, then yes, of course, we continue to be open and indeed monitor the market for those kind of high returning opportunities.
Of course, back to the capital allocation framework, everything competes for capital across a range of metrics. We know that. Anything that we bring forward into that, of course, has to satisfy those criteria. The CapEx question. The unconstrained case. The unconstrained case is essentially what we laid out here, give or take, and recognizing that still many of those opportunities are early in their life cycle. A reasonable view of how development planning would progress relative to our understanding of the resource base would demand the capital, on average, what we laid out today at current equity interests and at the earliest possible timing. In terms of the group CapEx, of course, we compete for capital on an annual basis. We go through the capital allocation process, and so it is incumbent on what I do, what Sonia does, and the team does.
If we want to compete for that capital, then we have got to maximize the value of those opportunities.
I think as has been already spoken from Peter and for Andrew, our guidance has been given for the next couple of years, and beyond that, the narrative has spoken to single-digit numbers. My job is to make sure that we can command a big chunk of that CapEx and deliver what we believe are very competitive projects. Thank you. Anyone from the phone? Yep.
Yes. Your next question comes from the line of Mark Samter from MST. Please ask your question, Mark.
Yeah. Hi. I'm just hoping for another follow-up question on Scarborough. I guess, when you look at the LNG market, most of the empirical evidence would suggest that actually one of the biggest drivers for economics has been liquids, and also brownfield expansion. Effectively, when you're paying a tolling fee on what sounds like a very high tolling fee to Woodside, you're effectively building that project on greenfield economics with zero liquids. You just bat your capital allocation framework. LNG has been a pretty dreadful investment for everyone in the last decade. You've got an awful lot of capacity being sanctioned without an end buyer now, so you're probably taking more price risk than you ever have before in an LNG project. How does Scarborough, A, stack up on a global cost curve basis?
B, how does it stack up for your economics for, isn't this asset worth more to someone who owns the infrastructure as well? C, within your capital allocation framework?
Mm-hmm. Maybe I'll answer from the asset perspective.
Yes.
You can talk the LNG piece. We're not at an FID point yet. We are well advanced on the commercial negotiation. We do consider the outcome across the range of prices and ensure that we're well protected on the low side. Ultimately, this will compete for capital, and so it will be tested independently of what the petroleum team do, with a strong governance process, and we have a very strong capital allocation process. The fundamentals, though, I would perhaps challenge some of what you said there in terms about the quality of the asset and its access to market. There is much going for it. The pie is big enough for both the upstream and the midstream. Rest assured that we're focused on making sure that our return is commensurate with the upstream exposure to price or resource.
Equally, that it'll be fully tested within our own governance processes.
Yeah, maybe I can add to that, Geraldine. Like every project we test against our ranges, that includes the possible low on LNG as well, and Scarborough has to pass that test for this to be considered. The possible low on LNG is, we're thinking about what could happen there of, you could see Qatar, for example, advancing their North Fields, accelerating development of that. That's part of our low case. We talked about the leapfrogging. That's part of the low case. We test against that, and Scarborough will be invested if that passes our low scenario.
I'm not sure if you said this publicly before, sorry, have you talked about how much you'd want to have contracted or how much spot risk you're willing to take on the project?
Yeah, I can talk to that. We're looking at a mix there. As I laid out, with the market changing, there's a bigger spot market now, and numbers quoted are contracts, let's say up to three, four years, about 40% of the market now. The liberalization of the Asian power market, I think is an important driver there, where utilities are not necessarily looking for that long tenor. I think ultimately you end up with a mix of contracts where we're definitely looking to have some longer-term contracts, and that could be a mix of different indices. We'll consider those, as well as some of that into the spot market. We'll definitely look to contract a big chunk of those tons.
We'll come back to the room here.
Yeah.
Any more from the room here?
Over on time.
All right. We might take sharp break now. Thank you very much.
Are we starting at 3:20?
We're starting at 3:20.
Sydney time.
Sydney time. Thank you very much.
Welcome back, everyone. I'm Sonia Scarselli. I'm the Vice President of Exploration and Appraisal. Today, I will talk about our exploration success and our exciting future opportunities. I've been at BHP for eight years and worked across exploration and production. I have a BSc in geology, and I started in the industry as a structural geologist, working petroleum system across multiple basins, such as Atlantic Margins, Middle East, and South America, just to name a few. I sense that the two biggest areas of interest in exploration are what are we investing in and how it creates value. I will address these questions for you today. Our exploration strategy has been in place for the past five years, and it is delivering. Since the 2017 financial year, we have added 758 million BOEs of net 2C contingent resources to the portfolio.
When we talk about exploration, we are referring to accessing opportunities, exploring those opportunities, and then appraising our discoveries. What does that look like? Our strategy targets the Tier 1 opportunities and is geographically focused. Based on our commodity outlook, we have a bias for oil. Where we find gas, if there is a structural advantage, we will look to commercialize it. If not, we will monetize. We target big reservoir systems with world-class source rocks. We go after big traps they can deliver multiple 250 million bbl discoveries. Why is that? This allow us to explore these basins for multiple decades, just like in the Gulf of Mexico. We focus on competitive opportunities with attractive fiscal terms, and we access the plays early at high equity.
Our exploration strategy in action targets material, high-quality opportunities which are low in the cost curve, offer scope to build scale over time, and are competitive within the BHP portfolio. This is underpinned by the BHP way. What does this mean? This means we apply a rigorous bottom-up understanding of how the petroleum system works, from the scale of the tectonic plate to the microscopic pore space in the rock. We understand the critical play elements and the risk of the system, and we invest in getting the right data to improve our understanding of the volume, the risk, and the value of our opportunities. For example, to reduce the technical risk in the Western GOM, we acquired an ocean bottom node seismic survey. Having the right data helps drive the right decisions and reduces the risk profile ahead of drilling. Our spend is aligned with this approach.
With around a third of our budget invested in seismic data and half going towards exploration drilling. Both of these help mature our current portfolio. Of course, we must also work on accessing new opportunities to replenish our growth pipeline. Why invest in exploration today? While our current portfolio is well-placed to deliver in the 2020s, our exploration program is preparing the opportunities for the future. Given the maturation cycle of opportunities in petroleum to be a sustainable return contributor from the late 2020s into the 2030s, we must bring forward additional portfolio options today. We mentioned, our strategy is to identify and access the right places early in the life cycle, where most of the value is captured. We capture major position in frontier basins and new plays, we have the opportunity to create new heartlands.
We are doing this now in the Western GOM and in Trinidad and Tobago. As you see on the right, we like to access at a high equity. This allow us to manage risk through the life cycle, including through partnering at the right time. Our approach to partnership centers on the following. Gaining access to resource. For example, partnering with Pemex allowed entry at Trion, a Tier 1 opportunity. To bring in understanding and knowledge of an area. For example, in Trinidad and Tobago, our partners are both long-term producers in the region. To manage and share the risk of exploration. Being an early mover at a high equity and with large position allow us to do three critical things: to manage the risk through the life cycle, explore using the BHP way, and increase our likelihood to build a heartland.
I'll now share with you some example that reflect these characteristics. Last year, we accessed the Orphan Basin in Eastern Canada. It was identified as having Tier 1 potential as part of our global endowment study. We recognized that the main part of the play was underexplored and still had a significant remaining potential. Geologically, the Orphan Basin is analogous to the North Sea, which we know is one of the most prolific regions in the world. Why now? The most recent license round drove the acquisition of new seismic data that allow us to map large structures. We could now understand the scale was big enough, and the risk profile was appropriate. The rest is history. We captured two major blocks at 100% equity, giving us exposure to a vast portion of the yet-to-find potential.
These blocks have multiple opportunities, and on success, allow for follow-up. As we mature the portfolio and work towards drilling of the first exploration well in the 2022 financial year, we will consider partnership. In the Western Gulf of Mexico, we are looking to extend the prolific Perdido play where Trion was discovered. Western GOM is a great example of where we have a large amount of untested potential. It sits under the salt, and the image quality is extremely poor. We know there is a world-class source rock and a reservoir system. We just can't see them. Multiple technologies have been deployed by the industry to improve the image, though without success. We designed and worked with suppliers to acquire the first industry ocean bottom node seismic technology for a large deepwater exploration project.
We are encouraged by the step change in the image quality. We expanded our footprint at the most recent U.S. Gulf of Mexico lease sale. What can you expect from us over the next years? We will be returning to Trinidad and Tobago North to appraise these discoveries. In the southern licenses, we're still evaluating oil potential in the area and how to further commercialize the gas discoveries at Leclerc and Victoria. In Mexico, we have exploration activity with the Trion license. In Central GoM, we're maturing drillable options in our existing heartland. In the Western GOM, we are awaiting the seismic data. In Eastern Canada, we are in the early stage of maturing drillable prospects. In parallel, we continue to evaluate and bring forward opportunities for further access so that we can replenish our pipeline.
To conclude, the key points I would like to leave you with today are our exploration strategy is delivering. We have added 758 million bbl of 2C contingent resources since FY 2017. We've done this through a focus on understanding the geology and getting the right data. We are continuing to build the pipeline for the future. With that, I would like to welcome Geraldine back to stage. Thank you.
Thanks, Sonia. Okay. Having heard about the suite of opportunities in the portfolio, I wanted now to talk to our capabilities and culture, as it's our people that underpin everything we've talked about, and indeed the future outlook. Let me start with social value. Our commitment to our people, the communities we operate in, and the environment is evident from our performance. Over the past five years, we have reduced the frequency of high-potential injuries, they're the events that have the potential to cause a fatality, by 44%. This is a key metric we use to understand our safety performance and indeed to learn from it. Furthermore, over the past five years, we've seen an approximate reduction of 60% in the frequency of total recordable injuries.
Beyond safety, we recognize how a diverse and an inclusive organizational culture enables higher performance and allows us to attract and retain the best talent. We rank as a global leader in petroleum in this space, across industry sectors well beyond the resources sector. In the environment, we're focused on reducing greenhouse gas emissions at our producing assets, and we've had good results through efficiency improvements in that. Beyond our producing assets of today, on all new developments, such as Trion, the engineering requirements specifically incorporate a greenhouse gas reduction plan. This demands inclusion of considerations in power generation efficiency, low fugitive emission equipment, and elimination of routine flaring. Finally, in our Mexico operation today, we have delivered up to double the license obligations for local content. As you heard from Sonia, we see our capabilities in exploration as a competitive advantage for us today.
In saying that, I do recognize that we've had mixed performance in times past. We have learned from that. We reset the strategy five years ago, Our recent results show we are on a much stronger trajectory. To put some numbers to that beyond the resource that Sonia shared, BHP ranks in the top third of peer companies for average deepwater exploration finding costs at $2.60 per barrel of oil equivalent. In addition, we also rank in the top third in terms of average discovery size. These metrics flow straight through to higher full-cycle returns and faster times to development. Staying with returns, a continued focus on productivity has led to a 25% reduction in unit costs over the last five years, despite a 12% reduction in volumes. To share briefly an example.
Through a zero-based organizational redesign, we successfully removed all shale-related overhead from the business on its exit earlier this year, with no trailing costs right from the point of exit. Beyond our producing assets, our deepwater drilling performance benchmarks very well. This is enabled through application of new technologies in automation and in surveillance, and in a high-performance team culture, from the rig floor to the office. With drilling accounting for 40%-50% of exploration and development costs, this is an important value driver. Finally, turning to transformation and how we think about unlocking future value. We look across the life cycle, and we focus on the big value drivers in each area. In exploration, we are adopting technologies that give us better image quality, which in turn increases the likelihood of finding the best opportunities.
Sonia shared how we are applying that in practice today in the Western Gulf of Mexico. In project development, we are integrating digital and subsea engineering solutions, which increase performance and resource recovery. That has direct relevance to our Shenzi operation and potentially to our Trion development. In production, reservoir and well surveillance, again, allows us to get the most from our assets. That shows up in our Pyrenees asset in Western Australia, where a further infill project has been enabled through well imaging tools. In summary, I'm confident that we have the capabilities required to execute on our plans and take us through to the next phase of development. How does all this translate to value and to returns? As we've demonstrated, our portfolio has the potential to deliver average production compound annual growth rate of 3% over the next decade.
We remain competitive in return of capital employed and EBITDA margins, which are resilient throughout the price cycle. Our average 3% production CAGR over the next decade comprises our base production, our sanctioned projects, and our unsanctioned opportunities. Our sanctioned oil-dominated projects will commence production from next year, replacing BOEs from field decline. Our unsanctioned growth opportunities give us the potential to grow our production volumes whilst maintaining our strong returns. This demonstrates the power of our heartlands through the competitive, embedded, unsanctioned growth options in the Gulf of Mexico and in Western Australia. Additionally, we've competitive discovered resources in Wildling, in Trion, and in Trinidad North. Beyond that, we are testing future Tier 1 oil opportunities, still in Trinidad and Tobago, in Western GOM, and in Eastern Canada. All projects, whether they're exploration or development, will compete for capital under our very rigorous capital allocation framework.
This means that whilst we have a broad suite of attractive opportunities, only the most competitive will progress. Over 75% of potential capital spend through to the late 2020s is associated with projects yet to be sanctioned. Because of our high equity interest and our operatorship in Trion, we retain significant flexibility in phasing and in scale. Finally, over 50% of our total potential capital investment is in oil opportunities. The outlook we have presented today has the potential to generate strong EBITDA margins and returns. These margins have exposure to the upside in price, yet they're protected in a low price environment. Our average ROCE is circa 12%, rising to almost 20% in the second half of the decade. Our options have the potential to increase the base value by up to 80%.
This starts with our sanctioned projects, which are on track to deliver from 2020 in the Gulf of Mexico. We have high confidence in our unsanctioned projects, with embedded flexibility that have potential to deliver from as early as the mid-2020s in Scarborough, Morgan, and Trion. Our discovery in Trinidad and Tobago is material, with development planning now underway. Finally, we have additional value associated with our exploration program. Importantly, these are distributed across the life cycle, which provides value creation opportunities well into the next decade. In summary, petroleum is a great business enabled by the BHP strategy. It has an attractive commodity outlook. Our assets and our pipeline of growth projects are resilient across the range of prices. We have the capabilities, supported by our commitment to social value and to capital discipline, to maintain and indeed grow superior margins.
Let me now pause, and we'll move again to the Q&A section. Sonia, Michiel will come back up and join, and we'll open the floor and the telephone line for questions. Doesn't matter.
Thank you. It's Tim Clark from SBG Securities. I apologize if my questions are a little bit simple, but I'm not an oil and gas expert. My first one is just how you think about event risk. Because we have, not often, but we have seen big events, and they cost a lot of money. How in your cost of capital, or how in your project assessment, you add event risk to the bottom line? Secondly, I think I'm right in saying that your returns exclude your exploration cost. Compared to your minerals exploration, oil and gas exploration's quite a big cost. It's more significant. Don't you think in your returns you should have an accumulation of exploration costs divided up by success or something like that to make it like for like with the competition for capital?
Thank you, Tim. I'll start with the event risk. We have a reasonably sophisticated risk management system within the company that captures event risk across health and safety, across market, across our customer base. We capture it in our capital allocation and governance framework, where we specifically look at risk exposure in a quantified and an unquantified way. Part of that is reflected in the range work that Michiel talked about. We also reflect it in our cost of capital, depending on the jurisdiction that we are operating in. That is reflected squarely in the economics. Whether it's in the governance or through capital allocation, we consider both financial metrics, but also exposure to particular events. In terms of our returns, I think the numbers we showed you here are inclusive, actually, of exploration investment.
The ROCE and the EBITDA numbers that we shared are inclusive of exploration.
Andrew Snowdowne on this side.
Sorry, I've got the mic. Liam Fitzpatrick from Deutsche Bank. Just a broad question, really. We've seen some of the other divisions in BHP give some fairly optimistic targets if we think about Olympic Dam and Met Coal. You've given some pretty bullish targets here for petroleum in terms of volumes where they could get to. I'm just trying to think, what is a more realistic base case for this division? Is it to keep volume stable out to 2030, or are you more ambitious than that? Thank you.
It comes back to our strategy and the returns we see from the suite of projects and the degree to which they can attract capital. We have communicated that we're in, for the most part, the pre-FEED stage. Whilst I have confidence in the directional integrity of what has been shared there, of course, there's always further resource understanding and development planning that goes into that. I think the integrity of the directional outlook is strong as it exists today. In terms of our ability to deliver that will come squarely back to the ability of those projects to compete for capital. Will it look exactly like that? Probably not. Not exactly like that, because inevitably we recognize that we optimize as we go through.
That can get bigger as we better understand the resource, refine the development concept, understand how we can access market in places like Trinidad. We also recognize that we have both operatorship and high equity interest, and in the interest of a value maximized case, we may choose to reduce our exposure to, in particular, project opportunities.
It's Andrew Snowdowne from Sanlam Investments. Two simple questions. You do show a chart in slide 11, which shows exploration spend going forward. It's difficult to see the absolute numbers. Are we talking about $500 million?
Is that the sort of figures over those periods, the two-year periods? The other question I have is just related to the actual ranges that you use. You've spoken a lot about stress testing, looking at returns under different scenarios. I'm surprised by your oil range from $60-$80, given spot is actually at $60. Maybe if you could just talk to what you regard as a long-term oil price and just how flexible are those returns if you do it lower. Obviously, it's not a particularly high fixed cost industry, how is it skewed if you go more towards a $50 per barrel oil price rather than $60 at the low end?
Shall I start with the second one?
Can do.
Yeah.
Yes.
Andrew. Yeah, hey. You're absolutely right. We think in ranges, yeah. We test all the projects against the low case. We do not take a single point forecast, nor do we actually disclose the ranges, but as I laid out today, and maybe get a bit more color to that, if we talk about our low case in oil, we look at a case where OPEC has no spare capacity, very rapid EV adoption, so that we go to a high case for EV adoption, very low macro assumptions on that. To give you some guidance, if you look at what we've approved so far, and Mad Dog 2 is a good example where we said the project breaks even at sub $50.
I think that should give you some comfort on what we're looking for also go forward, that's what we're looking at now on the Trion as well. We've used some data points and 60 and 80, that does not necessarily correspond with our ranges. I guess in historic, the Mad Dog 2 example can give you some idea on what we're looking for. The first question?
Yes, I can take the first question. For our spend is probably around $700 million given year. What that covers, as you have seen, we have opportunities in the pipeline that will mature through the next three years through drilling and further seismic data. Also we're looking to other opportunities for the portfolio. Saying that, the spend is not guaranteed. Each of the opportunity that we currently have on the portfolio has to compete for capital within the BHP portfolio. If it doesn't compete for capital, we will not progress those, and we'll bring forward only those opportunity that are really strong on time of returns. Yes, the budget is around that number, but it can go up and down.
Per annum.
Yeah, per annum.
Yep.
Yes, Tim Gerrard from Janus Henderson. I was just wondering with regard to your exploration priorities, you're very heavy offshore Gulf of Mexico and up and down the coast there of the Americas. How do you feel about deepwater opportunities elsewhere? What kind of, I guess you would see deepwater as being a natural competitive advantage. I'm a bit surprised you're not outside of that area. Thank you.
From a deepwater exploration point of view, we look from a global point of view where the resources are, and we look for material opportunities where we can expand ourselves, so we can get a large position. Where those are could be in different parts around the globe. Could be in other areas compared where we are today, and so we are evaluating those as well. Saying that, again, they have to compete for capital. They have to be larger, material, high quality, that we can expand through times.
Just to build slightly. I think it's fair to say that we do look globally. What you see are the opportunities that have been high graded over the past couple of years. I think as Sonia shared during her presentation, we're also doing what we call the global endowment study to inform where we see future opportunities and whether it's the below-ground risk or the above ground risk in fiscal terms and jurisdiction that informs our appetite as to the competitiveness of those opportunities.
Hi, Edward Sterck, BMO. Just looking at the pipeline of projects here, there's potentially quite a few coming on at the same time. Can you just comment a bit on the capacity within BHP to take on so many projects at the same time? Then also, can you comment on inflation or otherwise in contractor rates and so on in the oil and gas industry? Thank you.
In terms of our capacity to take on the projects, Trion is operated, Wildlings operated, Trinidad North is operated, and the others are a little bit out in time, Western GOM, depending on what we find there. We have been preparing for this. This hasn't all come upon us in the very recent past. Whether it's the retention of experienced staff that were deployed to shale and come back over to conventional, whether it's some of our folks seconded into some of our big minerals projects, Spence Growth Option, South Flank, and so forth, desal in Escondida. We leverage the experiences in those projects. We have what's a separate group controlling the Project Center of Excellence, that governance support standards. We've also maintained relationships and partnerships with the service providers in advancing our engineering standards.
Suffice to say, we're where we expected to be today, and we've built up our capacity, whether it's from internal sources or external. In terms of, can you repeat your second question, if you don't mind?
It was just on inflation rather than contracts base.
Maybe.
Yeah.
You were going to. Yeah.
I think, we're just off the low on offshore cost inflation, but not that far off. I think it's still a good part of the cycle, and that's why we haven't seen dramatic cost escalation, as of yet.
Another question.
Thank you. David Walker from Clime Asset Management. You've spoken about the framework for evaluating projects. Could you give us some examples of conventional oil projects that BHP has rejected or downgraded in recent years?
That's a good question. I'm going to ask Sonia, actually, to share some on the exploration side, which, yeah, Beagle.
Yeah. One example that we tested in the last couple of years, we had a position on the Beagle Sub-basin in North Australia, and we had two large blocks, and CNOOC was our partner. What we did there, we did have commitments for potential drilling. We did acquire 3D seismic data and evaluated the area. After the technical evaluation, we did not see the potential we were expecting going in, and also the risk profile was too high, so we actually turned that down. We did not move it forward. There are other examples that I can share later.
To summarize, probably another very recent example, where a nice discovery north of Shenzi in the Miocene, we understand the basin well. Ultimately it was not material enough to compete in our portfolio. A more natural owner was found for that. We got our money back. We didn't take that forward for all the right reasons.
Yeah. Thanks, Ryan Kauppila from Putnam Investments. I think on Orphan, you said you're likely to farm that down pre-drill. Could you just discuss sort of high level the cost benefit analysis that you do in-house around why you're reticent to carry an exploration well at 100%?
That's a very good question. In that case, for the Orphan Basin, there are a few reasons why we'll probably look to bring in partnership, is a large position. There are multiple applied potentials. From a cost analysis, even bringing in partner, that's definitely not to reduce the upside and the value. On the other hand also, we leverage partnership to really better understand the subsurface, to test different scenarios and reduce on the overall risk. When we think about the Orphan Basin, it comes quite natural to bring in partner. We've done something similar in Trinidad and Tobago. We entered 100% on the southern licenses, and after we brought in BG, at the time, Shell today, to reduce some of our exposure, and similar on the northern licenses with BP. Something pretty common, and we will look into that for Eastern Canada as well.
The phone lines. I think we're going to take it from there now.
Thank you. Your next question from the phones comes from Lyndon Fagan from JP Morgan. Please ask your question, Lyndon.
Thanks a lot. Look, just going back to the CapEx situation. If I take the guidance of almost $4 billion a year over that period, even the period before that at $2.5 billion a year, it doesn't look like BHP is going to generate any positive free cash flow before FY 2025 from the division. I guess it feels a little bit like U.S. onshore, where we're chasing good IRRs, but for a period of positive free cash flow many years in the future. I'm just wondering if you could reflect on that and whether the division is actually living within its means with that level of investment. Thanks.
Thank you, Lyndon. A couple of points. As I spoke about the capital is managed at group level, is what I would say first, and it's not managed at the petroleum level. That reflects part of the strength of the portfolio in that we are able to invest counter-cyclically when we see the best value potential. The second point I'd reiterate is the flexibility we have in some of those opportunities to optimize, whether through phasing or equity. Finally, we don't have to play any of those levers. If they are the most attractive opportunities in the portfolio and we can demonstrate that, then they will command the capital. In terms of the cash flow generation piece, then we don't share the specific scenarios, but across the range of price outlooks over the medium term, they're incredibly resilient to commodity prices.
Notwithstanding the capital-intensive period as you call out.
Thanks.
Okay.
Tony Robson, Global Mining Research. Following up on Lyndon's questions. It wasn't a question, I should say. It wasn't so long ago, of course, you were pumping several billion dollars a year into U.S. shale. It seems to me like there's an acceleration at the moment because there's possibly a catch-up effect that the rest of the world, if you like, was on a hiatus in exploration development while U.S. shale was ongoing. Is that the truth, or you were saying, would you believe that these projects would have happened at this stage in any case? Thank you.
The projects in the portfolio today have, in large part, come about from the reset of the exploration strategy some five years ago, when we both recognized the potential for deepwater and the potential for such opportunities to be competitive. We stayed in the exploration game, in fact, when many left. That has allowed us to take advantage of lower cost of service and, in fact, bring forward the projects that we've talked about today. In terms of where we are today, in large part, you have to go back five years and recognize that it was our strategy of then that brought this forward. I think Scarborough was, for us, the outcome of a strategic partnership with Woodside and trying to get better connectivity and alignment with the big infrastructure player in the West. That's what's brought us to today.
In terms of the go forward, I think the nature of the projects that we talked about today are such that there's adequate history in our performance and in industry to demonstrate the robustness. Put that together with our governance, our capital allocation, there is no doubt that the strength of the investments across the range of outcomes is very well tested internally, and we shared some of that today. Yep.
Hi. Yub o Mao from Exane BNP Paribas. Just a quick couple of questions. First one on productivity gains. Where do you see the most potential for further improvement after the progress in recent years? Secondly, on the competition landscape in Gulf of Mexico, what's happened in the recent couple of years in term of capacity, cost curve, CapEx intensity, et cetera? Thank you.
In terms of productivity gains, that's an interesting one. We put our attention to where we see the biggest prize. For us, that's at the moment at the front end of the life cycle. Maybe we'll get Sonia to pick up on it and give you some examples there. Secondarily, it's in our project development. Where we leverage our project center of excellence and lessons from other projects throughout BHP. Picking up particularly on automation, digital technologies, and particularly the use of data through data science, and maybe there's one to pick up on there.
Yes. To add on that, especially on the usage of data science and artificial intelligence, we are progressing our global endowment study that really position ourselves from a global point of view of the yet to find. We are working together with our copper partners. The key element of that is really introducing some of the new technology and innovation that we've seen disrupting different type of industries and leveraging that to create a competitive advantage, and also position ourselves for a future access.
In the Gulf of Mexico, can I just clarify, were you talking about the service sector there?
Yeah.
As Michiel said, we see some movement in the market, particularly around subsea service providers and infrastructures as that has been a focus in the more recent years in terms of accessing fast development cycles. Still quite low. On the deepwater drilling market, I think we see slow movement.
Yeah.
Still very competitive.
Thank you. David from Kleinwort Hambros again. By how much would you say this year's world economic slowdown has reduced total world demand for oil?
I think when we started the year, our internal forecast, I think we had it at 1.5 million bbl a day. We're now kind of closing in on the one. I think we're slightly above one. Yeah. If you ask the analyst team today. Yeah. That's kind of broadly in line with what we've seen other analysts say. I think people are putting it now around one. I think we are still at 1.2. A couple of hundred thousand bbl.
What kind of baseline growth do you see in looking out into the future?
Yeah. If you look for the next 10 years, we assume roughly around 1 million bbl demand per day, a year growth in our central case. Yeah. As I laid out the different case, we have the different cases, like we're in the low case, we see peak in 2025, but in central case, you have another 1 million bbl growth for the next decade, a year.
Thank you. Global bond yields have risen a little bit just lately. If world bond yields have now bottomed and may be trending a bit higher, how does that affect your cost of capital and decisions about whether rates of return on projects are high enough?
You want to comment?
I think it's our cost of capital. We test that through the scenario analysis pretty regularly. We're satisfied with where we are today. I think the ranging work kind of protects us kind of across the range of outcomes there and supports resilient investments. It's something that it's done independently of the asset team. It's done by the finance and strategy team, on a very regular basis.
Paul McTaggart from Citi. T&T North is a meaningful chunk of the valuation uplift and the potential for the business. We don't have a lot of parameters to think about in terms of scale, potential kind of OpEx CapEx, how it might look and feel. Obviously, in coming to those numbers, you've thought about plenty of that.
Would you care to share?
Some of that with us?
Sure. I think some of this is in the pack, Paul. In terms of the scale we've talked about, what we've modeled based on that resource is a 1.5 BCF a day facility. We have assumed it's somewhat analogous to Scarborough. In terms of we don't share our capital estimates at this point in time, but it's analogous to a Scarborough type development concept and cost, recognizing we're early in the stage there. Then it's a subsea integrated development, and we assume at this point, for the purposes of the illustration, that we tie into shallow water infrastructure that allows access into ultimately the domestic market and the LNG market.
Pricing.
Pricing.
Which energy? Product pricing.
We wouldn't be talking about that.
We talk about the domestic market and the LNG market, and I think Michiel's probably shared our outlook.
Yes.
Yeah.
Yes. Tim Gerrard from Janus Henderson. Look, you've given us some good insights into what the business might look like in five or six years, and then ongoing from that. I dare say you do a lot of scenario analysis. I'm just wondering if the time comes when BHP does commit to Jansen, there might be more pressure on fossil fuels and the cost of carbon. You've got your production profile in place and the strength of the petroleum in place.
If BHP were to spin you out, how would you think the way in which you manage your business would change, either in terms of the exploration spend you could afford, the risks that you'd be willing to take in deep water, et cetera? When you do your scenario analysis and have a think about how you would manage a single company, what kind of thoughts come to mind?
I'll start maybe. A lot of it still comes back to our outlook on the demand side and indeed on the supply side, and the range of outcomes that we see there. Beyond the current portfolio, we recognize the inherent uncertainty, both from a demand destruction on the oil side, but also demand growth. The commodity attractiveness piece still is the integral part of what drives that. I think we would continue to monitor the yet to find volume, the exploration success, and the inducement curve to inform the scale and the attractiveness of the opportunities, which would in large part come from the exploration of today. If that answers your question, I'm not sure I properly understood it.
Well, I was sort of wondering how you would manage the company differently without having a large company to support you.
Okay, that's a very different question. We are within the BHP portfolio. We believe that we benefit from that, and we contribute into that. We're integral to the strategy of BHP, and that's where we see petroleum generating most value and most return. That's what I'd say on that.
Hi, Edward Sterck. Just going to Eastern Canada, it's obviously quite a long data project. Maybe this will be less of an issue by the time a development decision is made, I think I'm correct in saying that area is also known as Iceberg Alley. How do you mitigate those risks if that is the case, what does it look like from a production perspective?
I can take it too.
Yeah. When we entered Canada, we did evaluate the different development scenarios and also consider the iceberg situation. There are ongoing development and production, so there are facilities that can handle and enable that. The iceberg are monitored. We know when they're coming. The course can be sort of moved. There is quite a lot in place that can help to mitigate that. As we will come with the development scenario, we will take in consideration all of those scenarios as well.
Hi. David Radclyffe from Global Mining Research. Just coming back to your chart of the unconstrained scenario and where production could go. Could you actually talk to the production mix there? Obviously, you talk to preferring oil. Can you actually grow the oil as a percentage of that production mix?
We do grow it out into the middle of 2020s. We go from some 39% today out to 45%. Beyond that, we do have a lot of gas, as you would have seen in the portfolio. Can we grow it? Yes. The GOM assets have a lot of embedded growth options. That's what makes them so attractive, the heartland concept. Trion, of course, is coming into the portfolio, and we continue to explore. We'll be exploring around Trion. The Western GOM is an oil play. Eastern Canada is an oil play. We are also testing in Southern licenses in Trinidad. Beyond that, whether it's continued exploration or acquisition, it's in pursuit of oil assets because we believe they're more competitive and ultimately can generate more returns. I think that answers your question.
One more question.
Ben Goodwin, Merlon Capital. Just wondering what sort of work you've done on U.S. onshore, I mean, that's been the biggest driver of supply over the last five to 10 years?
What's your sort of outlook for that underpinning your forecast for oil?
Yeah. Thanks for the question. Yeah, as I laid out today, I think we see it coming into a much more mature stage of development now. When you look at it, a couple of years ago we had, on a liquids basis, like I think two years ago, 2 million bbl at it. This year it'll be a bit over 1 million. For next year, we see around 1 million bbl at it. Where is the growth coming from? It's predominantly Permian. I think it's 75% or 80% of the onshore growth is going to come out of Permian. The other basins might have a little bit of growth, but Permian is where the growth is. On the total crude oil basis, we see it peak at around 16 million bbl. On a liquids basis, that would be 22 million bbl, and that's in the mid-2020s.
Somewhat growth, but much lower. Then plateauing and then starting to ease off beyond that. Permian is real the growth factor. If you think about cost-wise, I think Permian cost at the moment, core Permian is anywhere between, I think, $30- $50. Then you start moving out of the core to more the fringes, which there is a wide cost curve attached to that.
I think we're out of time, and welcome you to join us for refreshments after this. Thank you very much to those who joined us on the phone lines and on the webcast, and indeed to you here.