Good day, and thank you for standing by. Welcome to the Woodside Petroleum Limited Full Year 2021 Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference over to our speaker today, 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 role 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 US 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 decisions on Scarborough and Pluto Train Two, agreed to sell down Pluto Train Two, and announced a target to invest $5 billion in new energy products and lower carbon services by 2030.
We have been able to capitalize on the strong rebounds 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 $1.35 per share, representing an 80% payout ratio of underlying NPAT. Moving to slide four. 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 achieved 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 continued to maintain strong LNG reliability.
The Pyxis Hub and Julimar-Brunello Phase Two 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 North West Shelf, where we achieved a 14% reduction in underlying operating cost. I'd like to address our health and safety performance on slide five. 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 six, 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- 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 give us confidence as we increase our investment in future production. Moving to slide seven in 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 planned 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 eight.
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 Ambient 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 five-year social investment strategy and invested AUD 20.3 million in the community in 2021. Under governance, we released our Working Respectfully policy, confirming our shared commitment to a safe, inclusive. Moving to slide nine.
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. 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 three 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 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 a 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 interests 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%-35%. 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, gives 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. We're investing in our future in a disciplined manner. The directors have declared a full year, fully franked dividend of $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 92-98 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 a significantly higher level of trading activity for third-party LNG cargos. I'll speak to this later on. Slide 15 shows the flow of operating revenue, EBITDA and underlying NPAT.
All three 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 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 2021. We've mentioned a few times the impact of pricing and increased trading activity on our results, and this shows that 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 impairment reversals of over $1 billion on Pluto and North West Shelf gas.
These non-cash impairment reversals were due to the increased combined value of. Also we updated North West 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, this speaks to the resilience of our free cash flow, which incorporates all major expenditure, capital expenditure. A 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 2021. 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 $0.35 per share is at the high end of the board's target of 50%-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 12-18 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 2022 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 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 clearer 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. This year it's expected to be 20%-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. 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 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 92-98 million barrels of oil equivalent, and our investment expenditure guidance is $3.8 billion-$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 Two since we took FID three 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 Two 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 drill ship 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 Two achieved startup last year ahead of schedule and under budget. Greater Western Flank Phase Three, which will provide backfill to the Northwest Shelf, is targeting first production this year. Moving on to our 2022 priorities. Slide 30 outlines the timeline 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 planned to be held together with our 2022 annual general meeting on the nineteenth 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+ 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.
As a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, press the pound or hash key. Once again, if you wish to ask a question, please press star one on your telephone. Your first question comes from Dale Koenders from Barrenjoey. Your line is open.
Morning. Just a question on your LNG trading. How should we consider hedging, both in terms of volumes, fixed versus floating for this 20%-25% hub exposure in Corpus Christi through 2022?
Yeah, t hanks, Dale. Sorry, say that again, Dale?
Is there no hedging at all?
Yeah. Dale, just to, I guess, be clear. 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 UK NBP. Corpus Christi, much of our hedging is focused on our Corpus Christi volumes, to reduce the price risk associated with that offtake agreement.
Okay.
Does that answer your question, Dale?
Yeah, I think it does. Just the follow-on question then is, if you've 20%-25% of the 71-74 MMBOE of production, which equals about 100 million MMBtu, if that's exposed to hub pricing, which Platts forward pricing for 2022 this morning is about $22/MMBtu. For simplicity, call it $10/MMBtu above contractual pricing. 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?
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. Our total production guidance range, of course, includes oil production as well. I think we'll need to follow up with you on the math there. I'll go back and reiterate that the gas hub pricing exposure is in that 20%-25% range, again, associated with our produced LNG.
Okay. Just finally, the comment around special dividends and the slide, how it's ordered. Is that prioritizing special dividends over buybacks? Is it or is the implication you think the stock's expensive?
No, it's a great question, Dale. 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 toolkits on ways we can return value to shareholders. Obviously, our dividend policy has been and remains a 50% payout of underlying net profit after tax. We've 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 toolkit, and we will look at those, particularly post-merger, when we have a bigger and more diversified shareholder base. There'll be shareholders who will value buybacks. There will be shareholders who will value the dividends.
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. 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.
Okay. Thank you.
Your next question comes from James Redfern from Bank of America. Your line is open.
Hi, Meg and Graham. Good morning. Yeah, two questions, please. The first one, maybe a follow-on from Dale's question. I just want to understand this use of a concept that you've got there. Just so the 20%-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?
Yeah, that's correct, James. The gas hub exposure is as it relates to our produced volumes. Those are the volumes that we operate. Those are the Australian projects. 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. We felt like with the use of spots, the spot language refers to a single cargo sale.
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. 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.
Yeah. Thanks, Meg. I mean, like essentially the spot exposure, sorry to use that word, it has increased from 10%-15% to 20%-25%. Even if we're not talking about a spot cargo, we're still talking about effectively spot price indices, whether that be JKM or TTF as, you know, trading at $22 per MMBtu. It's almost the same thing though, isn't it? Is that right?
Yeah, it's just, I think it helps the markets understand more clearly, 'cause the reality is we do have some term deals now that are sold on those, I guess, spot prices.
Okay. Thank you. That's understood. I've got one more, please. BHP have indicated that the Trion Oil project in the Gulf of Mexico is gonna be FID ready by the middle of this calendar year. Obviously, the merger with BHP Petroleum hasn't completed yet. Just sort of wondering if you have any sort of initial thoughts or comments that you can make around the Trion Oil project, which, you know, we can assume, you know, should be FID in the second half of this calendar year. Just interested in any comments you can provide, please. Thank you.
Yeah. Thanks, James. I guess a few observations. First off, of course, until the merger is complete, ourselves and BHP Petroleum are operating as two independent businesses. 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. That's one of the kinda 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.
It'd be premature to conclude as to how that'll go, but we'll be looking at it through the lens of the capital allocation framework that we talked about in December.
Okay. Thanks, Meg. Thanks, Laura. Hand it over.
Your next question comes from Mark Samter from MST. Your line is open.
Yeah, hi, Meg O'Neill. Just quick question if I can on the Sangomar sale process. I guess your own process has been going on 7 or 8 months now, and gosh, there were two data rooms open for probably 18 months before that. I would've thought anyone who's going to take a look at Sangomar would've 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 sell down at a value well below what you think it's worth?
Yeah, thanks. Thanks, Mark. That's a great question. 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 a context. 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. The guidance that we've given the team is we need to be looking for two 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. We continue to hold that bar at a high level. We wanna make sure we get value that's accretive for our shareholders.
We wanna make sure we bring in the right partner, 'cause we'll be having, you know, we'll be working with those, that partner or partners over a very long time period. We'll be patient and make sure we are taking the right decision, when it comes to preserving value for Woodside shareholders.
Gotcha. Does that mean then, you know, obviously you've got the luxury of a strong balance sheet and a strengthening balance sheet post-merger of having time on your side. Does that also lean you towards thinking any thoughts on capital management, particularly if you hold higher equity for the duration of these projects?
Yeah. It's a great question, Mark, and we look at all of those dimensions. You know, Sangomar, of course, with first oil expected next year, you know, when we start producing, it's going to add a very attractive revenue stream. 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 points, which is we need to make sure we bring in the right partner for the right price. You know, we're not gonna be rushed, 'cause again, we do have the strength of the balance sheet to continue to carry the investment at 82%.
If that means we get revenue at 82%, that's not a bad outcome.
Yeah. Can I just one more quick question if I can, as well. Just the mindset for Woodside. Now, it's just my view, but I would argue Woodside as a business that historically has arguably chased production growth at the cost of value in the past. When you look at the BHP portfolio, obviously BHP Petroleum had a great result, like yours, the other day, but you know, 60% of production currently is in rapidly declining assets in the Northwest Shelf and Gippsland Basin. 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 a 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. We wanna make sure that we are disciplined in our investment decision-making. We want to ensure that we protect the balance sheet. You know, we've set out target ranges for gearing and liquidity, so we wanna make sure we are first and foremost. 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. I think capital management and fiscal discipline will be, you know, a very important factor for us.
Excellent. Thank you, Meg.
Your next question comes from Saul Kavonic from Credit Suisse. Your line is open.
Thank you, Meg. Two questions if I may. First one's 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.
Yeah, it's a great question, Saul. You know, obviously, we've been looking very closely at the register, the BHP register, trying to understand who holds BHP today. With unification, you know, that's changed the register a bit. We continuously look to refine our flowback analysis. Of course, unification is still sort of propagating its way through the BHP register. Nothing has come to light that would change our view that we expect any selling will be balanced by new buying. You know, a few reasons why we make that assertion. You know, we think buying will be well supported by index funds that'll adjust their weighting due to Woodside's increased presence in the sector and on the ASX.
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.
Just to confirm the secondary listings in the USA and London, what exactly is the timeframe you're envisaging that will be up and trading by?
Yeah, great question, Saul. We're working through those filings as we speak. We expect those will go live upon completion.
Great. Thank you. 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 US 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?
Yeah, it's a great question, Saul. Look, it's probably been a more recent phenomenon. 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, you know, buyers are looking to manage some of their price risk as well. We're seeing buyers who are interested in signing up for volumes that are linked to indices like JKM or TTF. You know, a bit of it is how the market has evolved over time. You know, the reality is we're just seeing a lot of change. I think, you know, there's a question in the marketplace around will gas structurally diverge from oil. We're seeing that today.
We wanna make sure we're positioned to take advantage of the upside that that offers. That's part of what underpins our thinking as to why we've, you know, locked in some additional volumes at those gas hub prices.
Thanks. Just a quick follow-up: is the locking in of some of the European indices TR under a term deal? We expect that to be kind of a material part of the leverage going forward. Just in terms of the pricing of that, should we just think about it similarly to the way we'll think about JK-JKM, and it's gonna move like that? Or are there formulas in some of these indices which could see significant premiums or discounts to what TTF actually trades at?
Yeah. It's an interesting question, Saul. One of the things that I think we've seen, particularly over the last year, is an increased globalization of the LNG market. You know, the winter or Northern Hemisphere winter that we're in currently, I think is a great example of that, where we were at a point where Europe, you know, 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 gaps are in terms of or where demand grows in one basin relative to the other basin. I think we are seeing some increased linkage between the two basins.
You know, I think that's, as an LNG producer, just creates a tremendous opportunity for us. 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. 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 probably phrased that badly. This will definitely be my last one. Just, is the link to 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 structurally, that structural linkage.
Great. Thank you. That's all for me.
Your next question comes from Nik Burns from Jarden Australia. Your line is open.
Yeah. Thanks, Meg and Graham. Just a question around Pluto. Just trying to understand a bit more detail around how we should think around Pluto production from here. Sales is doing around 5 million tons 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. I think that runs for around 3 years, the agreement you have with North West Shelf. That could increase output to 6.5 million tons, my understanding. I just wanted to check on that number. Then just post that 3-year period, how we should think about Pluto production. Does it go back to 3 million tons to accommodate Scarborough volumes? Or is there scope to bring additional volumes through the KGP and accelerate Pluto production further? Thank you.
Okay. 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 tons 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 tons over that time period. On an annual basis, that works out to be a little bit less than 1 million tons per annum. We are still going to be as we start flowing the Pluto gas through to the Karratha Gas Plant, you know, 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 tons 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 tons per annum, so that we can process about 2 million tons 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 four-year period.
Got it. That's clear. Just on the reserves downgrades at your Wheatstone and Pluto fields late last year, 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 your annual report you have 750 million barrels of undeveloped 2P reserves booked in those two assets. Just trying to understand when we might expect to see more capital coming through to develop those undeveloped reserves. Thanks.
Okay. Let me answer for the two fields separately. 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 multiple, call it smaller, individual gas reservoirs. We always knew that we would have multiple phases of development. We started up producing from the Brunello reservoir. The second phase of development, from the Julimar fields, just started up in 2021. We do have future phases expected, largely to go after more of those Julimar sands. We're at the point now where we're working through what exactly the phasing looks like, and what our investment plan looks like.
Team continues to do work to understand when exactly we need to take some of those additional backfill projects forward. On Pluto's 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. One of the outcomes is we'll actually spend less at Pluto. One of the projects that we had originally anticipated for Pluto was a compressor project relatively late in life. 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. 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.
Thanks for the answer, Meg. Appreciate it. Cheers.
Thanks, Nik.
Your next question comes from Gordon Ramsay from RBC Capital Markets. Your line is open.
Good. Thank you very much. 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. I know you've given indications that it will reduce significantly by 2030 and potentially, on my math anyway, the first three trains could shut in. This is with third-party gas coming into the plant. Can you just give us a feel for where
North West Shelf is a very significant asset for us. We are at a point in time where we are in process. The teams did a great job last year of really adapting to that change in mindset to kind of get more gas out of the ground as quickly as we can. Yields on decline coming up with agreements to process other gas is extraordinarily important. In January 2021, we finalized the agreements with the state government to allow us to process gas from Pluto and Waitsia through the Karratha Gas Plant. We will start flowing that gas later this quarter from Pluto initially, and then we'll start processing gas from Waitsia in 2023. That's, you know, 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 to kind of align in-basin gas resource holders around the basin to explore opportunities for processing other gas or processing their gas. To maybe get to the point, Gordon, you know, 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; our Greater Western Flank 3 development is a North West Shelf joint venture development to bring new gas into the plant. We are taking all the steps that we can within the venture to try to keep as much gas going through as we can.
Thanks, 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.
Yeah. Correct.
Okay. Thank you.
I mean, w e'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. Just lastly from me, coming back to the question of other analysts have asked about the gas hub exposure guidance of 20%-25%. You've mentioned different hub indices, JKM, TTF, and UK National Balancing Point. Can you give us a feel for the mix of those? Is this like 90% JKM or is it just too variable going forward? You did say there's interrelationships, and we get that because of arbitrage and trading. There are differences at times between these three hubs in terms of pricing. It'd be good for us to have some idea of the weighting. It'd be helpful.
Yeah. Thanks, Gordon. Look, I don't think we'd want to or even be able to be that precise. You know, 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. You know, I don't want to commit today as to what index those will be sold on.
Okay. Lastly, if we look at, like, 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 said what price indexation that is based on. That actually is a longer-term contract.
Okay.
I wouldn't try to draw any conclusions from that.
Thank you. That's good. Thanks.
Your next question comes from Daniel Butcher from CLSA. Your line is open.
Yeah. Hi. Hi, Meg. Hi, everyone. First question is just on your contracts you signed a while ago or the MOUs for Scarborough Pluto Two. 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 are sort of associated with Scarborough Pluto Two that you've signed over the years.
Yeah. Look, it's probably worth differentiating, Dan. We've signed firm sales agreements with a number of players. 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. 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 slowdown in COVID. We're, you know, continuing to talk to a number of prospective buyers about additional Scarborough offtake. Obviously, with pricing where it is right now, you know, we feel like conditions actually are pretty attractive for us as a seller.
As we communicated before we took the FID decision, you know, we didn't want to rush into too many LNG, you know, 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 apart from the Uniper deal, which is now unconditional, the rest of them are pretty much subject to wherever spot prices are moving right now for new contracts.
Look, Uniper's firm, of course. The Pertamina contract is firm. The Pertamina option is an option that remains firmly in our court. That's a decision that we have the right to take, and we'll be looking very closely at that option. Then we have a term agreement with RWE as well, which is also firm.
Okay, thanks. Yeah, just curious, going to your hydrogen strategy you 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 things are still coming down the cost curve. How do you sort of weigh up those risks? Is there a more capital light way of keeping your finger on the pulse of where new energy is moving without spending $5 billion this early in the piece?
Yeah. 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'd think a lot of people were doing a lot of work in this space. The reality is for the new energy opportunities, we need to be customer-led. 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. You'll have seen that we've signed a number of agreements, you know, 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.
Dan, 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. In our capital market update, we outlined what sort of return we expect to be acceptable. We said it's greater than 10%. The challenge I've given the team is, you know, we really wanna see early projects that are quite comfortably beating that target threshold.
Okay, thanks. I'll leave it there. Cheers.
Thanks, Dan.
Your next question comes from Tom Allen from UBS. Your line is open.
Morning, Meg. Most of my questions have been answered. I just have one outstanding on your emissions reduction strategy. To meet your emissions reductions targets going forward, you've been clear that offsets are gonna 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 ton. Can you just clarify how you can keep your carbon costs below your $ 20 a ton 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 space, is we wanna make sure we have a diversified portfolio of offsets, maybe similar to the diversified portfolio of products that we want to sell. 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. Similar to our strategy around LNG, you know, this is not a time for us to be buying. We're generating now, and we will continue to generate, but we wanna make sure that when we are in the offset market, we are purchasing at a point in time where it is value accretive. The team's been challenged to continue to deliver at very affordable prices. Thus far, they've been doing a fantastic job.
Sure. I agree that there is the focus on quality is progressing quickly. Can you share, Meg, what proportion of your offset portfolio would likely be procured internationally?
No, it's probably premature to signal that, Tom. You know, 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. 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.
Okay. Thanks, Meg.
I would now like to hand the conference back to our presenter. Thank you. Please continue.
All right. 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.
This concludes today's conference call. Thank you for participating. You may now disconnect.