Amplitude Energy Limited

Welcome to the Amplitude Energy Limited FY26 first half results webcast. All participants are in a listen-only mode. Following the call, there will be a question and answer session. To ask a question, participants need to dial star 1 on their telephone keypad. I will now pass over to Jane Norman, Managing Director and Chief Executive Officer of Amplitude Energy. Please go ahead, Jane.

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 calibre add to the strengths 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 two of the presentation before moving on to slide three. 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 August is underpinning our base business and with a good second half expected across all three of our basins, we have increased FY26 production guidance today. As we increase office production rates, it is important that the Seoul Reservoir continues to perform well. We significantly increased our two-tier reserves booking in Seoul 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, high-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 anti-discovery. Whilst the Eleanora 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 Eleanora, 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 gate and potential backfill to existing infrastructure from our booked 2C and Manchurian Gummi 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 five now to dive into the headline results. This morning we announced an outstanding set of numbers for the first half of FY26. These results highlight further improvement in production at August, 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 FY26. The confidence we have in the performance of our base business and expectations of further upside has allowed us to increase FY26 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 six now and provide an overview of our HSC 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 FY26 with no recordable injuries or Tier 1 or Tier 2 CROSA safety events. The company has now achieved over two 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 organisation will increase in FY26 and FY27 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 seven and an overview of the Gippsland Basin production. August 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 Solfield came online in 2020, there were zero cleans of the sulphur absorber units in the six months to the 31st of December. As of that date, one of the absorber units had run nine months without a clean. A lack of absorber cleans means higher production and lower costs. improving our margins and cash generation for the plant. In January, we undertook our first absorber clean for FY26 in both absorbers, utilizing the new clean-in-place method. This allowed some of our fastest cleaning times on record, with all this 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 a year ago. In December, we finally received regulatory approval to lift Sol Pipeline's production capacity, meaning Orbest can operate above its previous nameplate level of 68 terajoules per day. We have successfully trialled 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. Felt fields and reservoir performance continue to demonstrate strong and reliable production capability, with the existing wells comfortably supporting the increased throughput rates at all this. Importantly, the field's proven deliverability is expected to underpin anticipated near-term debolding making 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 eight. The average processing rate of Athena during the first half of FY26 was 8.2 terajoules per day, net to Amstitude 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, at just over one 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 three-well development campaign was undertaken in the Kalawonga field, with production expected to commence from this area in the second half of FY26. We are also assessing other Cooper Basin prospects ahead of the next phase of development. The next two slides talk to our initiatives to increase gas prices, starting with slide nine. 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 coming years. I should reiterate that this does not constitute production guidance. The profile we're showing here is based on actual group production for 2025 and illustrative group production at 75 terajoules equivalent per day from 2026 onwards. As noted in the call-out box on the top right-hand side, the chart does not include any increased volume from our ECFP project. Beyond the picture 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 gas marketing activities. On average, realized gas prices have consistently increased over the past three and a half 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 all this 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 maximise sales during high-demand periods, as well as prioritising sales into markets with the highest price. The chart on the right illustrates two contractual arrangements that we recently entered into with Anji for gas supply to its Pelican Point power stations. The agreement provides amplitude with exposure to South Street and spot electricity prices between a strike price and a cap, effectively mimicking the spark 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 FY25 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 two-thirds of this relates to production improvements. I have already discussed These and they're 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 FY23 before I started at Amplitude. In the half just gone, those costs were down to $5.2 million, despite three 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.

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 FY26, 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 FY26 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 all cost. We've therefore upgraded production guidance today which Jane will cover shortly. Sales revenue of $141.5 million was also a record for a half at 6% above the prior comparable period due to a combination of higher sales volumes and higher average realised 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 gigajoules. 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 FY25, another record for the company. This highlights the cash generation potential of the business and indeed adjusted cash from operations. for first half FY26 was up 5% to a record $85.6 million. Underlying net profit after tax was $25.7 million for the first half of FY26, 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 FY25. This was largely associated with ECSP long lead items. with OG Energy's cost carrier 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 of 31 December reduced to $34 million, reflecting a strong balance sheet ahead of the ECSP investment phase. Slide 15 provides further detail on underlying EBIT DAX in the half. This waterfall bridges first half FY26 underlying EBIT DAX of $100.3 million back to the first half FY25 result of $92.2 million. Increased gas sales volumes and higher average realised 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 FY25, impacted by flooding in the Cooper Basin. As Jane stated earlier, production from our Cooper Basin interest is expected to recover in the second half of FY26. The $4.5 million decrease in cost of sales was largely the result of lower all boss production costs. As compared to first half FY25, 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 realised from our continuous improvement program. On slide 16, we provide a six-monthly cash bridge from June to December 2025. Here, you can first see the contribution of operations. $98 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 stemmed 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 $490 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. maximising debt availability while offering a competitive cost of funds with debt service on the drawn portion 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 starting on slide 19.