Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Good day and welcome to Amplitude Energy Limited FY '26 Full Year Results webcast. [Operator Instructions] And finally, I would like to advise all participants that this call is being recorded. Thank you. I'd now like to welcome Jane Norman, Managing Director and Chief Executive Officer, to begin the conference. Jane, over to you.

Thank you. Good morning, and thank you for joining us for Amplitude Energy's FY '26 Full Year Results. This is Jane Norman, and I'm joined today by Chief Financial Officer, Ian Bucknell; and Chief Operating Officer, Chad Wilson. Today's presentation and announcement were released to the ASX this morning and are available on the Amplitude Energy website. The webcast is being recorded and will be available on our website later today. Please note the disclaimer on Slide 2 before moving to Slide 3. I'll start today by reflecting on our accomplishments through FY '26 before moving to an in-depth review of the financial year in the next section. FY '26 was another strong year of delivery for Amplitude Energy. We achieved record production and record financial results. Performance was supported by continued improvement at Orbost, resilient pricing from our contracted sales portfolio and active gas marketing and trading activities. Importantly, we also made substantial progress advancing the East Coast supply project, which remains a key driver of future growth. The acquisition of a 50% interest in Artisan alongside our existing Annie discovery has further strengthened the resource base underpinning the project. At the same time, we acknowledge that our first exploration well drilled earlier in FY '26 did not deliver the commercial outcomes we had hoped for. Geological success can never be guaranteed and investment decisions are always made with the best information available at the time. Importantly, the exploration program was executed safely, on budget and in accordance with industry best practice. Looking ahead, ECSP economics are underpinned by the Annie and Artisan discoveries. A comprehensive review of exploration results to date has reaffirmed the decision to drill Juliet for additional upside. We expect a final investment decision on the development phase of the project in the near term with the project foundation strengthened and development planning well progressed. We remain on track for first gas in 2028. Turning now to Slide 4. The highlights on this page demonstrate the strength of our operations. Group production increased to a new record of 27.6 petajoules equivalent or 75.5 terajoules equivalent per day. This was towards the upper end of our production guidance range, which itself was upgraded earlier this calendar year. Sales revenue reached a new record of $285.8 million. Despite increased market uncertainty, our average realized gas price increased to $10.36 per gigajoule, while group unit production costs fell to a new record low of just above $2 per gigajoule. This resulted in underlying EBITDAX increasing to approximately $191.8 million with an underlying EBITDAX margin of around 67%. Cash conversion was excellent with adjusted cash from operations reaching $191 million. These outcomes reflect the operating leverage in the business, higher production, higher realized prices and lower unit costs flowing through to stronger earnings and cash generation. With the base business humming, the focus in the immediate term turns to executing the next round of the ECSP drilling safely and on budget and schedule. In the last few days, we have received back the Transocean Equinox to commence the Juliet well, and we expect results by mid- to late September. Success at Juliet will provide a further boost to already attractive project economics and resource life at our Otway assets. The next section of the presentation will speak to the operational and strategic highlights of FY '26 first before Ian covers the financial results and Chad provides more detail on the growth projects and the FY '27 outlook. I'll start with operational details beginning on Slide 6. Safety remains fundamental to how we operate. In FY '26, when more than 0.5 million hours were worked across our activities, we recorded 0 lost time injuries and 0 medical treatment injuries. We have now gone more than 2.5 years without a single LTI, while our total recordable injury frequency rate improved to 1.97, well below the industry benchmark. We also recorded no reportable environmental incidents during this period. This is a strong outcome given the scale of activity undertaken during the year, including the ECSP drilling campaign, offshore maintenance work and a planned shutdown at the Athena gas plant. We continue to progress our environmental commitments through operational flaring reduction initiatives, the Athena Solar PV project and the voluntary offsetting of Scope 1 and Scope 2 emissions. Moving across to Slide 7. Orbost continued to be the main driver of the company's production growth. Average production from Orbost increased to 66.5 terajoules per day in FY '26, and the plant is now operating above its previous nameplate capacity of 68 terajoules per day. The plant's performance reflects the success of the operational improvement program with the sulfur removal system no longer acting as a regular production constraint than it once was. Absorber cleans reduced materially from 21 in FY '25 to just 4 in FY '26 and production downtime also continued to decline. With the plant holding daily production records around 74 terajoules per day over the last 6 weeks, the focus now turns to further reliability improvements and sustaining higher throughput. Importantly, the Sole reservoir continues to perform strongly to support these higher production rates. Please now move to Slide 8. We completed important development work at both our Otway and Cooper Basin assets in the second half of FY '26, which should provide production benefits into FY '27. In the Otway and offshore maintenance campaign, we established communication of the Casino-4 well, bringing it back into production and improving overall cycling of the Casino, Henry and Netherby fields. Since the Athena Gas Plant's planned maintenance in April, our 50% share of production has averaged 8.5 terajoules per day. The plant also recorded excellent uptime over FY '26 with reliability loss of just 0.7% of asset capacity. In the Cooper Basin, production was impacted by natural field decline and first half flooding, but improved in the second half as 3 new Callawonga wells came online. These assets remain small contributors, but they provide valuable free cash flow and portfolio diversity. Now on to Slide 9. At the 30th of June 2026, 2P reserves were 26.7 million barrels of oil equivalent or about 163 petajoules equivalent. The year-on-year movement is largely explained by FY '26 production with no material reserves revisions. Contingent resources increased to 50.8 million barrels of oil equivalent, reflecting additional contingent resource potential at Sole and a modest uplift associated with Patricia Baleen, partly offset by Otway permit relinquishments. These reserves and resource numbers do not include Artisan as completion of that acquisition is yet to occur. If we could go to Slide 10. Here, we show the latest picture of our existing gas contract stack alongside the uncontracted or spot gas exposure for our equity share of total production on a calendar year basis. As you can clearly see, our revenue base is made up of mainly fixed price CPI-linked gas sales contracts. Around 80% of gas sales this year are expected to be contracted under existing GSAs, providing a resilient revenue base while retaining exposure to higher-value spot and recontracting opportunities. The weighted average contract price stepped up by around 20% from January 2026, reflecting annual indexation and the commencement of higher-priced contracts. We will continue to reshape existing arrangements where it makes good economic sense and retain some exposure to spot gas markets. As a reminder, this slide speaks to contracts over our existing production position and excludes volumes from the East Coast supply project. Let's move to Slide 11. The continuous improvement program remains central to how we run the business. In FY '26, around 70 initiatives were completed or in delivery with approximately 1/3 realizing value during the year. In aggregate, the program delivered around $13.4 million in annualized cash flow improvement in FY '26, taking cumulative annualized benefits from our improvement program since FY '24 to more than $50 million. Most of the FY '26 value came from operational improvements at Orbost, including sulfur treatment and capacity improvements, reduced contractor and consumable costs and optimization of operations. The program has also reinforced a leaner operating culture across the business with the team continuing to identify value from production efficiency, waste disposal, maintenance planning, insurance and corporate cost discipline. Our commercial team continues to pursue sources of value through spot gas trading and marketing initiatives. Over the financial year, the team generated more than $1.5 million in net revenue over and above the Victorian daily spot gas price by modifying the profile of sales to preference high gas prices, prioritizing sales into markets with the highest price and realizing various other new trading initiatives. The focus in FY '27 is on sustaining these gains while finding new wins on cost, production efficiency and realized margin. In FY '27, there will be a particular focus on streamlining systems with the replacement of our internal ERP system, which we expect will catalyze G&A savings in subsequent years. Turning now to Slide 12, covering the growth potential across our portfolio. Our growth strategy remains centered on backfilling existing infrastructure. At Athena, the ECSP is designed to bring supply from new onshore Otway gas field through the plant, extending its life and improving utilization and installed processing capacity. In the Gippsland, we are continuing to increase Orbost production through debottlenecking and reliability improvements while progressing the Patricia Baleen restart project. The chart on this slide illustrates that when these growth opportunities are brought together by FY '29, the company has the potential to roughly double the earnings we produced in FY '26. We consider this to be very achievable given it assumes ECSP production from only Annie and Artisan and the other internal mid-case assumptions without factoring in further upside from exploration success at Juliet and potentially Nestor. This helps illustrate why the ECSP is so transformational for the company, and Chad will talk in more detail about these opportunities in the growth section. Part of the reason we're so focused on the growth is the gas demand story, which I'll describe on Page 13. On the demand side, the role of gas is becoming more important as electricity generation systems change and demand grows. Electrification is occurring in many forms from the uptake of electric vehicles to higher household electricity use to the rollout of new technologies. Globally, data center electricity demand is expected to grow significantly as AI adoption increases with large-scale data centers requiring reliable around-the-clock power. That is already influencing investment in conventional dispatchable sources of electricity internationally. In Australia, data centers are expected to contribute to renewed electricity demand growth at the same time as coal-fired generation retires. Renewables and batteries will be important contributors to supply that gas remains the only currently available and scalable source of long-duration dispatchable electricity in Australia. Batteries can help manage minutes and hours, but gas is needed to carry the system through longer periods when renewable output is low. Domestic gas supply close to market where it's consumed is best capable of providing this critical source of system firming. Amplitude Energy is well positioned to respond to these market dynamics. Southern Australia needs new local production to replace declining supply and reduce reliance on higher cost gas from further north or potential LNG imports. Our portfolio is focused entirely on the domestic market, located close to the demand centers in Victoria and South Australia and connected to existing infrastructure. The ECSP is, therefore, more than just a growth project for Altitude Energy. It has the potential to contribute meaningfully to energy security, reliability and affordability in Southeastern Australia. To get to this point on the ECSP, we have invested years and tens of millions of dollars in the project, navigating a complex and changing policy and approvals environment while doing so. There is clear scope for policy to be more supportive of domestic gas supply to deliver the lower-cost gas that consumers want. We continue to engage closely with the federal government on the proposed domestic gas reservation policy. Reform presents an opportunity to improve investment certainty for domestic gas projects through faster and more streamlined approvals, removal of duplicative regulation and a more workable consultation framework for offshore exploration and development. These changes do not require government to subsidize projects. All that is required is for the regulatory settings to facilitate timely investment in supply that the market clearly needs. I will now hand over to Ian to cover the FY '26 financial highlights, starting on Page 15.

Thanks, Jane, and good morning, everyone. FY '26 again demonstrates the opportunity operating leverage in the business before even considering the transformational growth potential of the East Coast supply project. Looking at the charts, production has increased nicely over the past 5 years, while unit production costs have continued to fall. Underlying EBITDAX and adjusted cash from operations have both grown at around 24% compound annual growth since FY '22. This is the financial expression of what Jane described operationally, higher production from existing infrastructure, disciplined cost control and better realized pricing. The result is margin expansion and a much stronger cash generation platform. Our high cash flows and operating margins are, of course, what one should expect from a capital-intensive business with conventional offshore gas fields. Substantial upfront investment is needed to realize these resources. However, once production is online, ongoing costs are low and the resulting cash returns are high. Moving now to Slide 17, looking at the annual results in more detail. Our financial results follow the excellent operational performance of the base business over FY '26 with a 3% increase in production to 27.6 petajoules equivalent for the year and a 5% rise in average realized prices, resulting in sales revenue increasing by 7% to $285.8 million. Production expenses fell to approximately $57 million, with unit production costs falling to $2.07 per gigajoule on a group basis. Specifically at Orbost, unit production costs were well below $2 per gigajoule, significantly outperforming our internal target set at the start of FY '26. Unit production costs at Orbost in FY '26 were 33% below FY '24 levels, showing just how far the plant has come. Production costs and other expenses landed in line with guided expectations. Followers of the company may recall around $16 million in general visual inspection or GVI costs were allowed for at the Solar Patricia Baleen pipelines in FY '26. These inspections were completed in FY '26. And pleasingly, the costs came in at less than half of the original $16 million budget. Higher revenue and lower costs resulted in a 12% rise in underlying EBITDAX to $191.8 million. The business generated $180.3 million in operating cash flows or $191 million in adjusted cash from operations once restoration and other irregular items are excluded. The strength of these cash flows provides us with comfort in funding the ECSP whilst maintaining a strong balance sheet. Our reported and underlying measures of profit and loss after tax were impacted by the circa $100 million pre-write-off of the Isabella and Elanora exploration costs from earlier this calendar year. CapEx came in a little under our guided range of $125 million to $150 million, driven by strong project cost control and the phasing of expenditure on long lead items. Restoration payments were also significantly lower and not expected to be material in the near to medium term. Our net debt position as at 30 June was $37.6 million, reflecting a strong balance sheet ahead of the ECSP investment phase. Net debt was reduced by over $200 million over FY '26 and is nearly $250 million lower than its peak in late 2024. Since financial year-end, we have continued to build cash reserves as the next phase of ECSP drilling approaches. We can now turn to Slide 17. This EBITDA bridge shows the drivers of the strong result. Higher gas sales volumes and higher realized gas prices were the largest positive contributors, both driven by the continued improvement at Orbost and the step-up in contract pricing. Lower crude oil revenue from the Cooper Basin was a headwind, reflecting both lower oil production and flooding impacts earlier in the year. Cost of sales improved through better plant reliability, operating efficiencies and reduced maintenance requirements at Orbost. Taken together, the bridge demonstrates that margin expansion was broad-based with pricing, volume and cost performance all contributing to the record result. We'll now move to Slide 18. And this cash bridge is equally important. Strong operating cash flows more than covered CapEx during the year despite the step-up in ECSP expenditure. Cash at 30 June 2026 was approximately $138 million, supported by operating cash generation and the equity raising completed during the year. Debt repayment reduced drawn debt materially, leaving net debt at around $38 million at year-end. Whilst commenting on debt, it is worth noting that our reserve-based loan, the RBL facility provides significant continuing financing flexibility. At 30 June 2026, debt available under the RBL was $480 million with $175 million drawn, together with our cash on hand and an additional $25 million working capital facility. This gives the company substantial available liquidity. Over time, we intend to optimize the borrowing base, including potentially incorporating ECSP discoveries where appropriate. The business enters FY '27 with strong liquidity and a materially lower net debt position than at the peak of FY '25. I'll now hand to Chad to cover the growth projects section, starting on Slide 20.

Thanks, Ian. This slide provides an illustration of our strategy to grow production into the late capacity of our existing assets. In FY '26, our group production on an equity share basis was around 75 terajoules equivalent per day. By 2028, the combination of the ECSP production through Athena and further optimization at Orbost has a potential to lift group production materially. The key point is that the growth is brownfield. It uses infrastructure we already own and operate, including the Athena and Orbost plants. That gives us a lower risk and faster pathway to new domestic gas supply than a greenfield development. The Athena plant will retain capacity for peak production or third-party tolling even after being backfilled with volumes from the East Coast supply project. The value of this available capacity is only likely to grow over time as the shape of gas use changes and supply from legacy gas fields declines. On Slide 21, I'll provide the latest on the ECSP. Over the weekend, we were pleased to welcome back the Transocean Equinox to commence the Juliet exploration campaign. I'll cover Juliet in detail on the next slide, but it remains a key source of upside potential for the ECSP. More broadly, the project remains on track for first gas in 2028. The economics are underpinned by discovered resources at Anne and Artisan. Beach has completed and flow tested the Artisan well, meaning it's now ready for tie-in to the ECSG. We will assume operatorship of the field once the Artisan acquisition moves through its final regulatory approval steps over this financial year. Customer support for the project is strong with foundation offtake contracts secured with Energy Australia and AGL. FEED is complete and the project is fully funded. We're now very close to locking in the final development phase contracts, at which point we will look to make the final investment decision for that phase of the project. When we put all those factors together, project return should comfortably exceed our internal investment hurdle rates based on our mid-case assumptions. Moving to Juliet now on Slide 22. Juliet has the highest level of prospectivity of all our exploration targets in the ECSP campaign, closely followed by Nestor. Prospect has strong geophysical support, including a conformable amplitude shutoff at the top of the -- we reservoir and a flat spot interpreted as a potential gas water contact. It is a simple structure imaged on good quality 3D seismic with reservoir and seal elements supported by nearby fields and wells. The gross and net prospective resource range is shown on the slide. Importantly, the location of Juliet lying directly underneath the existing CHN pipeline means tie-in costs post the discovery are low and the resource is, therefore, highly economic to develop. This would make a great addition to the ECSP on top of the Artisan and Annie base. Moving to Slide 23 on the upcoming ECSP CapEx profile. From the outset of the project, we have sought to carefully manage the risks and phasing of ECSP CapEx. Drilling and well completions will account for the majority of the FY '27 ECSP CapEx with the drilling phase expected to be completed over the remainder of the calendar year. This means that by the end of this calendar year, Amplitude will no longer face risks associated with ECSP drilling, and it will have completed the majority of total ECSP capital expenditure. Subsea and other development costs are already very well defined ahead of FID with a meaningful proportion related to long lead equipment and the remainder related to the actual development activity in late calendar year 2027 and early 2028. The profile shown here is illustrative and may, of course, change depending on the exploration outcome at Juliet and potentially Nestor. But the key takeaway is that in the next few months, we'll have a high degree of certainty regarding ECSP CapEx through to 2028. The subsea component of ECSP represents only 30% of total project CapEx and well over half of those costs are made up of fixed price contracts. With the base business more than capable of funding that CapEx over the next 2 years, we gain flexibility to allocate capital to other priorities as well. That's a nice segue to the Patricia Baleen restart project shown on Slide 24. The Patricia Baleen restart is complementary to our wider project activities and overall portfolio. It is wholly owned, already connected to Orbost and offers a low-cost pathway to add production flexibility through existing infrastructure. The select phase is complete and the project is progressing through FEED. The current focus is on the lowest cost restart option from the existing Patricia Baleen wells, where limited facility modification is required and the key work is focused offshore. The opportunity is attractive because it can add incremental production through infrastructure we already operate and can potentially utilize the same vessel that we can use for the subsea work on ECSP. The strategic value is broader than near-term production, preserving infrastructure and optionality that can support future discoveries, field developments and third-party processing opportunities in the Gippsland Basin, including Longtom as a potential future backfill option. Handing back to Jane now to cover the final section of the presentation on Slide 26.

Thanks, Chad. Slide 26 provides a summary of our market guidance for FY '27. Consistent with prior years, today, we are providing guidance for production, cash expense and CapEx. FY '27 group production guidance is 26.6 to 28.5 petajoules equivalent, which translates to roughly 73 to 78 terajoules equivalent per day across the group. This range reflects Orbost's ability to produce above 70 terajoules per day, but also allows for periods of lower production, a planned maintenance shutdown in FY '27, natural decline at CHN and PEL 92 and standard allowances for downtime across the group's assets. Production expenses in FY '27 are expected to total between $58 million and $64 million, a slight increase on FY '26, driven by a planned statutory shutdown at Orbost next year. We expect other cash expenses and cost of sales in FY '26 of $27 million to $31 million. This includes general and administrative, care and maintenance, royalties, selling, transport and tolling costs and other cash OpEx items. Note, this $27 million to $31 million figure now also includes expected selling and transport costs associated with accessing the Sydney spot gas market. These costs were excluded from guidance in FY '26. We are now regularly accessing the Sydney spot market if the premium to the Victorian prices is greater than the cost of transport as our production rates and spot gas sales volumes has become more predictable, and therefore, we can forecast these trading costs with great precision. Significant nonregular items that we expect will impact FY '27 expenses, including an estimated $5 million for Patricia Baleen well inspections and $6 million to $7 million to replace our internal ERP system over the next year. The ERP replacement is part of our commitment to continuing to streamline our internal systems and processes and to identify costs and process efficiencies for the future years. FY '26 capital expenditure guidance is $250 million to $310 million, largely reflecting our share of the Juliet and Annie drilling costs as well as long lead order costs for the development phase of the project, assuming FID in the near term. CapEx guidance includes appropriate weighting on weather and other activity allowances and the range incorporates a substantial level of additional project contingency. The range excludes uncommitted Nestor drilling costs and the upfront consideration for the Artisan acquisition. I'll wrap up with our FY '27 priorities on Slide 27. Our immediate priority is to complete the drilling phase of the ECSP on time and on budget over the next few months. While that is happening, we intend to progress the ECSC development phase to FID to maintain the time line to first gas in calendar year '28. Second, we will look to maximize asset utilization, optimizing Orbost production above 70 terajoules per day when market conditions support it, maintaining reliability loss below 1% across our operated plants and progressing the Patricia Baleen restart project. Third, we will seek to further grow margins through gas marketing and trading initiatives, continued cost control and organizational improvements. That brings me to the end of today's presentation. To summarize, we are pleased with our performance of our underlying business in FY '26. We delivered strongly in areas within our control, achieved record operational and financial performance, strengthened the performance of our base business and advanced our growth portfolio. The next few months will be an important period for the company with multiple catalysts ahead of us. The result of the Juliet well and a final investment decision on the development are both expected in the near term. Together, these milestones have the potential to create a significant value and reinforce our position as a key supplier of domestic gas to Southeastern Australia. We enter FY '27 with strong momentum and look forward to keeping shareholders updated on our progress throughout the year. Operator, we can now open the line for questions.

[Operator Instructions] And our first question comes from the line of Gordon Ramsay from RBC Capital Markets.

Just looking forward in terms of the drilling program, just trying to get my head around the decision on the optional Nester well. Is it just kind of a black-and-white decision that for some reason, Juliet doesn't come in, then you will drill Nester, but if Juliet comes in, then Nester won't be drilled. Is it that simple? Or am I misreading it?

Gordon, thanks for the question. The -- our joint venture partner, OG Energy wants to wait until we see the result of the Juliet well before making a decision. So at that point, our Board and also the OG Board will make a decision around whether to progress Nestor. There has been significant investment in the Nestor asset. We have all the approvals in place and all the long lead items, and we have one remaining rig slot available on the Transocean Equinox. So we can't proceed if that is approved.

Okay. And then just on exploration expense, looking at underlying NPAT, clearly, you haven't expensed your exploration there, and it's in the statutory loss. Just want to kind of make sure that we understand the policy going forward on exploration expense in terms of how that's going to be treated. Maybe a question for Ian.

Yes. Thanks, Gordon. Yes, I mean, obviously, the last time since we drilled with 2019, we saw this as sort of one-off lumpy piece. And so to carry it below the line, we want to highlight the progress in our underlying business for that. So you know with these offshore drilling campaigns, they are lumpy. And so yes, we've taken that decision.

Your next question comes from the line of Nik Burns from Jarden Australia.

Jane, just maybe a follow-up on Gordon's question in relation to Nestor. You talked about your recent engagement with the federal government in relation to the proposed domestic gas reservation scheme. How do you weigh up the commitment to a new well versus waiting for certainty or clarity around how this new policy may impact prices and therefore, the economics of the well? Is there a scenario here where you don't commit to Nestor even if you maybe wanted to or depending irrespective of the success or otherwise at the prior well?

Yes. Thanks, Nik. So look, today, the contracted position is 80% across the portfolio. And looking at the Annie and Artisan base for the project, we're around 80% contracted with the Energy Australia and AGL GSAs in place. That gives us a lot of confidence to move forward with the project. But we also know our big gentailer customers need more gas in southern markets. And we know that they are both -- all of them very frustrated by this reservation policy because ultimately, it just pushes back investment and reduces investment confidence, and they want to see gas delivered in these markets. They want diversity of delivery point, diversity of supplier, and they're very unlikely to rely on one pipeline from Queensland to deliver their gas. So we know there's appetite there. We also know that Athena plant has capacity of around 150 terajoules a day. Each of the upstream wells is going to have deliverability of around 60 terajoules a day. So we're choking the wells back to create the plateau that customers want, but we know that ultimately, we have the upstream deliverability to hit that 150 TJ a day production rate. So something like Nestor would give us a lot of flexibility to run the plant up to 150, and we see this demand in the market for peak products, peak demand, peak gas supply to meet that demand from electricity generation. So we think it's a really interesting opportunity. We remain really confident in the demand from our gentailer customers. They are not the group who are driving the noise behind this reservation policy. That's definitely the manufacturers. So -- and what we're hearing in Canberra in the last couple of weeks is more positive. They've well and truly heard the feedback from the industry that what's drafted is really unworkable and that ultimately, they would reduce investment and leave the company -- country exposed to LNG imports down the track. So we're expecting something in the form of an exposure draft or consultation in the second half of September. And so hopefully, that's a more balanced approach.

That's great. And just on your contingent resource booking at Sole, your reserves report talked about the need to potentially drill another well to access that gas. Is there any plans or any thoughts around going after that additional volume?

I'll hand that to Chad.

Yes. Thanks, Nik. At this time, yes, we booked it as contingent so that we could leave it there as a future opportunity. It will all come down to gas prices and what it will cost us to drill that well when we have a rig in the area. So right now, I wouldn't say there's firm plans. It's a potential plan for the future.

Got it. And just quickly on Athena, there was a mention in there about maybe spending money on relifing the plant. Can you just talk about what's involved with that?

Yes. So for Athena relifing, there was a few things that we had to do. One was we have to do an intelligent pig run of the pipeline into Athena. So that's more on the pipeline side. We have to replace the gas-to-gas exchanger bundle. As we've come down in volume there, we've had to plug tubes just to keep the velocity up through the gas-to-gas exchanger, so that we have to replace that. And then there's really just a few other minor controls upgrades that are required. So in general, pretty minor work at Athena plant.

Your next question comes from the line of Declan Bonnick from Euroz Hartleys. Declan, your line is open. [Operator Instructions] And your next question comes from the line of James Bullen from CGF.

Just a quick question around the Artisan acquisition. I mean it's not normal that you see an acquisition of this scale occurred during a period of regulatory uncertainty. I understand that you are pretty heavily contracted for ECSP. But is there anything in there that could prevent the completion happening if something in Canberra does go away around the domestic gas reservation? Or is there any scope to renegotiate any of the terms if there was to be substantial regulatory change?