Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by, and welcome to Cooper Energy Limited's Full Year 2023 Results Conference Call and Webcast. [Operator Instructions]. Thank you. Jane Norman, Managing Director and CEO, you may begin your conference.

Thank you. Good morning and thank you for joining the Cooper Energy Annual Results Webcast and Presentation. My name is Jane Norman, I'm the Managing Director and CEO of Cooper Energy, and I'm joined by Chief Financial Officer, Dan Young. After the presentation, we will 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 Cooper Energy website. Today's webcast is being recorded and a playback will be made available on our website later today. Please note the disclaimer on Slide 2 of the presentation. Today, we released our full year results for financial year '23 and my first as Managing Director and CEO. The Cooper Energy strategy to supply domestic gas to the Southeast Australian market has been set for some time. The market opportunity is part of what drew me to the role. After starting with the company in March this year, having now spent roughly 150 days as Managing Director, I am confident that the strategic direction to focus on the Southeast Australian gas remains correct. Forecasts continue to show the domestic gas market is structurally short and requires new gas supply to meet the widening gap between supply and demand. Cooper Energy has production and cash flow today, bringing gas to market via 2 operated gas hubs, supplying long-standing customers as well as the Victorian spot market. During financial year '23, we acknowledge that operational performance was below expectations, in particular at the Orbost gas processing plant and this translated to the share price. Nevertheless, it was a year in which we achieved record production, record underlying EBITDAX and record operating cash flow. Turning to Slide 4 and the FY '23 highlights in more detail now. In FY '23, we delivered record results from both an operational and financial perspective. Our safety performance remains strong and below the industry benchmark, with zero lost time incidents and more than 1,400 days since our last lost time incident. Our total recordable injury frequency rate was 4.38 per million hours worked and below an industry benchmark, and we maintained our carbon neutral position. These safety and environmental performances results illustrate the discipline embedded in our operations and activities. [ To select ] some key production and financial statistics. Production was up 7.8% to 3.56 million BOE. Operating cash flow, up 8.7% to $62.8 million and underlying EBITDAX up 35.4% to $109.3 million. Dan will discuss the financial results in more detail later in the presentation. Turning to Slide 5 now, and a look at health and safety results in more detail. Pleasingly, we remained LTI free in FY '23 despite an increase in hours worked. Unfortunately, we did record 1 medical injury, resulting from a single laceration that required stitches. As a result of this medical treatment injury, the total recordable injury frequency rate was 4.38 injuries per million hours worked compared to zero in FY '22. During FY '23, there were 2 minor environmental incidents, both as a result of emissions exceeded from an exhaust system at Athena Gas Plant. Both were assessed as not giving rise to actual or potential harm to either human health or the environment. Following the incidents, both matters were remedied with a revision to operating procedures. We maintained our carbon-neutral organization certification with respect to Scope 1, Scope 2 and relevant Scope 3 emissions. In FY '23, this has predominantly been achieved by offsetting via projects generated and purchased carbon credits. More information regarding Cooper Energy's carbon neutral certification is contained in our FY '23 sustainability report, that will be released concurrently with our Annual Report on October 9. Turning to Slide 6 now for an overview of the organizational changes that we have implemented to the executive team. The organizational structure shown on this slide reflects a greater focus on operational excellence and delivery. The leadership team has been rejuvenated with exceptional talent, to ensure the organization is future fit. The new structure reflects an increased asset focus with more clearly defined roles and responsibilities. Cooper Energy's transition to operator is also emphasized under the new structure, with the appointment of Chad Wilson as Chief Operating Officer, effective 23rd of October this year. Chad will have functional responsibility for operations, including both gas plants, maintenance, engineering, development projects as well as the operational task force responsible for the Orbost Performance Improvement Plan. Chad has a strong track record of driving transformational cost reductions and efficiency improvements, with a career spanning 20-plus years at Talisman and most recently, Santos. Nathan Childs, who currently leads to Taskforce, will transition to a newly created role of Chief Corporate Services Officer, effective the 1st of November. Under the new structure, Andrew Thomas remains responsible for the BMG abandonment program, to ensure continuity of operations, as we approach the commencement of the decommissioning work. Further to the organizational restructure, there will be a reduction in the number of key management personnel, and remuneration will be reviewed to be more aligned with the shareholder experience. One of the outcomes of the review will be an increased portion of at-risk remuneration, with a greater reliance on operational performance. Turning to Slide 7 and an overview of the Orbost operations. The FY '23 average processing rate at Orbost was 47.1 terajoules per day, slightly higher at 47.9 terajoules per day, excluding the April planned maintenance shutdown. Although the transaction to acquire the Orbost plant closed on the 28th of July 2022, operatorship was transferred on the 22nd of May, deep into FY '23. Throughout the transition period, plant performance was below expectations. Despite this, the trend indicates FY '23 improvements from FY '22, driving an increase in the underlying EBITDAX and operating cash flow this financial year. Stability at the plant became more visible in late January '23, following an increase in Cooper Energy's presence on site, after a particularly poor performance in November and December '22 and the first half of January '23. The second quarter of FY '23 was punctuated by a series of recurring plant trips, unplanned downtime in part due to human error, not significantly to disruptive processing rates. The Orbost performance improvement plan continues to be implemented, with the current focus on reducing absorber failing and clean time. To date, the team has successfully reduced the time taken for absorber bed cleans by more than 25% from over 40 hours to consistently less than 30. I'll expand on the status of the workstreams further in the presentation. The Athena Gas Plant on Slide 8 now, also struggled for consistency at times during FY '23. The average processing rate at Athena during FY '23 was 21.4 terajoules per day on a gross basis or 10.7 terajoules a day net to Cooper, with the well cycle to optimize performance. Throughout the year, processing rates were disrupted by unplanned downtime and maintenance of the C-701 export gas compressor, resulting in deferred production in December, February and May. Remediation work to the compressor completed in May, and has successfully solved a longstanding and systemic issue with a dry gas deal that has been present for over a decade. With that issue now resolved, it is our intention that Athena and the Casino, Henry and Netherby wells will provide a more reliable rate of production throughout FY '24. Slide 9 summarizes non-operated production in the Cooper Basin and other activities, including BMG and our FY '24 focus on cost reductions. Our net share of PEL 92 oil production in FY '23 was 319 barrels a day compared to 335 barrels a day in FY '22. Development wells drilled in FY '23 will partially offset declines from this maturing asset. Other significant activities during FY '23, included planning and pre-abandonment work on the BMG decommissioning project, which is scheduled to take place in coming months. In June 23, we announced to the market our intention to reduce general and administrative costs by at least 10% in FY '24. This work is an all-encompassing review of how and where we work, and will be transformational across the entire business. Turning to Slide 10 now and a wrap-up of the government policy changes in FY '23. There were 2 elements to the government intervention in FY '23. Firstly, the mandatory code regulations throughout the consultation process, Cooper Energy worked closely with the government and the ACCC following the announcement of the intervention in December '22. When the final gas code regulations were released on the 10th of July this year, carve-outs for domestic suppliers with production of less than 100 petajoules per year, ensure Cooper Energy is exempt from the $12 gigajoule price cap. Foundation GSAs commercializing undeveloped gas are exempt from the code's expression of interest and other timing provisions, and Ministerial Exemption is expected to be granted to larger producers for domestic gas GSAs to ensure JV alignment. This has a positive implication for potential JV partners farming into Cooper Energy operated licenses. Changes to PRRT announced by the Treasurer as part of the May Federal budget did not impact Cooper Energy, a new cap on deductible expenses to 90% of PRRT accessible receipts only applied to LNG projects, and there were no changes to rules on combination certificate. There is a clear positive distinction for domestic gas companies such as Cooper Energy versus large-cap LNG exporters. I'll recap the FY '23 highlights on Slide 11 now before handing over to Dan. As I mentioned in my opening remarks, FY '23, the company has achieved record results across a number of key metrics of production, underlying EBITDAX and operating cash flow. Our executive team has been refreshed and a new organizational structure is in place, with a focus on operations and clear accountabilities. The structure is set for our current operations with a greater focus on operational excellence. A significant milestone in FY '23 was the integration of Orbost operations into our portfolio. This was executed on schedule and on budget, showcasing our commitment to efficient project management. The August integration has not only bolstered our operating capabilities, but it has also reinforced our position as a key player in the Southeast Australian gas market. Following transfer of operatorship on May 22nd, I set up an operations taskforce responsible for the Orbost performance improvement plan, giving single point accountability, as we progress through the work streams. In addition to Orbost integration, our engineering teams have been focused on preparing for the BMG abandonment project. In June, we updated the market on the cost and timing for this project, and those figures and timelines are still the best estimate with the Q7000 rig expected to finish in New Zealand in late September. We are ready to progress growth in the Otway and continue to support Mitsui with their process. To enable the Otway growth, we have a foundation gas contract with AGL agreed for the Annie discovery, exemption from the $12 gigajoule price cap and a rig contracted for FY '25. Importantly, Otway growth will be funded by cash and existing debt facilities. So it is imperative that we achieve our targets with the Orbost improvement plan and complete the BMG abandonment work on time and on budget. I'll now hand over to Dan for the financial highlights, starting on Slide 13.

Thank you, Jane, and good morning, everyone. Today, we've reported again record full year results across a number of key metrics. Production for the year was around 3.56 million BOEs, which is equivalent to 9,750 BOEs per day or just under 60 terajoules equivalent per day and is a record for the company, 8% above FY '22 and within revised guidance. The key driver for the FY '23 production increase being, higher rates at Orbost relative to FY '22. Although average realized gas prices were up 4% to $8.59 per gigajoule, top line revenue was down 4% compared to FY '22 to around $197 million. This was due to lower sales volumes in FY '23, which was actually driven by the improved rates at Orbost, resulting in reduced third-party gas purchases, which were down by around 90% year-on-year. To put that another way, revenue was down 4%, but that's because we didn't need to purchase as much gas to fulfill contract nominations, because of the higher average rate at Orbost. Production expenses were down almost 1/4 in aggregate dollar terms versus FY '22, with the most significant driver being the removal of the capital charge embedded in the Orbost toll to APA. Unit production expenses were around $2.80 per gigajoule, down from $3.97 per gigajoule in FY '22 or a reduction of around 42%. Underlying EBITDAX was up 35% to $109 million compared to just under $81 million in FY '22, due to the higher production in margin expansion and also within revised guidance. This highlights the cash generation potential of the business that we've talked about for some time, and indeed, operating cash flow for FY '23 was up 9% to almost $63 million. Unlike underlying EBITDAX, the reported operating cash flow has not been normalized, so it includes the impact of around $6 million of nonrecurring Orbost acquisition and transition costs as well as the BMG abandonment spend, which in cash terms was around $20 million, and the July APA toll, collectively around $30 million of cash outflow included in the operating cash flow number. CapEx for the year was $42 million, including over $15 million for [ OGPP ] costs and around $6 million for Orbost transition costs. Drawn debt is unchanged from a year ago, with net debt at year-end at around $80 million. Turning now to Slide 14; we provide a bridge of FY '23 underlying EBITDAX of $109 million back to the result for FY '22 of just under $81 million. As expected, there were significant savings in OpEx, due to the cessation of tolling arrangements with APA, following completion of the acquisition of the Orbost plant in late July '22. These savings were partially offset by higher production expenses as owner of the plant, and production costs at Orbost were higher than planned, reflecting the higher cadence of absorber claims, and the enlarged engineering and technical support team. Other significant impacts to underlying EBITDAX included lower sales volumes, offset by fewer third-party purchases that I just discussed, and high gas price realizations, reflecting the embedded inflation escalation provisions that exist within our contracted gas stack. Next, on Slide 15, we provide a cash bridge back to a year ago. In the first part of the cash bridge, we have amalgamated the impact of the acquisition of Orbost and the related financing activities into a single bar. Note that this excludes the institutional portion of the equity raise, which was received before the end of the prior financial year and is reflected in the starting gray bar. That results in an adjusted opening cash of $52.5 million, which increased to $115 million after incorporating the operating cash flow of $63 million, which I just talked a little about. As called out in the blue balloon on this slide, this operating cash flow number includes around $20 million of restoration cash outflows related to BMG, plus the Orbost transition costs and the July toll. The remaining spend in the year included CapEx spent on OP3D fee costs and the capital portion of the Orbost transition costs, which combined were over $20 million. Cash at June 30 was $77.1 million. It's important to highlight that between the BMG restoration cash outflows, the CapEx and operating cost treatment associated with the Orbost transition and OP3D fee costs, we had around $45 million nonrecurring costs, which is to say underlying free cash flow generation was almost $75 million, despite particularly weak production rates at Orbost, between November and January, and with relatively soft spot gas prices during the last quarter of the year, with a relatively warmer start to the winter peak period. I'll now hand back to Jane to discuss the FY '24 corporate priorities.

Thanks, Dan. And here on Slide 17, we can see our FY '24 priorities laid out, and as you may well imagine, we are firmly focused on Orbost performance and BMG abandonment in the immediate term. These 2 work streams unlock Otway growth and our imperatives to accompany this financial year. This high-level schedule sets out the context for the next 3 slides, starting with a detailed look at the Orbost performance on Slide 18. The Orbost Performance Improvement Plan, which has been underway in parallel with the transfer of operatorship work stream, is now being accelerated under Cooper Energy's control, with specific tasks targeting incremental increases to average processing rates. There are 6 major work streams under the performance improvement plan. These do not include significant capital costs. This work is focused on reducing absorber bed fouling, and reducing the time required for absorber bed cleans in order to increase the average production rates at the plant. To-date, since taking over operatorship at the plant, we have reduced the time taken for absorber bed cleans from circa 48 hours to less than 30 per absorber bed clean. Without delving into the weeds too deeply, current near-term actions are focused on, freshwater circulation washing of the absorber beds to test whether in-situ cleaning as a possible replacement for the current mechanically intensive cleans. Alternative absorber packing trials, multi-nozzle spray distributor trials, alternative polisher strategy use; for example, using it tactically, as required for commercial upside or reliability mitigation. And nutrimix trials addressing density of solution and impact to sulfur deposition within the absorber beds. Separately, we continue to engage with multiple global experts and technology owners, Paqell, who will commence a detailed technical investigation in September. As we continue to implement aspects of the Performance Improvement Plan at site, there will naturally be minor operational instability, and this should be factored in when observing daily production trends. In addition to these near-term initiatives, we continue to develop the option of installing a third absorber bed. The third absorber bed, if approved, could potentially be operational in the course of calendar year '25, and would provide redundancy to current absorber bed operations and backup capacity to the improvement plan. The option to install the third absorber bed is pending sanction timing and other economic factors, and we expect the CapEx to be relatively modest. On Slide 19, our other immediate priority is the BMG abandonment program. The Helix Q7000 abandonment vessel contracted to perform the work is currently in New Zealand and will return to Australia following the completion of the current work schedule. We have been working constructively with Helix to ensure that we can meet our regulatory commitments within the required time frame. Although there is still some uncertainty around the schedule, we are also actively working with our other suppliers, to minimize any cost impacts associated with the delays. In June '23, we provided an update on the cost estimate for the abandonment project, recognizing industry cost inflations on supporting contracts, such as support vessels, helicopters, rig work and other costs. The mid-case cost to complete the well abandonment is estimated to be $193 million to $198 million on a 100% gross basis, with approximately $27.9 million of this incurred in FY '23. The mid-case cost estimate incorporates contingencies for nonproductive time and weather delays, as well as an additional general contingency. Cooper Energy continues to pursue its Supreme Court claim against Pertamina for its 10% share of the BMG decommissioning cost. Although the current BMG programs dominate our focus in the near term, I want to flag that the other decommissioning work in the next 5 years, certainly nothing like the spend of the current BMG program, but I hope this clarifies works on our radar, in terms of abandonment. On Slide 20, we summarize the Otway growth and the OP3D status. Although our immediate focus is on the job at hand, our opportunity to bring new gas supply to the market is most likely the OP3D growth project. The cornerstone of this project is the gas sales agreement signed with AGL for our share of the Annie gas. Additionally, we have signed on to participate in a rig club with other operators in the area for drilling in FY '25. The [ haulage ] of the Athena gas plant allows for significant development of new gas reserves, with additional capacity still available for potential third-party processing. I'll now hand back to Dan, who will run through the FY '24 guidance, starting on Slide 21.

Thanks Jane. For FY '24 guidance, we are providing customary production and CapEx guidance for the year. But unlike previous years, we will provide production expense guidance in lieu of underlying EBITDAX guidance. This change aligns the company with our E&P peers, and emphasizes the free cash flow elements that management and the company control. For FY '24, we are guiding to a production range of 55.5 terajoule to 65.2 terajoule equivalent production per day. That equates to around 3.5 million to 3.9 million BOEs for the year and compares to consensus at around 3.7 million BOEs. While we don't provide production guidance by asset, I would say that the midpoint of FY '24 production guidance assumes improvements at Orbost above the FY '23 average production rate of 47.1 terajoules a day, offsetting declining production from the mature Casino, Henry and Netherby wells in the Otway, as well as Cooper Basin oil production from PEL 92. The May 2023 resolution of the legacy compressor reliability issues at Athena and development drilling at PEL 92, has also helped to partially offset natural decline in both the Otway and Cooper Basin. Production expenses in FY '24 are expected to total between $60 million to $68 million, excluding any third-party gas purchases and royalties. Consensus also sits within this range if we exclude 2 higher outliers. A portion of this range represents an increase on FY '23, in part due to more frequent absorber cleans at Orbost than in FY '23 and a fully staffed technical and engineering teams supporting both plants. FY '24 capital expenditure guidance is $190 million to $210 million, dominated by the BMG abandonment expenditure. The balance of CapEx guidance is ordinary same business CapEx. On Slide 22, we provide some more guidance on production expenses. The first chart here on the top left-hand side shows the buildup of production expenses in Australian dollars for the Gippsland and Otway gas hubs, and excludes PEL92 Cooper Basin oil. The chart on the bottom left-hand side presents that same data, but on a unit basis. And so here, the total column represents the blended unit cost, across both our gas hubs. Upstream expenses are a little lower compared to a year ago, with savings across labor and materials. Midstream production expenses, however, have increased. A big part of this is the increase in operational maintenance, for example, increased absorber cleans at Orbost, a full engineering and technical support team, as well as wage increases following completion of a new EBA midyear at Athena, and general industry inflation. There are certainly opportunities for savings, especially in the second half of this financial year, and into FY '25, in parallel with the expected positive impact from the Orbost performance improvement initiatives, in terms of costs in handling the sulfur deposition problems in particular. For example, we expect to see a reduction in absorber bed clean frequency, increased plant uptime and reduced overhead. Turning now to Slide 23; on this slide, we lay out the expected net debt position through the course of the year, as we execute the BMG wells abandonment. The graph shows the starting net debt position of around $80 million as of June 2023, to a maximum level by the end of calendar year 2023, when we anticipate the majority of the debt drawdown, and the activity around the BMG wells to have occurred, and our net debt position to maximize at that level. As we move through the second half of FY '24, there will be continued deleveraging through organic free cash flow generation. You can see that both in terms of the red net debt bars, but also the net debt-to-EBITDA green shaded range. We're maxing out here at around 2.5x net debt-to-EBITDA, before some pretty rapid deleveraging through free cash flow generation, as I mentioned. A few comments on the Group debt facility; it's a straightforward reserve base line secured across a diversified borrowing base of assets. The bank syndicate comprises a group of 8 strong banks, that are experienced upstream E&P lenders. There are no near-term maturities and in fact, we have a $180 million loan repayment at the expiry of the loan in 2027. So from the bank's point of view, they are pretty relaxed at this point, without any real pressure in terms of debt repayments, just the interest service on the loan. So the picture overall is one that while we'll be incurring significant additional leverage this year, we will also rapidly delever, and with no real pressure in terms of principal repayments. I'll now hand back to Jane for concluding comments on Slide 24.

Thank you for your time today and hopefully, I've been quite clear on our priorities for FY '24. We must be successful in our endeavors at Orbost, the incremental cash flow is the enabler for growth. Concurrently, we must deliver the BMG abandonment program on time and on budget, removing the liability from our balance sheet, and clearing the way for future projects. Cooper Energy's twin hub gas strategy has the ongoing challenges, that are being systematically resolved. The strategy and market opportunity remains compelling, and there is deep value in the current depressed enterprise value of the business, and this will be unlocked. Significant high leverage long-term growth remains intact. In combination with our restructure and the FY '24 cost-out initiatives, Cooper Energy will be future fit and positioned for growth. I'd now like to open the lines for any questions.

[Operator Instructions] Your first question comes from the line of Nik Burns with Jarden Australia.

Congratulations Jane, on getting through your first 150 days. Just a couple of questions on Orbost. Slide 17 in your pack on FY '24, am I reading this correctly? You're targeting a mid-case average rate of mid-50s TJ a day in Q3 FY '24? If so, you did outline a bit of a laundry list of possible areas of improvement. Just wondering what gives you the confidence that some or most of these activities will be successful, in lifting average rates by at least 15% within 6 months?

Yes, that's right. That's the increased forecast on Slide 17. And then Slide 18 sets that out again, showing the impact of the planned shutdowns on volume as well. What we're trying to differentiate, is an average production rate throughout the year from maximum production rates, because we obviously have to factor in the regular absorber bed cleans, as well as any scheduled maintenance shutdowns. The series of activities we've outlined, will reduce the absorber fouling, and it's really a set of initiatives that we're working through, in order to understand the impact of them. You've probably seen in recent weeks, there's been some production reliability issues at the plant as we've been testing different nozzles and different types of packing. And through those trials, we get new information and then adjust the program accordingly. So the list of initiatives is constantly being reviewed and high-graded to focus on what's going to deliver the biggest impact. But that program outlined is aligned to the production forecast that is shown.

Got it. So you are pretty confident you can get [ to those ] numbers by Q3?

Look, we're continuing to work our way through this trial. And ultimately, it's about reducing the amount of absorber fouling and therefore, the need to clean the beds as frequently. And that's highly correlated to the operating costs as well. So we're confident we can make an improvement, and we continue to work through that program.

Got it. And you just -- you mentioned the merits -- you're assessing the merits of a third absorber at Orbost. Can you just walk through the thinking around this? I think you mentioned the words modest CapEx, maybe can you provide us a bit of an indication or quantification of what that could mean and when you'd be in a position to make a call on whether to proceed with this investment?

Sure, Nik. So today, we have 2 absorber beds that are planned. We are taking one down each week to clean it. The time for that clean has now been reduced to sub-30 hours, and then it's back online. When both beds are operational, the plant is running at around that low 60s or 60 terajoules a day level. When one bed is offline, the plant drops to 35 terajoules per day. So by having a third absorber bed, we hope to be able to clean the bed off-line and then maintain 2 beds online at any one time to get that average production rate up to low 60s, or with these other improvements hopefully into the mid-60s. So the thinking is really about having redundancy and that the cleaning can be done when the bed is off-line and not part of the processing system. So that's the rationale. The other improvements we hope to make with things like in situ cleaning and different packing to reduce the fouling, that's all intended to improve the overall performance of, whether it's 2 or 3 beds, but reduce the frequency of the bed cleans as well. To a modest CapEx, look, we're still working through this, and we are doing the work with the engineering company who designed and installed the current beds. But I'd say, very rough numbers, less than $40 million, and we'll continue to provide updates on that, as we do the work.

Your next question comes from the line of Gordon Ramsay with RBC Capital Markets.

Just a quick question on timing for the solids removal package. I know in the first half presentation, there was a goal to commission that in the first half of FY '23 presentation. The goal was to commission that in the first half of FY '24, and there was a target to get up to 68 terajoules a day. What's the latest thinking on this with all the other work that's going on?

The solids removal package is still part of the improvement plan, but it's a lower priority than the other initiatives today. We'd hope to significantly reduce the solid sulfur that's in the solution and also the absorber bed fouling before we turn that unit on, because otherwise, we're confident -- not confident it would run for a long duration. So it's still on the list, but the other initiatives around packing and the spray nozzle distributors, and also in situ cleaning are a higher priority today.

And just a quick question for Dan. Just on that restoration expense of $46.3 million, was that -- is that largely related to Bass and Manta?

The restoration costs that feed through into the P&L are largely a result of changes to our assumptions around restoration costs for projects that are no longer producing assets or have value on the balance sheet. So that's right. It changes to the cost to do BMG, but also Patricia Baleen and Minerva. And those things reflect general industry -- higher cost to undertake decommissioning activity and general inflation assumptions, and the different other pieces that feed into estimating that provision. So that's what you're seeing there, in terms of those -- that impact on the P&L.

And just to confirm with OP3D, this is back to you, Jane. Is there just one firm well committed, and how many option wells would you be looking at, depending on your position at the time when you're drilling?

Yes. It's one firm well commitment and a number of other optional well commitments later in the program.

So it sounds like more than 1 potentially?

Yes, more than 1.

Your next question comes from the line of Adrian Prendergast with Morgans Financial.

Yes. It just sounds like you're really making some important commercial lendings and improving the uptime at Orbost, is obviously a key focus. I just wanted to say, beyond looking at that -- the option of that absorber bed, another workstream previously mentioned was possibly tweaking the chemistry on the anti-foam solution itself. And just wanted to see what's happening there and what we can expect going forward.

Yes, we continue to look at the anti-foam solutions. So we're doing that as part of the nutrimix trials, with the specialist in particular Paqell and other global experts, to try and understand the interplay between the antifoaming agent and the lean solution, which contains the bacterial solution that's removing the sulfur from the gas. So it's still part of the trial and certainly looking at things like changing the packing and the multi-nozzle spray distributor trials, that's all about managing the foaming in the bed, and about managing where the foaming -- the fouling is occurring in the bed. So yes, that's absolutely on the list.

Great. And just another question, switching gears a little bit. You're obviously highlighting some big overheads and other cost changes that you're hoping to unlock from the business. Just kind of hear more on your vision for cultural changes that you're looking to deliver, given some of the increases in terms of the -- I guess, past regimes around attitude towards cost, culture and your vision [ venture ]?

Yes. So right across the business, we are looking at cost reductions, and that's everything from office leases through to headcount reductions and any discretionary spend. Culturally, it's really around resetting the whole business to focus on free cash flow generation, and being very mindful of any spend. I think the big shift we've seen in Cooper Energy in the last few years, is from an explorer developer to now an operator, and so the focus has to be on operational excellence delivering every day, meeting every target we promised. And certainly, the organizational structure and the exact leadership changes are part of that reset, and ensuring we deliver what we promise.

Your next question comes from the line of Henry Meyer with Goldman Sachs.

First question for me around receivable of the Q7000. Have you received a date or expected time for when that rig will be available?

Yes, Helix have nominated the window of the first to the 30th of September. And we understand that the program in New Zealand is going to wrap up in late September. And then the Helix vessel, the Q7000 will move to the Gippsland, to commence our work.

Great. Okay. So late September, and just a follow-on there, can you share what the assumption for rig receivable was in the mid-case CapEx outcome?

Sorry, could you repeat that, Henry?

Yes, sure. Sorry. Just what the assumption for the rig receivable time was in the mid case outcome and that perhaps what portion of contingency was for idle support vessels in the event of a delay?

So I think the best way -- Henry, it's Dan here. The best way to answer that is the way we've built those contingencies into the low, mid and high case, isn't driven so much around specific assumptions for support vessel, idle time or days for receiving the rigs, the Q7000 itself is really around, firstly, building up contingency for waiting on weather and for MPT and nonproductive time, and then a general bucket of contingency for whatever else might come through this project, whether that is the kinds of things that you're speaking about, or something else during the course of the program. And that's really how that's built up. So I can't link a direct tied to the contingency with respect to even to the 2 pieces you're talking about. But I can tell you that, yes, there's certainly very significant contingency we've built into the -- that mid-case estimate for those 3 general buckets.

Got it. Great. And maybe a third if I can, the gummy Resource volume booking? Are you able to share if you have a development concept in mind for what that might look like for the developments? Obviously, very early days. And if you have data available for the gas composition of the discovery?

Sure. Let me answer the first part of that. So the gas resources, prospective resources in that area in Manta Deep, Wobbegong, were announced at 1.3 Tcf of prospective resource back in May this year, with a 2C booking on Gummy. Our organic case is to bring that gas back to the Orbost gas plant, which could either be backfilled to the sole project back through the Patricia Baleen pipeline into the plant, or potentially expansion of the plant, if we can make the timing work on that. However, we know there are other operators in the area and Kipper is the closest infrastructure to this resource. So another option would be to look at going back through those facilities into a Longford plant. So we'll continue to pursue all options, but there is significant prospective resources there. And the gas itself is low CO2 and high condensate yield.

[Operator Instructions] Your next question comes from the line of James Bullen with Canaccord Genuity.

Just a question around Chevron's auction, when do they have to exercise that, to get the Q7000?

So we understand that Chevron have an option on the Helix Q7000 vessel. We're not privy to all the arrangements there, but we understand that they have an option to call the vessel in the next couple of weeks, so the first part of September.

Right. So if they do exercise that option, is late September out of play and it will essentially be arriving in October?

Yes. If they were to exercise that option and take the vessel up to the Gorgon field, then we would be looking at how do we minimize the rest of the spread costs and in particular, the supply vessels, and that would be auctioned to work with the vessel supplier to reassign the vessels to other work, and reduce manning levels on the vessels, that sort of thing. We understand it's roughly 35 days transit from the Gippsland up to Gorgon and back, and then 2 relatively short programs up there for Chevron.

And is that included in your cost estimates, if that does happen, is that included in your contingency, would that result in the $193 million to $198 million increasing?

Yes. The contingency hasn't been assigned specifically like that. But there is general contingency built into that mid-case cost estimate. In the event that they were -- Chevron were to take the vessel, we would be doing everything we could to minimize the cost of holding the rest of the spread.

Great. And just kind of confirm, with those leverage charts, does that assume that you have success in getting Pertamina paying this year?

No. The cash flow forecasts are done on a 100% gross basis at the moment. But that's not to say that we don't assume we will be successful, because we do believe that's going to be the case. So we continue to pursue and anticipate we get paid in arrears.

Understand. And you've got the comment there about resolution of Otway partner alignment. I was just hoping to get a bit more color on where Mitsui's at, in terms of their thinking around the Otway?

We continue to support their process that they're running. We've been running a data room on the growth part of that project, where we carried the costs. We've seen a lot of activity in that data room and a lot of interest. So we'll continue to support Mitsui on that. And ultimately, it's their 50% stake in that asset, and so we understand that they're looking at offers currently.

Great. So that could be near-term resolution, is that what you're suggesting?

That's what we're hoping, James.

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

Just following up on James' question around Otway, your impairment announcement last week flagged both misalignment and higher costs as the reason. Can you just talk through the higher costs you're seeing for Otway OP3D? And are you remaining confident that it's still an economic project for you to take forward?

Yes, I can say a few words there, and Jane may wish to add a bit more. So I think through the process around re-collaboration with the other partners. We did see an increase in day rates. And I think this -- you'll be aware, Nik, and we've heard quite a lot around is, general industry inflation. And so those elements fed into the analysis. I think it's important to emphasize, when it comes to the impairment that we've bought, we are following the accounting rules which constrain us, and so we can't factor in Juliet or Nestor, for example, into that analysis. Even though, as you're aware that, geological transfer success on those 2 wells is extremely high. And so a combination development across those 3 is really, really compelling and attractive, and adds a lot of value. The impairment analysis is based on Annie only, because it's the only 1 of the 3 that is discovered. And there are some fairly conservative assumptions as we've laid out there in the analysis beyond just the fact that it's only Annie factored in, in terms of things like no assumptions around repurposing with Athena, pretty low spot gas pricing, et cetera. So we feel like that analysis is very conservative. But turning to away from the accounting and into real value and how we think about OP3D, even with the industry inflation around rig rates, yes, there's no question in our mind that it's a very compelling project. So we're really continuing to do work behind the scenes to position ourselves to be able to accelerate that, once the 2 corporate priorities that Jane has talked about get addressed over the near term. So absolutely, we remain convinced it's a compelling opportunity. The accounting rules constrain us on how we can think about it in a very conservative way. I hope that answers the question.

Yes. Nik, I'll just add a couple of points to that. So on Slide 20, we showed the indicative Annie only volumes of 45 terajoules a day and then the indicative OP3D at 90 terajoules a day. It's obviously a bigger development. We're working through the options, but that could be an Annie, Juliet, Nestor type development to get to 90 terajoules a day. The plant can do 150. So obviously, we're highly motivated to increase the volume through the plant. If Juliet and Nestor are lower CO2 volumes than Annie, which we anticipate they will be, then we'll be able to blend away the Annie CO2, which is just slightly above pipeline spec. And in doing that, we'll move the need for aiming units to be retrofitted to the Athena plant. So that would definitely improve the economics of the project, if we can get a larger volume through the plant with lower CO2. I think the other factor is, this is very close to market. We are being inundated with customers wanting gas from this project. We've sold our share of the smaller Annie only project to AGL. But clearly, if we do the bigger project, there's our share of that bigger project plus our joint venture's partner gas, and we have significant interest from buyers. We are now exempt from the $12 cap, and that makes this project very attractive in terms of economics.

That's very clear. Just a quick clarification, Slide 20. You pointed out the 45 terajoules a day for Annie only. Can I just clarify, if that's Annie plus CHN at that point, or is it just Annie well rates?

Now that would be just Annie. So the higher pressure from Annie coming in will back out the lower pressure from the older wells. And CHN is expected to continue to produce until 2028 and beyond potentially. And so we anticipate that those wells will be suspended once the new higher-pressure production comes in.

Got it. And just one final one for Dan, just an accounting question. I think there's a -- in your accounts, you've got other expenses, including new ventures, $12.4 million in FY '23. I think it was only $1.3 million in FY '22. Can you just tell us -- explain what's actually in that line?

Yes, sure. So there's a few things in that, as is often the case. It includes the NOGA levy. It also includes a small provision for doubtful debts and some other pieces. But those are the 2 biggest items.

Just trying to get a feel for how much of that's recurring or nonrecurring?

I would say a significant portion is nonrecurring as a result of the doubtful debt piece.

Your next question comes from the line of Rob Koh with Morgan Stanley.

Just a question on sustainability, and kudos to Cooper for continuing to offset its emissions. I guess with Orbost bus coming over now and I think from memory, about 70,000 tonnes of new emissions, just if you could update us on your offset procurement strategy, if the Coorong projects are able to actually provide that additional supply? And I guess, related to that, I'm also assuming that you're not going to tick over the 100,000 safeguard mechanism threshold?

Yes. No, that's correct. Both plants remain below the safeguard baseline threshold of 100,000 tonnes a year of CO2. We will continue to work to reduce emissions outside, and then offset our emissions to our carbon credit purchases. We are looking at initiating and acquiring credits in Asia, from quality projects there, which provide access to cheaper credits. And our climate active certification allows us to increase the number of credits we have from programs outside of Australia. We do anticipate that with the changes to the safeguard baseline, the government has introduced that [indiscernible] will become more expensive. And therefore, we're trying to reduce the cost of our voluntary carbon neutral position by accessing lower cost credits in Asia, but through credible programs that allows us to continue our climate active certification.

There are no further questions at this time. I'll turn the call back to Jane for closing remarks.

Great. Thank you very much. Thanks for listening today, and we appreciate the support for the company, and we will hope to see you as we go around on the roadshow in the next few days. And we are very excited about what's ahead of us in FY '24 and beyond. Clearly, the focus right now is on the Orbost plant improvement, completing the BMG decommissioning and getting that liability off our balance sheet and then getting after the Otway growth program. Cooper Energy is a significant gas supplier to the Southeast Australian gas market. We are really confident that the gas demand is there. We know that from what buyers are telling us, and we see a bigger role for gas in providing firming and peaking power generation. And certainly, that's coming through in the demand for gas we're seeing from our customers. So we look forward to meeting with investors over the next few days, and thanks for your support.

This concludes today's conference call. You may now disconnect.