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Operator: Welcome to the Amplitude Energy Limited FY '26 First Half Results Webcast. [Operator Instructions] I will now pass over to Jane Norman, Managing Director and Chief Executive Officer of Amplitude Energy. Please go ahead, Jane.
Jane Norman: Good morning, and thank you for joining us. This is Jane Norman, and I'm joined today by our Chief Operating Officer, Chad Wilson; and our new Chief Financial Officer, Ian Bucknell. For those who haven't yet met Ian, he started with Amplitude as our CFO in January this year. Ian has held several prior CFO roles at ASX-listed energy and mining companies over the last 15 years, and we are very pleased to have someone of his caliber add to the strength of the executive team. Ian will cover our first half financial results in detail a little later on. After today's presentation, we will host a Q&A session, and we welcome your questions. Today's presentation as well as our first half financial report and summary 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 come to our record first half metrics in a moment, but reflecting on these results at a higher level, I see a business that has built strong foundations for near, medium and long-term growth. In the near-term, continued improvement at Orbost is underpinning our base business and with a good second half expected across all 3 of our basins, we have increased FY '26 production guidance today. As we increase Orbost's production rates, it is important that the Sole reservoir continues to perform well. We significantly increased our 2P reserves booking in Sole last year based on reservoir performance, and we will be undertaking reviews to assess further upside. The market fundamentals and the outlook for gas demand clearly support our business and the investments we are making. Our customer relationships have delivered new higher-value contracts that will materially increase our average contracted gas price from this year onwards. These relationships also position us well for future contracting of the Sole volumes and long-term supply agreements for the ECSP into the next decade. In the last month, we have embarked on our major medium-term growth project with the ECSP. The ECSP campaign is focused on drilling our attractive exploration targets in the Otway Basin in addition to developing the Annie discovery. Whilst the Elanora exploration result was disappointing and not as expected, we completed the well efficiently, and we are now sidetracking into Isabella, where results are expected in the near-term. It is important to remember that upon success, it is Isabella, not Elanora, that has been earmarked as the producing field for ECSP. A drilling campaign like ECSP with multiple exploration targets remains the most capital-efficient pathway to success and growth. Pleasingly, the ECSP remains on schedule and budget. Longer term growth from the Gippsland Basin also remains on the agenda with the Patricia Baleen restart progressing through a concept SELECT phase and potential backfill to existing infrastructure from our booked 2C and Manta and Gummy and the attractive Wobbegong prospect. We are in a great position to grow organically in both the Otway and Gippsland basins, backfilling existing infrastructure funded from strong organic cash generation. Our assets provide material volumes of gas to the Southeastern market, offering energy security and supply diversification to our customers and the community as a whole. I'll turn to Slide 5 now to dive into the headline results. This morning, we announced an outstanding set of numbers for the first half of FY '26. These results highlight further improvement in production at Orbost, higher realized gas prices and good cost control. This resulted in records in all of our key operational and financial metrics in the first half of FY '26. The confidence we have in the performance of our base business and expectations of further upside has allowed us to increase FY '26 group production guidance this morning, which I will cover in detail a little later. Underlying EBITDAX of $100.3 million and adjusted cash flow from operations of $85.6 million demonstrates the company's leverage to higher production and gas prices and its ability to generate strong cash flow. Followers of Amplitude Energy may have noted we have continually posted record production, revenue and underlying EBITDAX results over the last few years, and we look forward to continuing this track record of performance. During the half, we made important progress on the East Coast Supply Project, setting the company up for its next phase of growth. We are imminently expecting the results of the Isabella well, and we will speak about the ECSP in more detail later in the presentation. I'll turn to Slide 6 now and provide an overview of our HSE performance during the first half. Our total recordable injury frequency rate for the 12 months to the 31st of December 2025 was 3.18 injuries per million hours worked, below the 3.34 recorded in the corresponding period in 2025 and well below the industry benchmark of 4.94. We continued our excellent safety performance during the first half of FY '26 with no recordable injuries or Tier 1 or Tier 2 process safety events. The company has now achieved over 2 years without a lost time injury. We maintained our exemplary environmental performance throughout the period with no reportable or notifiable environmental incidents over the half. These results illustrate the discipline embedded in our operations and activities. Hours worked across the organization will increase in FY '26 and FY '27 due to the ECSP, in particular, with drilling operations and our safety culture will be important to ensure these operations run smoothly and people come home from work safely. Turning to Slide 7 and an overview of the Gippsland Basin production. Orbost produced a record average processing rate of 66.3 terajoules per day for the half. As we've said in the past, these improvements have been driven by a range of engineering solutions in the sulphur phase of the plant with sulphur processing and removal no longer a constraint to the plant's production rate. I'm pleased to report for the first time since the sulphur came online in 2020, there were 0 cleans of the sulphur absorber units in the 6 months to the 31st of December. As of that date, one of the absorber units had run 9 months without a clean. A lack of absorber cleans means higher production and lower costs, improving our margin and cash generation from the plant. In January, we undertook our first absorber clean for FY '26 in both absorbers, utilizing the new clean-in-place method. This allows some of our fastest cleaning times on record with Orbost producing around 60 terajoules on the day of one of the cleans. This would have been unheard of as an achievement for the plant only 1 year ago. In December, we finally received regulatory approval to lift Sole pipeline's production capacity, meaning Orbost can operate above its previous nameplate level of 68 terajoules per day. We have successfully trialed production at rates over 70 terajoules per day since then. The plant reset its 14-day average production record at 70.9 terajoules per day earlier this month, hitting a new daily production record rate of 71 terajoules. Sole field and reservoir performance continue to demonstrate strong and reliable production capability with the existing wells comfortably supporting the increased throughput rates at Orbost. Importantly, the field's proven deliverability is expected to underpin anticipated near-term debottlenecking initiatives at the plant, providing confidence in its ability to meet the higher target processing rates. As announced at the year-end 2025, Sole 1P and 2P reserves increased by 19% and 9%, respectively, reflecting the strength of the field performance and ongoing subsurface evaluation. Building on this momentum, further technical studies are underway to assess additional resource potential within the Sole field area. These studies are focused on evaluating opportunities for potential future bookings of contingent resource subject to technical maturity and commercial assessment. Beyond 2026, continued integration of subsurface studies and production performance data may support future reserves reassessment. Any additional resource classification or reserves revision will, of course, be subject to the completion of technical and commercial evaluations and applicable reporting standards. Moving on to our Otway and Cooper Basin producing assets on Slide 8. The average processing rate of Athena during the first half of FY '26 was 8.2 terajoules per day net to Amplitude Energy's 50% share. With the Casino 4 well unavailable during the half, production was cycled through the remaining Casino, Henry and Netherby wells. We have a plan underway to bring the Casino 4 well back into production during the current half and reduce the rate of decline from those fields. A successful Casino 4 restart will, on average, add just over 1 terajoule per day of additional gross production through the Athena plant over the coming year. Front-end engineering design for Athena gas plant upgrades as part of the ECSP were also completed. In the Cooper Basin, production is recovering after the easing of last year's floods. Production increased 21% quarter-on-quarter at the end of last year. A successful 3-well development campaign was undertaken in the Callawonga field with production expected to commence from this area in the second half of FY '26. We are also assessing other Cooper Basin prospects ahead of the next phase of development. The next 2 slides talk to our initiatives to increase gas prices, starting with Slide 9. Here, we set out our stack of existing gas contracts alongside uncontracted or spot gas exposure for our equity share of total production on a calendar year basis. Our GSAs are all fixed price take-or-pay contracts with the price indexed annually to inflation. The dark navy portion of the stack reflects our legacy gas contracts, including 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 capped price reviews for these volumes to be undertaken from around 2028 onwards. In the dark green color, you can see the gas we recontracted in 2023, aligned with prevailing mid-teen type pricing, with this tranche stepping up materially from the 1st of January, 2026. Together with CPI indexation, the result is an approximate 20% increase in our weighted average contract gas price this calendar year compared with the levels in 2025, where it averaged a little over $9 a gigajoule. The blue area at the top of the stack represents uncontracted or spot volumes, which illustrate the portfolio's attractive and growing exposure to higher gas prices. This is one of the key drivers of further margin expansion and earnings growth that we expect over the coming years. I should reiterate that this does not constitute production guidance. The profile we are showing here is based on actual group production for 2025 and illustrative group production of 75 terajoules equivalent per day from 2026 onwards. As noted in the callout box on the top right-hand side, the chart does not include any increased volume from our ECSP project. Beyond the picture we -- that we see here 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 exposure to East Coast spot gas prices. Slide 10 provides more detail on our gas marketing activities. On average, realized gas prices have consistently increased over the past 3.5 years. This is due to a combination of higher gas contract prices, as I just mentioned, and greater exposure to spot gas prices driven by Orbost's production outperformance. Greater availability and consistency of spot gas sales has allowed our commercial operations team to pursue trading opportunities available in various gas markets. This has included trading spot gas into various Victorian and Sydney spot markets, modifying the profile of spot gas sales to maximize sales during high demand periods as well as prioritizing sales into markets with the highest price. The chart on the right illustrates the new contractual arrangement that we recently entered into with OG for gas supply to its Pelican Point Power Station. The agreement provides Amplitude with exposure to South Australian spot electricity prices between a strike price and a cap, effectively mimicking the spot spread value of the power station during peak demand periods. We've talked at length about looking at different ways to access the spark spread for electricity generation, and this is an initial step in that direction for this calendar year. Moving on to Slide 11 now. As discussed in our FY '25 results, our continuous improvement program seeks to identify efficiencies and opportunities to extract further value from our operations. We have over 80 initiatives currently underway or identified across the business, which in aggregate are on track to deliver around $10 million in cash flow improvements by the end of this financial year. Around 2/3 of this relates to production improvements. I have already discussed these, and they are expected to drive near-term value through increased sales volume. There remains further opportunity to reduce our costs in areas such as waste disposal, maintenance and insurance. We also continue to pursue marketing and trading initiatives to maximize our gas price, some of which I touched on, on the previous slide. I'm also very pleased with the success of the continuous improvement program in keeping the business lean and constantly focused on doing things better. Net corporate G&A costs were $8.6 million in the first half of FY '23, before I started at Amplitude. In the half just gone, those costs were down to $5.2 million despite 3 years where the business has grown production and delivered major projects. This tells me that we are delivering value for our shareholders. I'll hand over to Ian now to talk to our first half financial performance from Slide 12.
Ian Bucknell: Thank you, Jane, and good morning, everyone. Before I start my prepared comments, I'd just like to say that while I've only been at the company a short time, I've been struck by the professionalism and depth of the management team and the sophistication of the company's processes. This has made the CFO handover and preparation of the financials very smooth. I'll start my prepared remarks on Slide 13 with a few comments on Amplitude's recent track record of performance. I'm happy to say that in the first half of FY '26, the company continued its consistent track record of increasing production and reducing unit costs, which has helped generate record underlying EBITDAX and strong levels of cash from 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 see our declining unit production costs, which demonstrate the operating leverage potential within the business as production rises with what is a relatively fixed cost base. We are pleased that the underlying EBITDAX and underlying operational cash flow from the business is showing the company's clear potential for margin expansion and organic cash generation. This provides comfort around our ability to both invest in growth and comfortably manage our senior bank debt at the same time. Turning now to some of the detail in our first half financial results on Slide 14. Our first half FY '26 results are the kinds of numbers you see when a business is really humming. Our record group production rates were tracking above our previous production guidance even prior to the recent capacity increase at Orbost. We have, therefore, upgraded production guidance today, which Jane will cover shortly. Sales revenue of $141.5 million was also a record for a half and 6% above the prior comparable period due to a combination of higher sales volumes and higher average realized gas prices. Production expenses were just under $25 million for the half, a significant decrease of 14% on the prior comparable period and well down in unit cost terms at $1.79 per gigajoule. We do, however, want to note that we expect higher production costs from maintenance at the CHN fields in the Otway Basin in the second half of the financial year as well as the scheduled maintenance shutdown at Athena in April. Underlying EBITDAX was up 9% to $100.3 million compared to first half FY '25, another record for the company. This highlights the cash generation potential of the business and indeed, adjusted cash from operations for first half FY '26 was up 5% to a record $85.6 million. Underlying net profit after tax was $25.7 million for the first half of FY '26 compared with $7.8 million for the comparative period. CapEx incurred for the half was $11.1 million, which was less than half the expenditure of first half FY '25. This was largely associated with ECSP long lead items with OG Energy's cost carry of approximately $28 million on ECSP expenditure active for the month of September 2025 onwards. Restoration payments were also significantly lower, reflecting the now complete Minerva Wells decommissioning program. Our net debt position as at 31 December reduced to $34 million, reflecting a strong balance sheet ahead of the ECSP investment phase. Slide 15 provides further detail on underlying EBITDAX in the half. This waterfall bridges first half FY '26 underlying EBITDAX of $100.3 million, back to the first half FY '25 result of $92.2 million. Increased gas sales volumes and higher average realized gas prices were the single largest drivers for the improved results. Oil production was down in the first half compared to the same period in FY '25, impacted by flooding in the Cooper Basin. As James stated earlier, production from our Cooper Basin interest is expected to recover in the second half of FY '26. The $4.5 million decrease in cost of sales was largely the result of lower Orbost production costs. As compared to first half FY '25, we did see an increase in certain other costs related to exploration and business development, including to support work associated with ECSP gas contracting. This was partly offset by lower G&A costs linked to savings realized from our continuous improvement program. On Slide 16, we provide a 6 monthly cash bridge from June to December 2025. Here, you can first see the contribution of operations, $98 million (sic) [ 90.8 million ]. This is total customer receipts less total cash OpEx, followed by the impact of restoration costs. After PRRT and interest costs, approximately $138 million in cash after operating cash flows remains. Other draws on cash for the period included cash payments for CapEx of $9.9 million. You can also clearly see here the debt repayments we made in the half, which stem from a combination of organic cash generation and the equity raising completed during the period. Cash at 31 December was $81.3 million. Moving now to our liquidity position on Slide 17. Our reserve-based loan, or RBL, provides financing flexibility and liquidity as the company enters its next leg of growth. The RBL facility limit of $480 million is supported by an assessed borrowing base that is fully available at present. 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 offtakers. 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 B -- at BBSY plus 325 basis points. We do expect to draw against the debt facility at some point this calendar year as our CapEx profile increases. I'll now hand you over to Chad to provide an update on our major projects, sliding -- starting on Slide 19.
Chad Wilson: Thanks, Ian. We remain very excited about growing production from the Otway Basin, and to that end, the ECSP made substantial progress during the first half of FY '26. I'll come to the live drilling results in a moment, but I wanted to remind listeners what the project means for Amplitude. The program involves new gas production from our existing Annie discovery and up to 3 additional fields in Isabella, Juliet and potentially Nestor, upon exploration success. There's over 260 billion cubic feet of gross mean unrisked prospective resource in the 3 exploration prospects, plus 65 petajoules of gross 2C at the discovered Annie field. Taken together, developing those resources would extend the production life of the Athena plant by over a decade from 2028. Upon exploration success, inclusive of Nestor, we continue to target a production plateau of over 110 terajoules per day for the first 4 years of ECSP production from Athena and the capacity of Athena to produce up to 150 terajoules per day means that we may have the ability to flex production up on peak demand dates or toll third-party gas through the plant. Contracting negotiations for ECSP gas supply are now very well advanced, and we expect to sign foundational gas supply agreements with multiple customers in the near-term. You will have heard Jane say before that there's no better projects in the oil and gas sector than ones that tie into nearby conventional fields to existing infrastructure. These types of projects are nearly always lower risk, faster to bring online and offer better economics. While significant upfront investment is required for the ECSP, the return on this investment comfortably exceeds our internal hurdle rates. We intend to proceed to a final investment decision to undertake the development phase of the project in the coming weeks. The ECSP is one of the most significant new domestic supply projects in Southeastern Australia and on success aims to produce enough gas to meet the needs of over 800,000 Victorian homes from as early as 2028. Moving on to Slide 20. While the recent results at Elanora were disappointing, we continued the ECSP campaign with the Isabella prospect, which is targeting a Waarre C reservoir completely separate to the Waarre A reservoir tested at Elanora. As we've said in the past, on success, Isabella is intended to be a producing field for the East Coast supply project, while evaluation of Elonora was intended to inform our longer term Otway Basin exploration and development plans. Another way to think about this is that Elanora is a cost-effective way of testing a large future exploration prospect, while the primary purpose of this well remains the discovery and development of gas from Isabella. The result at Elanora does not impact our views of the probability of success of Waarre C sand targets such as Isabella, Juliet or Nestor. Drilling of Isabella is very well progressed, and we expect to have initial results here in coming days. If gas is intersected in Isabella, evaluation of the discovery will be conducted to assess gas composition and quality of the reservoir. We plan to case and complete the well with the subsea tree upon success, incorporate a flow test, meaning it's ready for development as part of the ECSP. It's important to note that full evaluation of any discovery may take 1 week or 2 as the resource booking would coincide with our usual process around the end of the financial year. I'll move on to Slide 21 now. The potential restart of our Patricia Baleen field is a prime example of growth initiatives available within the Amplitude Energy portfolio, leveraging our existing infrastructure position connected to the East Coast gas market. Amplitude is currently well progressed through the select phase studies into the project. Current analysis indicates that Patricia Baleen could add around 4 to 10 terajoules per day of additional production through Orbost. There are minimal modifications required to the facility with the key works being focused on offshore repairs. The tight gas market and use of installed infrastructure means that this is a high-returning project and both value and earnings accretive. Amplitude anticipates entering FEED in this financial year following the completion of SELECT phase studies. SGH is also participating in the SELECT phase to assess long-term gas processing options through Orbost. I'll throw it back to Jane now for Slide 22, which helps explain why we are investing in these projects.
Jane Norman: Thanks, Chad. I see gas demand growth as the dark hole of the energy transition story. For decades in the developed world, gas is slowly but steadily taking market share from coal in the power generation mix as we now face a new reality where AI and corresponding data center investment is forecast to supercharge global power generation investment. The IEA estimates aggregated global power investment grew at 12% CAGR between 2022 and 2025. Data center electricity demand is projected to double by 2030 and nearly double again by 2040. With 24/7 power needs, data center operators are unsurprisingly investing in conventional dispatchable sources of power like gas, due to its availability and reliability. Back at home, AE's most recent forecast show gas-fired power generation growing strongly as coal exits the market. Gas demand on peak days in the East Coast is projected to more than double, driven almost entirely by the need to firm renewable power generation. It's another reminder that gas is the true enabler of renewables transition and that, that transition isn't all about replacement, it's about stacking. As coal retires, firm capacity must step in where renewables fall short. Batteries manage minutes and hours. Gas carries the system through days and weeks. No alternative yet matches that role at scale or at any realistic cost. Australia does, of course, have gas in abundance. Based on Geoscience Australia data in the Otway and Gippsland basins alone, there is more than 2,000 petajoules of reserves and 4,000 petajoules of discovered resources. These basins are geologically proven, close to major markets and connected to existing infrastructure. They can be developed far faster and at far lower cost than relying on imported LNG from overseas, yet investment is being strangled by regulatory delays, policy uncertainties and political hesitation. The projects that Chad spoke to earlier clearly demonstrate that Amplitude Energy is playing its part on the supply side of the equation. At the same time, we estimate that we will spend nearly $20 million in environmental and other regulatory approvals alone just to get the ECSP up. The local gas industry is currently participating in the federal government's gas market review. We see this as an opportunity for policy changes to incentivize long-term investment certainty for proponents of domestic gas, like ourselves. There is much low-hanging fruit here that doesn't require taxpayer support or legislation changes in any case. These include quicker, more streamlined project approvals to bring gas to market faster, removal of redundant or duplicative industry regulation and bureaucracy, regular acreage releases in all jurisdictions and approval of seismic surveys, recognizing that without both of these, exploration for new resources is impossible and reform to address the onerous consultation burden for offshore gas exploration and development. I'll move to our second half outlook, now starting on Slide 24. Today, we have increased our FY '26 group production guidance to 73 to 77 terajoules equivalent per day, up from 69 to 74 terajoules equivalent per day. Our new production guidance is equivalent to 26.6 to 28.1 petajoules equivalent for FY '26. The increase is driven primarily by Orbost yet again outperforming our expectations at the start of FY '26, together with point forward scenario analysis. Our confidence in recent production rates being sustainable means the top end of the upgraded guidance range now assumes Orbost's production rates moderately above the prior nameplate capacity of 68 terajoules per day. FY '26 guidance for production expenses, other cost of sales and cash expenses and capital expenditure is unchanged. We are tracking well in all of these areas. I'll wrap now on Slide 25. We presented these 4 business priorities for FY '26 at our last results, and I find it useful to assess our performance based on the same objectives. The ECSP is well on track with FEED for the development phase now complete and drilling of the Isabella well underway. While Elanora did not deliver the result we wanted, we expect the results from Isabella very soon, which was always the potential producer field for ECSP. We are pleased that the well operations are running to budget and schedule. Foundation GSA negotiations are also going very well and are advanced. We expect to have more news on this front in coming weeks ahead of the FID on project development. We are ahead of our target to increase Orbost's production to over 70 terajoules per day by the end of this financial year. The plant has run above that level for much of January and early February. There remains potential to increase Orbost's production through further plant debottlenecking, reducing plant reliability losses and longer term through restarting the Patricia Baleen project. We have increased our realized gas prices through greater spot gas exposure, opportunistic contracting and finding new opportunities in higher-priced markets. We've started down the road of gaining access to the gas to electricity spark spread, and we have new contracts commencing this year which substantially increase our average contracted gas price. We have maintained our focus on the cost base, and we are well ahead of our target to reduce Orbost's production cost to below $2 per gigajoule. Our continuous improvement program continues to focus on other opportunities to do things better, reduce costs and improve productivity. That brings me to the end of the presentation today. To summarize, we are very pleased with our progress against our FY '26 priorities with records across all key operational and financial metrics in the first half and further production and gas price improvements expected, Amplitude takes excellent momentum into the second half. With potentially further production growth at Orbost, a 20% increase in contracted gas prices from the 1st January 2026 and continued cost control, the company is on track to deliver solid growth in underlying EBITDAX, operating margins and adjusted cash flow from operations for the full year. We have a very exciting next few months ahead of us on the ECSP with the Isabella drilling results, gas contract finalizations and development FID, all expected in the near-term. I'll end on that note and open the line for any questions.
Operator: [Operator Instructions] Our first question comes from Gordon Ramsay with RBC Capital.
Gordon Ramsay: Jane and Ian, nice to see you back in the industry. Great set of numbers. My question relates to exploration and the result from the Elanora well. I think there was a comment, and Chad, you might have made this. I just don't know how you can say that Elanora does not affect probability of success at other wells. So the first question I've got is, have you done a postmortem on Elanora? And what have you learned from that well result? And what does that mean for some of the other prospects in the area in terms of the interpretation of the seismic data?
Jane Norman: Yes. Thanks, Gordon. So in terms of the Elanora result, there's a piece of work underway right away to assess how we could have got that amplitude support without gas-bearing sands. And what we see from the -- not only the amplitude response, but the characteristics of the reservoir, are that you need structure, reservoir, seal and charge. And so we're looking at where one of those might have been missing. And Chad will talk about that in more detail. Elanora was targeting Waarre A sands. The other prospects are targeting Waarre C sands. What we did get was information around depth of the sands and also confirmation of the seals. So I will hand over to Chad to address that in more detail.
Chad Wilson: Yes, sure. So Elanora encountered really good, thick Waarre A sands in the reservoir, probably better than we expected actually for the quality of the reservoir. It was thicker and a bit deeper. We -- from logs, we passed through really good top seal, which was fantastic. The structure was definitely there. We've seen that through the seismic and everything looked good and conforming to the structure. And from a charge perspective, there's actually gas that in the Shipwreck Trough, pretty much persistent through the whole area. So we weren't really concerned about charge. When we started to look at all the seismic data, again, after we had the logging data and compare that to where the tops were all coming in for the different reservoirs and the different sands, what we found was that the leading theory currently is that there was a potential gas deep zone in the adjacent Elanora green sand where that green sand [ abunded ] up to the Waarre A across a fault that was previously thought to be ceiling. So that's kind of the Elanora result. In terms of the other prospects, the actual trapping mechanism and the geological structure for those other opportunities or other prospects is different than the Elanora prospect. And like we said, reservoir Waarre C is a very strong producing reservoir across the whole Otway Basin. The structures in each one of these prospects is independent of the Elanora structure. And the Juliet and Nestor structures are extremely simple structures. As I mentioned, charge is throughout and ubiquitous through the whole kind of area. And with the seals, we don't see the same seal potential issue in the other prospects that Elanora has found.
Gordon Ramsay: Thank you very much for the detailed answer. My problem is I'm looking at Slide 20. And maybe it's an old cross-section and it's indicative. I don't have all the data. But when I look at the interpreted gas water contact for Elanora and then look at where Isabella gas water contact is interpreted, I can't help but thinking Isabella is going to be a smaller accumulation now because you didn't hit that gas water contact, if that is indicative of the mapping that was used for the prospective resource at Isabella. So what I'm saying is Isabella is going to be smaller if you do find gas and then what the other -- the next few prospects are quite small. So what does that mean in terms of the goal of filling up the Athena gas plant at least for the duration that you'd like to fill it up to? And does it put more pressure on the company to do M&A?
Chad Wilson: Yes. I guess from the cartoon -- we could have updated the cartoon. With the results from -- as we were actually getting the data from the logging and seeing where the tops were coming in, we have moved the Isabella prospect slightly to further up dip. And the good news is that, that Waarre B [indiscernible] kind of quite shaley seal on the bottom, we did get confirmation of that through the expedited palynology. So we have really good confidence in that bottom seal, and we drilled through where we have really good confidence in that top seal.
Operator: The next question comes from Dale Koenders with Barrenjoey.
Dale Koenders: Unfortunately, my question is probably for Chad still. I just want to expand on what you're saying at Gordon like the -- I guess, the gas fee for the leakage explains the lack of gas, but what's not explained is why you've got the false positive from seismic amplitude versus the presence of gas, which is typically driven by a differential in density between the reservoirs. So I'm just wanted to know, have you got an explanation for that because that's obviously more of an issue for future targets than potentially the seal, which is isolated to Elonora?
Chad Wilson: Yes. So that's the bit of work that Jane was talking about where we're going through that detailed quantitative seismic modeling project using the logging data that we had to tie that to the results that we were seeing and really testing to see what could have given that response. What I would say in the other prospects is there's 2 types of direct hydrocarbon indicators. There's the seismic response that we see and then there's flat spots in the seismic data as well. So for our other prospects, we do have flat spots on top of the seismic amplitude -- strong seismic amplitude support.
Dale Koenders: Okay. Got you. That makes sense. Secondly, just maybe for Jane and for Ian, probability suggest you should find gas [ in ] next target. But what does FID look like if you don't on this project -- on this current target?
Jane Norman: Yes. Look, thanks, Dale. The program was always backstopped by Annie, which is a discovery. And so it was around the opportunity to test a number of exploration targets in a program to understand which of those could be tied in. So the first well we're drilling is testing 2 reservoirs from one surface location. But on success, the plan is to keep the Isabella well as the producer. And the same with Juliet and Nestor. It was about testing exploration targets and then on success, taking them very quickly into development. So overall, with the risk -- the individual probabilities and then the risking across the whole program, there's a high chance of success. And it's really about adding resource to the -- any discovered number in order to move to a higher value, more economic project.
Operator: The next question comes from the line of Nik Burns with Jarden Australia.
Nik Burns: Again, congratulations on the record result here. Maybe switching talking about Orbost. So you reached 71 terajoules a day. Can you just talk about the performance of the plant operating at these higher levels, what challenges you're encountering at these rates? And I guess, anything you need to resolve around the plant for potentially being able to lift output sustainably higher from those levels?
Jane Norman: Yes. Thanks, Nik. So the first step in this was to receive the pipeline capacity increase, that came through late last year. And that's then allowed us to start the trials to push above 68 TJs a day. And through that, we're seeing at times, there's a high pressure differential or pressure drop across the Sole pipeline, and that's ultimately limiting the throughput of the plant to the compression capacity, the South gas compressors. So we are working to try and remove the pressure drop across the pipeline. There are some minor CapEx instrument changes that we're planning to do in the next couple of months when the opportunity arises, and that will help remove one of the risks around flowing at this higher rate, and then we'll be able to push the plant higher. What we are seeing is that as the plant does go and run at higher rates, that helps clear this pipeline pressure drop. So it's incremental steps, but the next step is really to push up into that sort of mid -- low to mid-70s and then continue to monitor the pressure drop across the pipeline from there.
Nik Burns: Just to be clear, you're hopeful you'll be able to be in a position to test those higher rates before the end of this financial year?
Jane Norman: That's what we're targeting.
Nik Burns: Right. Okay. And then you talked about Sole field performance supporting the higher rates as well, and you talked about that further technical studies underway to ascertain whether there is a potential contingent resource booking here. What data are you seeing at the field that gives you confidence there might be additional gas resources here beyond what's been booked? And I'm interested in the fact that you've talked about booking contingent resources rather than potentially increasing the reserve base 2P towards the 3P. How should we interpret that?
Jane Norman: Yes. Sure. I'll hand to Chad.
Chad Wilson: Yes. Thanks, Nik. Yes. As we've been running at those higher rates, all we're really getting is better and better flowing material balance data. As we did last year, what we ended up seeing was that the data was -- the data just couldn't support the 1P booking being as low as it was. And so once that became obvious that the 1P was there, you look at the 1P and the 3P, the new ranges for that and the 2P came out higher. We're continuing to see that really strong performance, and it appears that there's more energy in the system from gas than there is from water, like the aquifer providing some of that pressure support. So we just need some more running time to be able to make those decisions on that, but we're also seeing more capacity or gas energy in the system as a whole. And that's why we're looking at a contingent booking on top of that is it seems like there's more support coming from somewhere else.
Operator: The next question comes from James Bullen with Canaccord Genuity.
James Bullen: Congratulations on the result. Just around Nestor, so the JV hasn't approved that. What's holding that up? And do you need to complete the post on the reasons behind the false positive before it gets approved?
Jane Norman: Thanks, James. So maybe if I just back up to when OG came into these assets, they acquired the Mitsui stake. And at that stage, the program was the combined Elanora, Isabella well, Juliet and Annie and all the long leads have been secured for those. The joint venture has approved acquiring the Nestor long lead so that we are in a position to take advantage of the rig being in the region, but we're yet to make a final decision to call that slot. So we're progressing and advancing everything as though we're going to do it, but we just haven't yet had to call that slot. So Nestor is a really attractive prospect. It used to be held by us 100%, but we have equalized the ownership with OG right across the Otway Basin to 50-50. So we're fully aligned on the economics. And so we raised equity late last year, as you know, to add that prospect to the program and really to take advantage of all the costs and the approval we already had in place from NOPSEMA to drill that as part of the program.
James Bullen: Okay. And just around the potential at Sole and this potential 2C booking, is the best way for us to think about the size of the tank is still the same, but you're looking at higher recoveries from the reservoir?
Chad Wilson: No. We're thinking maybe the size of the tank is a bit bigger.
Operator: The next question comes from Declan Bonnick with Euroz Hartleys.
Declan Bonnick: Great set of results. My question is on the ECSP foundation contracts. You spoke to the Orbost re-contracting hitting the mid-teens per gigajoule pricing. I'm just wondering how the pricing is looking for the ECSP contracts, if it's in the same ballpark?
Jane Norman: Yes. Look, thanks, Declan. Yes, pricing is very consistent with our expectations and with recent deals that have been signed in the market. I think one development we have seen is that a number of the large customers are looking at LNG-linked pricing, which is typically a slope to oil as an alternative to fixed price contracts with CPI indexation, and that's really reflecting the alternative supply in the market being a netback from the Wandoan hub in Queensland or direct imports into one of the proposed regas terminals in the South. So that's the biggest change. But certainly, the fixed price CPI contracting is really aligned with recent deals we have done and others have done in the market.
Operator: Ladies and gentlemen, this now concludes our question-and-answer session and does conclude today's conference as well. Thank you for your participation. Please disconnect your lines, and have a wonderful day.