Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Good morning, and thank you for joining the Cooper Energy Financial Year 2022 Annual Results Webcast and Presentation. My name is Eddy Glavas, I'm the General Manager of Commercial and Development for Cooper Energy, and I've been the Acting Manager of Investor Relations. As of today, that responsibility has transferred over to Morgan Wright, who has recently joined Cooper Energy as Investor Relations lead. I'm joined by Managing Director, David Maxwell; and Chief Financial Officer, Dan Young, who will be taking you through the presentation this morning. Also with us in the conference are members of the executive leadership team. After the presentation, we'll be hosting a Q&A session, and we welcome your questions. The presentation and announcement were released to the ASX this morning and are available on the Cooper Energy website. Today's webcast is being recorded, and the playback will be made available on our website later today. Please note the disclaimer information on Page 2 of the presentation and on the final page of the ASX announcement. I will now hand over to David Maxwell to kick off the presentation.

Thanks very much, Eddy, and let me add my welcome to everybody that's live on the call and those that will listen in, I presume on the webcast in the next day or so. I'm just going to stay on the cover slide for a minute. The Cooper Energy business and strategy is very focused on cost-competitive gas supply to the Southeast Australia gas market. We've got a balanced mix of production, development and exploration, and we operate across 2 hubs. We're close to the market. This is a cost-competitive business that we've built over the last 7 years. The gas market we supply, which is Southeast Australia is short on supply and gas prices have been and are increasing. We've had some issues to address associated with the APA operated Orbost Gas Plant, and these have been managed and the growth is clearly now underway. The FY '22 operational and financial results we have released today and will now present clearly illustrate this. So I can go to Slide 4. In FY '22, we have delivered record results from both an operational and a financial perspective. Our FY '22 safety and environment management performance has been industry-leading and top quartile. In summary, the results are 0 lost time incidents and more than 1,000 days since our last lost time incident. Our total recordable injury frequency rate is 0.0. This compares with an industry average benchmark for offshore Australia of 6.91%. And we've maintained our net zero emissions position. And when we say net zero, that's net zero Scope 1, Scope 2 and controllable Scope 3. This is well ahead of our peers in Australia and something we have committed to maintain. These safety and environment performance results illustrate the discipline now embedded in our operations and activities. Select just a few production and financial statistics. Production was up 26% to 3.31 million barrels of oil equivalent. Revenue was up 56% to AUD 205 million. And underlying EBITDAX was up 169% to AUD 80.7 million and we'll share more background on this in the presentation. The next slide. We set ourselves a series of imperatives at the start of 2022. That's the start of the 2022 financial year. And we've delivered on every one of those imperatives. These imperatives recognized where we were at and addressed the operational and financial areas required to embed a firm foundation built around our 2 gas hubs to deliver the medium and long-term value for shareholders. The graph on the right-hand side illustrates the steady improvement in the quarter-by-quarter Orbost gas processing rate at the same time as the increase in average gas price received for our Sole gas sales. The average quarterly Orbost processing rate increased from 38.6 terajoules per day in the first quarter to an average in the fourth quarter of 47.7 terajoules per day. The average quarterly gas price increased from AUD 7.41 a gigajoule in the first quarter to an average of AUD 10.49 per gigajoule in the fourth quarter. The impact of this is best illustrated by the significant step-up in underlying EBITDAX, I mentioned earlier, and particularly, this was in the second half of FY '22. Dan is going to say a little bit more about that when he presents the financials. Turning now to Slide 6. Gas supply in Southeast Australia, which is our area of focus is tight, and the outlook is getting even tighter. It's in the news almost every day. We've seen Victoria and Sydney spot gas prices increase significantly over the last 6 months. The international LNG price is having an increasing influence on gas prices in Eastern Australia. This is something that the ACCC has also identified in their own analysis. The outlook is long-term take-or-pay gas supply contracts can be negotiated in the mid-teens per gigajoule at the mid-teens dollars per gigajoule, which is very good for the Cooper Energy near-term growth opportunities. Slide 7, a reduction in coal power generation during the June 2022 quarter led to increased gas for power generation to fill the supply gap in the national electricity market, which is referred to as the NEM. The volume of gas used in gas-fired power generation in the June 2022 quarter was the second highest quarterly volume since 2017. A consequence of the changes in the fuel mix for power generation is that in the June 2022 quarter, the emissions in the NEM were the lowest ever reported for a quarter. I think the role of gas in the energy transition is self-evident. On Slide 8, Wood Mackenzie has illustrated commercial reserves in Southeast Australia based on their own analysis. And this is illustrated in the series of boxes on the left-hand side. The Cooper Energy reserves as determined by Wood Mackenzie are well positioned relative to others in terms of location, cost and exposure to the spot price. This chart helps illustrate that we are really the pure play for investor exposure to the Eastern Australia gas market. On the right-hand side, we've compared the average realized gas price for Cooper Energy and that's the green bars and 2 of our peers or key competitors, and that's the pink bars, supplying gas to Southeastern Australia. This is the average price for gas supply to Eastern Australia customers for the financial year 2021- '22 and separately for the June 2022 quarter. Turning now to Slide 9. The FY '22 activities and projects have transformed our business to one where Cooper Energy will operate all aspects of the 2 integrated hubs in the Otway Basin, around the Athena Gas Plant and the Gippsland Basin around the Orbost Gas Processing Plant. This is from the reservoir to the respective processing plants and delivering gas to the Southeast Australia pipeline network. This position, together with the relationships that are in place enable us to further optimize across the assets to maximize the benefits for Cooper Energy and our customers. The Athena Gas Plant -- the commissioning of the Athena Gas Plant was a key milestone in December. This was delivered within schedule, within budget and safely. Since commissioning, we met all customer nominations during the financial year. This illustrates our skills and capabilities and it was this that then underpinned the merit and value, have been working with APA to acquire the Orbost Gas Processing Plant. Turning now to Slide 11. Towards the end of the financial year on the 20th of June, we announced the acquisition of the Orbost Gas Processing Plant. And at the same time, we announced a larger debt facility and an equity raise, and Dan will say more about those in a minute. This acquisition, together with the increasing production and revenue drives the sustained earnings boost anticipated in FY '23 and beyond. The graph on the right-hand side illustrates the steady improvements in Orbost processing rates. This trend is expected to continue. Importantly, as the average rate has increased, the volume of gas we can sell at spot prices has also increased. A few words now on reserves and resources for the year. The movement in reserves and that's 2P or proved and probable and resources or that's 2C or contingent resources. Between June '21 and June 2022, is mainly due to the reduction in volume for the record 3.3 million barrels of oil equivalent and oil produced in FY '22 and the reclassification of some Henry Gas resource as contingent resource rather than undeveloped 2P reserves. As we move the basis of the next offshore development in the Otway OP3D, to be around Annie-only. We made this decision because it is the most capital efficient for our shareholders and the company. As we get closer to a sanctioning the OP3D project, we will look forward to moving the Annie 2c, the Annie contingent resource of 32.4 petajoules, which is 5.3 million barrels of oil equivalent of gas from 2C to 2P reserves. These numbers on this chart and the numbers that I've mentioned are all Cooper Energy net. More details on the movements in reserves and resources are in a table at the back of this presentation and there's a release, separate release, which we also made to the ASX this morning. On Slide 23 -- sorry, Slide 13. The production, revenue and cash flow growth is being achieved whilst we maintain our net zero emissions position. To maintain and grow this leading position, we work on 3 pathways, which are somewhat interlinked. Firstly, we're maintaining the net zero position, which delivers some competitive advantages relative to our peers and Dan will talk a little bit about this in the context of financing. Secondly, we're evaluating and pursuing opportunities to further improve the energy and emissions efficiencies at and nearby our operating sites. And thirdly, we are assessing new energy opportunities where Cooper Energy has a competitive advantage and it adds value to the existing assets and portfolio. I'm now going to hand over to Dan to take you through the financial results in more detail where pleasingly, there is a lot of green.

Thank you, David, and good morning, everyone. Today, we reported record full year results across almost all key metrics. Production for the year was around 3.31 million BOEs, which is equivalent to about 9,070 BOEs per day and is a record for the company, 26% above financial year '21 and comfortably within guidance, which was most recently revised upward to the top end of the previous range. As David has mentioned, we saw quarter-on-quarter improvements in processing rates at Orbost, delivering Group Q4 production of 9,480 BOEs per day. Top line revenue was also a record for the company of AUD 205 million, more than 50% up on financial year '21, helped by the 21% jump in realized gas prices to [ AUD 29 ] a gigajoule. Indeed, as the processing rates at Orbost improved in the second half of the year, we led our peer group in realized gas prices into the East Coast gas market. I emphasize that point because it demonstrates the outstanding blend of Cooper's foundation term GSAs to a core group of high-quality gas customers and that underwrote our development of Sole alongside our growing volume of spot sales into a supply short gas market. A few words about production costs and total cost of sales, which is up around 34% in aggregate dollar terms versus financial year '21. Unit cash cost of sales is around $27.85 a BOE. And for Sole specifically, has been around $5 a gigajoule, but that includes third-party gas purchases of just under AUD 25 million and the Orbost capacity charge to the operator, which averaged around $2.70 a gigajoule across financial year '22. As we look to FY '23, with ownership of Orbost and with operating rates above our minimum customer contributions and hence removing the need for any material third-party gas purchases, we should see our unit cash cost of sales for Sole come down materially to something around AUD 2 a gigajoule. We're talking a good amount today about cash generation and with good reason, as you look at underlying EBITDAX more than doubling from 2021 to over AUD 80 million for FY '22 or an increase of around AUD 50 million. This represents a small beat to our underlying EBITDAX guidance range, which to remind people, was twice revised upward in the second half of the year with the most recent revision to a range of AUD 70 million to AUD 78 million. The cash generation potential of the business that we've talked about for some time is really coming to fruition. And as I've just mentioned, with ownership of Orbost from 28th of July, the cash generation in financial year '23 is going to continue to grow very substantially as well. Operating cash flow has also increased AUD 50 million in financial year '22 compared to FY '21. The main delta between underlying EBITDAX and OCF is interest costs under the RBL of around AUD 9.5 million, some restoration work ahead of next year and '24 and a small amount of PRT in the Otway. CapEx for the year was comfortably within budget and guidance, including a focus on the next phase of Otway Basin growth. With underlying EBITDAX of over AUD 80 million and operating cash flow of close to AUD 60 million, we are also continuing to deleverage during the year with a AUD 60 million debt repayment or around 28% of the drawn portion. Turning now to Slide 16, which provides a bridge of FY '22 underlying EBITDAX of AUD 80.7 million back to the result for FY '21 of AUD 30 million. As expected, the improved cash generation in FY '22 was in large part a reflection of our increased production at Sole and the higher contracted and spot prices. Our contracted prices for Sole on average increased around 7% versus FY '21, while our spot price realizations increased by more than 100%. Cost of sales increased as a result of the higher production rates and hence processing rates at Orbost, but also about AUD 11 million higher in relation to third-party gas purchases with the majority of that in the first half. The other block shown here at AUD 8.7 million is related to a few things, almost all of which were FY '21 related, including higher business development spend in the prior year, a small amount of stamp duty and some FX impacts. On Slide 17, we provide a bridge of cash back to a year ago. I've talked about the makeup of our operating cash flow of AUD 58 million. On a cash basis, our CapEx spend was just over AUD 20 million, spread across OP3D, 2 wells in the Cooper Basin and some smaller pieces. As I've mentioned a minute ago, we continue to delever in a significant way, and we received the institutional portion of the equity raise shortly before year-end. While it's true that we paid AUD 208 million to APA on July 28, please note that we received the AUD 61 million of net proceeds from the retail portion of the equity raise on July 14. So total net proceeds from the equity raise of AUD 239 million less the AUD 208 million to APA leaves us net up around AUD 31 million before other transaction costs or around AUD 100 million of Group cash. Lastly, an update on our new debt facility and the Group's net debt position. We executed the new loan on 29th of July, refinancing the old facility. This brings us numerous benefits, including a 100 basis points lower cost of funds, a lower discount rate in the borrowing base calculation and an additional accordion potential of AUD 120 million. We have added a sixth bank to the syndicate, a leading global participant in the RBL bank debt market and we're in ongoing dialogue with 2 additional banks seeking to join the facility. This desire to work with Cooper is partly a reflection of the strong macro thematic of a supply-constrained OECD gas market and our own very strong portfolio of assets and gas contract portfolio, but it is also partly a reflection of our current net zero status, which is unique in Australia among upstream companies. It means that we have a competitive advantage in securing capital markets funding to support development of gas resource. Cooper's gas resources are not subject to the risk of securing third-party funding. The net debt number reported here does, of course, include the institutional portion of the equity raise received shortly before year-end of AUD 178 million. If I remove that entirely, you can see that our net debt declined from AUD 127 million a year ago to around AUD 89 million of net debt at year-end not to be confused with the AUD 89 million of net cash shown in the slide. And if we roll that forward another month, net of the AUD 61 million retail portion that we received in July and the AUD 208 million paid to APA at the end of July, you come to around AUD 60 million of net debt before stamp duty and some other transaction costs. So in summary, the business is now demonstrating very strong cash generation even with the burden of the capacity charge to APA in FY '22, which is now released and is in a very strong position to pursue the next phase of growth as well as commencing the BMG decommissioning work in a little over a year's time from now. And having regard to these circumstances, we are naturally also analyzing the optimal capital management plans for the Group over the medium term. I'll now pass back to David.

Thanks, Dan. A few words on our near-term plans and the FY '23 outlook and beyond before we then take some questions. In the Otway Basin and specifically the offshore Otway Basin and around the Athena Gas Plant, we're really working in 3 key areas. Firstly, to increase production and the cash margin generated from the existing wells, infrastructure and the Athena Gas Plant. The second area, progressing the next step-up in production with the Otway Phase 3 Development. Our plans and work schedule are based on this being online before the winter of 2025. And the third area on the back of OP3D, rapidly adding further production to process at Athena. We have numerous drill-ready prospects available and these are all amplitude supported which in exploration terms means they are very low risk. The top 6 prospects equate to some 585 Bcf or nearly 600 petajoules on a 100% basis. That's a 100% equity basis. Similarly, and here I'm turning to the Gippsland Basin. In the offshore Gippsland Basin and around the Orbost Gas Processing Plant, which is now owned 100% by Cooper Energy, the activities are directed at 3 areas. First, working with APA to transfer the major hazard facility license as soon as practical, so the operations then come under Cooper Energy management. The second area, increasing the boss Orbost Gas Processing rate with the existing kit and infrastructure that's in place and this includes the polishing unit and the solids recovery package, which are on-site and in place. And third -- the third area is advancing the next wave of development of our own gas resources and assessing the economic viability of also processing third-party gas. Across both the Otway and the Gippsland assets, we now have a portfolio of production growth, developments and exploration opportunities, which are integrated and all operated by Cooper Energy and at a time when more gas is needed and gas prices are increasing. Slide 22, the growth staircase. The combination of what we delivered and achieved in the last financial year is a growing foundation cash flow, which enables the progress and delivery if the high-value growth opportunities and cash flow growth opportunities within the existing portfolio across the 2 gas hubs. As mentioned, this is a mix of growing existing production from Sole, Casino Henry Netherby, the development of contingent resources such as Annie and Manta and low-risk quick to commercialize exploration in both basins and in particular, the offshore Otway Basin. And I think it's important that we don't forget our heritage high-margin oil production and the development in the Cooper Basin as well. Now turning to guidance. In FY '23, the growth trajectory is expected to continue. We are being prudent and guiding to a 12% to 21% increase in production to 3.7 million barrels up to 4.0 million barrels of oil equivalent, a 49% to 86% increase in underlying EBITDAX to AUD 120 million on the low end to AUD 150 million and a 44% to 69% increase in capital to AUD 28 million on the low end and AUD 33 million on the high end. Note that the capital guidance excludes the Orbost Gas Plant transition costs and the BMG abandonment expenditure planned for FY '23. The transition costs, which will be spread across the year are some AUD 20 million, and it's yet to be determined how much of this is to be capitalized or not. And the BMG abandonment activity is planned mainly for the first half of FY '24, that is the following year. Now to wrap up before we take questions. FY '22 was a transformational year, particularly in an operational sense. The base has been set. Second message, the Cooper Energy team set and delivered on the imperatives, which demonstrates that the capabilities within the business and the ingredients are in place for a successful and growing Southeast Australia gas business. Third, our focus is very much the tight supply, high-priced Southeast Australia gas market where we have a distinct competitive advantage on a number of fronts. Fourth, the safety and management performance is top quartile and industry-leading, full credit to the Cooper Energy team. Fifth, as demonstrated by our underlying EBITDAX guidance beat on the high side and that was after 2 upward revisions and the FY '23 guidance increase, we have substantial cash-generating capacity. And sixth, a balanced and integrated basis for growth is now in place, built around production, development and exploration, all operated by Cooper Energy supplying gas into the high-value Southeast Australia market. On that note, happy to take questions and we've got the leadership team here to help with any answers, if needed.

[Operator Instructions] Your first question comes from Dale Koenders from Barrenjoey.

I'm just wondering, regarding Slide 22, when we look at the potential growth staircase for the business, it looks like sort of Sole is sort of seeing full production rates by FY '25. Can you just confirm that's the right timing? And I thought a lot of the work like the equipment being stalled was more over the next 6 to 12 months to really get up to a full production rate in more like '24?

I think that's probably a misinterpretation of that graph, Dale. We would expect -- and you'll note that there is nothing on the vertical axis there. We would expect -- and Mike Jacobsen can certainly add in on this. We would expect just the kit as existing is to steadily increase. And then obviously, we've got the polishing unit and then the solids recovery unit package to follow. And then separately, we've also got the opportunity to look at step-ups in the production rate. Now those step-ups are not included in this. I used the word prudent in our forecast as well. That was very deliberate. I guess we've been conscious in the past of making sure that -- well, from the past when over the last 18 months or so, we've a number of times where we've taken what APA has told us to be correct and then put it into our forecast to find ourselves under delivering against that forecast because of Orbost and we're wanting to make sure we don't have a repeat of that. We'd much rather be slowly hedging things up as based on performance. So they are the sort of background comments just specifically in terms of the next 6, 12, 18 months and let Mike to talk through the program that we've got in mind there.

Yes. Thanks, David. I think, Dale, I think, as David sort of alluded to for diagrammatic purposes, I think that's probably what you're seeing on that chart. But certainly, as we've said previously, through the rest of FY '23 for the majority of that time and that APA will continue to operate the Orbost Gas Plant. Once we take on the operatorship, when the license transfers, which through FY '24, it is our expectation and our plans to build the rate up at Orbost up to nameplate. So it really is around the FY '24 rather than the FY '25 as you've, I guess, interpreted from that chart.

Maybe I can help with that and ask Mike a question, a bit of a Dorothy Dix. Mike, we do expect the polishing unit to come back online in the next few weeks. I mean what would you expect that to do to production rates at Orbost?

I think certainly, David, in the instantaneous rate, we'll certainly see within the 60s and it is the plan or APA's plan at least to bring the polisher back online through the course of next week, early next week. They're just -- they're in the process of changing the media out for that unit. So the expectation will be instantaneous rates, as I said, in the 60s, with the averages on a monthly basis well into the 50s. Currently, we're seeing in the high-40s, but the expectation is they'll be back into the mid-50s on an average basis with instantaneous around, 60 and above.

You saved my job and David asking more questions. Could you maybe just provide an update on sort of what are the key hurdle rates to really move OP3D forward now through FEED and FID?

The sort of series of things in parallel, which are all happening in parallel at the moment. We're very well advanced conversations with customers. Don't be surprised if you see something on that in the next month or so, which is gas contracts at very good prices from come in regard to the past, take-or-pay gas contracts separately, there is the work being done together with other operators around a rig club, where we are looking to put this bigger program as possible together with other offshore Southern Australia operators. There's a group working on that and the timing of the program, which is targeted at around '24-'25 drilling campaign. And then there's the work that is being finalized before we go into FEED ourselves, finalize the design basis for the final costings for the plant. And we expect later this year to be entering FEED with a view to FID in the first half of next calendar year. So the second half of this financial year.

And then on the exploration targets, which obviously will provide upside to the growth staircase. When -- how are you thinking about timing for drilling those exploration wells? Would that be sort of back-end of that rig club in FY '25? Is that logical?

Yes. I think it's a function of a few things. But I think the idea would be -- the ideal would be to drill 1 or 2 reasonably early in the campaign and then a few later in the campaign. So if we had -- so the way that the rig club is being thought of is a minimum number of commitment wells and then a series of options. So -- and that's something that has been worked through at the moment with the others in the rig club and ourselves internally and as to how many we can put down as firm and then how many we hold back as options. So -- I'm not sure there's a bit of background at your end there, Dale, but that's the way that it's being thought of. But look, I think we'd certainly want to be thinking of 2 exploration wells on top of Annie and where they sit and then possibly another couple over and above that. And you'll see on the slide on the Otway we've actually highlighted that the tieback type arrangements at Juliet, Nestor and then separately at some stage, we will want to be drilling Elanora for certain for sure. I don't know, Andrew Thomas is on the line, if Andrew would want to add anything to that.

Thanks, David. I think you pretty much got the story right. I might just add that the Juliet and Nestor prospects are fairly high on our list because they are very, very low risk. In fact, I think people would note from our presentation and other operators that amplitude to put prospects in the offshore Otway have 100% success rate when drilled on based on 3D interpretation. So we've got a handful of those that we think exploration prospects are very, very low risk. So we're very confident of a positive outcome when we drill those wells.

I think I could add just a couple of other comments, Dale, which sort of help give you a little bit of the picture as clearly, the higher the rates at Sole, and the higher the spot gas price, the more liquidity there is to support the next wave of growth. So what we're trying to do is get a rig in the region for a decent period of time and then give ourselves optionality around how we go about it. And we are very mindful and Dan referred to this of capital management at the same time. OP3D makes a massive difference on the cash being generated off the back of just OP3D on Annie-only really sets us up. So what we'd like ideally to do is to get a rig in the region and have it be there for a couple of years, then we're away.

I might just with one other question. Just in terms of third-party gas, David, you mentioned you're talking to other operators, the APA was also sort of talking to other listed parties about processing gas in Orbost before they sold. Can you sort of provide some update on timing of when something there might materialize?

Yes. I would -- well, we have received approaches already, same parties that APA was talking to. And when we talk about a campaign in Southern Australia, we include the Gippsland in that, so we include the Manta appraisal/development opportunity in there. And we have started conversations with other operators in the Gippsland to join the club. It's a care question as to whether the rig that we select together with the likes of Beach and others in the Otway is suitable for the Gippsland as well, suitable for the others in the Gippsland, certainly will be suitable for us, whether it's suitable for others or not, we'll have to work that out.

Your next question comes from Nik Burns from Jarden Australia.

And just a couple of questions from me, David. Just first of all, you talked about bringing the sulphur filtration unit back online shortly. I believe one of the challenges with the unit in the first -- in the June half was running at to higher rates and that caused problems. Do you have a better sense now about how hard APA should be operating the plant without risking your repeat of the issues that you saw in that half?

I think you're talking about the publishing unit, yes...

Yes, that's right.

Yes. There has been root cause analysis undertaken and obviously, the lessons out of that will be applied when it starts up again. But I'll leave Mike to -- he's been working closely with the APA folks on all of this to answer the question.