WOODSIDE ENERGY GROUP LTD — Call Transcript 2023

Mar 1, 2023

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Woodside Energy Group Ltd ACN 004 898 962 Mia Yellagonga 11 Mount Street Perth WA 6000 Australia T +61 8 9348 4000 www.woodside.com

ASX: WDS NYSE: WDS LSE: WDS

Announcement

Wednesday, 1 March 2023

FULL-YEAR 2022 RESULTS BRIEFING TRANSCRIPT

Date: 27 February 2023 Time: 10:00 AEDT / 07:00 AWST (15:00 CST on Sunday, 26 February 2023)

Start of Transcript

Operator: Thank you for standing by and welcome to the Woodside Energy Group Ltd full-year 2022 results conference call. All participants are in listen-only mode. There will be a presentation followed by a questionand-answer session. If you wish to ask a question you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand this conference over to Ms Meg O’Neill, Chief Executive Officer and Managing Director. Please go ahead.

Meg O’Neill: Good morning everyone. Thank you for joining our 2022 full-year results investor call. We are presenting the results today from Sydney and I would like to begin by acknowledging the traditional custodians of this land, the Gadigal people of the Eora nation, 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 market along with our Sustainable Development Report and our Climate Report. I would encourage you all to read these reports together as they provide a complementary review of our business.

I am joined on the call with our Chief Financial Officer, Graham Tiver. Together we will provide an overview of our 2022 financial, operational and strategic performance before opening up the call to a Q&A session.

Please take the time to read the disclaimers, assumptions and other important information on Slides 2 and 3 . I would like to remind you that all dollar figures in today’s presentation are in US dollars unless otherwise indicated.

Moving on to Slide 4 . Woodside’s strategy has delivered exceptional results in 2022. We transformed the Company through the completion of the merger, which has provided increased scale and resilience and further strengthens the balance sheet. The addition of the heritage BHP assets and the expanded global portfolio, coupled with strong operating performance and strong market conditions, are key drivers in delivering record net profit after tax of $6.5 billion.

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We have backed out some one-off items which Graham will touch on later to deliver an underlying profit of $5.2 billion.

The Directors have determined a final dividend of 144 US cents per share, fully franked. This represents an 80% payout ratio of the second half underlying NPAT. The total full-year dividend is 253 US cents per share, meaning we are returning $4.8 billion to shareholders at a full-year yield of over 10% based on Friday’s closing share price.

The outstanding performance from our business has set us up well to continue investment in oil, gas and new energy projects. We are investing in a range of commodities for the next wave of growth and are fiscally well positioned for this period of higher capital investment.

Our 2022 performance speaks to the strength of the business, our ability to deliver results today, deliver projects for tomorrow and return value to shareholders.

Slide 5 provides an overview of key metrics underpinning our strong operational performance and how this translates to strong financial outcomes. In 2022 we achieved production volumes of 157.7 million barrels of oil equivalent, a record for Woodside. This includes production from the heritage BHP Petroleum assets for seven months of the year. Operationally, we delivered outstanding performance in our operated LNG assets, averaging reliability of 98.5% from Pluto LNG and the North West Shelf Project.

We also delivered value from the Interconnector with 9.8 million barrels of oil equivalent produced at a time the world needs more LNG.

Our unit production cost increased, impacted primarily by the inclusion of BHP Petroleum business and the Interconnector tolling fees. We had strong underlying cost performance in an inflationary environment.

The realised price of $98.40 per barrel of oil equivalent reflects strong global demand for our products and the benefits realised by our marketing and trading business.

This has translated to $16.8 billion in revenue and $6.5 billion of free cash flow. Our significant free cash flow is after investing $4.2 billion in the business and enables us to pay a healthy dividend. Free cash flow also allowed us to reduce gearing to ensure a strong balance sheet given our upcoming capital commitments.

Moving on to Slide 6 . We have now achieved the goals we set ourselves ahead of the merger delivering initiatives expected to realise over $400 million per year of post-merger synergies. We have delivered subsea-tieback and improvement projects across our West Australian LNG assets and Gulf of Mexico assets, continuing to keep the plants full.

On the sustainability side we achieved an 11% reduction against the starting base in net equity Scope 1 and 2 greenhouse gas emissions and are on track to achieve our 2025 target.

Higher profits have translated to higher tax and royalties paid to the Australian government. For 2022, we paid a record AU$2.7 billion, up 311% from our 2021 payments. We continue to advocate for a stable tax and fiscal environment in order to incentivise the large, long term investments that support energy security, decarbonisation and economic growth.

Slide 7 summarises our safety performance. Disappointingly we failed to improve on our safety outcomes of 2021 with our total recordable injury rate increasing to 1.8 per million work hours. Environmental performance has been good with just one Tier 2 loss of containment event recorded in the first half of the year, which resulted in no impact on the environment. Safety is central in everything we do and we have made it an imperative to return to leading performance in 2023.

Slide 8 demonstrates the changing price environment over the last two years. The landscape has changed as energy security and affordability are now at the forefront of the energy challenge faced today. Even before

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Russia’s invasion of Ukraine we were seeing market volatility increasing, with the invasion accelerating the rerouting of energy flows and contributing to volatile energy prices. There are growing concerns over the amount of supply available to meet immediate demand which is contributing to price volatility in the market.

Slide 9 demonstrates how we were able to capture value in these conditions. We actively positioned our portfolio through the year to realise the benefit of higher commodity pricing, utilising our expanded global marketing presence and trading capability. Our trading team optimises the value of our produced LNG supplemented by the trading of third-party cargoes. Realised price for this third-party LNG was $166 per barrel of oil equivalent, more than doubling from the prior year.

The price achieved for our produced LNG benefited from our planned exposure to gas hub indices which was 23% in 2022. This coming year we are targeting to sell approximately 20 - 25% of our produced LNG on gas hub pricing. We were also fortunate to bring the Interconnector online at the right time, which enabled the delivery of almost $1.2 billion of incremental revenue.

Slide 10 shows Woodside’s dividend performance over the last five years. The final dividend of 144 cents per share has been considered and balanced against our capital commitments over the coming years. We are pleased to return $4.8 billion of value to shareholders, being the $2.1 billion interim dividend and the $2.7 billion final dividend, while protecting the strength of the balance sheet.

We have made very good progress on our major projects in 2022. Slide 11 summarises our activities on the Sangomar field development in Senegal. 2022 was a great year as we progressed the project in preparation for targeted first oil later this year. We completed construction of the FPSO vessel and all subsea equipment. The drilling program continued, ramping up to two rigs. We commenced installation of subsea infrastructure.

The FPSO has been relocated to Singapore where it will complete topside integration and precommissioning. The image on the right of this slide is a close-up of the turret which really gives you an idea of the scale of the project which we are undertaking. We will spend 2023 finalising the execution activities and preparing for start-up. First oil is expected in late 2023.

On Slide 12 the Scarborough project is progressing across all work streams. We have commenced fabrication of all major facilities including the offshore floating production unit topsides and hull, the Pluto Train 2 modules, subsea facilities and the trunk line. Fabrication of both Scarborough and Pluto Train 2 is progressing well and will continue through 2023. Site works have commenced at the Pluto LNG site. In parallel we are progressing the secondary approvals needed for certain offshore activities.

Slide 13 highlights some changes in the Australian regulatory environment affecting our activities on the west and east coasts. There have been some changes in offshore approval requirements which requires stakeholder consultation over a more extensive area. We have clear plans to consult in a manner aligned with the new requirements and are progressing those consultations. Our project execution schedules have been adapted to enable more extensive consultation. We do not anticipate an impact on first LNG from Scarborough, which remains planned for 2026.

Regarding the intervention in the east coast gas market, Woodside is supportive of the government’s objective of access to affordable and reliable energy. We believe as a supplier of energy that increasing supply is the most effective way to address these issues in the market.

Slide 14 demonstrates the breadth of projects that Woodside has across the oil, gas and new energy commodities. You can see that we have a strong mix of sanctioned projects and a healthy pipeline of future opportunities. Our focus is on executing these sanctioned projects safely, on time and within budget. For 2023 we are targeting final investment decisions on Trion and H2OK.

Of course, a decision on sanctioning new projects must be made in line with our capital allocation framework which is shown on Slide 15 . This framework is unchanged from what you’ve seen before but it is always important to reiterate in the context of our pipeline of opportunities. We have to be disciplined in our

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investment decisions which are guided by our targets for expected return in addition to how they fit within the overall portfolio. Our corporate emissions reduction targets do not change with new investments, which must include the cost of abating incremental emissions.

I would now like to move on to Trion on Slide 16 . Trion is a deepwater development in the Mexican waters in the Gulf of Mexico. Trion provides us with the opportunity to leverage our deepwater Gulf of Mexico experience. A semi-submersible floating production unit would have a production capacity of up to 100,000 barrels per day of oil and the initial field development would include water injection and gas injection.

We are very excited about Trion. The technical work is well advanced as is the execution planning. In 2022 we completed front-end engineering design, or FEED, for the floating production unit. We issued key tender packages, and we are now evaluating the responses. We expect to select the FPU contractor within the first half of the year, ahead of an FID decision.

Moving on to Slide 17 . We are also targeting a final investment decision on H2OK in 2023 which would be our first major new energy project. H2OK is a hydrogen opportunity in Oklahoma in the United States. H2OK is well positioned given its proximity to a strategic transport and supply chain corridor in the US, close to customers who wish to adopt hydrogen as a fuel in the heavy transport sector.

The potential fiscal incentives of the Inflation Reduction Act represents an opportunity for our H2OK project. In 2022 we completed front-end engineering design activities. We have awarded contracts for the electrolysers and liquefaction equipment and will continue to progress approvals and customer offtake agreements in support of final investment decision readiness.

On Slide 18 , we are delivering on our Scope 1 and 2 targets which have also now been expanded to the merged portfolio. Our heritage Woodside operated assets have identified plans for potential decarbonisation opportunities. If all our opportunities are implemented in full this could result in a 300 kilotonne of CO2 equivalent reduction in emissions in 2030. In 2023 our focus is on extending these plans to the heritage BHP assets.

On Slide 19 , we are also making progress on our investments in new energy and lower carbon services. We have now spent $100 million towards our new energy target which is to invest $5 billion by 2030. We expect spending against the target to ramp up over the coming years as the market for these products grows and we have progressed projects into the execute phase.

I will now hand over to Graham Tiver to discuss our financial performance in more detail.

Graham Tiver: Thank you Meg and good morning everyone.

Starting off with Slide 21 . Across the board we have achieved very strong financial outcomes in what has been an outstanding year. This was driven by high operational reliability, higher prices coupled with the active positioning in the market from the marketing team, the contribution of the former BHP assets to the portfolio and the Pluto-KGP Interconnector.

We have delivered record shareholder returns while retaining flexibility to meet our capital commitments and deliver future returns against the backdrop of global volatility. Returning value to shareholders is important to us as is delivering the next phase of growth.

Moving on to Slide 22 . We continue to deliver in line with our capital management framework which you would be very familiar with. Ability to generate cash and remain resilient through the price cycle was demonstrated by our high operating cash flow of $8.8 billion for 2022. We are also putting this cash to use across oil, gas and new energy projects with investing cash flow totalling $4.2 billion when we exclude the positive impacts of the merger completion payment and the contribution from Global Infrastructure Partners from Pluto Train 2.

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Our three boundary conditions which were outlined at our investor briefing day last year have been met. First, our ability to meet our investing expenditure commitments, mainly Scarborough and Sangomar. Second, our investment grade credit ratings were reaffirmed during the year. Third, our final dividend of 144 US cents per share represents a payout ratio of 80% which is at the top end of our targeted range. This represents a full-year dividend yield of over 10%.

Whilst gearing for the period was 1.6% it is important to note that if the final dividend was added to the end of the financials, the payment would have the effect of increasing the year-end gearing to 9%, which is just outside of our targeted range of 10% to 20% through the cycle. We may at times sit temporarily outside of this range but the low gearing provides us with the flexibility for future uncertainty which is important when we consider the current volatile price environment as well as upcoming capital expenditure and future shareholder returns.

Slide 23 shows the movement in our net profit. Each bar represents the increase or decrease in each category compared to 2021. The two largest increases are due to price and volume with the combined effect of these two columns totalling over $9.8 billion. The boost to volume is primarily due to the contribution of the BHP assets post-merger and the boost to price was primarily higher realised prices across all markers. The other positive contributor to income was the completion of the sale of Pluto Train 2 to GIP which was completed in January 2022.

The increase in the cost of sales is driven by changes to the business. This includes the cost of operating the BHP assets which includes depreciation, higher royalties and excise linked to higher prices and finally the start-up of the value-accretive Interconnector. Other costs were predominantly made up of the hedging losses which were put in place for two reasons. First, to provide downside protection to the balance sheet, and second to lock in positions on our Corpus Christi contracts.

We also incurred significantly higher income taxes and PRRT as a result of the increased income. The bar does include a credit of approximately $1.4 billion relating to the recognition of an increase in the Pluto PRRT deferred tax asset. This simply represents the recognition of additional off-balance sheet credits available to Pluto which reflects the strong 2022 profit and future view of profitability.

The underlying NPAT figure removed the one-off impact of the merger transaction costs, the benefits of derecognising the Corpus Christi onerous contract provision, Wheatstone impairment reversals, the Pluto PRRT DTA and the Orphan Basin exit costs. As a result, we achieved an underlying NPAT of $5.2 billion which is used as the basis for the dividend calculation, being a fully franked dividend equivalent to US 144 cents per share. As Meg mentioned, this represents a full-year dividend payout of $4.8 billion.

Slide 24 shows the five-year comparison of operating revenue, EBITDA and underlying NPAT. As outlined previously, the merger and market conditions, along with strong operational performance and the Pluto-KGP Interconnector, were key to driving increased profitability. Our underlying NPAT of $5.2 billion is our best fullyear result ever recorded.

Slide 25 demonstrates the cash generating capacity of our operations. Both the operating cash flow of $8.8 billion and free cash flow of $6.5 billion on this page include the impact of a collateral payment of approximately $0.5 billion against hedging activities. We are expecting to receive our money back in the second half of 2023. Without the collateral payments, operating cash flow would have effectively been $9.3 billion and free cash flow would have been $7.1 billion.

As mentioned, the statutory investing cash flow of $2.3 billion is positively impacted by the benefit of the $1.1 billion in cash received as part of the completion of the merger and the capital contribution by GIP to Pluto Train 2 of $0.8 billion. Key underlying drivers of the increase in investing cash flow are the project execution costs for Scarborough and Sangomar.

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Moving to slide 26 , unit production cost has increased but underlying cost performance remains strong despite inflationary pressure. The addition of the BHP assets and the Interconnector have added to our production cost base. We have included a waterfall highlighting the changes. Whilst the Interconnector has contributed to unit production cost, it has delivered substantial value with incremental revenue of almost $1.2 billion.

We are managing inflationary pressure on our assets and will continue to keep this in focus. The $0.50 cost increase is primarily driven by the Wheatstone turnaround and planned cyclical maintenance at Pluto. It is worth noting the unit production cost is also consistent with our pre-merger expectations of approximately $8 per barrel of oil equivalent as outlined in our merger documentation.

Slide 27 demonstrates the resilience of our gross and cash margins. Our margins have remained resilient through the price cycle; the cash margin averaging approximately 80% over the last five years. This demonstrates the quality of our portfolio and the continued benefit of the merger.

Slide 28 shows our five-year liquidity and 10-year debt maturity profile, both of which speak to our strength of the balance sheet and our preparedness for the upcoming committed capital expenditure. Our liquidity remains high at $10.2 billion, but when we think about this figure in the context of the $6 - $6.5 billion of capex which we have forecast for 2023, we are well covered. Our debt maturity profile has minimum nearterm maturities and our low gearing of 1.6% provides additional flexibility for future uncertainty. Our net debt position is strong at under $600 million. With this robust balance sheet, I am confident of our ability to meet our investment expenditure commitments and continue to return value to our shareholders.

Slide 29 demonstrates overall tax contributed to the Australian Government. This isn’t a non-cash number; this is genuine cash paid to the government in the form of a number of different taxes which are listed on the right-hand side of the chart. This is a record tax contribution for Woodside. Taxes designed to capture the upside, like PRRT, are working. With top-up payments resulting from our 2022 full-year profits, we can also expect our 2023 tax contribution to continue to be strong. We are proud of the contribution that we make back to the Australian economy and this demonstrates that high prices do translate to higher taxes paid.

I’ll now hand back over to Meg. Thank you.

Meg O’Neill: Thanks Graham. I’d like to close by providing a quick overview on how market demand remains resilient across our products as shown on slide 31 . It’s clear that the global energy transition can take many pathways. What the last two years has demonstrated is that the energy transition is unlikely to be a smooth, linear progression. An enormous amount of investment is required in all forms of energy in the coming decades to meet demand under these scenarios.

For example, analysts such as Wood Mackenzie expect global LNG demand to grow by more than 60% in volume between 2021 and 2040 and more LNG projects will be required to ensure adequate supply from the late 2020s. Woodside is positioning itself with opportunities across these three products and remaining prepared to supply the world with the energy it requires.

Slide 32 lists our key priorities for 2023. First, in our core business we need to focus on safety performance, an imperative for maintaining high performance in both day-to-day operations and when executing maintenance campaigns. Whilst the merger is complete, there are a number of integration activities such as integration of systems and SOX compliance.

Second, in our major projects we will look to continue to safely deliver Sangomar and Scarborough. We will continue to progress opportunities that deliver value to shareholders consistent with our capital allocation framework. Following the merger, we have the benefit of a broad set of potential investment opportunities and we will be disciplined and selective in moving opportunities forward.

Third, we need to progress our decarbonisation opportunities, extending the asset decarbonisation plans to heritage BHP operating assets. We also need to mature our new energy growth opportunities. All of these

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priorities support our strategy to be a low-cost, lower-carbon, profitable, resilient and diversified supplier of energy. We are delivering today and intend to deliver these priorities. The whole organisation is focused and we are excited about the year ahead.

We will now open the question and answer session.

Operator: Thank you. If you wish to ask a question, please press star/one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star/two. If you are on a speakerphone, please pick up the handset to ask your question. Your first question comes from Tom Allen with UBS.

Tom Allen: (UBS, Analyst) Good morning Meg, Graham and the team. The presentation references higher capex incurred on Scarborough and Sangomar. Can you please provide some colour on the magnitude of that and which work packages you’ve seen that pressure and also share some colour please on how the Australian offshore regulators’ expanded consultation requirements might impact the drilling schedule, or costs generally for Scarborough over the next couple of years?

Meg O’Neill: Thanks for the questions, Tom. So when we said a higher capex for Scarborough and Sangomar, that was 2022 versus 2021. I know there is a lot of concern about inflationary pressures. What we’re seeing in both of these projects is they are both tracking to the FID spend. Sangomar, as we noted, is working towards first oil later this year. Scarborough, we continue to execute, we’re about 25% complete and we do expect Scarborough to remain on budget. So the comment on higher capex was really a year-on-year comment.

The consultation requirements, as I’ve noted in the pack, NOPSEMA has provided the market with guidance on what is expected and the court was very clear in their ruling around the sorts of activities that proponents need to be providing to relevant parties. We have put together a very detailed consultation plan that aligns with that guidance from NOPSEMA and the team is off executing it. We’ve done a number of things to provide ourselves with a bit of additional flexibility in the schedule, so we do not anticipate any impact on Scarborough activities that would affect the first LNG which we remain targeting for 2026.

Tom Allen: (UBS, Analyst) Okay, thanks Meg. If I could please just ask another question on the capital demands on the business, is Woodside still assessing, let’s say, mid-cap sized acquisition opportunities that could extend your Gulf of Mexico exposure and in some cases even bring perhaps an onshore shale exposure in the US? Just keen to understand whether that’s still a live assessment and something we should be considering when looking at the broader capital demands on the business for the year ahead.

Meg O’Neill: Sure. So of course we remain open to M&A kinds of opportunities and we are quite interested in continued growth opportunities in the Gulf of Mexico, nothing to signal beyond that. You’ll note that we have been doing a bit of exploration work and we do have more exploration planned. We picked up some blocks in the most recent lease sale in the Gulf of Mexico, so we’re looking at both organic and inorganic opportunities there and if anything comes to fruition, we’ll let you know.

We will remain very cautious about onshore opportunities. I think when you look at the capabilities of Woodside, we’re an organisation that’s really well designed for the risk and the capital intensity associated with offshore, so we remain a bit cautious around the onshore. That’s a different skillset required to be successful in that space.

Tom Allen: (UBS, Analyst) That’s clear, thanks Meg.

Operator: Your next question comes from Mark Samter with MST Marquee.

Mark Samter: (MST Marquee, Analyst) Yes, morning everyone, didn’t think I’d ever start with a question on depreciation in my life, but just wondering if we could talk about FY24 when we think about the fact that Sangomar starts out with a pretty low 1P base, Mad Dog 2… obviously these assets are going to be

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depreciated over 1P basis, obviously got higher production expected, but should we be thinking that Group unit D&A costs will be higher in 2024 than in 2023 on that logic? Obviously I’m going to tie this into the dividend after I hopefully get an answer to that question.

Meg O’Neill: Okay, thanks Mark, I’ll let Graham field that one.

Graham Tiver: Yes, thanks Mark. So in the results announcement, we have included a depreciation expense reconciliation for 2023. You will see our 2022 depreciation increase from US$2.9 billion to $US4.4 billion. The majority of that is driven by the additional five months of deprecation of the BHP heritage assets and you’ll also see the breakdown in there of the change in the application of the depreciation policy. So of that movement, $600 million is related to the change in the deprecation policy as well, so there is a reconciliation provided in the appendices of the results announcement.

Mark Samter: (MST Marquee, Analyst) So it’s fair to say the assets that produce the added production is coming from assets that are noticeably low 1P reserve base and noticeably high capex, am I wrong in thinking that?

Meg O’Neill: In 2024?

Mark Samter: (MST Marquee, Analyst) In 2024.

Meg O’Neill: Yes, so Mark, I mean you’re correct that the assets that will start up in 2023 and then have fullyear production in 2024 are assets that will be depreciated on a 1P basis. So as you would expect in those sorts of assets, the unit depreciation rate is higher. The positive of course is that as you do infill drilling, for example, and continue to develop the full 2P resource, that additional resource comes in with limited incremental unit depreciation costs.

Mark Samter: (MST Marquee, Analyst) Cool. Can we just roll that into how we’re thinking about, I mean you said, you highlighted today, since I think gearing would have been – I’ve lost the page, was it 8% or 9%, taking into account the final dividend? If we look back at the chart you gave us on Investor Day on free cash flow pre-dividends through the course of this year, I mean if you mark to market for the current future scope in JKM, I think that would have you free cash flow negative this year. So by the time we get to the interim dividend for FY23, the gearing should be well and truly within that 10% to 20% gearing range.

Can you talk through how you think about (a) do we think still 50% to 80% despite the change in depreciation policy is the sensible number we should base it off? And I guess both ends of that range, I don’t want to frame this as a negative question, what would you need to see happening to pay out more than 80% and what do you think we would need to see for you to think about reducing that payout ratio below the 80% that has been the standard for so long?

Meg O’Neill: Thanks for the question, Mark. Yes, as you know our capital management framework has been unchanged for a period. There are a few things that are really fundamental for us. First up is protecting investment grade credit rating and we’re very pleased that the ratings agencies have reaffirmed our strong credit rating over the course of the year.

The second thing that’s important, and we hear this quite consistently from our shareholders, is the way they value our dividends. We’ve done extensive modelling to understand our ability to pay out and the dividend policy remains very firm at that 50% payout ratio as the policy. Of course we’ve been paying out at 80% for the last few years. The market conditions this past year and the profitability of the business allowed us to pay out at that 80% in this full year results.

As we play the year forward, as Graham noted, we do have significant capital expected for this year. As the Scarborough project continues into next year, we’ll have a significant capital investment there as well, assuming Trion and Oklahoma FIDs are successful. We just need to continue to have that disciplined

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approach to ensuring that, so we protect the balance sheet, we protect our ability to invest and we protect that ability to return value to shareholders.

Mark Samter: (MST Marquee, Analyst) Yes, and I hope this isn’t pushing too much, Meg, but when we think about three years ago we would have thought $15 JKM is the greatest thing ever. But when we think about that pretty precipitous drop we’ve seen in JKM, do you tend to think that just the lower earnings from that is a balancing factor enough? Or do we think as that macro is potentially working then it could swing back the other way? Do we think you need to be more prudent, assuming a much lower level of JKM, persists for a while, then talk forward. Or do you think just the 80% of the smaller number compensates for it?

Meg O’Neill: Yes, so Mark I think it’s probably worth highlighting that whilst JKM has fallen from its heady levels of last year, it’s still at levels that are well above historic. $15 JKM is pretty attractive. Three years ago we would have been ecstatic to be at that pricing level. So we do, as I said, we model a variety of price forecasts going forward, we test our ability to pay out and we’re still comfortable at the 50% to 80% range of payout is still appropriate, as long as we also keep our eyes on that gearing ratio, the 10% to 20%.

We’re well positioned this year, but we do have a period of significant capital ahead of us and that’s why we’ve been, I think, quite prudent in balancing the desire to give shareholders good returns this year with protecting the balance sheet and the ability to invest.

Graham Tiver: I think, Mark, it’s worth pointing out that testing of the scenarios, we see the balance sheet as still quite resilient at our low-price scenario as well. So we’re comfortable where we are today, but we are conscious that times are quite volatile, but we do see ourselves resilient at the low price.

Mark Samter: (MST Marquee, Analyst) Yes, absolutely, thank you. Sounds very sensible to me. My second one really last, quick question if I can, probably a bigger picture one Meg. If we think broadly about the business in its biggest form, Scarborough largely offsets the declines in LNG production you’ll see from North West Shelf and Pluto broadly-ish. It will be without new project sanction or M&A, it’ll be pretty much 65% of the reserve base by the time it starts. When you think about the rest of the business and let’s say Trion perhaps doesn’t FID for whatever reason, do you see the need to replace reserves and keep a business of scale outside the LNG portfolio or is there a scenario where Woodside just becomes ever more an LNG business and you're happy for the rest of the portfolio to be in runoff mode?

Meg O’Neill: So Mark one of the things that we do extensively is take a look at scenarios around how the world’s energy mix might change over time. It’s probably shown on that slide 31 that’s got those graphs on it, which shows that in all scenarios oil continues to be an important part of the energy mix for the next 30 years. Gas is important. Whilst our foundation is LNG, the BHP Petroleum acquisition really does give us a lot of strength in the oil side of the house. So we are open to continued investment in all three of these commodities.

We’ll continue seeing what opportunities are out there, but we need to be disciplined about progressing those opportunities, so I think we’re open to a variety of investments, we’re pleased with our LNG position today. Scarborough will allow us to continue to have a strong LNG position into the future, but opportunities beyond that, we’re looking across all three commodity types.

Mark Samter: (MST Marquee, Analyst) Brilliant, thanks Meg, thank you.

Meg O’Neill: Thanks Mark.

Operator: Your next question comes from James Byrne with Citi.

James Byrne: (Citi, Analyst) Good morning, two questions. Firstly PRRT related, slide 29 Graham, you came almost pre-emptively swinging on any sort of higher taxation in the future. I’m wondering are you aware of any potential changes to PRRT that could be coming up in the May budget that would sort of see you put out a slide like this that really defends your position of paying higher taxes during higher commodity

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prices. Meg, you're obviously very involved with APPEA, are you lobbying against PRRT actively at the moment for changes?

Meg O'Neill: James, I think we have been really consistent in our public messaging for a very long period which is for us to make the big investments that we make which pay out over, or generate revenue, over 20-plus years we need a stable fiscal and regulatory regime. The fiscal framework with PRRT has been in place for decades. The Federal Government has had a number of reviews of the PRRT, but part of why we have that slide in there is just to help communicate more effectively that when Woodside is profitable many of our shareholders benefit.

Our shareholders benefit and the Government of Australia benefits. $2.7 billion is really a phenomenal contribution and if you think about how far that stretches in terms of aged care, education, infrastructure investments, we're a very significant contributor to Australia. The investments that we are making in things like Scarborough will allow us to continue to make that sort of significant financial investment for decades to come.

James Byrne: (Citi, Analyst) Okay, a second question then just around these secondary approvals for Scarborough. Are you able to say what court cases there are outstanding against the project and in that context when you do your workshops with NOPSEMA do you feel really comfortable that you are aligned with NOPSEMA to get those secondary approvals? If we saw a Barossa style sort of delay to Scarborough and the rig was idle, I'm also wondering how expansive your contingency budget is at the moment to absorb any delays to the projects?

Meg O'Neill: Okay, that's a wide range of questions there James. Look, I will start with the facts. So outstanding court cases, we have two. One is in the Supreme Court of Western Australia. It was from CCWA related to Pluto LNG Train 2 construction. The hearing on that matter was heard in August and we are waiting an opinion from the court. The Australian Conservation Foundation commenced proceedings last year related to Scarborough environmental approvals broadly. That matter continues to progress through the court system.

When it comes to NOPSEMA, we have a very active discussion and NOPSEMA has been very forthcoming publicly and with a number of proponents on how the results of the Barossa court case influence their thinking when they're reviewing environmental plans. For Scarborough we have three environmental plans that we are progressing… One for seismic... Sorry, three related to Scarborough. One for seismic, one for drilling and one for the pipeline installation. As I said in my opening remarks, we are consulting in accordance with our consultation plan that aligns with that NOPSEMA guidance. It's a much broader consultation than we historically would have performed but we are getting after it. The team has got a lot of enthusiasm and is out talking to a wide variety of potential relevant persons. We have got flexibility in the schedule to be able to accommodate this longer consultation period and as I said, we remain on track for first LNG in 2026.

James Byrne: (Citi, Analyst) Thank you.

Operator: Your next question comes from James Redfern with Bank of America.

James Redfern: (Bank of America, Analyst) Oh, hi Meg, Graham, good morning. I guess my questions are going to follow on from Mark Samter’s question just around the dividends. I mean the presentation, you know, the last 12 months referred to special dividends and buybacks with regards to increasing shareholder returns. I guess the prudence or conservatism you have shown today suggests that we should not be assuming any special dividends or buybacks in the foreseeable future given the oil price outlook and also the capex commitments coming up. I guess the best we could expect is the 80% dividend payout ratio which is fine, but I just want to check that that's consistent with your thinking. That's the first one please.

Graham Tiver: Yes, thank you. Look, the way - we look at it at a point in time, at the time of assessing the dividend and declaring the dividend, so it's a bit early to call that out just yet. I guess where we are today with

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the dividend at the 80%, it takes into account two things. One is the capex that we have in front of us and nothing new there, the US$6 billion to US$6.5 billion and I guess the market volatility and how the overall market is playing out as well. When we get to the half year, we will be making the same assessment. We will be looking forward, looking at the global economic scenarios, how our operations are performing and we will be looking at it in the context of how our capital programmes are playing out. I certainly wouldn't be in a position to say there will be no additional returns in any shape or form moving forward. We will make that point, well that decision, at that point in time based on the overall performance of the business and global macro.

James Redfern: (Bank of America, Analyst) Okay.

Meg O'Neill: James, I think it's important to keep that really front and centre in our capital management framework just to remind the market that we do have additional tools at our disposal. If the market conditions allow us to use some of those tools we're prepared to, but at this point in time as Graham noted with the capital spend ahead in the next year plus, we are being prudent.

James Redfern: (Bank of America, Analyst) Yes, no, I understand. Thank you. The second question is just a housekeeping question with regards to Sangomar. If we see increased production later this year the expected plateau production is about 75,000 barrels a day. Just wondering, how quickly do you think Sangomar will ramp up to that 75,000 barrels a day? How quickly will the ramp up be and what are you seeing in terms of plateau production in terms of years? Thank you.

Meg O'Neill: Well, thanks for the question, James. Look, what we've said I guess just to make sure we are all on the same page is that we expect first production in 2023, but for purposes of the production guidance we have not assumed anything material in the production guidance for this year. In terms of the pace of ramp up, look, that's something that we are working on. It will depend a bit on how we manage the flow assurance. This is a deep water development with pretty complex subsea infrastructure so it will be ramped up over the course of a few months. Plateau, I think we will want to reserve commentary on plateau period until we get a bit more confidence in how the reservoir is going to perform. We have certainly modelled it and we will put out production guidance at a point that is appropriate in time for that particular asset.

James Redfern: (Bank of America, Analyst) Okay. Thanks Meg. Appreciate it.

Operator: Your next question comes from Dale Koenders with Barrenjoey.

Dale Koenders: (Barrenjoey, Analyst) Morning Meg and Graham. Just I guess going back to prior questioning. The free cashflow outlook you presented for the business at the Investor Day was just under $1 billion or thereabouts in 2023 and about $4 billion in 2024 before thinking about a couple of billion dollars for Trion and H2OK capex. Oil price has fallen off. Can you just confirm we are right to think about negative free cashflow this year at current forward curves before thinking about dividends and probably more break even next year, is that the right way to think about the business?

Graham Tiver: Dale, the 2023 or the free cashflow graph that we put forward an indicative position for the future at the IBD was using forward curves and it does take into account the drop in prices. However, I would just point you back to the overall strength of the balance sheet, our overall gearing and the flexibility we have. We have the ability to be able to continue our capital programs, in particular Scarborough and Sangomar and we have the ability to continue to maintain strong shareholder returns into the future. The balance sheet is in great shape. Yes, cash will be lower this year because of the capex spend and there has been a drop in prices. We think we have captured that and as I have touched on with Mark, our low-price sensitivity analysis does prove that we can robustly get through 2023.

Dale Koenders: (Barrenjoey, Analyst) How do you think about the preference between maybe pulling back your dividend payout to 50%, restarting the DRP or delaying FIDs?

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Graham Tiver: Yes. Look, once again it's similar to what we answered to James. We will assess that at the point in time of making the decision on the dividend looking at the overall balance sheet, global macro trends and performance of the business Dale, but every time we have a discussion with the Board on capital management, these are the kinds of conversations we are having on how we set the business up and how we distribute shareholder returns.

Dale Koenders: (Barrenjoey, Analyst) Okay and then just finally, can I check my maths? It looks like Greater Enfield gas with 2P Reserve downgrade in the order of 200 Bcf. Can you talk through that? Is that Wheatstone?

Meg O'Neill: We will have to follow up with you on that Dale.

Dale Koenders: (Barrenjoey, Analyst) Okay, thanks.

Operator: Your next question comes from Saul Kavonic with Credit Suisse.

Saul Kavonic: (Credit Suisse, Analyst) Hi team. I hope the connection is okay. I'm just calling from overseas. A quick question on the Sangomar drilling results that were referred to there, which factored into some of the reserves changes for Sangomar. Can you give us an update on what the latest drilling results - what they are, what the implication is for Sangomar and particularly Sangomar Phase 2 if there is any read through for that?

Meg O'Neill: Yes, great question Saul. The Phase 1 results actually have been really close to prognosis throughout. The only well that I think we commented on specifically was one of the exploration wells which was the SNE North-2 well which was a potential nearfield tie back opportunity. That encountered gas and we abandoned it as was part of the initial drilling plan. We will continue to assess whether or not there is opportunity there. As we have talked about from the beginning with Sangomar there’s two main reservoir horizons that we were targeting the S500 sands and as I said the drilling results there have been coming in really close to prognosis. That's the - we call it the sweet spot of the field.

Then we have got the S400 sands which are laterally extensive high in place but questions about connectivity and we won't be able to really understand Phase 2 until we get some of that dynamic data, particularly in the S400 section. So, it's still open questions around what Phase 2 would look like, but if you look at our history in fields like this, I would fully expect that there will be in fill opportunities and there will be future phases of development, but we do need that dynamic data to figure out exactly what those look like.

Saul Kavonic: (Credit Suisse, Analyst) Thank you and one more I guess following on from a lot of balance sheet questions, but perhaps I'll just ask quite a specific one. Is Woodside willing to go above its 10% to 20% gearing target for a single year in a high capex year in order to try and smooth out and maintain an overall dividend payout? Is that something you would consider for particularly the 2023 year?

Meg O'Neill: Yes, absolutely Saul. I think Graham described it well by talking about us being on the low side of the range this year. If we had paid out the dividend last year we would have been at 9%. The 10% to 20% is a gearing target range through the cycle so there may be periods where we fall below and there may be periods where we go above, so I would use that as a soft guard rail and not as a hard limit set.

Saul Kavonic: (Credit Suisse, Analyst) Thank you. That's all from me.

Meg O'Neill: Thanks Saul.

Operator: Your next question comes from Mark Wiseman with Macquarie Group.

Mark Wiseman: (Macquarie Group, Analyst) Hi, g'day Meg, g'day Graham. Thanks for the updates. I have a couple of questions, one on the Bass Strait in the context of the Government intervention. I was just wondering if you could provide a bit of an outlook for the investments in the Bass Strait and the reduction in

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capacity at the Longford Gas Processing Plant. Could you maybe just help us understand how much of that capacity is going to be permanently closed in terms of gas processing and just on the government consultation piece, are you able to provide a bit of colour just on how those discussions are going? Are you getting more confident that the government realises the impact that they're having on the market and perhaps could we end up with a more reasonable outcome here?

Meg O'Neill: Thanks Mark. So, Bass Strait, there's probably a few projects to talk about. You will be aware that the joint venture and this was pre-merger sanctioned the Kipper Compression project. That was sanctioned in October 2021 targeting RFSU in 2024, so that project is underway. When you step back and look at Bass Strait in aggregate, we are in a mature basin, these fields are mature and production is declining and so we are working very closely with the operator to define projects to ensure we have the capacity that fits the production that is flowing through it to make sure that we are managing the costs of running these assets.

Obviously we would be keen to continue to bring new gas to market in the east coast of Australia. You will be aware we were looking at some opportunities for bringing LNG across. With the government intervention there is great uncertainty and so we have paused and you will be aware that the Bass Strait joint venture for this year only approved a six month budget because of the uncertainty. It's very difficult to make investment decisions when there's this residual uncertainty around the prices that we will be able to get for our commodities. I think it is a certainty that the production for Bass Strait is declining and as that happens we need to make sure we are managing the costs as well and managing the capacity of the facilities.

From a government consultation perspective, we have been having a lot of discussions, as have many other members of the industry. Look, I think there is an understanding of the complexity of the market. I don't want to signal too much. I guess you’re probably best question posed to the government around are they going to be thinking about different solutions than what has been tabled thus far. I do feel pretty positive about the quality of the conversation we are having, about the recognition that our business, the Bass Strait business, all we are selling to is the domestic market and we are keen to continue to support that market. We know households and small businesses depend on it.

Mark Wiseman: (Macquarie Group, Analyst) Okay, that's great, thank you. Just finally from me, just on the Sunrise project. In the last couple of updates it has sounded like you're getting a bit more positive on that asset. I was just wondering how those PSC discussions are going and how are you thinking about the concepts at this point in time?

Meg O'Neill: Yes, so Mark, we announced to market, it was probably a few weeks ago, that the Sunrise joint venture has agreed to start some formal work on concept select looking at options to process the gas in Australia as well as options to process gas in East Timor. The venture is going to conduct those technical studies. The PSC discussions are continuing. The thing that is probably most encouraging for us is we do have a real clear signal from both the Australian Government and the East Timor Government that they are keenly interested in this opportunity progressing. I think that government engagement and the government's desire to move things forward is something that is very positive and something that I think will catalyse a bit of action in the venture. But it’s still going to be a long road ahead for us. The technical work is part of it, the commercial work is part of it, the government negotiations are part of it and we will just keep pushing on all those fronts and hopefully be able to move this opportunity forward.

Mark Wiseman: (Macquarie Group, Analyst) That’s great. Thank you.

Operator: Your next question comes from Nik Burns with Jarden Australia.

Nik Burns: (Jarden, Analyst) Oh, thanks Meg and Graham. Just a couple of questions from me. The first one, one of the shining lights in 2022 looking at this segment data is from your marketing team. If I’m right I think profit before tax was up 140% versus the prior year. We’ve seen the strong LNG trading margins coming through in your quarterly reports. It feels like LNG markets are less volatile right now versus last year and if we look ahead, if that lower level of volatility continues through this year does that mean the arbitrage

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opportunity available this year will be less and should we expect lower margins coming out from that team this year? Thanks.

Meg O'Neill: Yes, that's an interesting question Nik. If we look at 2021 versus 2022, we actually did a lot more trading in 2021. 2022 the market was in what was extraordinarily tight and so there was a lot less pure trading going on. What you do see in our segment earnings is the benefit of optimisation. Our marketing team was able to come up with a lot of creative ways to increase the value of our produced LNG business. The second aspect to the marketing business of course is our Corpus Christi position. You will see that that's also turned the corner last year to be quite profitable and that's profitable even after the hedge loss.

The outlook going forward. Look, we are seeing more liquidity in the markets and we are seeing prices of course have fallen off a bit and China we expect to come back into the market. There is still a bit of an open question around what is going to happen in Europe. They appear to be finishing the winter with storage in a pretty good position but prices are now at the point where we may start to see some coal to gas switching. So I think the volatility that we have seen over the past years is likely to persist into the coming years. The marketing team is ready to go. What we I think have historically guided is that for the pure trading part of our business that the margins normally are quite slender, but where we can really make a big difference and you certainly saw it in the segment of this year is in the optimisation…

[Technical difficulty - audio cuts out]

Operator: I will now hand back to Ms O'Neill for closing remarks.

Meg O'Neill: All right. I hear from the team that there is still a few folks in the queue and apologies that we didn't get around to answer everyone's questions. We know who you are and so our team here will follow up offline. Appreciate everyone for joining us on the call today and I look forward to meeting with many of you in the coming weeks. Thank you.

End of Transcript

Contacts: INVESTORS MEDIA Matthew Turnbull (Group) Christine Forster M: +61 410 471 079 M: +61 484 112 469 E: christine.forster@woodside.com Sarah Peyman (Australia) M: +61 457 513 249 Rohan Goudge (US) M: +1 (713) 679-1550 E: investor@woodside.com

This announcement was approved and authorised for release by Woodside’s Disclosure Committee.

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