Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Amplitude Energy Limited FY '25 Half Year Results Webcast. [Operator Instructions] I would now like to hand conference off to Ms. Jane Norman, Managing Director and Chief Executive Officer of Amplitude Energy. Please go ahead, ma'am.

Good morning, and thank you for joining us. This is Jane Norman, and I'm joined today by our Chief Financial Officer, Dan Young; and Chief Operating Officer, Chad Wilson. After today's presentation, we'll be hosting a Q&A session and we welcome your questions. The presentation and announcement were released to the ASX this morning and are available on the Amplitude Energy website. Today's webcast is being recorded and a playback will be available on our website later today. Please note the disclaimer information on Slide 2 of the presentation before moving on to Slide 3. I'll start today by reflecting on our accomplishments through the first half of FY '25. Today's results are an example of what can be achieved with a disciplined focus on delivery and improvements. We have overcome complex technical challenges at our plants and achieved dramatic increases in production at Orbost that many thought may not be possible. We delivered strong financial performance with the business generating the kind of cash flow we know it is capable of. We have continued to make progress on several of our strategic initiatives setting the business up to pursue its next chapter, one where we are positioned for growth. Importantly, we have done this while maintaining exemplary safety and environmental performance. Throughout the first half, we continue to evolve as a business in November, becoming Amplitude Energy, a name and identity that represents who we are as a company and our purpose to be proudly part of Australia's energy future. On Slide 4, I'll spend a few moments on our strong market positioning and how we intend to unlock value in the business. When I started at Amplitude Energy in early 2023, there were 3 main issues overhanging the company. Firstly, there was the uncertainty of the execution and cost of the BMG decommissioning program. Secondly, Orbost production issues were constraining the company and commercializing our gas from the Sole field. And thirdly, misalignment with our JV partner in the Otway was delaying progress on what we called OP3D. Fast forward to today, and I'm pleased to say the company is close to overcoming the last of these 3 issues. The decommissioning of 7 BMG wells was successfully completed last year, in what was one of the largest and most complex restoration projects in recent Australian history and a reflection of the first-class capability of the workforce. Orbost is in a much better place following the improvements and strong reliability performance we've delivered since taking operatorship at the plant in May 2023. While we expect further production improvements there, the plant is now becoming the cash flow bedrock of the business. And lastly, we are excited about the prospect of a new aligned joint venture partner in the Otway Basin to progress the preferred 3-well development programs. With these challenges behind us, the path is now clear for us to focus on unlocking Amplitude Energy's latent value. The company is strongly positioned for growth as the only pure-play gas company exposed to an increasingly tight Southeast Australian gas market. Our focus for the short term is to grow our margins, maximize our cash flow and reduce debt as quickly as possible ahead of our planned growth investments in the Otway, where activity will begin later this year. This focus is reflected in our Orbost production improvements where we have in turn -- which have in turn provided us with the opportunity to increase spot gas sales, increase realized gas prices and the flexibility to pursue new commercial gas marketing arrangements and to reduce our unit production expenses. Over the medium term, we will continue to pursue opportunities to add margin to our gas and support the energy transition by moving down the supply chain into products like gas storage and supporting gas peaking power generation. Over the next few years, our major focus will be on delivering the East Coast supply project, a significant opportunity to backfill and increase production at the Athena Gas Plant by more than 4x, bringing much-needed gas supply through existing infrastructure into the domestic market. On success, East Coast Supply Project will deliver 2P reserves and 2C resources equivalent to around 10 years of steady production at the Athena Gas Plant from 2028. More details on the ECSP program will be provided in coming weeks, but we are on track to commence drilling of our first well late this calendar year. The following slides go into the detail of our delivery against our priorities, starting with our health, safety environment and community performance on Slide 5. Our total recordable injury frequency rate for the 12 months to the 31st of December 2024 with 3.34 injuries per million hours worked, below the 5.86 recorded in the corresponding period in 2023 and well below the industry benchmark of 6.17. Excellent safety performance was achieved during the first half of FY '25 with no recordable injuries or Tier 1 or Tier 2 process safety events. The company has now achieved over a year without a lost time injury. We maintained our exemplary environmental performance throughout the year with no reportable or notifiable environmental incidents in FY '24. These results illustrate our strong safety culture and the discipline embedded in our operations and activities. Turning to Slide 6 and an overview of the Orbost operations. Orbost produced at an average processing rate of 61.5 terajoules per day, up 19% on the prior 6 months and up 30% on the prior corresponding half in FY '24. It is great to see that the plant has been able to sustain production levels at these higher rates for over 6 months now. It gives us confidence that further improvement initiatives can, in time, drive the plant to nameplate production levels on a consistent basis. As we've said in the past, these improvements have been driven by a range of engineering solutions in the sulfur removal phase of the plant and from a greater focus on reliability and process efficiency, which have led to increased plant availability. As a demonstration of this, Orbost reliability loss as a proportion of asset capacity was reduced to 1% in the first half of FY '25. We continue to set new production records, absorber and polisher run times and absorber cleaning durations. A record absorber run time at 3 months was achieved in the first half compared to the typical absorber run times of 2 to 3 weeks in FY '24. The number of absorber cleans during the first half of FY '25 was reduced to 12 compared to 26 cleans undertaken in the first half of FY '24. Absorber cleaning times continue to improve, with cleaning durations now regularly below 8 hours when conducted without a confined space entry. The faster absorber cleans -- fastest absorber cleans on record was recently completed in less than 6 hours with peak gas rates restored in less than 20 hours. An additional point to note is these cleaning durations allow us to produce more gas than our gas customer nominations on the day on an absorber cleans, allowing us to make spot gas sales on those days. Further Orbost improvement initiatives have been progressed to improve reliability and maximize production rates. In the current half, we expect to undertake further trials of chemical clean in place for the absorbers and a new type of polisher media. Some of this work will be incorporated into Orbost planned maintenance shutdown in March this year. The polisher unit continues to play an important role in the sulfur removal phase of the plant, and we believe there is scope to improve its performance and further extend the unit's run time with a new type of media. In the meantime, we have been trialing other solutions such as a liquid H2S scavenger unit, which is an inexpensive piece of kit to improve sulfur removal and enable higher production rates. Work continues to identify the root cause of the absorber foaming and fouling issues. We're working through the results of our work with 2 data analytics firms to analyze what other improvements at Orbost can be made. Moving to our Athena and Cooper Basin producing assets on Slide 7. The average processing rate at Athena during the first half of FY '25 was 10.3 terajoules per day net to Amplitude Energy's 50% share. The reliability of the AGP has significantly improved compared to previous years with a 0.07% reliability loss in the first half of FY '25 and 97% improvement in reliability loss when compared to the FY '24 full year. This means we have achieved our reliability goals at both Athena and Orbost, well ahead at the end of FY '26 target we set ourselves last year. Regular well cleaning operations at the Casino, Henry and Netherby wells were impacted by a failure in the umbilical cable, which slightly reduced production volumes at Athena from mid-November. Work to restore communications through the umbilical was recently undertaken with the CHM wells now cycling again. Our non-operated interest in the onshore Cooper Basin continue to contribute good margin and cash flow and a natural hedge for U.S. dollar expenditure. Slide 8 provides an update on our gas trading activities into the domestic East Coast gas markets. Our exposure to the domestic spot market and ability to capitalize on market pricing dynamics is largely due to the improved performance out of Orbost. In the first half of FY '25, we were able to sell around 30% of Orbost volumes into the spot market, up from 17% in the prior 6 months. During the December quarter, we commenced sales from Orbost into the Sydney spot market in addition to the Victorian market. We do this by participating in the day-ahead auction for pipeline capacity from Victoria to Sydney. As you can see from the larger chart, the Sydney spot market often trades at a slight premium to its Victorian equivalent. From around August last year, the Sydney premium began to widen with Sydney spot prices rising above $15 per gigajoule in December. Having the flexibility to sell uncontracted gas in these market dynamics is a great asset and is adding margin to our gas. Our average realized gas price was $9.69 per gigajoule in the first half of FY '25. And more recently, it's been around $10 a gigajoule, almost $1 higher than level 12 months ago. We see an increasing likelihood of higher and more volatile spot gas prices as gas-fired power generation becomes critical to firm the electricity grid in the peak demand periods in the evening. This will create opportunities for us to supply gas when it's needed most and to capture peak pricing in the market. Turning to Slide 9 now on our continuous improvement program. As discussed in our FY '24 results, we are seeking to build on the success of last year's transformation program to drive a mindset of continuous improvement, to keep identifying opportunities to do things better, reduce costs, maximize margins and improve productivity. We have 59 initiatives currently underway or identified across the business, which, in aggregate, are on track to deliver around $12 million in cash flow improvements by the end of this financial year. Around half of this relates to Orbost improvements which are expected to drive near-term value through increased sales volumes, while other initiatives relate to gas marketing and trading to maximize our gas pricing, some of which I touched on in the previous slides. There remains further opportunities to reduce costs around Orbost absorber cleans and in the use of contractors. This is all incremental to the $10.5 million in net annualized cost savings achieved in FY '24 and that we previously announced. In FY '25, we will also be giving more attention to improving energy efficiency, reducing waste and emissions at our plants. This will not only maximize our sales gas volumes but position us as an operator of choice when looking to bring third-party volumes through our facilities. Slide 10 provides an update on the East Coast supply project. I am personally enthused about working with O.G. Energy to assist its potential entry into the Otway joint venture and progressing the ECSP. Our discussions are proceeding on the basis of our preferred 3-well program and that O.G. will fund a 50% share of past and future project expenditures. These discussions are ongoing, so we will not be saying anything further beyond this for the time being. We encourage all listeners to read our ASX announcement on this topic released today alongside these half year results. As a reminder, the preferred 3-well program includes Elanora and a sidetrack to Isabella, the Juliet and Annie wells. These fields are geologically similar to our existing discovered fields and supported by Amplitude data and have high probabilities of gas discoveries. The project could deliver more than 350 Bcf of mean unrisked resource potential through discoveries at Elanora, Isabella and Juliet, while developing the 65 petajoules of contingent resource the Annie field has on a gross basis. A key advantage of this development is that Juliet, Elanora and Isabella are all located within the existing production leases. The production lease application for Annie has been submitted following a successful Annie-1exploration well and is expected to be received prior to drilling. This approach shortens the approvals time line allowing us to bring first gas line as early as 2028. This project is crucial for addressing the structurally short East Coast gas market. As was previously outlined, the project is economically attractive exceeding our internal project hurdle rates. We have strong customer support with significant interest in underpinning the development through foundation gas contracts. Our project aims to deliver up to 90 terajoules per day through Athena, positioning it as potentially the largest new domestic source of supply in the Southeast domestic market. To put this into context, this is enough gas to supply over 600,000 Victorian homes currently using gas for heating, cooking and hot water. This development also has a minimal emissions footprint compared to the alternatives, utilizing nearby gas pipelines and tying into existing infrastructure. Amplitude Energy expects to formally sanction the drilling phase of the ECSP during FY '25. The Transocean Equinox drill rig is expected to commence drilling the first firm well in its campaign for Amplitude in late 2025. On Slide 11, we highlight the need for this project and other new gas supplies into the East Coast domestic market. Due to supply constraints that we have already started to see in the market, our customers are telling us that they see LNG imports as their only alternative if more domestic gas cannot be developed. As you see from the left-hand side of this page, this is driving gas contract pricing up towards LNG import parity, representing a significant premium on the current contract pricing as sourced from the ACCC's gas market reports. On the right-hand side, you can see emissions intensity of the gas that we produce against that of LNG imported from either Northern Australia or the U.S. Our local production has a significantly lower emissions intensity even before the impacts of LNG shipping and regasification are considered. None of these facts are presented to criticize the LNG industry, which remains a critical enabler of the global energy transition. But to point out that gas produced and consumed within the local market will nearly always be lower cost and lower emissions. This is in the context within which we are speaking to customers to support the East Coast Supply Project. We continue to see strong demand from customers who are interested in any new gas we can bring to market. Slide 12 shows why the need for new gas is becoming urgent. The charts on this slide are sourced from of the AEMO, the Australian government's energy market operator, and its 2024 gas statement of opportunities. AEMO's central case is that gas demand stayed largely flat in our primary markets as increases in gas demand from power generation and extra 13 gigawatts of gas-fired generation will be required, offset the assumed growth in electrification from residential and commercial customers. The dash line above shows what gas demand could look like if residential demand doesn't decline due to electrification. As you can see from the gap to the dash line, there is a big assumption in the AEMO data that households can and will convert their appliances over time and that the transmission networks can keep up with growing electricity demand. The demand stack also highlights the relatively stable large tranche of industrial demand, which includes customers where electrification is not possible as gas has been using -- used for high temperature heat or as a feedstock. The chart opposite shows the supply stack with a clear gap to demand emerging in coming years. Even under the conservative assumptions that residential and commercial customers electrify and that does not occur, the gas demand remains flat rather than grows. For the southern states of Victoria, New South Wales, South Australia and Tasmania, there is a clear and urgent need for more gas to be developed. The supply side situation has not changed much in recent years with a steep decline forecast in existing production. AEMO assumes that more than 150 petajoules a year or approximately 400 terajoules per day of production could be redirected from Queensland. Even if this was to occur, there is significant demand for more domestic production from the southern states themselves. It's important to note that Victoria and Australia are not themselves short of gas resources. On the contrary, in Victoria alone, there are approximately 6,500 petajoules of 2P and 2C in the conventional supply basins of the Otway, Bass and Gippsland. This is equivalent to almost 25 years of current Victorian gas demand. Although there remains a lot of resource in these traditional gas supply basins, there are very few projects aiming to bring new supply online in the near to medium term. The industry needs streamlined approvals and free market incentives to stimulate investment. This shows the significant market opportunity for us to grow our own gas supply by the East Coast Supply Project. The project is arguably one of the largest supply projects to the southern states. It makes commercial sense, leverages existing infrastructure and is close to market. I'll hand over to Dan now to talk to our first half financial performance.

Thank you, Jane, and good morning, one. I'll start on Slide 14 with a few comments on our recent track record of performance. I'm happy to say that in the first half of FY '25, the company continued its consistent track record of increasing production, reducing unit costs, generating record underlying EBITDAX and strong levels of cash from our operations. Jane has talked through the production performance for the first half shown here in the top left-hand side of the slide. On the top right-hand side, you can see our declining unit production costs, which demonstrates the operating leverage potential within the business as production rises with what is a relatively fixed cost base. We're pleased that the underlying EBITDAX and cash flow from operations for the business is now demonstrating the company's strong potential for margin expansion and organic cash generation. And this gives us comfort around our ability to both comfortably manage our senior bank debt and to invest in growth. At Amplitude, we're striving to build a performance culture that delivers what we promise. With the strong gas market tailwinds behind us, improving production performance and the start-up of the ECSP, shareholders should expect continued improvements in profitability over time. This track record is being evidenced and we look forward to continuing this consistent delivery results into the future. Turning now to some of the detail in our first half financial results on Slide 15. Today, we reported another set of record results for the business across a number of key metrics. I take the opportunity to note again the 21% increase in production, another record for the company. We are currently tracking ahead of our production guidance of 65 to 72 terajoules equivalent per day. However, we are mindful that shutdowns at both Orbost and Athena will have a short-term impact on production in the next month or so. Sales revenue of $133.7 million was also a record for the half and 26% above the prior comparable period due to a combination of higher production and higher average realized gas prices. Production expenses were just under $29 million for the half, an increase on the prior comparable period, but well down in unit cost terms at $2.14 per gigajoule. This was in spite of some elevated costs to overcome the sold pipeline restrictions faced in the first quarter of FY '25. Pleasingly, we are growing production at a rate far faster than associated costs and production expenses are tracking in line with our FY '25 full year guidance. Underlying EBITDAX was up 53% to $93.2 million compared to first half FY '24, another record for the company. This highlights the cash potential -- cash generation potential of the business and indeed, adjusted cash from operations for the first half FY '25 was up 15% to around $81.5 million, excluding restoration and other non-underlying and nonrecurring items, including the costs of the amend and extend on the RBL. Underlying net profit after tax was $8.5 million for the first half of FY '25 compared with $5.4 million for the first half of FY '24. CapEx incurred for the half was $23.9 million, which was largely ECSP-related. Restoration payments of $32.9 million predominantly related to the payment of final invoices for the BMG wells decommissioning program. Slide 16 provides further detail on underlying EBITDAX in the half. This waterfall bridges first half FY '25 underlying EBITDAX of $93.2 million back to the first half FY '24 result of $60.9 million. Higher gas sales volumes and higher gas price realizations were the single largest driver for the improved results, driven by the higher production at Orbost, together with the work of our gas marketing team. Oil production was down in the first half compared to the same period in FY '24, partly due to the Callawonga-23 and Rincon-4 wells, which came on stream in early July in the prior financial year production. With natural decline, this resulted in lower crude oil liftings as reflected here. This was partly offset by lower G&A and other costs when compared to the first half of FY '24. On Slide 17, we provide a 6 monthly cash bridge from June to December 2024. Here, you can see, first, the contribution from operations of $90.1 million. This is total customer receipts less total cash OpEx, followed by the impact of restoration costs, almost all of which relates to the final payment of invoices under the BMG wells decommissioning project and is, hence, nonrecurring. Subtracting PRRT and interest costs left approximately $60 million in unadjusted cash after operating cash flows. Other draws on cash were the final Orbost deferred consideration payment, which was paid in July 2024 and CapEx payments of $22.5 million. CapEx included regular stay-in business spend as well as the procurement of long lead items related to the East Coast supply project. Cash at 31st of December was $51 million. Moving now to our liquidity position on Slide 18. Our debt facilities comprise a reserve-based loan and a smaller working capital facility. Many of you will know we completed an amend-and-extend process on our debt facilities late last calendar year. The result was to reset our facility back to a 5-year term out to late 2029 and to unlock significant additional funding flexibility ahead of the funding phase of the East Coast Supply Project. The newly increased RBL facility limit of $480 million is supported by an assessed borrowing base that is currently above the facility limit. The borrowing base reflects the company's strong credit quality, producing from low-cost conventional gas fields and selling most of our gas into fixed price CPI indexed medium- and long-term gas sales agreements to predominantly investment-grade off-takers. The RBL is a highly effective form of funding for the company, maximizing debt availability while offering a competitive cost of funds with debt service on the drawn portion at BBSY plus 325 basis points or around 7.4% at the current prevailing BBSY. We currently have $175 million of committed available liquidity to us under the facility and over $240 million of liquidity in aggregate, once our cash balance and unutilized working capital facility are included. With cash of $51 million and drawn debt at $305 million at 31st of December, our net debt stood at $254 million at the end of the half. I talked at last year's June investor briefing of our ability to fully repay our RBL in less than 2 years from organic cash generation and based on Orbost rates of 60 terajoules a day and before any ECSP spend. The first half's organic cash generation of $81.5 million clearly demonstrates exactly that. Turning now to our contracted position on Slide 19. Here, we set out our contracted gas stack alongside uncontracted or spot gas exposure for our equity share of total production and on a calendar year basis. I should say at the outset, this is not production guidance. We're showing a profile based on 70 terajoules a day, which we consider a somewhat conservative assumption based on the improved rates at Orbost, alongside our 50% share of current Otway production. As noted in the call-out box at the top right-hand side, the chart does not include increased volumes that will come from our East Coast Supply Project. The dark navy portion of the stack reflects the bulk of our contracted gas today, which is all fixed price and indexed annually CPI. This largely reflects foundation contracts for Sole gas that were entered into several years ago at the development stage of the project. You can see that this component of the contract stack declines over time, with cap price reviews to be undertaken from 2028 onwards. For 2025, the price of our contracted gas averages a little over $9 a gigajoule for the company overall. In the dark green color, you can see the gas that we recontracted in 2023, aligned with current mid-teen type pricing with this tranche stepping up a year from now. This tranche together with the blue uncontracted or spot volumes illustrate the portfolio's attractive and growing exposure to higher gas prices. This is one of the key drivers for further margin expansion and increased underlying cash generation that we expect over the coming years. Beyond the picture that we see today, we will continue to seek to optimize the customer portfolio. You can expect to see us continue to reshape existing contracts with our customers where it makes good economic sense for us to do so while seeking to offer investors as much exposure to East Coast spot gas pricing as we can. I'll now hand back to Jane on Slide 21 to discuss FY '25 priorities.

Thanks, Dan. We presented this slide at our FY '24 results, and I think it's useful to assess our performance against the 4 objectives we set ourselves over 6 months ago. We are well ahead on our target to produce over 70 terajoules equivalents per day at the group level by the end of this financial year. A run rate of 73.5 terajoules equivalent per day was achieved over the first half. We will continue to focus on production improvement at Orbost to maximize plant performance, and our priority will be on maximizing cash generation and paying down debt ahead of investing in our major growth projects. For the first half of the year, we have kept the East Coast Supply Project on track by taking the lead on engineering, project preparation and long lead item orders. We hope to soon be working with a new aligned joint venture partner in the Otway to progress the project on a 50% basis. Our preferred 3-well drilling program remains the base case to backfill the Athena plant and bring much needed supply to the East Coast domestic gas market. We have increased our realized gas prices through greater sales into the tight spot market, and we are exploring opportunities to gain exposure to gas to electricity spark spreads by providing gas when our customers need it most. We have maintained focus on the cost base and expanded last year's transformation program to focus on other opportunities to do things better, to maximize margin and cash generation, reduce costs and improve productivity. As we turn our focus now to the next 6 months, we see a number of catalysts for the business to outperform as described on Slide 22. We have a very exciting few months ahead of us. In the near term, we are confident that our operational and engineering teams can achieve the next step change in Orbost production with the improvement initiatives being implemented. Our average realized gas price and resulting margins should continue to increase as CPI indexation flows through our contract book and as we continue to sell spot gas into a tight domestic market. We will continue to look for opportunities to add margin to our gas through recontracting and other commercial opportunities. We expect to further balance sheet deleveraging in the current half of FY '25 as we continue to generate good cash flow from operations. In the first half, we generated over $80 million in cash from operations once restoration and other non-underlying and nonrecurring items are removed. We think this business can comfortably generate around $150 million or more of underlying organic cash flow per year on average before growth CapEx. This gives us confidence in our ability to fund our share of the ECSP. We also look forward to finalizing the status of the ECSP joint venture in the near term, following which we will confirm the details of our aligned 3-well projects in the Otway. We intend to announce the full details of the program, including the timing and sequence of wells being drilled, overall project CapEx and funding. The Transocean Equinox drill rig looks to be on track to arrive in the Otway Basin this half with Amplitude's first drilling likely to land in late calendar year 2025. That brings me to the end of today's presentation. And to summarize, we are pleased with our progress against our FY '25 priorities. We remain committed to delivering strong reliability and production performance at both plants, maintaining our focus on continuous improvement, paying down debt and maximizing cash flow. We will continue to work with stakeholders, customers and financiers to progress the East Coast Supply Project. We look forward to an exciting second half of the year where we intend to continue building on our achievements and delivering against our commitments. I would now like to open the line for any questions.

[Operator Instructions] And your first question today will come from Nik Burns with Jarden Australia.

Jane, Dan and Chad, a couple of questions from me. Look, Jane, I know you mentioned you weren't going to say anything more about the current process underway with O.G. Energy, but I'm going to try anyway. And I appreciate it's not your transaction between Mitsui and O.G., but the fact that you're allowed to talk about feels like the transaction must be pretty close to completion. Do you have any sense for timing from here?

Thanks, Nik. Yes, we are limited in what we can say from here, but we're pleased with the progress to date, and we are really focused on finalizing negotiations and entering binding agreements and we hope to be able to offset the market in the near term.

Got it. And maybe just a different angle here. Obviously, O.G. is JV partner with Beach and the nearby Otway permits. I guess beyond the potential participation in upcoming drilling program and Athena Gas Plant, with the replacement of Mitsui with O.G. potentially open up opportunities for Amplitude to do some sort of collaboration or cooperation with the Beach-led joint venture next door.

Thanks, Nik. Look, we are very open to any opportunities that deliver synergies and reduce costs across our business. So yes, certainly, we'd be open to that.

Got it. Okay. Look, I might just slip in one more. Slide 9, you mentioned $12 million in cash flow improvements achievable by the end of FY '25. You listed a number of items that might assist in achieving that. I guess it's difficult for us from the outside to see how you're tracking against that. Can you give us a sense of how much of that $12 million was achieved in the first half of FY '25?

Yes. We haven't got that split for you, Nik. But the key message we want to make around the continuous improvement program is that it is adding momentum to what we achieved last year. You can see in the donut there that there's a portion around cost reduction. There's also quite a bit here that is around volume and what we're doing on the marketing side. So yes, we're certainly comfortably on track to achieving that for the full year, but we haven't given the half yearly split on that number.

[Operator Instructions] And your next question today will come from James Bullen with Canaccord.

Congratulations on the result guys as cracker. Just around the back costs that you've incurred in the Otway. Could you give us a sense around the magnitude there?

Thanks, James. The back costs relate to time writing as well as expenditure to date on the assets and also the long lead items and the costs associated with that, that have already been incurred today. So we'll provide further detail on that when we can speak to the binding agreements having been finalized.

Okay. I understand. And does this negotiation include VIC/P76 or is that outside?

Thanks, James. We are working through that at the moment. It's part of the negotiations. And we are certainly focused on getting an aligned joint venture in the whole basin.

And your next question today will come from Declan Bonnick with Euroz Hartleys.

Congrats on the results. James said, it's a cracker. I think I did cancel it. It was really around the split on those back costs that Cooper has covered to date. Jane, I think your answer was that you can't really answer that right now. If so, could you please do so?

Thanks, Declan. Yes, we'll provide more color on that when we can and also the sharing of the go-forward 50% costs.

Sure. I guess another one, you might not be able to answer this one either, but just on O.G. Energy farm-in, do you think -- how's the approvals on that in terms of FIRB? Do you think because they're already operating in the basin in Australia that should progress slowly? Is that some of the hold-up here? Or is it really the discussions with Mitsui that have taken this long so far?

Yes. Thanks, Declan. Look, O.G. is an established player in the upstream business. They've got significant investments in the U.S. Gulf of Mexico and are already in the Otway. There are a known entity to Australian authorities and regulators. And so we can't really comment on the regulatory approvals because ultimately, that's up to them. But we see the need for new gas in Australia and the fact that the authorities would understand that a new partner coming in to allow us to do a bigger project is a good thing for the market.

And your next question today will come from Stuart Howe with Bell Potter Securities.

Just a quick question on Minerva abandonment. Have you -- is there any update on that, the timing of that potentially the magnitude? I guess, just looking at the balance sheet, current provisions are around $21 million. Is that a good guide?

Yes. The vast majority of that, of course, is Minerva, Stuart, and that activity is already underway. And of course, they are part of -- Woodside is part of the reconsortium. And so that activity will continue through the course of the coming months. It's still, I guess, fairly early in the actual activity offshore, but we'll give more updates in the coming months as we are in a position to do so. But yes, at current portion as you correctly identified, the great majority -- vast majority of that is Minerva related.

Great. And then just a second question. Dan, you noted increasing exposure to spot gas prices. Just wondering how the banks think about that in the lending capacity that they've provided so far. Is there a limit as to how much you can increase into the spot market? Do they want firm contracts ahead of them?

Yes. So there is provisions in our loan that relate to how much is contracted versus noncontracted. So we look at that carefully. And we also look at opportunities like the one in 2023, where we could recontract in mid-teens. So the balance that we have at the moment at kind of roughly 70-30, which is still more or less the same as the market, but we want to keep options open and retain flexibility. And so when contracts do roll off, if we're in a position to negotiate something like a mid-teen pricing, then we think that's very attractive for investors, nevertheless.

And just one last quick one for me. Just noting on Slide 19, and I know this is a fair way out, but looking at 2027 versus 2028 if you would exclude the uncontracted proportion of that chart and just look at that cap price review component versus the existing price CPI index. Does 2028 get better than 2027 in that pricing environment?

Yes.

There are no further questions at this time. I'll now hand the call back to Ms. Norman for closing remarks.

Great. Thank you very much, and thanks for your questions and interest in Amplitude. We have an important second half of the year coming up, and we're looking forward to seeing many of you over the coming days and weeks. And we'll sign off now. Thanks, operator.

That does conclude our conference for today. Thank you for participating. You may now disconnect.