Cooper Energy Ltd
ASX:COE
Earnings Call Analysis
Summary
Q2-2024
In the December 2023 quarter, Cooper Energy delivered a robust performance with a 6% quarterly increase and a 15% annual increase in production, averaging 63.6 terajoules per day, underpinned by the improved functioning of the Orbost Gas Processing Plant. Revenue climbed to $55 million, a surge of 20% compared to the same quarter last year. Stronger market pricing was reflected in the gas sales agreement extension with EnergyAustralia until 2028 and in contract price reviews. The average realized gas price rose to $8.58 per gigajoule, up 3% from the previous quarter. Despite a 5-day shutdown, Orbost's performance enhancement initiatives led to higher quarterly production and increased spot gas sales. The BMG decommissioning was revised to an estimated $240-$280 million due to delays and slow progress, but financial stability is maintained with substantial cash balances and a $400 million senior secured debt facility, offering $80-$120 million headroom. Cooper Energy stays on target for its annual production and cost guidance.
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Good day, and welcome to the Cooper Energy Limited Q2 FY '24 Quarterly Report Conference. [Operator Instructions] And finally, I would like to advise all participants that this call is being recorded. I'd now like to welcome Jane Norman, Managing Director and Chief Executive Officer, to begin the conference. Jane, over to you.
Good morning. Thank you for the introduction. I'm joined this morning by our Chief Financial Officer, Dan Young. This morning, we released our December 2023 quarterly report with strong results driven by improved Orbost performance. I will start with commentary on the quarter and then open up the call for questions. The total quarterly production averaged 63.6 terajoules equivalent a day up 6% quarter-on-quarter, excluding the impact of the planned shutdown at Orbost and up 15% compared to the same quarter last year. Additionally, Q2 production averaged around the midpoint of the full year guidance range. This was driven by increased gas production at our Gippsland asset due to improved performance at the Orbost Gas Processing Plant and is the highest quarterly production since September 2022. Gas market prices remained strong due to declining gas supply in the southern states as forecast by AEMO. Higher spot sales into a strong market also lifted our average realized gas price to $8.58 a gigajoule, up 3% compared to last quarter and 2% compared to the same quarter a year ago. Sales revenue was $55 million, up 8% quarter-on-quarter and up 20% compared to the same quarter last year. In this last quarter, we also extended our gas sales agreement with EnergyAustralia to the end of 2028 and completed the price review on one of our contracts with VICI, and we achieved the best possible outcome for the company. These outcomes are in line with the stronger market pricing we've observed over the quarter and highlights tightness in the market and the ongoing demand for more domestic gas supply. Whilst I can't comment about specific contract prices, I can point to the latest starter from the December 2023 ACCC gas report. The ACCC reports that all GSAs executed between February and August 2023 for near-term supply was struck at a price range of $10 to $20 a gigajoule. In addition to our contract price reviews, we also continue to see the benefit of annual indexation across all of our existing gas contracts. The weighted average price across all of our gas contracts increased by 6% from 1 January this year. Throughout this quarter, we have maintained our focus on our 4 business priorities for FY '24. Firstly, to Orbost performance. As I mentioned, Orbost performance has improved quarter-on-quarter as the benefits of several of the improvement initiatives were realized. Production was up 5% quarter-on-quarter and up 12% compared to the same quarter last year, despite the 5-day maintenance period in December, which was completed successfully and on schedule. Excluding the shutdown period, the average quarterly production was up 9% quarter-on-quarter. The increased production, combined with lower customer nominations, meant that during the quarter we were able to sell around 900 terajoules of spot gas, up from 254 terajoules the previous quarter. Increased and more stable production also meant gas purchases were limited to 47 terajoules, down from 284 terajoules the previous quarter. A new media for the polisher was introduced, and this is performing well and is supporting higher plant throughput rates. The improvement initiatives are focused on reducing absorber failing and cleaning times and reducing or eliminating foaming in the absorber beds. In coming weeks, we will undertake tests on the performance of the inlet coalescer and trial further in-situ washing of the absorber beds with a view to significantly reducing the time required for absorber bed cleans. We continue to implement the various initiatives under the improvement project with the aim to significantly increase processing rates, avoid the need to invest in the third absorber bed and lower our unit operating costs. A more detailed update on the Orbost improvement project will be provided at the half-year results. Secondly, BMG decommissioning. On the 15th of December, the Helix Q7000 vessel commenced its contract with Cooper Energy and after extended delays in the vessels work program in New Zealand. Delays in New Zealand caused the late arrival of the Q7000 at the BMG field, which has resulted in us incurring more than 3 months of holding costs for the remaining contractor spread on the BMG program. This delayed start, together with the additional time required for start-up activities, has consumed the budget of contingency. Along with the slow progress being experienced on the Basker-3 decommissioning work to date, this has meant that a reforecasting of the program for the remaining 6 BMG wells was required. This reforecast has incorporated learnings from the Basker-3 well. As a result, we revised our mid-case cost estimate for the BMG decommissioning project yesterday to approximately $240 million to $280 million.
This updated estimate is inclusive of low FX rates and includes a range of reasonable contingency for future nonproductive time and waiting on weather. It also reflects the delays we have incurred to date. It is important to note the range given on the revised mid-case cost estimate reflects the addition of general contingency and a risking on the delivery of operational learnings and efficiencies and scope simplification opportunities. The top end of the new range does not consider any of the cost-saving opportunities. Following the reforecast, we now expect the program to be finished in early May.
Where possible, Cooper Energy and its contractors, in particular, Helix, continue to pursue savings to offset the increased costs, including implementing operational learnings and efficiencies and simplifying the scope of decommissioning. We remain well funded from existing cash balances, positive operating cash generation and our $400 million fully committed senior secured debt facility. We expect to have headroom of $80 million to $120 million under the debt facility incorporating the revised mid-case cost estimates. That means that even in the event of a high case outcome on BMG where even further contingency has added to the cost estimate, we remain well funded from existing undrawn committed funding. Given the delays to the timing of the BMG well decommissioning, the group's net debt and ratio of net debt to EBITDA are now expected to peak in late Q4 FY '24 or early Q1 FY '25 relative to the outlook provided on the 29th of August 2023. Based on the top end of the revised mid-case estimate for the BMG well decommissioning, net debt is anticipated to peak at up to approximately $50 million more than was indicated in the August 2023 outlook. While the peak for the ratio of net debt-to-EBITDA is not expected to change materially given the shift in phasing of the decommissioning spend and the various improvements in the underlying performance of the business. Third, our cost out initiative. As we mentioned in previous updates, one of our key priorities for FY '24 is our cost-out initiative and all-encompassing review, including production costs and G&A. We are making positive progress with close to 90 initiatives identified. Around 15% of these has been delivered already, and most of the initiatives are expected to be delivered through FY '24. A more fulsome update will be provided at our half year report in February. Fourth and finally, Otway growth. In this quarter, we have continued to progress our planning of the Otway growth project. As we mentioned last quarter, we secured the Transocean Equinox rig as part of a consortium agreement with 3 other operators. The Transocean rig is not expected to commence work in the Otway before late 2025. We continue to progress discussions with our joint venture partner, and we'll update the market when the program has been agreed. As we look to funding for Otway growth, we anticipate accessing the $120 million accordion incorporated within the existing debt facility that was agreed with the bank group last year, along with ongoing free cash flow generation. We are also encouraged to see significant ongoing interest from a number of gas customers to support new domestic gas supply through a range of funding options, which could include prepayments. In summary, this is a strong quarter for Cooper Energy. We remain on track for our production and cost guidance for the year. Second quarter production of 63.3 terajoules equivalent a day is up 6% quarter-on-quarter, excluding the impact of the planned or be shut down and up 15% compared to the same quarter last year. Q2 Revenue of $55 million, up around 20% compared to the same quarter last year. The management team and I remain focused on driving business performance to deliver what we have promised.
Now I would like to open the line up to questions.
[Operator Instructions] Your first question comes from the line of Nik Burns from Jarden Australia.
Just a couple of questions from me initially. First one, just after some more details around the issues you've encountered during the abandonment of the first well in the sequence of BMG Basker-3, can you just talk through maybe the nature of the problems you have encountered? How long the first well took? And then, I guess, as we look ahead to the remaining 6 wells, how much time you've factored into abandoning each well in the sequence? And if any of the remaining 6 are seen as more challenging than the others?
Thanks, Nik. So to answer your first question, in terms of the activity on Basker-3, the decommissioning work there is still ongoing. We anticipate finishing later this week, assuming everything goes to plan and then we are able to move to the next well. Some of the activities that took place on Basker-3 were really set up activities for the rest of the program, for example, integrating equipment such as the integrated riser frame and the bracing frame, that's a one-off activity that was part of the start-up that won't be repeated on other wells. And then some specific issues have been connecting the gravity-based structure and the tensioning on the tethers that control the riser system. So those activities will take the learnings from the Basker-3 experience onto other wells. So some of it has really been the contract team learning to work together and starting off those activities for the first time, and then we anticipate there will be an improvement in learnings and efficiency. In terms of timing for the rest of the program, the revised cost estimate does include some improvements in activity as we move through the program. So Basker-3 was one of the more complicated wells, so we've started with that. And we anticipate being able to apply the learnings from that through the program and that each time we repeat those activities, for example, pensioning of the gravity-based structures to support the riser that there will be an improvement in that. And those reforecasts and the schedule have been reviewed independently by Helix and that come to a similar view on the timing required for those activities to our team. So it is a combined team effort in terms of the reforecast.
Got it. And just looking at your releases yesterday and today, you talked about the fact that there are risks outside of your control that could increase the total cost of the program above your estimated range. I appreciate that you do have a liquidity buffer available after this increase and your revised cost estimate range includes additional contingency. But I'm just conscious of the fact that there are unknowns remaining in this program. Was there any consideration given yesterday to potentially raising equity just to take any further risk off the table?
Thanks, Nik. No, there's no need to raise equity. We've got the funding in place even for the high side outcome on this, which is effectively the mid-case plus further contingency. What I will say is that the program is going well technically. The engineering work has been successful. It's just simply taken longer than planned in terms of the start-up activities and then integration of some of the equipment. So at this stage, we don't see any issues with the technical aspects of the program or the engineering work. It's really events such as very extreme weather or an unexpected event on one of the wells which would result in us deviating from the current revised estimates.
[Operator Instructions] Your next question comes from the line of Henry Meyer of Goldman Sachs.
Thanks for the update. Obviously, a disappointing update on the cost increase yesterday, and you've touched on it a bit there. But could you flesh out a bit how this budget and schedule has been assist and built up differently compared to the prior estimate? Is it largely the increase in delays in getting set up? Is it what you've encountered so far in decommissioning Basker-3 so far that's fed into the updated cost for the remaining wells? Is this sort of a rough split as what continues to be -- continuously rather has been eaten up already, the delay is getting started and then what cost increase has been assumed just purely based on Basker-3 so far, just considering that there is a little bit of uncertainty in other wells?
Yes. Sure. Thanks, Henry. So the revised mid-case cost estimate, it absorbs all of the delays and the slow start-up activity we've had to date. It then builds in new contingencies but waiting on weather and nonproductive time. And we think that's a reasonable thing to do given we're on the first well of the 7-well program. The learnings on Basker-3 have been reviewed with Helix and they've endorsed the revised cost estimate The confidence we have around the program is that when we see Helix operating in the well, their operations are more effective and more productive. And the remainder of the program is dominated by time in the well. It's not set up time and integrating equipment and the issues where we have seen delays to date. So we do anticipate learnings and improvements. And as I said earlier, the top end of that revised range does not bank any of the cost-saving opportunities, but we are aiming to deliver those and really execute the learnings from 1 well to the next.
Got it. And looking beyond the decommissioning, I guess, you've touched on the VICI gas recontracting. And appreciate you can't give too much detail around specific contracts. According to the ACCC recontracting range of 10 to 20 is pretty wide. And this is about 25% of your contracted gas. Could you share a bit more color on -- do you think this recontracting starting in this quarter will provide a material uplift from the realized price you've just achieved in Q4?
Henry, it's Dan here. So Jane talked about the 6% average increase in the contract stack that commences January 1 this year. And that's a blend of the various different factors, including indexation on the stack.
[Operator Instructions] Your next question comes from the line of Declan Bonnick of Euroz Hartleys.
Could you please comment on the timing of that net debt peaking versus the targeted finish date of early May that you stated?
Declan, it's Dan here. So yes, we wanted to give an update on when we expect that peak net debt period relative to what we talked about last August when we set out the rough approximate outlook based on the anticipated timing of BMG at that point. And with the program now running through into April and potentially early May, we expect net debt to, as a result, peak around June, July time frame. And so that's really what we were referring to there in terms of a slight alteration in that profile that we have given relative to August last year.
Okay. And then the other one is on OP3D timing. I note that other people in the rig club have commented on the rig arriving in January 2025. But I think you said it would be entering the basin on -- in late 2025. Is that specifically for your work step or -- what's your best timing on what analysts should be looking at for this OP3D drilling at this point in time?
Declan, I would use the one which we've just put out, which is the end of 2025, which is the rig coming to the basin and our wells will be late '25 possibly slipping into early 2026.
Your next question comes from the line of Alistair Rankin of RBC Capital Markets.
Just after a quick update on the -- how the polisher media is going so far. I understand that you've put in the release that it looks like it's fit for the requirements of the new gas stream. But do you think it's going to last quite a bit longer than the last polisher media?
Alistair, yes is the answer. This new media is designed for a wet gas service, and it doesn't absorb water in the way that previous polisher media did. And so far, it's performing well. And the new media is indicated to the last 8 months in a service of up to 20 ppm H2O. So, so far, so good, and we've had it in for about a month now, and we're not seeing any pressure differential issues.
Excellent. And I guess just keeping on this sort of line of questions, just on the Orbost improvement plan. What was the outcome of the most recent absorber packing trial? Just a bit of color there. And then maybe just an update on -- I understand that you haven't started the new in-situ cleaning trial yet, but have there been any changes to how you're going to test that? Or if there's any update on that trial in particular?
Yes, sure. So in terms of the packing trial, we have reinstated the snowflake packing and that was part of a piece of work where we took out the top distributor play -- tray and installed the 4-nozzle spray distributor. And what we're seeing is good performance out of that bed now. So we're trialing 1 bed at a time in order to manage risk around these changes. But so far, so good. And moving to the 4-nozzle spray distributor was the first step in being able to move to effective in-situ trials. So we have a trial for in-situ washing coming up later this month, possibly into February, and that will be the opportunity to see whether we can successfully clean all the sulfur deposition of the packing right down to the middle of the bed.
Excellent. So maybe an update on the half-year result?
Yes, yes, hopefully.
Your next question comes from the line of Henry Meyer from Goldman Sachs.
Maybe just a couple from me, if I can. In the August update, we're looking at roughly the Otway partner alignment completing end of last year. Is there an update you could provide there on Mitsui's position, please?
Well, Mitsui's sale process is really a question for them. But what I can say is that we are working well with Mitsui to progress the project in terms of what they would agree to and if they remain in the asset and looking to progress that to the point where we can commit to the required well options as part of the Transocean rig program. So yes, we're making progress on that, and we will provide a market update when we can.
Great. Okay. And just a final one for me, please. The production at Orbost seems to be tracking towards the mid-case forecast you provided last year as well. Is it safe to assume that, that's sort of what you're turning through for the year? Or do you think you could achieve the higher-case scenario based on the trials you've completed so far and that are yet to complete?
The first quarter of this financial year, we had a number of challenges at Orbost because we were trialing some initiatives, and we learned a lot from those, but some -- not all of them succeeded. So we're hoping that we can improve production quarter-on-quarter. We do have a number of activities taking place in the next couple of months. And we're aiming to try and improve the performance of the plant in order to not have to go forward with the third absorber bed. It's a bit too early to say at this stage, but it's positive so far, and we'll continue to try and deliver that improvement as quickly as possible.
[Operator Instructions] As there are no further questions, I'd like to hand the call back to Jane.
Thank you. Thank you very much for your time today, and we look forward to providing a further update at the half-year results at the end of February.
This concludes today's conference. You may now disconnect.