Woodside Energy Group Ltd (WDS) 2021 Q4 法說會逐字稿

Good day, and thank you for standing by. Welcome to the Woodside Petroleum Limited Full Year 2021 Results Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions) I would now like to hand the conference over to your speaker today, Mr. Meg O'Neill, CEO and Managing Director. Thank you. Please go ahead.

Good morning, everyone, and thank you for joining us for our 2021 full year results.

I would like to begin by acknowledging the traditional custodians of the land from which we are presenting today, the Noongar Whadjuk people, and pay my respects to their elders past, present and emerging. I also extend my respect to all other aboriginal nations, the future generations and their continued connection to country.

As you would have seen this morning, we released our annual report and full year results briefing pack to the ASX, along with our sustainable development report and our climate report.

I'd like to welcome our new Chief Financial Officer, Graham Tiver, who is on the call today. Graham started with us on the first of February, joining us from BHP, where he previously held the results of Group Financial Controller with responsibility for BHP's global accounting and reporting function and for financial improvement. Together, Graham and I will provide an overview of our 2021 financial, operational and strategic performance before opening up the call to a Q&A session.

Please note the disclaimer on Slide 2, advising that this presentation does include some forward-looking statements and that our reported numbers are all in U.S. dollars.

On Slide 3, 2021 has been a transformative year for Woodside. On nearly every metric, this is our best financial performance since 2014. And strategically, it is perhaps our most significant year on record. We have taken several strategic decisions, which position Woodside for a bright future. We agreed the merger with BHP's Petroleum business, took final investment decision on Scarborough and Pluto Train 2, agreed to sell down Pluto Train 2 and announced the target to invest $5 billion in new energy products and lower carbon services by 2030.

We have been able to capitalize on the strong rebound in market conditions, and our financial results reflect this. We reported a net profit after tax of $1.98 billion and an underlying NPAT of $1.62 billion. The Directors have declared a full year total fully franked dividend of USD 1.35 per share, representing an 80% payout ratio of underlying NPAT.

Moving to Slide 4. We have delivered solid operational performance and been able to capture the benefit of improved market conditions. We achieved a very healthy average portfolio realized price of $60.30 per barrel of oil equivalent, underpinned by the significant increase in oil and gas prices through the year and increased trading activity to capture incremental benefits. Our strong operating revenue of just under $7 billion is almost double what we have in 2020. The higher operating revenue has resulted in a large increase in free cash flow to $851 million, up 424% from 2020.

This is a great result considering our major project expenditure of approximately $2.3 billion, which includes the FID payments made for Scarborough. You'll recall that we define free cash flow as cash flow from operating activities less cash flow from investing activities, including all major capital expenditure.

Our production was 91.1 million barrels of oil equivalent, down from the record production we achieved in 2020. Production was impacted by adverse weather events, natural field decline and increased planned maintenance.

On our facilities, we continue to maintain strong LNG reliability. The Pyxis Hub and Julimar-Brunello Phase 2 projects, which provide additional gas to Pluto and Wheatstone, respectively, were both delivered ahead of schedule and under budget. Our focus on cost is paying off at the Northwest shelf, where we achieved a 14% reduction in underlying operating cost.

I'd like to address our health and safety performance on Slide 5. While we had 0 Tier 1 or Tier 2 process safety events, we have seen a disappointing increase in personal injury rates in 2021, with our total recordable injury rate increasing to 1.74 per million work hours. We have had some challenges as a result of COVID-19, which have resulted in disruptions to workforce continuity and capability. One of our priorities for 2022 is to return to leading personal safety performance.

On Slide 6, you will see the impact of the significant increase in oil and gas prices throughout 2021. Using proactive portfolio optimization, including weighting our LNG spot exposure to the first and fourth quarters to align with the Northern Hemisphere winter, we have been able to capture the favorable market conditions and deliver an annual average realized price of $60.30 per barrel of oil equivalent, the highest we've seen in 7 years.

The table in the bottom left-hand corner shows the increases in realized prices for our products from 2020 to 2021. Oil prices continued to climb in 2022. And this week, Brent touched $96 per barrel.

We look at a range of different published energy demand forecasts to help inform our investment decisions, and it's clear that demand for our primary products will remain strong for decades. Significant investment is required to ensure the world has access to reliable and affordable energy through the energy transition. The current high prices for oil and LNG gives confidence as we increase our investments in future production.

Moving to Slide 7 and the merger, one of the key strategic achievements of 2021. The proposed merger with BHP's Petroleum business is transformative, and this slide explains the key reasons for this. The merger will deliver increased scale, diversity and resilience to better navigate the energy transition and provide the financial strength to fund plant developments in the near term, investment in future energy opportunities and return value to shareholders through the cycle. Completion of the merger is targeted for early June following a shareholder vote, which is planned to be held together with our 2022 Annual General Meeting on the 19th of May.

On to Slide 8. And as I observed at our investor update in December, we understand environmental, social and governance performance is integral to our success. A responsible ESG mindset is core to a high-performing culture and is part of our strategic framework. ESG covers a broad range of topics, and I'd like to highlight a few of our activities in 2021.

Under environmental, we continued support for the Burrup air monitoring program and we've worked with customers to sell carbon offset cargoes, demonstrating how we're helping our customers meet their emission reduction goals.

Under social, we launched a new 5-year social investment strategy and invested AUD 20.3 million in the community in 2021.

And under governance, we released our working respectfully policy, confirming our shared commitment to a safe, inclusive and respectful working environment. Our sustainable development report, which we released today, provides detailed information on Woodside's sustainability approach and achievements.

Moving to Slide 9. In 2021, we articulated our plan for a lower carbon future. Our strategy is twofold. First, we will reduce our net equity Scope 1 and 2 greenhouse gas emissions; and second, we will invest in the products and services our customers need as they decarbonize. We are targeting a reduction in net equity Scope 1 and 2 greenhouse gas emissions by 15% by 2025 and 30% by 2030 towards a net zero aspiration by 2050 or sooner. We can achieve these targets in 3 ways: by avoiding emissions through design of our facilities, reducing emissions through operational practices and improvements and by offsetting for the remainder.

In 2021, we achieved a 10% reduction on our 2016 to 2020 gross annual average emissions, and we are on track to deliver -- we are on track to achieve our 2025 target of a 15% reduction. To help build and support a market for the products and services needed by our customers, we have set a target to invest $5 billion in new energy products and lower carbon services by 2030. We have several new energy opportunities, which we are progressing in support of this goal.

In summary, Slide 10 outlines our strategy to thrive through the energy transition by developing a low-cost, lower carbon, profitable, resilient and diversified portfolio. 2021 has been a strong year financially, and we have made a number of key strategic decisions to set us on a path to delivering ongoing shareholder value.

Graham will now take you through the financial update in closer detail.

Thank you, Meg, and good morning, everyone. Before I begin, I'd like to say how excited I am to join Woodside at this pivotal time, and I look forward to meeting many of you over the coming weeks.

Let me kick off with Slide 12, which speaks to our strong business fundamentals. A feature of the macroeconomic environment in 2021 was the strong recovery of oil and gas prices, underpinning our operating revenue and our annual average realized price of $60.30 per barrel of oil equivalent. We recorded very strong free cash flow of $851 million, even with the increased major project expenditure on Scarborough, Pluto Train 2 and Sangomar. Meg announced the new capital allocation framework at the 2021 investor update in December, reiterating our commitment to disciplined capital allocation, which is something I'm very passionate about. We also agreed the sell-down of a 49% share of Pluto Train 2 to Global Infrastructure Partners, and we will continue to review the appropriate participating interest for our other assets.

Woodside has spent the past few years preparing and protecting its strong balance sheet ready for growth, and we are well primed to deliver. Our liquidity is over $6 billion. Our gearing of 21.9% is at the lower end of the target range of 15% to 35%. And the additional capital contribution of approximately $822 million from GIP for Pluto Train 2 further supports our upcoming period of increased investment.

Moving to Slide 13, give us an overview of our key financial outcomes. There are a lot of green arrows on this chart, which indicate the improved environment in 2021. I'll speak about the majority of these metrics later, but the key takeaways are that we captured the benefits of higher oil and gas prices. We delivered our highest profit since 2014. We were cash flow -- free cash flow positive. Our liquidity remains strong, and we're investing in our future in a disciplined manner. The Directors have declared a full year fully franked dividend of USD 1.35 per share, an increase of 255% from 2021. We understand how much our eligible shareholders value distribution of our significant franking credit balance.

On to Slide 14. Our production was 91.1 million barrels of oil equivalent, down from the record high of 2020. The key factors impacting 2021 production were natural field decline, the expiry of North West Shelf joint venture domestic gas contract obligations, planned turnaround activity on the North West Shelf project and also Wheatstone and adverse weather events in the first half of 2021. We are expecting higher production this year of 92 million to 98 million barrels of oil equivalent as set out in our production guidance, which is repeated on Slide 24. Our sales volumes, on the other hand, increased, primarily due to a full year of Corpus Christi offtake and the significantly higher level of trading activity for third-party LNG cargoes. And I'll speak to this later on.

Slide 15 shows the flow of operating revenue, EBITDA and underlying NPAT. All 3 are the strongest we've seen since 2014, with underlying NPAT up 262% from 2020. These results demonstrate the value of our high-margin, low-cost operations and the ability to convert revenue into shareholder value.

On Slide 16, we present a more detailed breakdown of our net profit after tax, showing the variance from 2020 to '21. We've mentioned a few times the impact of pricing and increased trading activity on our results. And this shows sales revenue increased by nearly $3.2 billion. We also have higher revenue due to sales volumes as a result of increased trading activity and the Corpus Christi volumes.

In January, we announced our impairment reversals of over $1 billion on Pluto and North West Shelf gas. These noncash impairment reversals were due to the increased combined value of Pluto and Scarborough associated with the Scarborough and Pluto Train 2 final investment decision. Also, we updated Northwest shelf cost and production profiles, as well as the impact of pricing.

Trading costs increased in line with our higher trading activity, and taxes increased as a result of higher revenue and impairment reversals. All these factors have contributed to a 2021 reported NPAT of $1.983 billion. The chart shows how reported NPAT has been adjusted for the one-offs to realize an underlying NPAT of $1.62 billion.

Moving to Slide 17, and this speaks to the resilience of our free cash flow, which incorporates all major expenditure -- capital expenditure. The key takeaway from this slide is that we are investing in Woodside's future by increasing investment in Scarborough, Pluto Train 2 and Sangomar and doing so within our means. The improved market conditions are highly supportive, and importantly, our balance sheet is strong.

The resilience of our free cash flow is highlighted on Slide 18, which provides a breakdown of how our cash balance has moved over the last 12 months. The strong cash generated from our operations has supported our major investments and also the repayment of a $700 million bond in '21. We are on a solid financial -- we are in a solid financial position, actively managing our balance sheet while investing in our future.

Moving to Slide 19 and some detail on our margins. Gross margin has returned to a pre-COVID level of 45% as a result of higher realized prices, and importantly, good cost control. Our cash margin is strong, above 80%, and the graph on the right demonstrates the contribution of our producing assets to our strong cash margin.

Slide 20 talks about balance sheet strength. Net debt is down to $3.8 billion, and our gearing is at the lower end of the target range. The declared full dividend of USD 0.35 per share is at the high end of the Board's target of 50% to 80% payout ratio of underlying NPAT, a target that was reaffirmed by the Board last year.

Further to this, on Slide 21, I'd like to talk about how we are managing our debt and liquidity. Our balance sheet is characterized by a well-managed debt maturity profile and our liquidity remains over $6 billion. We continue to manage our near-term debt maturities and maintain a low cost of debt. Importantly, we have minimal drawn debt maturing in the next few years as we invest in Scarborough, Pluto Train 2 and Sangomar. During 2021, our credit ratings were reaffirmed, and we continue to maintain our strong liquidity cover of 12 to 18 months.

Slide 22 summarizes how we have adjusted our marketing strategy in 2021 in response to market conditions to capture value. Our trading activities increased significantly. Trading is opportunistic and enables us to extract additional value from flexibilities within Woodside's contract portfolio. In 2021, we had 21 third-party traded cargoes compared to 2 in 2020. We're expecting trading to be at similar levels in '22 compared to 2021.

The purchase cost of Corpus Christi volumes is part of our reported trading costs. Corpus Christi is expected to be cash flow positive in 2022 post hedging impact, and the volumes provide exposure to the Atlantic Basin and enables further optimization.

Moving to Slide 23 and the trading outlook. We've previously provided spot exposure guidance. However, our contract portfolio is evolving with the market, and our contracted cargo pricing is linked to a range of pricing indices, including gas hubs, such as JKM, TTF and NBP. In 2022 and going forward, we will provide guidance on our overall gas hub exposure to provide a clear indication of our revenue exposure to gas hub pricing, some of which we realize through term contracts.

Gas Hub exposure is the proportion of our produced equity LNG volumes expected to be sold on gas hub indices, excluding Henry Hub. And this year, it's expected to be 20% to 25% of produced volumes.

I'd also like to talk to the presentation of trading activities in our financial statements, in particular, the segment note. Trading revenue is included in the LNG revenue and presented at the average portfolio LNG realized price, and that aligns with our LNG portfolio strategy, while trading costs are presented at the actual price the third-party cargo is purchased.

Slide 24 provides a summary of our 2022 guidance, which is a Woodside-only view and it excludes the impact of the proposed merger and any subsequent sell-downs. As disclosed in our fourth quarter report, our full year 2022 production guidance is 92 million to 98 million barrels of oil equivalent, and our investment expenditure guidance is $3.8 billion to $4.2 billion, noting this excludes the benefits of the additional contribution from Global Infrastructure Partners for Pluto Train 2 of approximately $822 million.

I'll now hand back over to Meg.

Thanks, Graham. Before we move to questions, I'd like to give an overview of our project performance and discuss our 2022 priorities.

Slide 26 provides an update on how we are progressing with Scarborough and Pluto Train 2 since we took FID 3 months ago. The FID resulted in an increase to our 2P total reserves by over 1.4 billion barrels of oil equivalent. We have since completed the sell-down of a 49% stake in the Pluto Train 2 joint venture to Global Infrastructure Partners, and we have issued full notice to proceed to key contractors to commence construction activities.

Scarborough is, in our opinion, a world-class project with an expected internal rate of return of greater than 13.5% and a globally competitive cost of supply of approximately $5.80 per MMBtu. We expect net cash flow of approximately $26 billion over the field life. 90% of the total development contractor spend is lump sum or on a provisional sum basis, effectively shielding the project from inflationary pressure.

On Slide 27, our Sangomar project is progressing well and on track for first oil next year. We have successfully drilled and completed the first production well in Senegal and a second drillship is expected to arrive this year to support the drilling campaign. FPSO conversion activities are progressing, and the subsea installation campaign is expected to commence early this year.

Slide 28 provides an update on our other projects in Western Australia. We have made really pleasing progress across the board. Construction was completed for the Pluto to KGP Interconnector pipeline in the fourth quarter of 2021, commissioning activities are underway and startup is targeted for later this quarter. Both Pyxis Hub and Julimar-Brunello Phase 2 achieved startup last year, ahead of schedule and under budget. Greater Western Flank Phase 3, which will provide backfill to the North West Shelf, is targeting first production this year.

Moving on to our 2022 priorities. Slide 30 outlines the time line to our targeted completion of the merger. We are pursuing secondary listings on the New York and London Stock Exchanges. We expect to provide supporting materials to the market in April, ahead of the shareholder vote plans to be held together with our 2022 Annual General Meeting on the 19th of May. Following the shareholder vote, completion is targeted in early June.

On Slide 31, I was delighted earlier this week to announce the nominees for our executive leadership team to lead the business after completion of the merger. We have said all along that the combined organization would bring together the best of Woodside and BHP Petroleum. This team has the capability and deep experience to deliver long-term success for Woodside. A reminder that these nominations will only become effective if and when the merger completes.

Finally, on Slide 32, our priorities for 2022 are very clear. Our operational priorities are to maintain reliable and efficient operations and return to leading personal safety performance. Our strategic priorities are to complete the merger with BHP's Petroleum business and deliver the $400 million-plus in synergies and to advance the project execution of Scarborough, Pluto Train 2 and Sangomar. Our sustainability priorities are to achieve the new energy project milestones we have set for ourselves and to deliver our 2022 emissions reduction targets.

2021 was a game changer for Woodside as we made transformative decisions for our future. 2022 will be just as exciting as we implement these decisions and become a larger, more significant company.

We will now move to the Q&A session.

(Operator Instructions) Your first question comes from Dale Koenders from Barrenjoey.

Just a question on your LNG trading. Should we be considering -- I guess, how should we consider hedging, both in terms of volumes, fixed versus floating, for this 20% to 25% hub exposure in Corpus Christi through '22?

Yes, thanks, Dale, that's -- sorry, say that again, Dale?

Or is there no hedging at all?

Yes, Dale, just to, I guess, be clear. So the gas hub pricing exposure refers to the percentage of our produced LNG that is exposed to being sold on those indices, JKM, TTF or U.K. NBP.

So Corpus Christi, much of our hedging is focused on our Corpus Christi volumes to reduce the price risk associated with that offtake agreement. Does that answer your question, Dale?

Yes, I think it does. Just a follow-on question then is, 20% to 25% of the 71 to 74 MMBoe of production, which equals about 100 million in MMBtu, if that's exposed to hub pricing, which flat forward pricing for '22 this morning, it's about USD 22 in MMBtu. In simplicity, call it, USD 10 MMBtu above contractual pricing. And this is implying more than $1 billion per annum of incremental EBITDA versus if you'd contracted the portfolio at legacy pricing. Is there any reason why you won't realize that going forward? Or is that the right way to think about it?

And so your quick back of the envelope math there, Dale, we'll need to check. I think it's important just to be really crisp that the gas hub exposure is on our produced LNG. So our total production guidance range, of course, includes oil production as well. So I think we'll need to follow up with you on the math there.

But I'll go back and reiterate that the gas hub pricing exposure is in that 20% to 25% range, again, associated with our produced LNG.

Okay. And then just finally, the comment around special dividends and the slide, how it's ordered, is that prioritizing special dividends over buybacks? Or is the implication you're seeing the stock expensive?

No, it's a great question, Dale. So when we spoke to the market in December, one of the things we wanted to articulate with that slide was that we will be looking at a variety of tools in our tool kits on ways we can return value to shareholders. So obviously, our dividend policy has been and remains a 50% payout of underlying net profit after tax. We have historically been paying out closer to 80%. But what we wanted to articulate with that chart, Dale, was that we do have other tools in the tool kit, and we will look at those, particularly post-merger when we have a bigger and more diversified shareholder base.

And there'll be shareholders who will value buybacks. There will be shareholders who will value the dividend. And of course, it's worth emphasizing the franking credits that come with our dividend today, and we know how valuable that is for our Australian investor base. But the purpose of that slide is to really illustrate that we do have greater flexibility in the tools we'll use to return value to shareholders.

Your next question comes from James Redfern from Bank of America.

Two questions, please. The first one, maybe a follow-on from Dale's question. I just wanted to understand this new sort of concept that you've got there. Just -- so the 20% to 25% exposed to those market indices relates to produced LNG from the Australian LNG projects. And then the trading revenues and earnings from Corpus Christi is separate. Is that right?

Yes, that's correct, James. So the gas hub exposure is, as it relates to our produced volumes, so those are the volumes that we operate, so those are the Australian projects. And it may be worth just elaborating a bit as to why we've made this change. One of the things that we've seen over time is that some of our customers are preferring to link their purchases to these indices for longer-term deals. And we felt like with the use of spot, the spot language refers to a single cargo sale.

So previously, we might have missed, for example, if we had a term contract that was linked to a gas hub index or if we had a spot sale that was on Brent linkage, for example, it might have been confusing to the market. So we think this language around gas hub exposure really does provide more insight as to how much of our production goes against those gas hubs and how much of our production goes against oil indexation?

Yes. So I mean, like, essentially the spot exposure, sorry to use that word, it has increased from 10% to 15% to 20% to 25%. Even if we're not talking about the spot cargo. We're still talking about effectively spot price indices, whether that be JKM or TTF, is trading at $22 per MMBtu. So it's almost the same thing though, isn't it? Is that right?

Yes. It's just, I think, it helps the market understand more clearly because the reality is we do have some term deals now that are sold on those gas spot prices.

Okay. Understood. I got one more, please. BHP have indicated that the Trion oil project in the Gulf of Mexico is going to be FID-ready by the middle of this calendar year. Obviously, the merger with BHP Petroleum hasn't completed yet. But just sort of wondering if you have sort of initial thoughts or comments that you can make around the Trion oil project, which we can assume should be FID in the second half of this calendar year. So just interested in any comments you can provide, please?

Yes. Thanks, James. So I guess, a few observations. First off, of course, until the merger is complete, ourselves and BHP Petroleum are operating as 2 independent businesses. But of course, they have taken the Trion project into the FEED stage and are working towards that milestone of being ready for an investment decision.

Look, it's a very significant asset, a very big resource. BHP has done a great job in building a strong working relationship with the Mexican government and with PEMEX as the partner. But that's one of the kind of first tasks for us as the merger completes is to really understand the quality of the asset, understand the investment metrics, understand how it stacks up with the other opportunities that we have. So it would be premature to conclude as to how that will go, but we'll be looking at it with the -- through the lens of the capital allocation framework that we talked about in December.

Your next question comes from Mark Samter from MST.

Meg, just a quick question, if I can, on the Sangomar sales process. I guess your own process has been going on 7 or 8 months now and, I guess, there were 2 data rooms open for probably 18 months before that. I would have thought anyone who's going to take a look at Sangomar would have taken a look already. Can you give us an update on how that's progressing and if your appetite exists to keep 82% rather than potentially have to settle down a value well below what you think it's worth?

Yes. Thanks, Mark. That's a great question. So as you know, the process -- the sale process has been underway for a period of time. Look, I think it's important to think of the sale process in context. And when we look at the strength of our balance sheet, we look at the strength of our financials, it's clear we don't need to sell down Sangomar. And so the guidance that we've given the team is we need to be looking for 2 things. We need to be looking for a quality partner at the right price, and we will not be schedule-driven on the sell-down. And so we continue to hold that bar at a high level. We want to make sure we get value that's accretive for our shareholders. And we want to make sure we bring in the right partner because we'll be having -- we'll be working with those -- that partner or partners over a very long time period. So we'll be patient and make sure we are taking the right decision when it comes to preserving value for Woodside shareholders.

Got it. And does that mean -- obviously, you've got the luxury of a strong balance sheet and a strengthening balance sheet post merger of having time on your side? But does that also mainly towards thinking any thoughts on capital management, particularly if you hold higher equity in these projects rather than giving away value for the sake of deleveraging that you don't need to do it that probably pushes back thoughts on that excess capital management if you do hold higher equity for longer or for the duration of these projects?

It's a great question, Mark, and we look at all of those dimensions. So Sangomar, of course, with first oil expected next year, when we start producing, it's going to add a very attractive revenue stream. So we need to make sure that if we were to progress the sell-down that it would be value accretive. Obviously, in today's oil prices, near-term oil volumes are more attractive in the marketplace.

But I'll go back to the key point, which is we need to make sure we bring in the right partner for the right price. And we're not going to be rushed because, again, we do have the strength of the balance sheet to continue to carry the investment at 82%. And if that means we get revenue at 82%, that's not a bad outcome.

Yes. And then just one more quick question, if I can as well. But just the mindset for Woodside, not just my view, but I would argue Woodside's business that historically has arguably chased production growth at the cost of value in the past. And when you look at the BHP portfolio, obviously, BHP had a great result. Like it was the other day, but certainly, 60-ish percent of production currently is in rapidly declining assets in the North West Shelf and give somebody some -- does Woodside look at those assets and assuming it holds them and feel the need to replace that production? Or do you think we see the Woodside that's happy to see production go backwards and run the business more for cash?

Mark, maybe the best way to answer that is to refer back again to the capital framework that we talked about in December. So we want to make sure that we are disciplined in our investment decision-making. We want to ensure that we protect the balance sheet. We've set out the target ranges for gearing and liquidity. So we want to make sure we are, first and foremost, a financially sound company.

Now where we do have opportunities to invest in a way that meets those investment criteria for each of the sorts of commodities we might pursue, be it oil or gas or new energy, we'll want to be able to invest in the business and invest in business growth. But I think capital management and fiscal discipline will be a very important factor for us.

Your next question comes from Saul Kavonic from Credit Suisse.

Two questions, if I may. First one is just back on the merger. I was wondering if you have any updated views on the outlook for register flows and any overhang risk now post BHP unification and how you're thinking about that.

Yes, it's a great question, Saul. Obviously, we've been looking very closely at the register, the BHP register trying to understand who holds BHP today. With unification, that's changed the register a bit. So we continuously look to refine our flowback analysis. Of course, unification is still sort of propagating its way through the BHP register, but nothing has come to light that would change our view that we expect any selling will be balanced by new buying.

And a few reasons why we make that assertion. We think buying will be well supported by index funds that will adjust their weighting due to Woodside's increased presence in the sector and on the ASX. And we do see stronger international demand, particularly in the U.S., where I think we're going to be a very attractive alternative to many of the other players in our sector.

Understood. And just to confirm the secondary listings in the U.S.A. and London, what exactly is the time frame you're envisaging that will be up and trading by?

Yes, great question, Saul. So we're working through those filings as we speak. We expect those will go live upon completion.

Great. My second question is just back on the EU gas hub indices and the increased spot exposure there. Obviously, great for the time being with high spot pricing. I was just hoping you could give us some color on what's been the driver behind taking on this increased exposure into U.S. indices? Is this something that's happened recently? Or is this some contracts which have been put in place a number of years ago which are only kicking in now?

Yes, it's a great question, Saul. So look, it's probably been a more recent phenomenon. And as we look at the LNG market and how it's evolved over the last decade, what we've seen is, particularly as the U.S. industry has grown, buyers are looking to manage some of their price risk as well. And so we're seeing buyers who are interested in signing up for volumes that are linked to indices like JKM or TTF. So a bit of it is how the market has evolved over time. The reality is we're just seeing a lot of change. And I think there's a question in the marketplace around will gas structurally diverge from oil. We're seeing that today. We want to make sure we're positioned to take advantage of the upside that, that offers. And so that's part of what underpins our thinking as to why we've locked in some additional volumes at those gas hub prices.

Just a quick follow-up is the locking in of some of the European indices here, is that under term deal? So should we expect that to be kind of a material part of the leverage going forward? And just in terms of the pricing of that, should we just think about it similarly to the way we'll think about JKM and it's going to move like that? Or are there a formula in some of these indices, which could see significant premium or discount like TTF actually trade that?

Yes. So it's an interesting question, Saul. So one of the things that I think we've seen, particularly over the last year is an increased globalization of the LNG market. And the winter that -- or Northern Hemisphere winter that we're in currently, I think, is a great example of that, where we're at a point where Europe started the winter low on storage. That caused volumes to flow -- LNG volumes to flow into Europe. We're seeing linkages between TTF and JKM. They move relative to one another, depending on where gas are in terms of -- or where demand grows in one basin relative to the other basin.

So I think we are seeing some increased linkage between the 2 basins. And I think that, as an LNG producer, just creates a tremendous opportunity for us. So historically, we would have sold most of our volumes on a Brent-linked basis and really just had a pretty modest portion of our sales that were on these spot gas indices. But as we see the spot indices start to become more structurally linked, I think that does create more opportunity for us as a producer.

Apologies, I've probably phrased that badly. This is definitely the last one. Just the link to the European indices, should we expect that to continue in the years ahead and not just be a temporary kind of one-off phenomenon this year or next year?

No, I think we will see that structural linkage.

Your next question comes from Nik Burns from Jarden Australia.

Just a question around Pluto. Just trying to understand a bit more detail around how we should think around Pluto production from here. Facility is doing around 5 million tonnes at the moment, you've just flagged you've got the Pluto-KGP interconnect ready to start up at the end of this quarter. I understand that I think that runs for around 3 years, the agreement you have with North West Shelf, so that could increase output to 6.5 million tonnes, from my understanding. I just want to check on that number.

And then just post that 3-year period, how we should think about Pluto production? Does it go back to 3 million tonnes to accommodate Scarborough volumes? Or is there scope to bring additional volumes through the KGP and accelerate Pluto production further?

Thanks, Nik. That's a comprehensive question. Let me give you a few kind of fun facts and figures. The interconnector is sized to be able to handle about 5 million tonnes per annum. So it's a very large piece of pipe. What Pluto has contracted with North West Shelf is a 4-year agreement to process a total of 3 million tonnes over that time period.

On an annual basis, that works out to be a little bit less than 1 million tonnes per annum. But we are still going to be -- as we start flowing the Pluto gas through to the Karratha Gas Plant, I think we'll get some good learning experience early about what does it take and how much can KGP actually process of Pluto gas, just recognizing the composition of the gas coming from Pluto is quite different from the composition of the gas that North West Shelf processes today.

So the planning basis, just to be clear, 3 million tonnes over 4 years, and that starts up this year. So when we look forward to Pluto, we will see more Pluto production in 2022. When Scarborough comes online, you're absolutely right, we will curtail Pluto production to enable processing of Scarborough gas through Pluto Train 1. And we expect that when Scarborough starts up that we will curtail Pluto to about 3 million tonnes per annum so that we can process about 2 million tonnes of Scarborough gas through that Train 1.

Now you highlight future optimization potential. Obviously, there's lots of optionality that exists with the interconnector pipe in place, but the contract that's been agreed thus far with North West Shelf is for that 4-year period.

Got it. That's clear. And just on the reserves downgrade for your Wheatstone and Pluto fields late last year. Just can you talk about what the implications are for future CapEx there? Will you need to bring forward some further wells, et cetera? I think in the annual report, you have 750 million barrels of undeveloped 2P reserves booked in those 2 assets. Just trying to understand when we might need to see more -- when we might expect to see more capital coming through to develop those undeveloped reserves.

Okay. Let me answer it for the 2 fields separately. So for Wheatstone, when we -- if I go back to when we bought into the Wheatstone development, one of the things that characterizes the fields that we produce from, so those are the Julimar and Brunello fields, is it is multiple, call it, smaller individual gas reservoirs, and we always knew that we would have multiple phases of development.

So we started up producing from the Brunella reservoir. The second phase of developments from the Julimar fields just started up in 2021. We do have future phases expected, largely to go after more of those Julimar sands. So we're at the point now where we're working through what exactly the phasing looks like and what our investment plan looks like. So the team continues to do work to understand when exactly we need to take some of those additional backfill projects forward.

On Pluto, Pluto is a little bit of a different story. As you'll recall, with Pluto, we actually increased the proved reserves. We decreased the 2P with the reserve adjustment that we made. One of the things we did with the reserve update was took a hard look at some of the future investments that had initially been included in the development plan. And one of the outcomes is we'll actually spend less at Pluto. So one of the projects that we had originally anticipated for Pluto was a compressor project relatively late in life. And we don't expect to make that investment at this point in time. The gas associated with that uplift has been moved to contingent resource. So it's something we'll continue to test, but that is actually CapEx that we have taken out of the long-term development plan for Pluto.

Your next question comes from Gordon Ramsay from RBC Capital Markets.

Meg, I've raised this before, and I'm kind of coming back to it, and apologies. But I'm still trying to understand the outlook for North West Shelf marketable LNG output capacity going forward. And I know you've given indications that it will reduce significantly by 2030 and potentially, on my math anyway, the first 3 trains could shut in. Just -- and this is with third-party gas coming into the plant. Can you just give us a feel for where that all sits right now in terms of the outlook for the North West Shelf going forward?

Yes. That's a great question, Gordon. Obviously, North West Shelf is a very significant asset for us. We are at a point in time where we are now constrained offshore, which means the plants volume we produce is limited by what the reservoir can deliver, not what the plants can process. The teams did a great job last year of really adapting to that change in mindset and trying to find ways to continue to kind of get more gas out of the ground as quickly as we can.

But obviously, with the fields on decline, coming up with agreements to process other gas is extraordinarily important. You will recall in January 2021, we finalized the agreements with the state governments to allow us to process gas from Pluto and Waitsia through the Karratha Gas Plant. And we will start flowing that gas later this quarter from Pluto initially. And then we'll start processing gas from Waitsia in 2023.

So that helps for a period of time. But obviously, we are out looking for additional gas to process through the Karratha Gas Plant. The joint venture has set up a marketing entity, which is talking to kind of all-in sundry gas resource holders around the basin to explore opportunities for processing other gas or processing their gas.

But to maybe get to the point, Gordon, in our investor briefing in 2020, we signaled that 2024 notionally is when we would be shutting down the first train if we didn't have additional gas at that time.

I guess it's worth highlighting, we are also looking for self-help. So our Greater Western Flank 3 developments is a North West Shelf joint venture development to bring new gas into the plant. So we are taking all the steps that we can within the venture to try to keep as much gas going through as we can.

Meg, just to be clear. This is all about deliverability of gas into the plant. It's less about the age of the plant and the requirement for significant ongoing maintenance CapEx?

Yes, correct. I mean, we've been investing for several years on a variety of, call it, life extension projects in the Karratha Gas Plant to ensure that the plant is ready to process gas as gas is available.

Okay. And just lastly from me, coming back to the question other analysts have asked about the gas hub exposure guidance of 20% to 25%. You've mentioned different hub indices, JKM, TTF and U.K. National Balance Point, can you give us a feel for the mix of those? Is this like 90% JKM? Or is it just 2 variable going forward? And you did say there's interrelationships, and we get that because of the arbitrage and trading. But there are differences at times between these 3 hubs in terms of pricing. It'd be good for us to have some idea of the weighting, would be helpful.

Yes. Thanks, Gordon. Look, I don't think we'd want to or even be able to be that precise. Some of the contracts do have a clear link to one or the other. But some of it -- this also reflects what we would have historically called spot, which are volumes that are not yet sold today. And so I don't want to commit today as to what index those will be sold on.

Okay. Lastly, so if we look at, let's say, the Uniper contract that you signed, we could assume that's TTF pricing. That's not a bad assumption. Would that be right?

No, the Uniper deal we signed -- look, we haven't set what price indexation that is based on. That actually is a longer-term contract. I wouldn't try to draw any conclusions from that.

Your next question comes from Daniel Butcher from CLSA.

First question is just on your contracts you signed a while ago or MOUs for Scarborough and Pluto 2. Just curious about their status. And is the pricing on those set already? Or can that be renegotiated in the background of higher or tight LNG markets?

Sorry, Dan, just which MOUs are you referring to?

The various ones that's sort of associated with Scarborough and Pluto 2 that you've signed over the years.

Yes. Look, it's probably worth differentiating, Dan. So we signed firm sales agreements with a number of players. So Uniper is probably the most notable one. The Uniper contract had a condition precedent of Scarborough FID, which obviously, we ticked that box last year. And so that contract has now gone unconditional. So that's a firm contract. We have MOUs with a few other players that we signed probably back in 2019. Those kind of went into a bit of a slow point in COVID. But we're continuing to talk to a number of prospective buyers about additional Scarborough offtake. Obviously, with pricing where it is right now, we feel like conditions actually are pretty attractive for us as a seller.

As we communicated before we took the FID decision, we didn't want to rush into too many LNG term sales agreements at a point in time where pricing was soft. We felt like patience would allow us to get more value for Woodside shareholders. And it looks like that strategy is bearing fruit.

Okay. Just to summarize, except in part for the Uniper deal, which is unconditional, the rest of them are pretty much subject to where the slopes are moving right now for new contracts?

No. So look, Uniper's firm, of course. The Perdaman contract is firm. The Pertamina option is an option that remains firmly in our court. So that's a decision that we have the right to take, and we'll be looking very closely at that option. And then we have -- and then we have a term agreement with RWE as well, which is also firm.

Okay. And just curious, going to your hydrogen strategy unveiled a couple of months ago. You seem like you're in danger of being an early mover. I'm just sort of curious how you weigh up the advantages of being an early mover versus perhaps the risk of moving too early when the things are still coming down the cost curve. How do you sort of weigh out those risks? And is there a more capital light way of keeping your finger on the pulse of where new energy is moving without spending $5 billion just early in the pace?

Yes. Look, it's a great question, Dan. And obviously, there's a lot of interest in new energy. Thanks for calling us an early mover. I'm not sure that if you read the paper, you think a lot of people were doing a lot of work in this space. But the reality is for the new energy opportunities, we need to be customer led. And so a lot of the work that we're doing right now is to ensure that there is demand for the products that we are potentially going to be producing. And you'll have seen that we've signed a number of agreements -- MOUs, study agreements with partners like Marubeni, with Osaka Gas, with Keppel to look at opportunities to use products like ammonia or liquid hydrogen, either for power use or for ground transportation.

So then we're absolutely keenly focused on ensuring that any significant investment we make in new energy is one that is going to deliver a return that is acceptable to Woodside shareholders. And in our capital market update, we outlined what sort of return we expect to be acceptable. We said it's greater than 10%. But the challenge I've given the team is we really want to see early projects that are quite comfortably beating that target threshold.

Your next question comes from Tom Allen from UBS.

Most all questions have been answered, but I just have 1 outstanding on your emissions reduction strategy. So to meet your emissions reduction targets going forward, you've been clear that offsets are going to play a key role. I understand that Woodside have been pretty active in the forward market for ACCUs, Australian Carbon Credit Units, just to build a long exposure. But those prices are currently trading over AUD 50 a tonne. So can you just clarify how you can keep your carbon costs below your $20 a tonne target without buying the cheaper, lower-quality international [CERs]?

Yes. It's a really great question, Tom. Look, one of the things we've done, and we feel like we really did get out ahead of the game on the offset spaces. We want to make sure we have a diversified portfolio of offsets, maybe similar to the diversified portfolio of products that we want to sell. So we've gotten very active in origination. We have a number of projects that we are managing ourselves. We are also participating in the markets, both in the Australian market as well as the international markets.

Now as, of course, the focus on the quality of offsets has evolved, we are absolutely focused on making sure we are buying quality offsets that those are scientifically verified. We want to make sure that we are buying at an appropriate time, and you're spot on that the ACCU market right now is particularly hot. And similar to our strategy around LNG, this is not a time for us to be buying. So we're generating now, and we will continue to generate. But we want to make sure that when we are in the offset market, we are purchasing at a point in time where it is value accretive. And the team has been challenged to continue to deliver at very affordable prices. And thus far, they've been doing a fantastic job.

Sure. So I agree that there is -- the focus on quality is progressing quickly. Can you share maybe what proportion of your offset portfolio would likely be procured internationally?

No, it's probably premature to signal that, Tom. Obviously, for projects where we have a regulatory obligation to provide ACCUs, we obviously comply with those regulations. For our voluntary commitments, that's a space where we have the flexibility to use international offsets. But again, with the international and domestic offsets, we need to make sure that we are participating and purchasing offsets that meet our expectations around quality.

I would now like to hand the conference back to our presenters. Thank you, please continue.

All right. Well, thank you all for your questions. I'm looking forward to meeting with many of you over the coming weeks. We will keep you updated as we finalize the shareholder materials ahead of the vote on the merger. Thank you.