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Ladies and gentlemen, thank you for standing by, and welcome to the Senex Energy Q3 FY '20 Quarterly Report. [Operator Instructions] Please be advised that today's conference is being recorded. I'd now like to hand the conference over to your first speaker, Managing Director and CEO, to Mr. Ian Davies. Thank you. Please go ahead.
Thank you, Kevin. Ladies and gentlemen, good morning, and welcome to Senex Energy's quarterly results conference call for the third quarter of FY '20. I am Ian Davies, MD and CEO; and with me is our CFO, Mark McCabe.
Good morning, everyone.
Since our last quarterly report, the macro environment certainly has changed significantly with the challenges of COVID-19 and a rapid decline in oil prices. Senex has a low-cost and resilient business model with an ability to adapt quickly with business operations in great shape, and we have another set of solid quarterly results to present. Gas production growth is again a key highlight, and we continue to deliver our transformational gas projects with minimal disruption from the macro challenges. To begin with, it's worth touching on our COVID-19 response and recapping our important news flow from the recent weeks. In response to COVID-19, Senex acted early and proactively to protect our workers, operations and the communities in which we operate. Like other oil and gas operators, we've implemented a broad range of protocols and procedures, and we continue to monitor and react to the evolving situation. Actions taken include travel restrictions, strict field access arrangement, hygiene discipline and social distancing at our work sites. And we're also working closely with government, industry bodies and our joint venture partners. Our operations and work programs are continuing safely and with minimal disruption at this point. Our highest priority, of course, continues to be the safety and well-being of our employees and the communities in which we work, and we'll continue to provide the market with updates as appropriate. As well as COVID-19, we're also managing in lower and volatile oil price environment. Senex is well positioned to navigate this volatility, which we've communicated recently in our investor briefing of 11 March and also a follow on ASX release of 27 March. Those communications demonstrated the resilient nature of Senex' operations. We're well protected from lower oil prices thanks to oil hedging in place over the next 18 months or so, strong fixed price gas contracting in Atlas and downtime protection in our gas sales agreement at Roma North. This means we're well placed to navigate this downturn and come out the other side very strongly indeed. Looking forward, our investor briefing set out the production and cash flow generation profile that our Surat Basin work programs will deliver from FY '22. As a brief reminder, from FY '22, we're targeting annual production of more than 3.6 million barrels of oil equivalent, EBITDA of between $100 million and $110 million, free cash flow between $70 million and $90 million, and net debt-to-EBITDA of less than 0.5x. And it's important to note, these targets represent our foundation asset base only and very clearly defined prices and FX rates. We can debate that for ages, but I'll leave that. And for clarity, there are no growth projects assumed at all within this portfolio in which we have complete discretion over. This strong cash generation profile and scalable asset base will be the platform for low-risk expansion and acceleration opportunities, which we will of course pursue with our usual disciplined approach to capital allocation. So with that as a backdrop, I'll now turn to our highlights from the quarter. Firstly, production, and it was another strong gas production growth -- it was another quarter of strong gas production growth in the Surat. A clear highlight was Roma North, reaching the facility's initial nameplate capacity of 16 terajoules a day. And we achieved this a year -- one year ahead of schedule, a full year ahead of schedule, which is an amazing outcome, and I again thank all those involved in the team. Not only was nameplate capacity reached, but we have also successfully continued to increase production at Roma North and have been consistently producing above 18 terajoules a day for the past month. We also continued to progress through FEED for the low-cost 8 terajoule a day expansion to 24 terajoules a day or approximately 9 petajoules per year, given we have more than 20 years of 2P reserves coverage of Roma North at 24 terajoules a day. At Atlas, we experienced some interruption to well production following heavy rain in the -- early in the quarter, which I think was well-publicized at the time. These wells came back online recently, and production is now getting new heights. Our production has exceeded 10 terajoules a day in Atlas from the first 23 wells. It's also worth noting that current production is only from 1 of the facility's 5 compression trains. So production ramp-up and facility performance today give us lots of confidence in the outlook at Atlas. In the Cooper Basin, oil and gas production increased 4% to 230,000 barrels of oil equivalent. We saw natural oil field decline, offset by increased gas and gas liquids production from the Gemba field. In total, production for the quarter was up 31% to 588,000 barrels of oil equivalent, with year-to-date production of 1.4 million barrels of oil equivalent. We have reiterated today also our full year FY '20 production guidance of 1.8 million to 2 million barrels of oil equivalent, and clearly, we're tracking well against this guidance. Turning to the Surat work programs. Our progress is continuing at a rapid rate, and it's exciting to be nearing completion of the execution phase in the first quarter of FY '21. As we announced during our investor briefing, we've reduced the drilling campaign by 25 wells due to production outperformance to date. At Roma North, we have completed the drilling campaign of 35 wells. And at Atlas, the remainder of the 50-well campaign is underway. We've also announced that we will build, own and operate water management facilities at Atlas. It's a value-accretive opportunity with capital investment of around $15 million to alleviate ongoing water processing tolls and provide greater operational flexibility. Lastly, a quick word on gas contracting. Despite speculation of weak demand and softening prices for short-term contracts, we continue to see pragmatism from domestic buyers and demand at firm prices for term contracts. And it should be noted that term contracts do attract term pricing. We are progressing negotiations on new contracts for our Atlas gas, and we continue to receive inbound inquiries for new supply, which highlights the underlying strength in this market, specifically at the end of FY 2022 into FY '23 -- or into calendar '23, excuse me, almost. We have over 60% of expected Atlas gas production contracted through to the end of the '22 calendar year, with new contracts, obviously, we'll have announcements on. And on that note, I'll hand over to Mark to talk through our financials. Mark?
Thanks, Ian, and good morning again, everyone. I'll begin with sales volumes, which saw a 35% increase in our own production volumes to 539,000 barrels of oil equivalent. And this included a 68% increase in gas and gas liquids volumes and lower oil sales volumes in line with natural field decline. And in addition, this quarter, we had roughly 570 terajoules or 97,000 BOE of third-party gas purchases, which we undertook during the early stages of Atlas production ramp-up. Our total sales revenue was up 13% to $33.3 million. Key drivers were obviously higher gas production and strong prices, sale of those third-party gas purchases offset by the impact of lower oil prices. The rapid fall in oil prices had a significant impact on our revenue with a 48% decline to $10.2 million. This reduction is largely attributable to the accrual method we use, the Cooper oil revenue recognition. I'll take a minute to explain that. It has an impact because there's generally a 70-plus-day lag between accruing revenue and provisional prices when oil was delivered to the SACB joint venture at Moomba and then the final price determination when oil is shipped to the end customer. This means that most production for the quarter is accrued at quarter end, and therefore, was marked down this quarter to reflect spot prices at the end of the quarter. In a declining oil price environment, average realized oil price in the quarter may be relatively lower due to that repricing effect and the opposite that will occur in a rising oil price environment. Despite the drop in oil revenue, and as Ian mentioned, we remain in a strong financial position with revenue streams diversified and well protected from oil price declines. We can say this because of the following characteristics: Firstly, at Atlas, over 60% of expected gas production through the end of calendar year '22 is contracted at strong fixed prices. At Roma North, as we've explained, the oil-linked gas sales agreement has downside price protection built into it. As we announced on the 27th of March, this contract delivers positive operating cash flow at oil prices below USD 15 a barrel. When oil touched $27 a barrel last month, the contract was delivering gas revenue of more than $5 a gigajoule. In the Cooper Basin, we have over 400,000 barrels of oil production hedged in the 15-month period through to June 2021 at average swap prices between AUD 90 and AUD 95 a barrel. No new oil hedges were placed during the quarter, and we continue to monitor our position there. With these revenue streams and mix of fixed and downside protective prices, we reiterated FY '20 full year EBITDA guidance between $40 million and $50 million. Turning to the balance sheet. Our overall liquidity position remains healthy. We closed the quarter with net debt of $26 million and cash reserves of $99 million. As we approach the end of the execution phase of our Surat Basin gas development projects, the bulk of our capital spend is nearly behind us. As we mentioned in the investor briefing, our expectation is the peak net debt below $80 million on completion of the work programs early in Q1 FY '21. This will leave significant headroom and available cash reserves based on our current debt facility of $125 million. Lastly, CapEx at $42 million tracked broadly in line with last quarter, with the bulk of spend once again relating to activities at Roma North and Atlas. Some spend was also incurred in the Cooper Basin to complete connections and some associated activities as part of the free-carry program with Beach. As Ian mentioned, we've reduced the Surat Basin drilling campaign by 25 wells due to production outperformance to date, and we've also decided to build and operate water management facilities at Atlas. The net effect of these changes to the work programs is a reduction in capital expenditure for the Surat Basin development projects of around $15 million. On that note, I'll hand back to Ian to wrap up the formal part of the call.
Thanks, Mark. Well, certainly, an unprecedented quarter for Senex. However, our financial discipline, low operating cost model, and diversified revenue streams position us well to not only deliver our growth objectives as planned but also come out the other side of what is a pretty ordinary time, very, very strongly indeed. With Surat Basin gas production now above 29 terajoules a day, or actually 29.9 as of this morning, so almost at 30, which is actually a reasonably large number when you consider the performance of the Roma field for the last 8-or-so years, we're struggling to get over 20 terajoules a day for us after the last 12 months or so, to hit 30 is quite a good milestone. And we are rapidly tracking, of course, toward their initial nameplate capacity of 48 terajoules a day and clearly establishing ourselves as an important supplier of gas to the East Coast market, which is totally in line with our stated strategy. So on that note, we'll conclude the formal part of the call and happy to open the lines to Q&A, Kevin.
[Operator Instructions] Our first question is from Mr. Adrian Prendergast from Morgans Financial.
Well done on another good quarter, Ian, and the team. So thanks for that.
Thanks, Adrian.
Just a couple of quick questions, just more on the market, and thanks for your comments on the health of demand for term volumes and prices. That's certainly helpful. But just wondering in recent months, with the continuation of some LNG producers selling extra volumes into the domestic market, do you see it as posing any material risk if this continues or increases that it would start to drag on customer demand for term volume?
Yes. So look, multifaceted question and exactly the right question to ask. There's -- look, there are so many variables to go into the -- if you take a global outlook in terms of low oil prices, oil-linked LNG contracts, lack of customer demand in Asia at the moment. Does that swing around materially and quickly as China, Korea and other countries recover from COVID-19? What does that do to energy demand and pickup of those term contracts through the Gladstone LNG projects, et cetera? Not to mention, of course, the inevitable pullback in CapEx that's been announced over the last couple of weeks from, well, everyone and the inevitable effect that has in replacing production because remember it's a declining resource. And I can't help but thinking people forget that global supply naturally declined by about 5% a year, and the CSG projects are certainly no different to that and actually more. So you need to replace production before you're even growing production volumes. So with all that coming about, I mean there is obviously short-term softness. And we're not so worried about short term because we're fully contracted in calendar '20. We're 60% contracted through to '22 from Atlas. We've got fully contracted volumes in. Roma, and the rest is oil, which is obviously liquid. So we're not all that concerned in the short term. Longer term, I can't help but think the demands globally picks up pretty materially and also with the CapEx pullback that we're heading for an extremely strong East Coast gas market, especially when you take into account the drop into supply from Southern -- the traditional Southern supply areas and a very large uncontracted book from the buyer side from calendar '23 onwards, very large indeed. So we're pretty bullish late '22 into '23 from a supply side, and we think there's a huge amount of demand waiting, as I say, by the -- I think, recognize this. You're not having the [ dollar swing ] that happened last time around trying to quite ingenuously -- disingenuously relate short-term spot prices to 5-year deals. You've got much more pragmatism in the market with that.
[Operator Instructions] Our next telephone question is from Mark Samter from MST.
I guess, first question, it's a bit of a follow-on from Adrian's question. The previous cycles we've been through in the oil market have shown that domestic gas producers, whether there's an economic trigger from the gas price or not, have not sown money into the ground. Do you get a feel from your conversations that domestic gas wells do appreciate that nuance? And almost whatever the gas price is, there might be a limited amount of capital getting put into the ground on the gas side of it?
Well, I think that's right. And the difference with this -- the issue we're seeing today is a twin effect of both economy-wide disruption, and that's on the buyer side as well, obviously, from the traditional demand sources. But on the supplier side, with lower oil prices as well, it sort of doubly felt because you're getting this -- you're carrying it not only oil prices but also the traditional demand that they get otherwise. And there's no doubt that conversations we've been having. There is an appreciation that every company is going to pull back CapEx, and that's almost without exception. The balance sheet of companies are quite a bit stronger this time around, obviously, which is I think a good thing. But the discipline you're seeing even over the last 2 weeks from very bullish E&P companies very quickly pulling back and deferring and saying, "Actually, this is going to be here for a while." So we've got to defer, defer, defer for as long as it takes. And I think that will obviously come through in the supply/demand dynamic.
And then just a quick question about expansion environment. Also, I can't remember if we covered this up at the Investor Day a lot, but can you give us a bit of a feel for the cost of it? And therefore, yes, I mean, even a $30 oil given what we know. Pricing now is about $30 oil for this contract. Presumably it's a pretty quick cash payback even at $30 oil for this one.
Yes, look, it is. There's 2 parts to it. One is, is it economic and is it a good use of capital. There's no question that the answer to those 2 things is yes. The other question is when. And the when question, when you're in a market like this, is actually far more dynamic in nuance. And we've made no secret of the fact that we think this is a very robust project that will go ahead. The question is when. And there's many aspects to that, including alternative uses of capital and being inherently fairly risk-averse from a balance sheet perspective. And we keep -- we get the occasional feedback that people are worrying about balance sheet, et cetera. I challenge anyone to find a business that's handled its balance sheet more pragmatically and risk-aversely than Senex has, and that's from 2012 onwards. And we came out of the last oil price crash with $100 million in cash. And this time around, we've said we'll have less than $80 million of net debt and net debt-to-EBITDA of less than 0.5. I mean it's a very, very strong balance sheet in the back of our $400 million CapEx program. So we're feeling pretty good about things.
Our next telephone question is from Saul Kavonic from Credit Suisse.
Congrats on good results on the gas side of things. If I may, I just have some questions on oil pricing -- on the crude side and the oil pricing. And just the first one, I mean, in my numbers here, your realized oil price is a pretty steep discount to Brent compared to the previous quarters. I appreciate the timing elements, Mark, that you discussed. But I'm wondering is there anything else to it beyond that timing element. And in particular, are you able to give an indication on how the crude -- the realized crude pricing is versus brand compared to our previous quarters before the oil price crash?
Saul, it's Mark here. No, there's nothing complicated in the math. So we have sometimes over 70 days in the accrual, and then the amount that actually washes out each month can be a pretty small amount. So we -- our opening accrual was in the order of sort of AUD 90, and that got marked down to low 50s. So we had -- offhand, I think it was around 100,000 barrels that got repriced at the end of the quarter. And so all of that washes through when you can have a -- when it's that dramatic a slump, you can have almost 0 revenue for the quarter because so much is accrued. So there's no real trick, just the nature of that contract.
It's very much exacerbated that when -- at times of high volatility around the end of the quarter accruals process, and you see it on the upswing as well.
Got it. And just secondly, on the Cooper Basin oil volumes, are you able to just provide an indication on the life of the fields there? What abandonment cost might be associated with it? And when -- or particularly if we could see any abandonment cost associated with Cooper Basin oil over the next 2 to 3 years?
Yes. So I think we've got -- there's -- in South Australia, there is an agreed P&A program that all the operators have agreed with what is, I would argue, one of the best regulators in the world. And I think we've got 2 wells to P&A in the next couple of years. And then our producing fields, we're in the 30s, Saul. So I think it's mid-30s, early 30s by the time. And it's fully provided for but it's -- at the time we're actually planning P&A and producing fields, it's in the 30s, so 10, 15 years away. The producing -- our IP environment is probably about 8 years, but obviously, there's a very long tail. And that's assuming no more discoveries or development of -- or appraisal development of existing resources. So there's a very, very, very long tail in Cooper Basin oil, and 90-something percent of our production reserves is the Western flank around existing infrastructure. So there's no material abandonment coming up at all.
[Operator Instructions] There's no further questions at this time, and I'd like to hand the call back to Mr. Ian Davies for closing remarks. Please go ahead.
Ladies and gentlemen, thank you very much for joining us for our Q3 call. I hope you agree that we're going from strength to strength as promised. I look forward to updating you again in Q4. Thank you very much, and good morning.
Ladies and gentlemen, that does conclude the call for today. Thank you for participating. You may all disconnect. Goodbye.