Exhibit 99.3
| Announcement |
| |
| Tuesday, 25 February 2025 | 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 | ||
FULL-YEAR 2024 RESULTS BRIEFING TRANSCRIPT
Date: 25 February 2025
Time: 07:00 AWST/10:00 AEST (17:00 CST on Monday, 24 February 2025)
Start of Transcript
Operator: Thank you for standing by and welcome to the Woodside Energy Group Limited Full Year 2024 Results. All participants are in a listen only mode. There will be a presentation followed by a question and answer session. If you do 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 the conference over to Ms Meg O’Neill, Chief Executive Officer and Managing Director. Thank you. Please go ahead.
Meg O’Neill: Good morning, everyone and welcome to Woodside’s 2024 Full Year Results presentation. We are presenting 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 and present.
Today I am joined on the call by our Chief Financial Officer, Graham Tiver. Together we will provide an overview of our full year 2024 performance before opening up to Q&A. Please take time to read the disclaimers, assumptions and other important information. I would like to remind you that all dollar figures in today’s presentation are in US dollars unless otherwise indicated.
I am very pleased to present an outstanding set of full year results today. Leveraging our proven track record of operational excellence, disciplined investment decisions and world-class project delivery, we are rewarding our shareholders while laying the foundations for a new chapter of value creation. During 2024 we took significant steps across all three goals underpinning our strategy to thrive through the energy transition, providing energy, creating and returning value to our shareholders and conducting our business sustainably.
Outstanding performance at Sangomar drove record annual production in 2024 of 194 million barrels of oil equivalent at the top end of the full-year guidance range. We made excellent progress on our major growth projects at Scarborough and Trion, while investing in new opportunities set to deliver decades of growth and value.
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Our reliable and cost competitive base business has translated into strong financial performance and a fully franked total full-year dividend of 122 US cents per share, once again at the top of our payout range. And we delivered on our climate commitments further reducing our net equity Scope 1 and 2 emissions in 2024 to 14% below our starting base. Looking across Woodside’s global business we are strongly positioned to provide energy the world needs while delivering value to our shareholders.
Our key operational performance and financial outcomes demonstrate how well our base business is performing. In 2024, we combined record production with increased efficiency reducing our unit production cost to $8.10 per barrel of oil equivalent, an outstanding result in an inflationary environment. Our net profit after tax of $3.6 billion was a significant increase on 2023, as were our earnings per share of 189 US cents per share. We reported an underlying net profit after tax of $2.9 billion.
The tragic death in October 2024 of a construction contractor employee at our Beaumont New Ammonia Project is a painful reminder of the need for constant vigilance and continuous improvement in our safety performance. Our growing business saw a greater volume of hours worked in 2024. It’s positive that during this period of increased exposure we did not record any permanent injuries or Tier 1 process safety events, however we remain focused on further strengthening our safety culture, simplifying our processes and improving our systems.
While the full impact of these initiatives will take some time, we are already seeing some positive results. The outstanding safety record achieved at our Sangomar project and during delivery of the Pluto Train 2 modules, shows what we are capable of and sets the required standard for Woodside going forward.
In 2024, we made transformative decisions that we are confident will reap future benefits for our shareholders. Through targeted acquisitions and excellence in project execution we are expanding our high quality and geographically advantaged portfolio. We are more than offsetting declining legacy production with new growth opportunities and expect a 4% to 5% compound annual growth rate for portfolio sales from 2024 to 2030.
This positions the Woodside of the 2030s to be a business that is even better placed to capitalise on growing global energy demand. The decisions we take today are also positioning Woodside to generate substantial cash flow over the next decade. Following Sangomar start up and as Beaumont New Ammonia, Scarborough, Trion and Louisiana LNG come online, we expect to be generating significant free cash flow in the years ahead. This enables more options to reward our shareholders on top of our established track record of dividend distributions.
I will now turn to the global market environment and our firm belief that LNG will continue to play an important role in the energy transition. The essential drivers of global energy demand, growing populations, economic development and rising living standards underpins strong growth in LNG demand over the next decade. Emerging Asia is expected to be a key driver of demand as these nations seek to reduce the reliance on coal while maintaining grid reliability and energy security.
There is a sizeable opportunity for LNG suppliers to support this transition. For example, switching 20% of Asia’s coal fired power stations to gas would require 310 billion cubic metres of gas per year, roughly three times the volume of Australia’s annual LNG exports. New long-term supply agreements we executed with major Asian energy customers during 2024 reflect the ongoing robust demand for LNG within our region.
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In recent briefings I’ve drawn on incorrect predictions from the past to highlight why a so-called LNG supply glut is unlikely to materialise in the years ahead. Events over the course of 2024 give us even more confidence that this will be the case. Compared to forecasts in late 2023, we see project delays causing almost 30 million tonnes per annum of supply growth to slip beyond the end of this decade.
Ongoing strong demand through this decade with a significant supply gap emerging in the 2030s continues to firm as the most likely scenario. This will result in a strong price environment as customers continue to seek LNG from secure reliable suppliers. Periods of heightened volatility in the market, like we experienced in 2022, have demonstrated the crucial role LNG plays in maintaining global energy security.
As nations around the world seek to build out their renewable energy networks, gas will play an important role in backing up these networks and smoothing out volatility caused by periods of intermittence. LNG is a globally mobile energy source that can be plugged into existing networks and flexed to meet fluctuating demand making it a prized commodity for a nation seeking to maintain energy security as they decarbonise.
Underpinned by these strong market fundamentals, our reliable and cost competitive base business continues to meet customer needs and drive value for shareholders.
As I mentioned earlier, Woodside’s world-class operational capabilities are demonstrated by consistent high reliability and strong operating cost control across our global asset base and our teams continue to find new ways to extend the production life of key operated assets, increasing our proved reserves and allowing us to extract additional value from our base business. In this regard, it was pleasing to receive Western Australian State environmental approval late last year to extend the operating life of the North West Shelf project. We are hopeful of receiving Federal approval soon to underpin ongoing reliable supply from this significant asset.
Early production performance at our Sangomar project has been exceptional with nameplate capacity of 100,000 barrels per day achieved within nine weeks of startup. This fantastic result is underpinned by excellent reservoir productivity and connectivity, leading us to increase proved reserves and extend our production plateau forecast into the second quarter of 2025. We are also evaluating Phase 2 development options.
We have sold Sangomar crude to buyers in Asia, Europe and the US and earlier this month we supplied the first cargo to Senegal’s domestic refinery. We have made excellent progress with our Scarborough Energy project, 80% complete and on track for first LNG cargo in 2026. The image on the slide showcases the successful completion of the Pluto Train 2 module program with all 51 modules now in position.
Another major milestone during 2024 was installation of the 433 kilometre trunk line. Our development drilling campaign is going well and last week we welcomed the Commonwealth regulator’s acceptance of the offshore facility and trunk line operations environment plan. During 2024 we were also pleased to welcome two strategic partners to the Scarborough Joint Venture, LNG Japan and JERA, demonstrating our ability to attract high quality partners to this important Woodside operated project.
Moving to Trion. We remain on track for first oil in 2028. During the year all major contracts for the project were awarded and we transitioned into the construction phase with work commencing on the floating production unit. The importance of Trion to Mexico’s energy future was reinforced in 2024 following a declaration as a priority project within Mexico’s national energy plan.
While progressing our growth projects we continued to advance the two acquisitions made in 2024. At year end Phase 1 of our Beaumont New Ammonia project was 83% complete. We are targeting first ammonia production in the second half of 2025 with lower-carbon ammonia targeted for the second half of 2026. As I highlighted at the time of our acquisition, Beaumont is a competitively advantaged, de-risked investment offering strong commercial and strategic rationale. We expect it to quickly generate strong returns and cash flow once production hits steady state.
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Our acquisition of Tellurian and the Louisiana LNG development was a defining moment for Woodside in 2024 positioning us as a global LNG powerhouse. We are tremendously excited at the opportunity Louisiana LNG presents for long-term value creation leveraging Woodside’s proven strengths and project execution, operations and marketing. We are moving toward FID readiness from this quarter, with site construction activities progressing well under our EPC contractor, Bechtel.
Consistent with the approach taken for the selldown of Scarborough and Pluto Train 2, we are focused on attracting high quality partners who share Woodside’s vision for this project and we are pleased with the strong interest shown from multiple parties. As I’ve stated previously, we will exercise discipline in the selection of our partners and key decisions in relation to Louisiana LNG to maximise shareholder value.
While 2024 was a year of significant growth in our global portfolio, it was also a period of streamlining Woodside’s asset base to prioritise assets and activities that deliver maximum value for shareholders. Our Australian asset swap agreement with Chevron announced in December, consolidates our focus on operated LNG assets and unlocks future development opportunities through the North West Shelf.
We are demonstrating similar discipline across our new energy opportunities. With the acquisition of Beaumont New Ammonia, we have slowed work on H2OK. We are also reducing exploration activity to focus on delivering value from the assets currently in our portfolio. I will now hand over to Graham to provide an overview of our financial strategy and performance.
Graham Tiver: Thanks, Meg and hello everyone. Our financial performance and balance sheet have remained resilient because of our strong underlying business and our consistent approach to capital management. Let me highlight here that our capital management framework remains unchanged. We remain committed to an investment grade credit rating. We target a gearing range of 10% to 20% through the cycle and as I have stated previously, may move outside the range at times. We will however return to within our target gearing range by utilising the various levers at our disposal. As a result, the framework provides us the flexibility to balance funding value accretive growth while delivering strong shareholder distributions and when Scarborough is online, the cash generation will provide an opportunity to look at additional returns.
We run our business with a consistent cost focus. Despite inflationary pressures over 2024, we continued to keep unit production costs down and cash conversion up. We continue to be disciplined in our application of the capital allocation framework to maximise value for our shareholders. As an example, the selldowns of Scarborough to high quality partners, reaffirmed its value with cash proceeds of $2.3 billion strengthening our liquidity.
Knowing the importance of dividends to our shareholders, we assume a dividend payout ratio at the top of our range when evaluating financial scenarios, even at stress case. We also actively manage our debt portfolio. We continue to access premium debt markets and receive strong support. For example, our $2 billion bond issuance in September 2024 was oversubscribed nearly four times.
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Looking at our 2024 financial performance, we continue to deliver outstanding returns from our base business despite lower average realised prices. Exceptional early production performance from Sangomar, strong cost control and the successful selldowns of Scarborough, contributed to a peer leading EBITDA margin of 70%. This translates into another healthy fully franked dividend payment representing a full year yield of 8% at year end.
Cash flow generation through 2024 was strong delivering a cash margin above 80% which has been sustained consecutively for four years. The business continues to generate strong cash flow through this period of investment. For example, if we back out the impact of acquisitions and divestments in 2024, free cash flow would increase to $1 billion despite investing in our near-term production growth projects of Sangomar, Scarborough and Trion.
Our balance sheet is well positioned and our liquidity remains strong supporting our capacity to meet future investment commitments as well as returning cash to shareholders. This is how we have created and returned value to shareholders in 2024. I will now hand back to Meg.
Meg O’Neill: Thanks, Graham. Conducting our business sustainably is one of three goals underpinning our strategy to thrive through the energy transition. Our strong performance in 2024 has seen Woodside maintain strong overall sustainability ratings from external benchmarks. Key to this is a climate strategy for all our shareholders that balances ambition with discipline and achievability. We only set targets where we have identified a pathway to meet them.
Woodside’s climate update released today demonstrates how we are doing this. By the end of 2024 our net equity Scope 1 and 2 emissions were 14% below the starting base, putting us firmly on track to meet our 2025 and 2030 targets. We also took a step-change towards achieving our Scope 3 investment and abatement targets through our acquisition of Beaumont New Ammonia. Woodside’s increased position in the Angel CCS project, to be acquired through our asset swap with Chevron, further demonstrates our intent to address Scope 3 emissions.
Conducting our business sustainably also extends to supporting community development wherever we operate. Our 2024 performance has shown yet again that when Woodside performs well, the economies and communities where we operate benefit significantly. With our business in a growth phase, we are injecting billions of dollars into local economies through the purchase of local goods and services. In 2024, this was more than $7.9 billion, including $5.1 billion in Australia.
Our strong financial performance also translates into billions of dollars of revenue for governments. On the most recent Australian Government figures we are the fifth largest taxpayer in Australia and the largest payer of petroleum resource rent tax. We were also pleased during 2024 to continue our significant social investments in the communities where we live and work.
Our total contribution spend of A$35.4 million included community investments across our expanding global footprints, ranging from education programs in Trinidad and Tobago and Mexico, to sustainable waste management in Senegal. In addition, we were pleased to announce last month, a A$50 million commitment towards education and cultural infrastructure in our home state of Western Australia. I look forward to providing investors with an overview of Woodside’s sustainability strategy and 2024 performance at a briefing scheduled for early April in Melbourne.
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I’d like to close by recapping on Woodside’s compelling investment case as we look to 2025 and beyond. In 2024 we demonstrated disciplined execution of our strategic goals, doing what we said we would do and we plan to do the same again in 2025 with key milestones to be achieved as we build the foundations of a global LNG powerhouse. We are focused on executing our growth strategy, progressing new opportunities for long- term success and delivering strong and consistent returns. We are well placed to reap the benefits of our achievements and decisions in 2024, building a strong and cash-generative business that delivers enduring value for our shareholders. Thank you.
I’ll now open the call to questions. Please limit your questions to two each so everybody has an opportunity to ask their questions.
Operator: Thank you. If you do wish to ask a question, please press the star key then one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press the star key then two. If you are on a speakerphone, please pick up the handset to ask your question. Also, as requested, we ask you please limit your questions to only two per person. Thank you, your first question is from Gordon Ramsay from RBC. Go ahead, thank you.
Gordon Ramsay (RBC, Analyst): Thank you very much and congratulations Meg and team on a solid result. Just in the appendix in your presentation, I’m looking at slide 37 and it looks like you’ve moved forward some of the decommissioning costs that you were previously advising on. Can you just comment on what’s driven that?
Meg O’Neill: Sure, thanks for the question, Gordon. So a couple of things with the decommissioning program. We last communicated a graph like this to the market in our 2023 Investor Briefing Day. We’ve seen a couple of changes, so the approval delays that we encountered in 2023 meant some of the work we’d expected to complete in 2024 has extended into this year. The key focus of the activities this year really are cleaning up legacy assets and if you look at the names of the fields listed there, heavy activity in fields like Stybarrow, Enfield, Griffin and Minerva. Once these scopes of work are complete, those fields and the leases will be complete, so there will be no enduring spend for those assets.
Bass Strait, the profile is, I would call it a little bit lumpier, so we do continue with extensive P&A campaigns. That’s been going on for a number of years in Bass Strait. We do have a big milestone ahead of us in 2027 where we will be removing a number of the platforms. So you’ll see a continued bit of lumpiness in the profile, 2026 will be a more modest spend, as indicated in the charts, 2027 will be a bigger number and we’ll guide the market to that as we get closer to the date and firm up the execution plan. But beyond 2027 we should return to call it a steady state level of activity in the decommissioning space.
Gordon Ramsay (RBC, Analyst): Just to confirm, this is cash spend?
Graham Tiver: Gordon, yes, confirming that is, what we’re showing here is the proposed cash spend. Where you do see the P&L impact in other expenses, that is in the A1 segment note, that is related to a provision update for the closed sites, so the sites Meg was just talking about, Stybarrow, Enfield and Griffin, but it’s important not to double count or get that mixed up with the cash outflow and that’s what Meg’s been referring to on this slide.
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Gordon Ramsay (RBC, Analyst): Okay and second question if I may, just on Beaumont New Ammonia, that project’s now completing, 83% complete, just wanted to get a feel for how that’s comparing to target to get an IR of greater than 10% in your new energy projects.
Meg O’Neill: It’s going well. As we communicated when we announced Beaumont New Ammonia, we expect to reach 10% and have upsides beyond the 10% target for New Ammonia investments [Clarification: “New Ammonia investments” should be “New Energy investments”]. One of the things we included in the pack this year, Gordon, is a bit of guidance around the ongoing unit cash [cost] of production, so that’s $260 to $300 per tonne. That’s the steady state Opex when we get to call it 2027 to 2029, so when CCS is up and running, but we thought that would be helpful for the market to be able to do your own back-of-the-envelope calculations and look at things like ammonia forward curve prices. That will help you calibrate your models. But we do expect to meet our capital allocation framework and see opportunity to go well above that.
Gordon Ramsay (RBC, Analyst): Thank you, Meg.
Operator: Thank you. Your next question is from Nik Burns from Jarden Australia. Go ahead thank you.
Nik Burns (Jarden Australia, Analyst): Thanks. Hi Meg and team. First question, late last year you signed an EPC contract with Bechtel for the construction of Louisiana LNG. That contract contemplated three LNG trains. Can I just get an update from you in terms of when you get to FID in the coming months? Will it be for two LNG trains or three? Thank you.
Meg O’Neill: Sure, first off it’s worth highlighting that having a priced EPC contract with Bechtel is differentiating. So if we look at many of the competing US Gulf Coast or even the Mexican Gulf Coast projects, there are very few that have that attribute, so we’ve got everything fully locked in with Bechtel from a pricing perspective. It is for three trains and the marketing we’ve been doing with our potential partners is focused on that foundation development of three trains.
Now the mechanics with which we progress to full notice to proceed, the first notice will be for Trains 1 and 2 and there will be a subsequent notice for Train 3. But again, the pricing is based on three trains and our expectation and the expectation we’re communicating to all of our prospective partners is that the plan is to move ahead with the foundation.
Nik Burns (Jarden Australia, Analyst): Got it, thanks Meg. My second question, just picking upon Graham’s comments that Woodside would consider additional shareholder returns post the startup of Scarborough, shall we interpret that comment to mean the expected gearing to peak just after the startup of the Scarborough project? Thank you.
Graham Tiver: Thanks Nik. So I guess if we take a step back, we’ve discussed about our three near-term growth and positive NPV projects being Sangomar delivering very well, you’ve seen deliver $950 million cash to Woodside in the first seven months of operation, so that’s 24-26. We have Scarborough coming online which will start to deliver significant cashflow, 28 is Trion.
So in terms of our debt profile, as that cash starts to flow, yes we do see the turning point in our gearing, if you want to call it and also having the ability to have excess cash available to us from 27 onwards. So 25 and 26 we will see our net debt grow based on a positive FID for Louisiana, but once those Scarborough flows start to kick in, it does give us flexibility and optionality as we move forward.
Nik Burns (Jarden Australia, Analyst): Thanks great, thanks Graham.
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Operator: Thank you. Your next question is from Saul Kavonic from MST. Go ahead, thank you.
Saul Kavonic (MST Financial, Analyst): Hi. First question, it’s reported in the press that Louisiana selldown process is advancing and data room’s been closed etc, so I might assume you’ve had some early indications of bids coming in. Meg, can you give us some more colour on that process and particularly I think you made some comments last year that you’re expecting a premium for any selldown price, are you still expecting a premium and if so, are we talking very modest premiums or should we be looking at valuations implied by some of the US LNG analogues?
Meg O’Neill: Yes, thanks for the question, Saul and thanks for also highlighting the valuation that our US peers in this space, companies like Cheniere and Venture Global are attracting. We view ourselves as warranting the same sort of premium and so we do see a lot of opportunity with Louisiana LNG to bring in quality partners. To your question on the selldown, so we are well advanced in that process. We have a number of high-quality counter parties with whom we are negotiating as we speak.
The pricing point we will communicate in due course, but bear in mind, Saul, the key thing that we’re focused on with the selldown is making sure we have those co-investors to share the capital investment. There is still quite a bit of spend facing us ahead as we move forward into this investment, so we’re focused on getting partners who will share the capital, see that same long-term value that we see and we’ll be getting a price that we think is attractive and fair for our shareholders.
Saul Kavonic (MST Financial, Analyst): Thank you. Can I also ask about Sangomar Phase 2 progress, the update last week seemed to derisk Phase 2, there’s potentially a few hundred millions of barrels of resource there that could become reserves. Can you give an indication of when we might get an update on reserves for Phase 2 and how we should think about value in that regard?
Meg O’Neill: Sure. So as we’ve said, probably since pre-FID, the S500 isands are the high-quality reservoirs and we’re really seeing outstanding production from those reservoirs. Where there is quite a bit of in-place oil is in the S400s, which are geologically more complex. What we’ve seen thus far is enough connectivity to remove some of the low side cases off the table, but we do need to get more production performance and more data from the wells that we have in place to understand what exactly does Phase 2 look like and we’ve said we probably need 12 to 24 months of data to inform decision making in that space.
We will continue to book reserves as data comes in. You would have seen we booked reserves late last year that was based on the initial production performance. As we get more information on water injection, we will continue to migrate reserves from 2P to 1P. Saul, it’s worth reminding the audience here that with our US secondary listing, we report 1P reserves in a manner that’s defined by the SEC, so it’s a very rigorous and tight process for defining 1P and very tight rules for migrating. So we still believe that we’ll recover the full 2P that we sanctioned at the time of FID, but the migration to 1P will follow those SEC rules and it links to reservoir performance.
Saul Kavonic (MST Financial, Analyst): Thank you.
Operator: Thank you. Your next question is from Tom Allen from UBS. Go ahead, thank you.
Tom Allen (UBS, Analyst): Good morning Meg, Graham and the broader team. I was hoping you could please provide a comment just on the production outlook for the producing US oil projects, just noting that we saw a very modest 2P reserve cut to Mad Dog in the release last week, it was just a little bit surprising just given that the big Mad Dog phase 2 development and Argos platform is still fairly new. Was there anything that you’re seeing in the subsurface that looks challenging that BP has done at Mad Dog or anything across those three US producing assets?
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Meg O’Neill: Yes, thanks Tom. So you would be aware that we took an impairment on Shenzi in 2023, we saw some disappointing performance out of the Shenzi North development in particular. With Mad Dog, it’s really a matter of timing for getting wells online and that was the bit of the factor that underpinned reserve adjustments there. We do still have quite a bit of drilling ahead of us and as we look forward, we do see the US Gulf as continuing to be a very important part of our portfolio well through the 2030s. For example, we still have the Mad Dog South West development to bring on, we have other satellite developments at Atlantis, so particularly those two big assets we do see continued development ahead of us and those will be part of our portfolio for the long-term.
Tom Allen (UBS, Analyst): Thanks Meg. For my second question, just a comment please on the outlook for the North West Shelf. Now that the asset swap with Chevron has been executed, obviously supports better alignment in the North West Shelf joint venture to spend money pursuing potentially other resource to backfill the plant or pursue tolling options. So looking hopefully for a comment on opportunities that the joint ventures see there that you might go after over the next couple of years.
Meg O’Neill: Yes, so we’re excited about North West Shelf. It’s an asset we know extremely well and we have every intention of squeezing as much gas out of the field as we possibly can. Last year we sanctioned the Lambert West development, that’s an infill tieback that’ll be drilled this year. We also sanctioned a project to lower the back pressure on the Goodwyn Platform with some modifications to the compressor. Again, that’s to get more gas through the system, get more gas out of the reservoirs. We’re working, scoping some additional subsea tiebacks that would be packaged together as Greater Western Flank Phase 4, so continued work to figure out how do we squeeze more gas out of this reservoir.
One of the things though that’s going to be important is getting that federal government approval for North West Shelf life extension. I’m sure as everyone on the call knows, our current approval is valid until early 2030, so we do need to get that approval to give ourselves confidence in investing for the long-term. The second phase for North West Shelf is tolling and we continue to talk to players in onshore Perth Basin about bringing some of their gas through the plants. Then the Browse resource is the biggest tolling opportunity and the Browse and North West Shelf joint ventures continued to have discussions about what’s the best way to develop the Browse gas.
Tom Allen (UBS, Analyst): Thank you, Meg.
Meg O’Neill: Thanks Tom.
Operator: Thank you. Your next question is from Dale Koenders from Barrenjoey. Go ahead, thank you.
Dale Koenders: (Barrenjoey, Analyst) Morning. It’s just interesting the comment around delivering $150 million cost reduction in 2025, wondering about the scope of works base this year and how much of this is already included in production guidance, cost guidance?
Graham Tiver: Yes, so Dale, thank you for the question. What we’re talking about here, the $150 million, a portion of it is factored into the unit cost, but the majority of it relates to expenditure that will not factor into the EPC calculation, so we’re talking around exploration, Meg spoke in her speech around focusing the new energy business in on BNA, Beaumont New Ammonia example. So small portion in the unit cost, we’ll continue to keep really tight control on our unit costs and we’ll continue to manage them closely, but majority of this is separate and is related to exploration, new energy and corporate costs.
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Dale Koenders (Barrenjoey, Analyst): Thanks for that, Graham. Then just in terms of, I guess thinking about those Beaumont cash cost guidance and thanks for providing that, just wondering what are you assuming in terms of Henry Hub price or price range within that?
Graham Tiver: Yes, so it is a range and that’s why we’ve provided the range, but similar to what it has been over the last six to nine months, Dale, so let’s just say around the low threes.
Dale Koenders (Barrenjoey, Analyst): Okay and if I can just sneak one more in, it seems to be the market is a bit worried about you FID-ing Louisiana LNG without a selldown, which seems to be an FID date that’s fixed given the limited to notice to proceed, should we be, I guess, not worried and think that a case like Scarborough could proceed where you’ve already got partners all but locked in, I saw the comment of marketing with possible partners would suggest is pretty progressed, high conviction in the quality of those partners, but just a need to keep moving forward until final approvals are signed off, how are you thinking about that?
Meg O’Neill: Yes, Dale, it’s worth nothing what we’ve said is we want to be FID ready from the first quarter of this year and the teams are working very hard to that objective. But we would not take FID without confidence that we have partners either signed up already or extremely close to signing up. I think Scarborough Pluto Train 2 is a fantastic analogy, so with the whole Scarborough development we were able to secure a selldown of 49% of Pluto Train 2, kind of coincident with FID. Then we were patient to bring in other partners to the offshore resource.
So look, we’ve seen great interest. I think there’s potential for us to have the whole 50% sold down by FID, but again, it is complex commercial negotiations, so we will be certainly well advanced, if not signed with one key partner and then continue to be progressing. But the team have certainly got their skates on, we’re deep in negotiations with a number of, as I said, high-quality counterparties and we’ll let the market know when we’ve got something announce-able.
Dale Koenders (Barrenjoey, Analyst): Okay, brilliant. Thanks for that, Meg.
Meg O’Neill: Thanks Dale.
Operator: Thank you. Your next question is from Jennifer Hewett from Australian Financial Review. Go ahead, thank you.
Jennifer Hewett (Australian Financial Review, Journalist): Good morning. I was just wondering what would happen, you talked about the fact that you were very disappointed that it had taken six years to get State Government approval for North West Shelf expansion, are you disappointed by the federal government delay and if in fact there is a minority Labor government, do you think that would mean further delays and what would be the significance of that for your thinking in terms of investment?
Meg O’Neill: Yes, thanks Jenny. Look I continue to be pretty frustrated that it’s taken more than six years to grant approval to extend the life of an asset that’s been operating for 40 years when we’re not planning to do anything that’s outside the fence line we’ve already established. We’re at the point where we’re looking at business decisions that are ahead of us, things like drilling new wells to bring new gas to the markets, particularly the domestic gas market, which needs it as early as 2028 and we’re having to ask ourselves can we make that decision with confidence not knowing if there’s federal approval is going to be granted. Look, we’re disappointed that they continue to request more time.
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I think it’s proof of some of the challenges that Australia faces in the approvals environment that you’ve got things like reconsideration requests that come in at the eleventh hour where proponents who have no skin in the game can ask the Minister to review decisions that were made 40 years ago. We think about what this means for our workforce up in Karratha, what does this mean for our workforce at the mine sites that depend on our gas to keep going. There’s families whose lives are at stake [Clarification: “lives” should be “livelihoods”]. So, very frustrated. I’ll leave it there. Hopefully, we’ll get an approval before the election.
Jennifer Hewett (Australian Financial Review, Journalist): If you don’t get an approval before the election, will that make it more dicey do you think, given the likelihood of a minority Labor government dependent on Greens and Teals?
Meg O’Neill: I think the outcome of further delays means more coal in the energy mix longer, so if you’re serious about the environment you’d approve this.
Jennifer Hewett (Australian Financial Review, Journalist): Thank you.
Meg O’Neill: Thanks, Jenny.
Operator: Thank you. Your next question is from James Byrne from Citi. Go ahead, thank you.
James Byrne (Citi, Analyst): Good morning, team. So, Louisiana LNG, just thinking about the selldown process. Assuming you do quite well out of that and there’s a gain on sale, this is obviously a catalyst that we’re all focused on as a market, how do we think about that gain? Because you actually bought the corporate entity of Tellurian as opposed to buying project equity so what’s the base there that we should think about for a gain on sale?
Then just to be clear, when we think about the 12% hurdle rate, will you take into account gains on sale into that calculation or is it like a pure project IRR that we should be considering?
Graham Tiver: Thanks, James. Look, the gain on sale will be exactly the same as what we treated for the life of the selldown of Scarborough to JERA and LNG Japan. Same concept; there’s accounting rules. Obviously, you’ve got the acquisition price of Tellurian and then we would have to look at the additional Capex and funding that’s continued post the acquisition, so normal standard accounting rules. So, I’m not sure if I’m missing something in your question.
Meg O’Neill: Maybe, Graham, the pointer is for accounting purposes the acquisition was treated as asset accounting. So, in the financial statements - and the team can follow up with you later on the exact page number you’ll see there’s a file note in the financial statements.
Graham Tiver: Yes. It’s very clear in our financial statements what the acquisition costs were and then we would take into account the additional funding post that, and then a portion of that would be recognised against the gain on sale against the proceeds.
Meg O’Neill: With respect to IRR calcs, as we did with Scarborough, we do account for that. We’ve done the legwork and money coming in, if it’s revenue that’s accelerated through selldown, that counts.
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James Byrne (Citi, Analyst): Perfect, thanks. Okay. Second question just for you, Meg, I’m interested in how you think the dynamic is changing for US LNG under a second Trump Presidency. On the one hand I think there’s a little bit of concern in equity market that there’s this big reduction in red tape that’s coming. We saw Commonwealth LNG get its approvals recently, which was earlier than what I’d anticipated and then whether that would increase competition for offtake and equity.
Perhaps on the other side though there’s this almost US exceptionalism where Trump is pressuring allies to buy more US LNG and I’m wondering whether you think that would result in a contract premium in the US versus the rest of the world.
Lastly, there’s talk now of a Ukraine peace deal and whether that might mean that there’s more gas flows probably into eastern Europe as opposed to western Europe. I don’t think anyone expects the same amount of volume is exported but nonetheless, prices are set at the margins it would have a deflationary impact and might make us question the economics of Louisiana. So again, red tape, contract prices in the US and Russian gas.
Meg O’Neill: Thanks. Thanks, James. I think on many fronts, Trump is changing the landscape. The thing that’s really striking for me is all of the competitive advantages that Louisiana LNG has, we’ve got all of the permits we need, we have a priced contract with Bechtel, and I can’t over emphasise how important that is. All of the other projects in this market will have to go back and get repriced.
The other thing that sets us apart is the fact that we are able to progress this between ourselves and our partners funding on balance sheet. Many of the US developers still have to go through the sequential process of securing LNG offtake, using that to then secure financing, in parallel repricing contracts and in inflationary markets. I just do not have confidence that there’s going to be as much competition as simply streamlining the red tape might imply. We’re at least a year ahead of everybody else in the US and we continue to attract a premium from many players who are seriously interested in US LNG.
In terms of price premium, LNG is a highly fungible commodity. I wouldn’t expect any price premium. We may be able to attract offtakers who come from nations that are looking to restore the balance of trade, but I think we’ve seen this in a number of ways in the past, things like low-carbon LNG, people don’t pay more for that. So, we’ll continue to negotiate very competitive pricing. I think Woodside’s reputation sets us apart, the way we partner with companies and customers sets us apart, some of the flexibilities we offer customers which is different from other suppliers sets us apart, and those are the sorts of things that will get us better pricing than others in the marketplace.
Russia and Ukraine, look that’s a bit of a wildcard. Physically, not as much Russian gas will be able to enter Europe as was flowing in 2021. There may be a bit of gas coming into the marketplace, but again when we look at LNG demand growth forecasts for the long haul, and that’s for the latter 2020s and the 2030s, Asia is the engine. Asia is going to be the engine room of energy growth, Asia is going to be the engine room for LNG growth, and it doesn’t materially change our thesis.
James Byrne (Citi, Analyst): Thank you. Appreciate it.
Meg O’Neill: Thanks, James.
Operator: Thank you. Your next question is from Rob Coe from Morgan Stanley. Go ahead, thank you.
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Rob Koh (Morgan Stanley, Analyst): Good morning. First question from me is in relation to the derivative item that went through to P&L, and that was not a surprise because you’d talked to us extensively beforehand, but just wanting to understand (a) should we be looking for that gas price derivative volatility going forward or is this more of a one-off adjustment, and then secondly, is there any natural hedges within the business that we could think about to offset that item?
Graham Tiver: Thanks, Rob. I think you’ve captured it. We’ve provided insight on this for the last couple of years in our accounts. Even though this is a non-cash item, the really important point here is we strongly believe the contract has significant expected value. So, selling the gas linked to a urea price we think is good for the business in the long-term as opposed to a domestic price. There will be - the nature of the fair value accounting required under an embedded derivative…
Meg O’Neill: Sorry, I think he was asking about the Henry Hub. Rob, are you asking about the Henry Hub TTF hedging or are you asking about the urea pricing?
Rob Koh (Morgan Stanley, Analyst): The urea pricing that Graham was just talking about then. Yes.
Graham Tiver: Sorry, I’ll just get back my train of thought now. As a part of that, we have to recognise the embedded derivative, we have to value that component on a half-yearly basis in our half-year accounts and full-year accounts, but what we will do going forward, Rob, is we’ll provide an update on the movement in the embedded derivative in the quarterly production report similar to what we do with our hedging derivatives, so the market will be able to keep up to speed with it. It will continue to be revalued through the life of the embedded derivative.
Rob Koh (Morgan Stanley, Analyst): Yes. Okay, all right. Thank you. Then my next question, and it may be that you’ll be telling us at your climate briefing in I think early April you said, but I note you’ve got a small element of your cost reduction is focused on new energy. You haven’t reiterated the $5 billion investment aspiration by 2030. Can you just maybe give us a sense of how you’re evolving on your climate ambition?
Meg O’Neill: Yes, Rob, nothing has materially changed. We put another document out today called The Climate Update. What has changed is we’ve made a $2.3 billion acquisition of a low-carbon ammonia plant. So, instead of a pathway that would have had us organically pursuing potentially multiple pathways for growth of this new energy and low-carbon business, we’ve taken a material step forward with this single acquisition that we believe is profitable. We believe it meets our investment targets, we believe it’s even got upside potential. We’re very much focusing on delivering shareholder value from the acquisition we’ve made and that’s going to cause us to reduce some of the other new energy-related business development that we would have been doing over the past few years.
Rob Koh (Morgan Stanley, Analyst): Okay, great. Thanks very much and all the best with it.
Meg O’Neill: Thanks, Rob.
Operator: Thank you. Your next question is from Adam Martin from E&P. Go ahead, thank you.
Adam Martin (E&P, Analyst): Morning, Meg, Graham. First question just on Woodside’s equity. It’s underperforming global and local peers in the last 12 months. Just wondering any view on that any changes or how you’re responding, please? Then I’ll come back with a second.
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Meg O’Neill: Sure. Well look, at a headline, one of the things we’re emphasising in our full-year results is the quality of the base business. We have absolutely world-class assets starting with North West Shelf, which is the Marquee LNG development in Australia, Pluto which has been an absolutely phenomenal asset for us since we started up in 2012; Bass Strait continues to be a significant cash generator, and the US Gulf properties.
As you would have noticed in the chart on slide 7, you’ll see that many of our mature assets are declining and so we’re in a period of investing in that next wave of profitable assets for Woodside, but the quality is uncompromised. The same thing, Sangomar, Trion, Scarborough, Louisiana LNG, Beaumont are all Tier 1 phenomenal assets.
Once we get through this high investment phase, we’re going to be in a period of generating substantial free cash flow. That’s the message that we hope shareholders take away from this presentation today.
We know there’s been some questions around the acquisitions and I think that’s probably a little bit why our share price has been a bit suppressed, but the reality is we’ve got absolute world-class assets, we’ve got a world-class team, we deliver strong operations, we deliver on our project commitments, and that allows us to deliver shareholder distributions through this high period of capital investments and well into the future.
Adam Martin (E&P, Analyst): Okay. Thank you, that makes sense. Then just a technical one maybe for Graham, just on these abandonment liabilities or restoration liabilities. They seem to have fallen on the balance sheet in 24 versus 23 but you’ve obviously got the greater spend in 25 versus historical guidance. Just wondering, how often do you update for things like Bass Strait? Clearly, there’s uncertainty on what Bass Strait is going to cost, and Exxon is still working with the regulator. Perhaps you could talk through that, please.
Graham Tiver: Adam, as a part of our processes we will update the provision formally every year towards the end of the year. Obviously, we have a decommissioning team in the US and also in Australia and they’re working these projects and if anything was to come that was unexpected or not necessarily included in the plan, we would update ordinarily, but generally it’s an annual process.
In terms of the accounting side, I don’t want to get confused with the cash, which is what the slide is talking about, on the accounting side. If the operation is operational, it will be reflected through the balance sheet and asset and liability and that will be updated on a regular basis, so when you come to the time of decommissioning you’ve got the liability ready to go, the provision available to cost against.
For closed sites such as Stybarrow, Minerva, et cetera, they will cost - any updates to the provision will be charged directly to the P&L and you see that in the A1 note under other expenses, and that’s clearly laid out there. I just want to reemphasise, we shouldn’t get confused with the P&L Impact of the provision update for closed sites versus the underlying cash outflow which is what the slide relates to.
Adam Martin (E&P, Analyst): Okay. Thank you very much. That’s all from me.
Operator: Thank you. Your next question is from Henry Meyer from Goldman Sachs. Go ahead, thank you.
Henry Meyer: (Goldman Sachs, Analyst) Morning, Meg and Graham. Thanks for the update. The Scarborough and Pluto Train 2 continue to make good progress. Could you expand on the remaining scope and schedule for FPU fabrication, D&C progress and plant construction? As we’re getting closer to potentially first cargo, maybe one year from now, do you have a view to narrow the expected startup timing?
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Meg O’Neill: Sure. So, a couple of key milestones for us. The floating production unit, which is scheduled critical path, is being built in China. The hull and top sides are at two separate yards, so an important milestone for us will be meeting the two structures together. That will happen in the second quarter of this year. Then the facility or the FPU will go to another yard for integration work.
We expect we’ll start towing from China before yearend, and then we go through the hookup and commissioning phase. We need to hook up the mooring lines, hook up the risers, get everything commissioned on the facility, start pulling gas to the beach. Then there’s a period of getting the gas through Train 2. Train 2 is at the stage where we’re completing construction.
As I said, all the modules are onsite so we’re completing construction. We’ll move into commissioning this year. Drilling and completions, that’s progressing very well. All the wells will be drilled and completed, all the wells we expect in this first phase will be done by the end of this year. So, we’re making extremely good progress.
The activities offshore are weather sensitive and so those are the key factors that we’re going to be watching that will drive the exact timeline for getting gas to the floating production unit, then gas to the beach and then LNG. I thought in one of the notes we updated that our expectation is for first LNG in the second half of 2026. That’s the timeline we’re on towards for Scarborough Pluto Train 2.
Henry Meyer (Goldman Sachs, Analyst): Excellent. Thanks, Meg. To expand on some of the previous comments on US LNG exports and Commonwealth, which is making progress towards FID in September, targeting first gas in early 2029, similar to Louisiana, presumably you’d rather lift your own Louisiana cargoes. Are you still committed to the 2 million, 2.5 million tonnes from that project if its sanctioning comes online, and similarly for Mexico Pacific?
Meg O’Neill: Absolutely. As we think about building a portfolio of quality LNG position, being able to get attractively priced offtake is part of the strategy. We have what I think is a pretty fantastic contract with Commonwealth so we would be absolutely keen to include that in our portfolio of LNG offtake, as well Mexico Pacific.
I’m sure you’ve seen some of the news about some of the changes that are affecting that organisation. We signed those agreements with the hope that FID comes and that we get the LNG but one of the things we offer to our buyers is a lot of confidence that with the capability we have both in project development, operations, and marketing that they will get the LNG they want when they want it.
Henry Meyer (Goldman Sachs, Analyst): That’s clear. Thanks, Meg.
Operator: Thank you. We have a further question from Saul Kavonic from MST. Go ahead, thank you.
Saul Kavonic (MST, Analyst): Thanks, Meg, Graham. One last one, just coming back to the dividends, because Woodside got punished quite strongly last week for a dividend miss which was less than $200 million in payout but it’s probably knocked $1 billion off the share price. You’ve now got a dividend payout which can move a few hundred basis points either way based on a urea contract based on forward urea pricing, which adds this level of uncertainty here.
Can you perhaps give us some colour as to why this wasn’t normalised out for dividend purposes and can you give us a level of colour and comfort towards the concerns that ultimately the balance sheet couldn’t withstand an extra $200 million payout here.
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Graham Tiver: Thanks, Saul. Good question. What we do is we remove - moving from our statutory net profit to underlying, it’s more based on recurring - non-recurring items. This is a 20-year contract that starts in 2027. It was recognised upon FID of Perdaman. It is a part of our business that will be around for quite a period of time so we don’t believe it appropriate to normalise, if you want to call it.
I’ll just bring you back to my opening comments in the previous question from Rob, is that the contract is a good contract and we think it will add significant expected value to the business by having it linked to an underlying global urea price versus a domestic price. We’re very happy with the contract itself. We’re dealing with the accounting technicalities of it, if you want to call it. It is ongoing but what we are committed to doing going forward is providing an update on the embedded derivative component of this contract in our quarterly production report, similar to what we do with our other derivatives, and they’re related to our hedging positions.
Operator: Thanks very much. There are no further questions at this time. I’ll now hand back to Ms O’Neill for closing remarks.
Meg O’Neill: Thanks, everyone, for listening in and participating today. I look forward to speaking to many of more of you - many more of you at other upcoming events and continuing to share how we are delivering on our strategy to thrive through the energy transition. Thank you.
Operator: Thank you very much. That does conclude our conference for today. Thank you all for participating. You may now disconnect your lines.
[END OF TRANSCRIPT]
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