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Thank you for standing by, and welcome to the Senex Energy Limited FY '21 Q3 Quarterly Update Conference Call. [Operator Instructions]I would now like to hand the conference over to Mr. Ian Davies, Managing Director and CEO. Please go ahead.
Thank you, Rachel. Good morning, ladies and gentlemen, and welcome to Senex Energy's quarterly results conference call for the third quarter of the 2021 financial year. I am Ian Davies, Senex's Managing Director and CEO; and with me is our CFO, Mark McCabe.
Good morning, everyone.
This morning, I'll take a few minutes to discuss the highlights of the quarter, and Mark will then talk to the financial results, and then he and I will be very happy to take any questions that you might have. Ladies and gentlemen, let me reiterate our long-term priorities before we begin: Balance sheet strength; enhanced shareholder returns; and accelerating our growth. The value we are delivering to shareholders through each of these priorities is clear following the delivery of another record quarter. We delivered quality operational and financial performance in the third quarter as we reap the rewards of our $400 million investment in our Surat Basin natural gas projects. In fact, we reached a significant milestone in Senex's growth in the third quarter with the decision to commence dividend distributions to our shareholders. I can't imagine a more resolute demonstration of our view of our resilience going forward. Let me start with total production where the exceptional quality of our high-growth, low-risk Surat Basin foundation asset base and operational capability are really shining through. Total production increased 8% from the previous quarter to 4.6 petajoules. Peak production reached above nameplate capacity of 52 -- to 52 terajoules a day or about 19 petajoules a year, with Atlas production up 5 terajoules a day or around 18%. Sales revenue increased 19% to $33.2 million, largely due to greater production from Atlas and improved realized pricing from Atlas and the oil-linked Roma North field. Senex continues to shore up future sales with further customer contracts signed during the quarter. New gas sales agreements were secured, including the CleanCo Queensland for 2.5-plus petajoules a year in 2022. Balance sheet strength is our foundation. It continued to be a standout feature of our performance as the completion of our Cooper Basin asset sale in March resulted in a buoyant net cash position of $36 million at year -- at quarter end. I've already mentioned the commencement of dividend distributions to our shareholders, which began much earlier than previously indicated and which, combined with the myriad of growth options within the portfolio, puts us in a very strong position. We've also made strong progress on our expansions. So let me take a step back and remind you of our growth outlook. Firstly, our growth is supported by over 780 petajoules of proved and probable natural gas reserves, that's 2P reserves, and over a Tcf of 3P I might add. To put this in perspective, this is more than the entire East Coast gas demand for a year and represents decades of natural gas production potential. Put another way, and this is simplistic, but every dollar per gigajoule of gas price is equivalent to over $780 million of future revenue. And we see the East Coast gas price contracting and remaining in that $7 to $9 per gigajoule range ex Wallumbilla. Although obviously, this is simplistic, it does highlight the large intrinsic value of our portfolio.We've announced the 2025 production target of more than 60 petajoules equivalent a year or more than 10 million barrels of oil equivalent. This is more than triple current production. And given our proven track record of low-cost development and operations, this is achievable primarily through developing Senex's material natural gas portfolio in the Surat. Senex has a pipeline of projects in various stages of development to continue powering our growth. The first of our production expansion projects is at Roma North. And we've already taken the final investment decision to increase production of this development by 50% to 24 terajoules a day or around 9 petajoules a year. This is a high-return, low-cost and long-life investment as it's expected to be online in early FY '22. We've also advanced the further expansion of Roma North to 48 terajoules a day or 18 petajoules a year into FEED, and we're making good progress. At Atlas, we continue to advance our expansion project following the award late last calendar year of additional acreage adjacent to the field. The expansion will deliver a 50% increase in production at Atlas from 32 terajoules a day firm or around 9 petajoules a year to 48 terajoules a day or around 18 petajoules a year. And given the significant capital involved in all upstream natural gas developments, including this one, we are looking forward to customers agreeing offtake commitments before we reach a positive final investment decision. And on this -- with our -- customer conversations are making very good progress. What I've just outlined is an exciting snapshot of the past quarter's performance and future growth opportunities which we'll continue to update you on. I'd like now to hand over to Mark for an overview of the financial performance. Mark?
Thanks, Ian, and good morning again, everyone. As Ian said, it was another solid set of financial results this quarter, reflecting continued production growth, especially at Atlas, and improved oil-linked pricing at Roma North. As per the December quarterly report, we've separated the Cooper Basin as discontinued operations throughout this report. So we're talking primarily about the Surat Basin results. I'll start with sales volume in the Surat, where we saw an increase of 13% from the prior quarter to 4.3 petajoules, and that excludes third-party purchases, largely due to continued production growth at Atlas combined with ongoing solid performance at Roma North. As we noted in February, Atlas reached nameplate of 32 terajoules a day during the quarter. Turning next to sales revenue. The growth in sales volumes, combined with the improvements in oil-linked pricing from our Roma North contract, helped contribute to revenue growth of 19% this quarter to $33.2 million. Average realized gas prices, this excludes hedging benefits, were 10% up on the December quarter to $6.80 a gigajoule, largely because of the Roma North lag exposure to oil pricing benchmarks, which improved during the quarter. Our hedging benefits reduced a bit this quarter as Brent prices strengthened. Turning next to liquidity and capital expenditure. There have been some substantial movements here, all of which were expected and earlier flagged. At our half year results announcement, we flagged that post the Cooper disposal, we expect it to be in a $33 million net cash position. With that disposal completing in early March, we're now in a $36 million net cash position at the end of March. Drawn debt reduced to $75 million in Q3, following a voluntary debt prepayment of $35 million. The undrawn debt balance of $50 million, remembering we have $125 million facility, remains available for redraw. Capital expenditure for the Surat Basin was down slightly on the previous quarter to $7.9 million. Activity in the quarter included ongoing development planning work for the Roma North and Atlas expansions, as Ian mentioned. That's a brief snapshot of the financials for the quarter. So now I'll hand back to Ian to summarize and wrap up the formal part of the call.
Thanks, Mark. And look, before we take questions, I'll just spend a few moments summarizing basically our investment proposition and the significant value that we see in the portfolio and we see creating for our shareholders. We continue to deliver a material step change in production, having now more than doubled production in the past 12 months. This has supported the acceleration of our inaugural dividend to shareholders and delivering an FY '21 dividend yield at our share price when it was announced, the 4.3%, well and truly above the ASX 200 average. We have an extensive natural gas reserves position with material uncontracted volumes for a structurally tight East Coast gas market. We have a number of low risk and high-returning growth opportunities within our existing portfolio with the Roma North expansion already underway. Our hub-and-spoke infrastructure platform is in place and is scalable to support future appraisal and development activity. And lastly, we have a strong balance sheet from which to grow in a net cash position following completion of our Cooper Basin business sale. So with that, I'll be happy for Mark and I to take any questions you might have. Thank you.
[Operator Instructions] Your first question comes from [ Daniel Levy ] from Citigroup.
Congrats on the good results. Just a couple of quick ones from me. I just wanted to get an update on marketing or at least kind of the marketing environment to the volumes for that Atlas expansion. And if you guys see any read-throughs from that Origin Beach arbitration results.
Daniel, look, it's a great question. And ultimately, you've asked them in 2 parts: One has more to do with price; one has more to do with appetite. The appetite-wise, look, at the end of the day, there is a huge uncontracted market from the start of calendar '23 onwards, which ultimately is when our uncontracted position opens up, which was rather deliberate. And we've got a very extensive ongoing conversations with many customers, some existing, some new potentially. And this is going well. So we're not concerned about it whatsoever, except customers actually do have to commit to term contracts. And the federal government [indiscernible] you that's going on around pricing, doesn't help matters. It really just causes stagnation around the ability to commit, which obviously then goes back into commitment of investments in upstream development. So all reasonably unhelpful, but I think we're getting through it. The read-through from the Origin Beach deal, look, has been written on pretty extensively. And I think ultimately, the unassailable fact remains that there's a structurally tight market coming in the north, let alone the south. And the south -- the southern markets, our supply is dropping off, imports are structurally higher prices. Even if you go and get Henry Hub prices, which I'd encourage those asking for Henry Hub to go and do, it's the structurally higher prices. And I think that just reflects underinvestment in New South Wales and Victoria, in particular, onshore because of moratoria and the like, but also the fact that molecules are getting harder to get because you don't have the oil credits anymore. And I think no amount of wishing is going to change that. I think what we should be doing is getting on developing resources, which is what we want to do. But again, we look for customers to step up for that offtake as well.
Okay. So maybe a bit cheeky, but so were you guys surprised by that result given what you've seen in your own marketing?
Look, they're all pretty opaque in terms of the -- look, there's a read-through. There's about 5 different ranges of outcome per the analysts -- [ sort of align ] my own opinion. But the ACCC, in their own words, said that the pricing in Southern markets was in that range. And I think that's what's been borne out in the judgment. Am I wanting to say it's right or wrong? I don't -- I haven't read the judgment, so I can't really say, except that we do know that even if you say the $7 to $9 range, it encourages investment in Wallumbilla, and you think that there's somewhere between $1 and $3 transportation depending on all the commercial arrangements around it, then you're in the range of the ACCC price -- price markers and you're in the range of what that arbitration outcome is. So it all seems to hang together reasonably well to the cost of production, the risk-adjusted return and transportation to Southern markets.
Okay. All right. And then just quickly, can you talk me through the 150% quarter-on-quarter increase in your third-party purchases and just how I should think about modeling them going forward?
Look, think of it a bit like working capital, and Mark, jump in here as well. Think of a bit like working capital. We -- given the ramp-up period of CSG, we always put a bit of insurance in place. We're in the market day-to-day buying and selling, depending on what happens with our existing portfolio, permitted interruptions for maintenance and the like. I mean this is pretty much a -- a pretty standard thing going forward. But it will swing around a touch. So Mark, I suspect there'll be some degree of purchasing quarter-to-quarter, but it's not going to swing well there, I wouldn't expect.
Yes. I agree with that. The key thing will be the longer shutdowns that we have at our facilities and then just balancing out the customer portfolio.
Just [ heading ] in risk management than anything else, it's not -- we don't sort of actively go after merchant trading or anything like that so it won't swing around too wildly.
Your next question comes from Adrian Prendergast from Morgans Financial.
Yes. And congratulations on another good result, which is always good. But just a couple of quick questions from me. Just first on your upstream performance from the Surat project. Obviously, checking really well compared to nameplate. And just what you've learned as plans have been filled and the performance is ongoing, how much sustained sort of gains versus nameplate you're expecting going forward, if there's an opportunity for that? And then secondly, just, I guess, longer term, once we're past this pretty abnormal market conditions this year, the long-term plans for how much of your big reserve base you're expecting to contract out in the medium term? Are you looking to keep some more exposure to future markets with some uncontracted volumes? Or are you looking to tie up the majority in the near term?
Yes. Adrian, so look, let me take the first one, and I'll give a bit of intro to the second one and hand to Mark. In terms of the upstream performance versus nameplate, you can see at Roma North, where we designed to build the facility for 16 TJs a day, it's doing about 19 or so. And we would expect that level of outperformance when we expand to 24, yes, 25, 26, somewhere around there. When you debottleneck things over time, it might not be immediately, but we certainly expect that as you debottleneck facilities, they're a bit like children, you got a love and care for them and help them to perform. So -- and at Atlas also, we're in a period of bottlenecking with Jemena. And we're getting amazing uptime from both of our facilities, and we expect that to be a feature going forward. So -- and certainly, they're very high-value molecules going through debottleneck facilities because they're effectively free for lack of a better term. In terms of the contract book, I might just start by saying we are more than happy to do some nice chunky long-term contracts. In fact, it would be a benefit to us to do that. So the rhetoric you hear, and I just can't help but think about, yes, [ Jane Jonza's ] performance on the 4 corners where apparently there's no gas around, but I just don't understand because it must be a different market that they're looking at. So from that point of view, we're more than happy to sell gas. We're here for our customers. And if our customers want long-term contracts, that's what they'll get. If they want mid-term or short-term contracts, that's what they'll get. But we just need to price the risk appropriately and make a return on our investment. Mark, do you want to continue with how we see the portfolio?
Yes. And maybe just to carry that point on, we are having a variety of discussions with customers across those different terms. So the same sort of terms we've had for the last few years, 1 to 2 years, but also some medium and longer-term contracts. So there is [ interest ] in that long term. In terms of the target for us and contracted percentage out of the total Atlas portfolio, we are not compelled to contract everything. We see prices strengthening, particularly through the sort of 2-, 3-, 4-year outlook. So locking in now is not what we need to do, but a combination of some longer term and some shorter term is what we're hoping to achieve this year and then hopefully [ gets ] back to the strengthening market.
[Operator Instructions] Your next question comes from James Bullen from Canaccord.
And congrats, Ian. Just very briefly, you mentioned transportation rate of between $1 and $3 a gigajoule to get to the Southern states. That's a pretty wide range. Could you give us an indication of where you think the current rate is to get gas down there?
Yes. James, it was deliberately wide because the amount of commercial constructs out there are actually very wide as well. If you're forwarding haul or backhauling, swapping or doing any other myriad of deals in the middle, you'll see it in that range. If you want to go take gas from the NGP down to Victoria forward haul, you're paying a lot more than that as well. So look, the trans -- mining point is the transportation side, I don't think gets quite enough attention that it deserves in the final delivered price. The end -- the ACCC and others talk about prices, and it's pretty hard to see. Is it ex Wallumbilla? Or Is it delivered? And if it's delivered, what is the transportation component or other commercial components outside of the cost of supply that's built into that. And I think it just needs to be called out every now and again. You'd be pretty lucky to get a forward haul contract rate of less than $1. And you're pretty unlikely to get a forward haul rate between Wallumbilla and Victoria heading towards $3. So it sits in that range depending on the commercial constructs.
Okay. And just given the bind that the Southern states are in and also the fact that there seems to be, particularly in the likes of South Australia, increasing incentives to get moving on new gas production. Is that -- are those states that you're looking at in terms of a potential entry into Victoria or into South Australia?
So we've -- I mean, we just disposed of our South Australian Cooper business, which had a pretty high potential gas field in it as well. So look, we're an onshore natural gas producer. We're very focused in our Surat position. We've got a lot of reserves to develop. That's the focus. Nothing in Victoria really tickles that fancy, I have to say, because the regulatory regime is shocking onshore. And offshore, it's just not our game with the regulatory changes coming through and the risk/reward associated with it. There are other players in there that are far more capable as incumbents to bring that supply to market. And I note the announcement by Exxon and BHP today as well in the papers this morning of bringing new volumes into Victoria also. So look, our view is we're very focused on where we are and very focused on helping our customers. Mark?
Yes. Just on that last point, I would add that we are talking to customers in those Southern states. They are looking for some alternative supply sources and a bit of competition. So moving our gas down to New South Wales, South Australia and Victoria is on the cards for us.
Yes, absolutely.
Thank you. There are no further questions at this time. I'll now hand back to Mr. Davies for closing remarks.
Thanks, Rachel. And ladies and gentlemen, thanks for taking time and for your interest in our results. It is an exciting time as we deliver our promises as a low-cost, high-growth natural gas producer. I look forward to presenting, again with Mark, our full year results in our quarterly on the 20th of July. So thank you again, and good morning.
Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.