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Thank you for standing by, and welcome to the Senex Energy Limited FY '21 Q4 Quarterly Update. [Operator Instructions] There will be a presentation followed by a question-and-answer session. [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, everyone, and welcome to Senex Energy's Quarterly Results Conference Call for the Fourth Quarter of the 2021 Financial Year. I'm Ian Davies, Senex's Managing Director and CEO. And with me is my CFO, Mark McCabe.
Good morning, everyone.
So what an exciting day in energy markets. Not often you see a $22 billion merger proposal, nor we seem to be heading into a volatile time with oil as well. So we do pick the days. Anyway, this morning, I'll take a few minutes to discuss the highlights of the quarter, which has been a great quarter for us. And then Mark will talk to our financials, and we're happy to take any questions post that. So during the quarter, Senex really did reach a milestone, achieving its initial production plateau at an annualized run rate of around 19 petajoules per year before our production expansions, which I'll come to, or around 53 terajoules a day. Total production increased to 4.7 petajoules for the quarter, a small increase from the March quarter. But importantly, it's a 56% increase on the 2020 June quarter. We've been able to materially grow our production level over the past 18 months, which really highlights the quality of our Surat Basin field and also the operational capability that we've developed in the company and we've demonstrated in spades.Sales revenue for the March quarter was $33.5 million, a 4% decline on the previous quarter. The slight fall in revenue was due to a combination of factors, including the decision to bring forward gas processing facility maintenance activities into the quarter. And also, there's a slightly higher realized Australian dollar gas price at around $6.90 a gigajoule.Senex continues to make progress on future sales with further customer contracts signed during the quarter with Nyrstar announced today. The GSA with Nyrstar will supply the metal processing plant at Port Pirie in South Australia with gas over 3 years commencing in January '22. So it's 1.7 petajoules, a reasonably small contract but 750 employees in Port Pirie, quite an important contract with everything going on in the East Coast. And gas sales do -- gas sales negotiations are, of course, continuing with other buyers in what is an increasingly tightening East Coast market. We've made really good progress on our expansion plans at our Roma North field. We've already taken the final investment decision to increase production by 50% to 24 terajoules a day or 9 petajoules per year. This is a high-return, low-cost, long-life investment, and it demonstrates the value available to us from incremental investments now that our hub-and-spoke infrastructure platform is in place. We expect this expansion to be online this quarter.At Atlas, we continue to make progress on the expansion to 18 petajoules per year or 48 terajoules a day with FEED now complete. So it's a 50% increase. We're basically all set, with the final investment decision, as we've stated ad nauseam really dependent on agreeing contracted term volumes with customers. And as I said, discussions are continuing well.We also continue to progress our Roma North expansion, which is 100% expansion to 18 petajoules a year, also 48 terajoules a day. We've completed the FEED activities on the original design, and we continue to target a final investment decision on the expansion in the first half of FY '22 with an initial production target obviously in '23. The expanded natural gas production will be delivered to GLNG under our existing gas sales agreement should we reach that final investment decision.And I say that we've completed FEED on our initial design because we're actually looking at electrification studies of the processing plant and field for a couple of reasons. We believe in the energy transition, and electrification is a really good and compelling way to reduce our carbon emissions and obviously that of our customers from the project. But also, there's real operational efficiencies at play also, so we're doing that work now. So what I have just outlined is a snapshot of the past quarter's performance and growth opportunities, which we'll continue to update on. I'll hand over to Mark to work through some of the financials.
Thanks, Ian, and good morning again, everyone. So as Ian said, it was another solid production result this quarter, having reached plateau production during the third quarter of FY '21. Just to be clear, the data we're reporting today and going forward is all Surat Basin only, being the first quarter since the Cooper Basin sale completed. I'll start with total sales volumes of 4.7 petajoules, which is a decrease of 2% from the prior quarter. Before third-party purchases, sales volumes were down from 4.3 to 4.1 petajoules. And on purchase volumes, we had maintenance shutdowns at Roma North and Atlas this quarter, which required additional purchases, as did the Callide power station outage, which saw increased customer nominations.On sales revenue. Sales revenue was 2% lower than the prior quarter, basically reflecting lower sales volumes we discussed just now. Average realized gas prices, and this excludes hedging benefits, were 1% up on the December quarter to $6.90 a gigajoule, largely reflecting improvements at Roma North pricing due to the lag exposure to oil pricing benchmarks. And as we noted today, there's roughly a 5-month lag between Brent prices and how that flows through the GLNG contract to us. Hedging benefits reduced this quarter, again, as Brent prices improved further. So it's worth noting that the hedge payouts reflect Brent in effectively real time, whereas the GLNG contract has that delay I just mentioned.And then lastly, on liquidity and capital expenditure. Our net cash position at the end of the quarter is $26 million, and that's after our inaugural dividend payment during the quarter, which was just under $15 million. So that -- and that reflects an improvement of around $5 million on the 31 March cash position. Drawn debt remains at $75 million unchanged since Q3. And similarly, the undrawn debt balance of $50 million is unchanged, and that's available for redraw. Our capital expenditure for the Surat Basin was up slightly on the previous quarter at $10.4 million. Activity included -- this quarter included ongoing development planning work for the Roma North and Atlas expansions that Ian talked about and also some early work ahead of our CY '21 drilling campaign.That's a brief snapshot of the financials for the quarter. I'll hand back to Ian to wrap up the formal part of the call.
Thanks, Mark. So before we take questions, I'll just spend a few moments summarizing our investment proposition and the significant value that we're adding. We have an extensive natural gas reserves position with material uncontracted volumes for a structurally tight East Coast gas market, which we're clearly witnessing now. We continue to deliver a material step change in production, having increased production by more than 50% over the last 12 months. We'll continue to deliver production growth with the Roma North expansion already underway. And we continue to progress the low-risk, high-returning Atlas and Roma North expansions -- the expansion projects. So that will take production of our portfolio to around 36 petajoules per year, well on our way to our 60 petajoule per year target by the end of FY '25. Our hub-and-spoke infrastructure platform is in place. It's scalable to support future development activity. Our production and sales performance continued to deliver strong and stable cash flows. And those stable cash flows, when combined with our strong balance sheet, provides us the ability to pay dividends, which we'll continue to do, and also to accelerate the development of our significant Surat Basin gas reserves. And lastly, we're pleased to announce today some appointments. So the appointment of Ben Lacey to the newly created position of EGM Energy Solutions. Ben joins us with a wealth of experience from AGL, where he's currently GM Originations and head of the wholesale gas markets. He's also been with Shell Energy Australia, BG Group and also QGC. And this announcement also follows the recent appointment of Simon Ellinor, who'll commence as CFO in late August, with Mark continuing the move of the deckchairs to Chief Commercial Officer. And I bet he's waiting for Simon to get here.So with that, I'll hand over and take questions. Thank you.
[Operator Instructions] Your first question comes from Daniel Levy from Citi.
Just a couple of quick questions from me. Can you give me a bit more detail on the outages of both plants? Because it was my understanding that the modular design of those processing units meant that they didn't need to be taken off-line all at once for maintenance, yet it looks like that's exactly what happened at both projects.
Yes. So it's -- I mean you're mostly right. So for maintenance of the compressors themselves, that's exactly right because we have redundant units. But when you do the balance of plant, so the TEG unit and all the common facilities, you need to take it off-line. So we had a -- I think of that being a 2.5-day shutdown for that, which went pretty much on schedule. And that's not uncommon. We expect that -- actually, I can't recall, but I think it's in the order of every 18 months or so with a major shutdown every 5 years. So -- and that's -- it's pretty usual for those things. But where we do save well and truly above other plants is with that modular design. The actual compressor units themselves can be rotated, if you like.
Understood. Now looking at your production versus sales numbers, you've lost about 6 petajoules or 13% through fuel usage and flaring, but that's up from 7% last quarter. Can you tell me why that's gone up and how I should think about it going forward given that 13% is actually a pretty significant chunk of your production?
Yes. So look, I'll hand over to Mark in a sec, but the -- if you look at the top of Page 2 around the commentary in volumes, firstly, there was the shutdown for maintenance, which we brought forward to the end of the financial year. So clearly, production still continues because we have to -- we can't turn off the field like a conventional field, so production continues through the bypass. But also, we had the Callide outage this month where, I mean, frankly, we had some customers, one in particular, that's nominated to zero for their own shutdowns, and Callide went off-line, and they ramped up to full MDQ. And yes, notwithstanding, we could possibly have not supplied that, we chose to, because it's the right thing to do to honor our contract. So it's a one-off because of Callide. And clearly, the entire market has seen that go through, and it's caused quite a few upsets, which just really shows the fragility of the market. Mark?
Yes. Daniel, yes, Ian's right in that the 6% or 7% that you talk about is the typical number. If we're perfectly balanced, so our production equals our customer obligations, then that's the number you should see. But from time to time, customer nominations don't match. And so normally, we will see that coming in terms of shutdowns that will be planned for ahead of time. But with things like Callide, that came at very short notice, so we stepped into the market.
And actually, I might -- just if I can add to that, too, because this is a relevant comment for the way our gas sales agreement work, there seems to be -- if you look at the press in recent days with spot markets, I mean we're clearly concentrating on term market volumes with good quality customers that we can grow with and help. And the nature of the gas sale agreements that are done for term have quite a bit of flexibility in them, which is not well understood in the public markets.For instance, there's take-or-pay obligations, which are usually less than 100% of volumes. There's the MDQs, the maximum daily quantity, is normally more than 100% of volumes, sometimes quite materially more, which provides flexibility. So as a supplier, we have to make sure that the gas is there for not only the take-or-pay obligations but also the MDQ. And when you have particular upsets in the market like Callide, then you have a few customers go to MDQ that you weren't expecting a short notice, and sometimes you call it short. Now in terms of materiality, we always manage the book, so it's generally covered. Sometimes it's not 100% covered, it is what it is. So we step into the market, which is what we did this quarter. And quite often, we'll be on the other side of the trade as well. Like a few months ago, we had spare volumes to sell into the market. So that's the nature of the beast, which is part of the reason we're actually building a fairly sophisticated trading capability to manage those sort of risks.
To sort of belabor the point, I don't like to use flaring because it's a bit of a dirty word, but so is the read-through here that there was increased flaring this quarter while you had downtime at those processing facilities?
Look, that's exactly right. And considering -- I mean the flaring, it's not -- I mean we certainly don't want to flare for operational reasons. For safety reasons, the flare is there for a great reason. But for operational reasons, we're doing quite a lot of work internally to think about how we reduce flaring, and that will reduce both volume and sales.So for instance, the last -- during the shutdown, we installed, I think, it was 15 choke valves in the Atlas field, which our high-producing wells were able to turn down a bit, so that helps. And then secondly, what else can we do to the field to eliminate flaring altogether, which is one of our goals.
Your next question comes from Adrian Prendergast from Morgans Financial.
Ian and Mark, just a quick question on the spot markets. As you said, they are very different from term markets. But is there any read-through at all around increasing interest in those very big uncontracted reserves you've got?
Well, so as a general rule, yes, you might be reading with interest the conversation happening at the moment around the ACCC's draft determination on the netback pricing model. And if I take a quick step back, netback pricing is a theoretical thing that says the LNG producers should be indifferent to one market or the other, and the mechanism for that price of indifference is the netback. Now as a domestic producer, we -- and this is all about the netback, but it is actually relevant because, obviously, as a material exporter, same as Woleebee or whatever else, when you have access to export markets, rising LNG prices, countercyclically in particular, the rising LNG prices equals rising netback prices, which equals rising expectations of future term contract volumes as well, especially when you see supply tightening in the South, which is where a lot of the demand is, hence, the large conversation around East Coast gas markets. So I think it is fair to say that the buyers are recognizing that the market is tightening and rising. To be clear, it's in no one's interest to have large volatility in these markets. And we don't actually like to see huge volatility because we're not here to trade. We're here to build, yes, really good-quality, long-term relationships that provide good quality cash flows to the business and then use those relationships to grow our business and our customers. So -- and clearly, going forward, we will have a portion of our portfolio non-contracted. As a general rule, we're targeting broadly 2/3 contracted, 1/3 uncontracted or shorter-term markets as a -- and don't use that as Gospel, that's just a sort of rule of thumb that, that will move around. But certainly, the expectations of the term markets are increasing in terms of price.
Your next question is from Gordon Ramsay from RBC.
Just very quickly on the gas market, with your new contract in South Australia, do you see increasing opportunities in Southeastern markets considering that Atlas at the moment is mainly contracted with Queensland-based customers?
So I'll give an intro and then Mark. Ultimately, our entire focus is helping our customers with energy supply, and natural gas was the core of our business for a long, long time. And I see natural gas as being a core component of the economy for a very long time. And whether we like it or not, the major demand centers as it currently stands is in the South, particularly in Victoria, so we've put in place a range of measures, commercially in particular, to make sure that we have availability to deliver gas to our customers in Southern markets also. And you'll see that more and more over time as the market also increases in sophistication. But Mark, do you want to expand on that?
Yes, just a couple of points. So Ian mentioned the tightening gas market in the South. Queensland is the solution for that at the moment and probably the only solution in the foreseeable future. So with our production growing and heading towards the 60 petajoule target that we're talking about in FY '25, we do see ourselves playing an increasing role in the South.
And just to add to that, do you see pipeline capacity being an issue going forward?
Yes. So there was an interesting article by Joel Fitzgibbon in the [indiscernible] where he's calling for increased pipeline capacity from North to South. And yes, I've certainly heard other views from others also. And I think that's only sensible because whether we are happy with the situation or not, New South Wales is closed to new projects outside of Narrabri with the looks of it. Victoria's certainly closed, and the existing fields are declining materially and will continue to do so. Now if those -- you've really got 2 or 3 solutions, I guess, for Southern market demand and those customers who require energy. It's an import terminal, which I think ultimately has to be fairly complete because there just needs to be that seasonality of volume, which improves. It's a virtual pipeline rather than a physical pipeline. Secondly, building new capacity into Southern markets for pipelines, that's always difficult because you're not only dealing with long-life assets, you're also dealing with lots of land issues also. Or alternatively, those customers take the opportunity to move their operations at major shutdowns or major turnarounds or end of life to -- closer to where the energy is produced, and that's Queensland and which I would support.
[Operator Instructions] Your next question is from James Bullen from CG.
Ian, just with the rising gas prices, are you concerned that the ADGSM comes back into play? Have you heard any rumblings about that?
Yes. Well, I've heard, assuming he was quoted correctly, the Resources Minister, Keith Pitt, quite clearly said the ADGSM is there for market failure, and there's no market failure. There's -- those customers who've chosen to lock in term contracts are not worried about spot prices. Those customers who have deliberately taken spot market exposure, that's the risk you take in your portfolio when you do that. And ultimately, we -- I beg your pardon?
Sorry, just keep coming in, sorry.
Sorry. So look, I don't particularly see a risk of the ADGSM coming into play because it's designed for a specific purpose, and that purpose is not now.
Great. And just we've seen a few more of your peers now talking about moving towards net zero. Have you had any further thoughts around whether it's an appropriate time to look at potentially buying carbon offsets, et cetera?
Yes. So we're doing quite a lot of work on the sustainability front. But culturally, which is actually pretty important, is we will never promise something that we can't deliver or have a plan to be able to deliver. Now a couple of competitive -- well, comparative or competitive, depending on where you're coming from, advantages that we do have is coal seam gas is structurally lower carbon than pretty much every other form of fossil fuel. And our operations are lowest quartile in the hydrocarbon economy, and we have a natural advantage from that point of view. And we -- our Scope 1 and 2 emissions we've done quite a lot of work on and are actually relatively easy to do something with, which you'll hear about over time. Scope 3, of course, is where the -- all the largest conversations around abatement are happening. And ultimately, as a domestic producer, our Scope 3 is our customer's Scope 1. And I'd go back to the fact that we're a customer-led organization, and we want to have good quality relationships with good quality customers who take this stuff seriously, and we can have these conversations around how we work together to reduce emissions and increase efficiency, which is also part of the reason Ben Lacey is coming on board in this slightly nebulously named Energy Solutions team, which will be a small team but an important team to, yes, think about customer-led solutions for helping our customers on their journey to decarbonize because it's happening. Corporate Australia is leading the country effectively in terms of those net zero targets, as you say. But I fundamentally have a philosophical issue with promising something you have no idea how you're going to deliver. But in saying that, you're going to be hearing quite a lot more from us around that as we head up to our sustainability report in, not that long, not many weeks' time.
Your next question is from Nik Burns from Jarden Australia.
Ian and Mark, just a question in relation to your underlying production potential from your well fleet at Roma North and Atlas. Just trying to get a sense of how your understanding of the well performance is evolving over time and how we should think that feeding into requirements for future drilling to either increase or maintain plateau production.
Yes, Nik, look, there's probably 2 different -- obviously, 2 fields with quite different characteristics. Roma North is currently producing above nameplate and actually has wells that have capability above that even, which is -- and as you know, from your years in coal seam gas, Nik, it's not exactly an exact science in terms of each well's capability and timing. Some wells surprise you to the upside, some to the downside, and you try and get the P50 right, and you're there or thereabout. And that's how we really think about it. And the more well stock that you have, the lower your margins for error is, which is why expansions are also important. Atlas, on the other hand, very high productivity wells and very easy to correct unders or overs, which, again, is part of the reason for our expansion at Atlas, its high economics, its long life and good productivity. So ultimately, we're continuing to range-bound our reservoir model, which is not the easiest thing in the world. But as you have more wells, your margin for error decreases. So the expansion has become almost self-solving.
Got it. And just a question around your conversations with customers for Atlas expansion volumes. You've already touched on it in talking about flexibility in sales. And thinking forward, just reading into your comment around sort of circa 2/3 contracted, should we be thinking that some of your future contracts might offer a lot more flex or shape in order to attract a higher price but then holding that gas to play in the spot market or potentially increase the number of wells that you can choke back?
Yes, all of the above is probably the answer and with the philosophical that we're here to serve our customers and we're here to create value for our shareholders. And I guess a couple of points you bring out there. We believe in pricing risk, and it's an education occasionally with customers around what risk actually is. And the good thing about volatility in the market, it reminds every participant that risk actually exists and you probably need to price it. And when you have long periods of low or high prices, that's not really great for anyone. You need to have it where people make money and create value on both sides. And we firmly believe that as just philosophical. Mark, do you want to talk about the way we think about contracts, et cetera?
Yes. And maybe just to clarify one thing there, the flex that's inherently in contracts today, that already exists. That's what's led to some of the short-term flexibility that customers have in the event of something like the Callide outage. And so I'll -- say that we are looking to introduce a lot more flex going forward. That's just the nature of the market. We are also thinking about our portfolio of contracts. So Ian talked about that very roughly, 2/3-1/3, where the conversations we're having are a combination of sort of short, medium and longer term and also a combination of fixed or escalating prices and perhaps a portion of Brent exposure or something like that as well. So it'll end up with quite a diverse portfolio, we think.
Your next question is a follow-up from Daniel Levy from Citi.
Just a quick question on the electrification of Roma North. So you're talking about replacing the 7% infield fuel usage in favor of connecting it to the grid for power? And if so, do the economics of saving that gas outweigh the additional processing costs? Or is it more ESG-driven than economically driven?
So we'll always have a degree of economics where, yes, it's great to -- the ESG piece is very important, but it comes at a price, obviously, and you need to make sure that you balance both of those things. And I mean, clearly, we're not here to sort of just give money away because it's our shareholders' money, obviously. And I think -- let me take a step back. The world is moving to electrification and decarbonization. They just are. And we actually see lots of opportunity as a natural gas producer, specifically coal seam gas, which has that comparative advantage because not all gas is created equal. Many gas sources in Australia have very, very high levels of CO2 and/or mercury or other products. Coal seam gas is almost pure methane. And accordingly, we see quite a lot of opportunity to play quite a meaningful role in the transition of that electrification and decarbonization. And hence, if you think about electrification of newbuild kit, so I could just assume new for a moment, then you generally have tradeoffs. So you save fuel. Now we happen to think that natural gas is an incredibly important part of the economy and will become scarcer over time and more valuable over time for decades to come. Now that's our view. Others will have different views, but that's certainly our view. And certainly, in the investment horizon time line, we're thinking about 3 to 5 years with a 10- to 15-year cash flow, we're very comfortable with the position that we have in an expanding natural gas portfolio.In saying that, I believe we have an obligation because pollution is bad. And I think everyone can recognize pollution is bad. We have an obligation to improve the efficiency of our own operations. And if we can do that whilst being economic or value adding, more the better, which is where the electrification opportunity comes from. You've got an opportunity to have captive electricity production through gensets effectively or generators or open-cycle turbines or there's a range of things available without even connecting to the grid. And connecting to the grid's obviously a step beyond that. And the way we generally look at economics is it's obviously a life-cycle economics. We see the benefit of electrification saving on natural gas, obviously, the fuel, so that 6% or 7% that you talk about, but also the carbon emission reduction, which whether there's a federal carbon tax or something similar, there is a de facto market happening right now with the ACCU market. And with the customer base that we want and we have, they're taking these things seriously as well. We're driven by our customers. And ultimately, someone will have to pay for that, and you'll see it flowing through into the price eventually. So slightly long-winded, Daniel, but hopefully, that gets to the point.
It does. But so basically, are you a bit too early on in the process to be able to give any figure like assigning a dollar a gigajoule to processing or something like that?
Yes, it is a bit early for that, but we're actually quite confident that stacks up economically.
Okay. Excellent. And then just one very quick last one. Just looking at the third-party purchases, can you just help me understand kind of where you purchased that gas from just so I can get the price right in my modeling? Should I be thinking about it you just purchasing it on market at a price similar to the Wallumbilla benchmark? Or do you have other agreements in place to source that gas when it's needed?
Yes, there's probably 3 answers, perhaps, Daniel. So day-to-day, sales don't perfectly equal customer demand, and so pretty immaterial balancing happens through a number of different channels. For the shutdowns, we see them coming, and we can often talk to counterparties and put in place whether it's a 3-, 4-, 5-day arrangement with them. And so that's the sort of thing that you can take your time and put in place. And then for the -- for things like the unexpected Callide situation, we normally have to step into the market at short notice there. So a combination of a few different things.
Thank you. There are no further questions at this time. I'll now hand back to Mr. Davies for closing remarks.
Thanks, Rachel. Ladies and gentlemen, thank you for taking the time to listen today and for your interest. It is an exciting time here as we deliver on our promise as a low-cost, high-growth natural gas producer and, I should say, low-carbon natural gas producer also. And Mark and I certainly look forward to presenting our FY '21 results on the 19th of August. With that, thank you, and good morning.
Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.