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Ladies and gentlemen, thank you for standing by, and welcome to the Senex Energy Q4 FY '18 Quarterly Results Call. [Operator Instructions] I must advise you that this conference is being recorded today, July 31, 2018. I would now like to hand the call over to your first speaker today, Mr. Ian Davies. Thank you. Please go ahead.
Thank you, Edison. Thanks. Good morning, everyone, and welcome to the Senex Energy Q4 Conference Call. I'm Ian Davies, Managing Director and CEO of Senex Energy; and with me today is our CFO, Gary Mallett.We've made 3 very positive announcements for the market today. Firstly, our financial quarterly results for the full year 2018, in which we report very strong production and pricing. Secondly, our 2018 annual reserve statement, in which we report material additions in our Surat Basin Gas Projects. And thirdly, and pretty importantly, clearly, the delivery of a $150 million debt facility fully underwritten by ANZ.So first, with the funding. We're absolutely delighted to announce the results of an extensive assessment of bank and nonbank financing alternatives in both Australian and international capital markets to deliver funding for the business. This funding arrangement really delivers to Senex. It provides us with certainty, highly competitive interest cost and terms and gives us flexibility to both expansion and repayment. As far as we know, this is the first time an Australian corporate has secured senior debt against unconventional development stage gas projects. ANZ's commitment to funding the Western Surat Gas Project and Project Atlas is in no doubt a vote of confidence in the quality of the asset base.And following the successful Project Atlas infrastructure partnership that we announced last month, we're working towards a similar solution for the Western Surat Gas Project. Once again, it will allow us to access another pool of efficient permanent capital. The delivery of this funding is an important milestone to the execution of our East Coast gas strategy. It provides us -- excuse me, it provides us the financial wherewithal to rapidly progress both of our major projects to development, and that financial wherewithal obviously is on the back of a conservative balance sheet and a strong balance sheet. We know that the financing is an important catalyst in the eyes of the market, and we're delighted to be able to provide that certainty of low cost funding today.Now to look back briefly in the 2018 financial year and review our performance. Fair to say, it's been a big year for Senex. We made major steps forward in our strategy to build a material East Coast gas business, while our oil business continues to perform strongly. Against the backdrop of significantly improved oil pricing, we are, today, reporting a return to growth in production, revenue and operating cash flow. Importantly, production and capital guidance -- excuse me, production and capital expenditure were both delivered in line with guidance. In addition, today, we announced a strong reserves upgrade result, increasing 1P reserves by 21% and 2P reserves by 35%. And our annual charts tell the story. We have managed to build our reserves position year-on-year with a compound annual growth rate over 5 years of 38% for 1P reserves and 30% for 2P reserves, a terrific result. We have a significant 2P reserves life for both gas and oil, with the majority of our undeveloped resource booked against our East Coast gas development projects which, clearly, we now have the funding to go and develop. It should be no surprise to you that our overwhelming priority is the conversion of these undeveloped 2P reserves to developed reserves and production.Which leads me to a review of our gas businesses, starting with Project Atlas. Today, we have booked maiden 2P reserves of 144 petajoules on this project on the western 2/3 of the block, as guided to the market, I might add. This represents a 30% recovery factor on the 427 petajoules of original gas in place estimated by Netherland Sewell & Associates. Based on current work to date, we are targeting ultimate recovery of up to 65% of original gas in place or some 278 petajoules over the life of the project. We have a clear development path in this project, and by this time next year, with wells on the block will have started converting the process -- we started the process of converting incremental reserves booking and conversion.This quarter, we reached a significant milestone on Project Atlas, partnering with Jemena on a downstream facility and pipeline that will fast track gas to the domestic market by the end of 2019. This agreement has a number of benefits to Senex. It materially derisks our schedule, it represents compelling value, and is a very efficient permanent source of capital, all reasons why it makes perfect sense for us to target a similar solution for the Western Surat Gas Project. Today, we also announced the booking of additional 1P and 2P reserves on the Western Surat Gas Project, driven by positive subsurface results from the Phase 2 appraisal program. The debt facility we announced today and did today, along with our existing strong balance sheet, ensures the liquidity required to develop this asset. Gas volumes from the Phase 2 wells have continued to increase, producing above 3 terajoules a day on average across the quarter, an increase of 67% compared to Q3, albeit off a small base.In April, we received a Petroleum Lease over the Glenora and Eos blocks, and now we are only waiting for our Commonwealth approvals before having all approvals in place to make the next investment decision. We also made important progress on 2 gas opportunities in the Cooper Basin during the quarter. The Vanessa gas field is now online and producing, and during the quarter, we signed a Gas Sales Agreement with ENGIE to supply gas to their Pelican Point powerstation, which is a significant generator of electricity in the South Australian market. We also drilled, cased and suspended the Gemba-1 well, intersecting gas in the target zones as well as a potential new gas play in the deeper Dullingari group. We're developing a fracture stimulation and testing program to further evaluate the well in the second quarter of FY '19.Moving to our Cooper Basin oil business, where the key highlight of the quarter was the completion of an agreement with Beach Energy transferring up to $43 million of free-carry commitment from the joint venture's unconventional gas project to the Senex-operated western flank oil field. The joint venture is totally in line with the well program which will commence at the end of this week and will include at least 3 horizontal development wells and 7 exploration wells. And this program leverages the 688 square kilometers of merged 3D seismic data across the western flank as well as the lessons learned from our recent and very successful Birkhead horizontal development well, Growler-15. So with that, I'll hand over to Gary.
Thanks, Ian, and good morning, everyone. As Senex's new CFO, I'm very excited to announce our 7-year debt facility today which will be used in combination with our cash balance to fund the company's growth profile -- portfolio. I hope you'll agree that our starting interest cost of approximately 6% is highly competitive, with this rate stepping down 50 basis points on completion of our development projects.I'm happy to answer further questions on the facility during Q&A, but we won't be providing much more granularity on the debt facility until after reaching financial close, expecting over the next few months. Now turning to the quarterly results. Production volumes increased 42% compared to the third quarter at 270,000 barrels of oil equivalent. In our oil business, we saw the impact of a full quarter's contribution from Growler-15, which continues to perform very strongly. In our gas business, we saw the WSGP Phase 2 wells continue to increase. Full year production of 840,000 barrels of oil equivalent was in line with guidance and a 12% increase on the prior year with the gain driven by gas and new wells successfully offsetting natural decline in the oil portfolio. Our revenue for the quarter was $26.5 million, up 89% on the prior quarter and driven by stronger volumes and price. This was the first quarter of recognizing WSGP gas sales as revenue for accounting purposes with 1.3 million recorded. Full year revenue was $70.3 million, up from $42.6 million in FY '17. During the year, we recognized an average realized price of AUD 95 per barrel compared to AUD 61 the prior year. Finally with CapEx. Due to increased work activity undertaken in the Surat Basin, capital expenditure was higher, totaling $23.1 million for the quarter. This included spend on long lead items in the Western Surat Gas Project compression facility as well as early works spend on Project Atlas. In the Cooper basin, we invested the final dollars in bringing Vanessa online, along with drilling in the Gemba and Marauder-2 wells. Overall, full year FY '18 capital expenditure was $80.1 million, in line with our guidance.With that, I'll now hand back to Ian.
Thanks, Gary. So as we reflect on financial year 2018, I'm very proud of what we've achieved. We've delivered against our strategy, realizing the near-term potential of the East Coast gas market and focusing our material -- from a material position on the Cooper Basin. Today, we announced a key catalyst in the delivery of a corporate and development debt facility to fund the development of our Surat Basin projects. With a clear pathway to development for these assets and a fully funded and agreed work program in the Cooper Basin western flank, 2019 is set to be a transformational year for Senex.So with that, thank you for listening. I'd like now to open the call to any questions for Gary and myself.
[Operator Instructions] Your first question comes from the line of Andrew Hodge from Macquarie.
The first question I just wanted to ask was, with bringing on the next third-party infrastructure person, when do you expect to also try and give an update for that?
Andrew, there's 2 logical dates for that. One is a full year results in about 3 weeks, and the second one is financial close. And clearly, we're reasonably progressed along this path, given that it was specifically carved out of the financing facility with ANZ.
And I guess sort of broadly, I mean, bringing on whoever the third-party person is, how much -- like does this facility essentially mean that you guys don't need any more money to be able to try and go ahead into WSGP and Atlas?
We can go full steam ahead as of now. So we've got a strong balance sheet already. And this RBL, so the reserve-based land, which is actually quite a flexible facility once the base case is agreed, allows us specifically designed for us to bring the gas projects online. So a major milestone, of course, is first gas in Atlas. So the whole facility is focused on both Western Surat Gas Project getting to a material production profile and also bringing Atlas online.
Okay. And regarding the -- the question I was asking around gas customers. So now that you kind of got this in place, how long do you kind of expect to be able to try and go through it before you can start talking about gas customers for Atlas? And also, can you give sort of a ballpark idea about the pricing that you sold to ENGIE for Pelican Point?
Yes, so let's -- on ENGIE first. I mean, clearly all these things are confidential, but it's market. It's very flexible considering it's a 1 well field. So we've got a bunch of flexibility built in and at the market price which we're very happy with. And look, you'll see it in our quarterly in the fullness of time. The second -- the first part of your question, I guess, around the Atlas marketing. I mean, to be fair, we've already commenced a lot of discussions, but -- when we bid for the block, but also since, and look, we are very happy with the position we have from a marketing point of view. It was important for us to have our field development plans sorted to have the reserves booked initially to get their financing in place. So those 3 major milestones are now done. We're on a pathway forward with our both state and federal approvals which we're expecting mid-2019. We've got the infrastructure announced and it's soon to be constructed by late 2019. So between now and then, we'll contract the gas. And look, with the market extremely strong, as you know, it's a domestic-focused block, and there is a lot of demand for domestic customers for good partners.
Looks like a great deal. Last thing I got was on the drilling program with Beach. Just I guess, given the success you guys have had so far, do you have any kind of like -- what sort of ways should we be kind of thinking about the program you guys have? And what can we see forward?
Yes, so look, we're hopeful. Obviously, it's 7 exploration wells starting this week, and we haven't done a material exploration program in a while. So that's 7 wells back to back broadly, but a mixture of through exploration and near field exploration are all on the western flank. So yes, we're really hopeful. If you look at the statistics, 2 out of 7 is pretty much bang on the stats, so upside from there would be 3 or 4. In the PDs, the chance of success of the wells is between 20% and 40% in broad terms, which are reasonably good quality western flank fields. And the development wells we're expecting 3 horizontal development wells in and around Growler, hopefully replicating Growler-15 which was an unmitigated success.
Your next question comes from the line of Mark Samter from MST Marquee.
A couple of questions, if I can. First of all, with the debt package, I'm not sure ANZ would lend me money much cheaper than 6%, which maybe says more about me than it does about you guys. But I mean, we saw some conventional project without naming too many names last year that probably struggled, you're thinking kind of offshore Victoria, that struggled to get full debt package around that. Can you maybe just share some of your insights why you think this project stacked up so well maybe against some of those conventional projects and probably what's evolved? I suspect none of us thought you'd get this cheap this time last year. So just kind of what evolved in the thinking around that?
Mark, and welcome from MST. So look, a couple of things, I guess. I mean, we've spent in the order of $80 million of equity in the Western Surat Gas Project proving it up, and it was a project that really needed to be proved up, frankly, because there's a lot of skepticism in the market. Obviously, we've got the asset for free, to remind people's memories. So -- and look, the reason of our performance is it's really good. We've had a bunch of operational issues which we've been very open about, but it's onwards and upwards from here. And the subsurface data and the work that we've done on the surface really came through, through the huge amount of work that we had to do around independent experts report and the like. So we're actually very comfortable with the project. And Project Atlas, given the analog data around, it's a bit of a no-brainer from a subsurface point of view. So from -- as not only a standalone asset, but as a portfolio, I mean, we're in extremely good shape. And that really came through with the due diligence, and it's a fully senior secured facility. So we're actually really pleased. Gary, do you want to add to that?
No, I don't want to talk about anyone else, but I think the fact that there's a lot of production around our facility certainly helped us around Project Atlas. And also, the good production and forecast out of Cooper Basin was also supportable for that loan base. So number of factors, but yes, I think just good confidence, good vote of confidence on the 2 development projects that we have.
And to add to that really quickly as well. The Roma field is performing really well these days, as you're probably seeing from Santos' results. They've had a lot of operational issues in the early years, and it's -- the subsurface, I mean, they're pumping $900 million in the field. It is a good quality field, and this is exactly the same field with our lease line in the middle of it.
And I guess the second question probably slightly follows on from that because they would have had to take a view on reserve progression at Atlas, and I know the contract you've signed with Jemena obviously has underpinnings over a lot more reserves and the current booking. Can you just talk us through the actual timeline of when we should expect to see the 2P reserve number move up in Atlas?
Yes, so look, I'm glad you asked the question because note that we're going to get more questions during the day. We booked 144 petajoules over the western 2/3 of the block, which is sort of the rough guidance we gave to the market also. The facility or the agreement that we had with Jemena is for 220 petajoules over 25 years. Now remembering one's raw gas production and one's sales gas reserves, the -- like-for-like is 144 versus about 200 petajoules. Now the analogs around the fields from both second-tier and top-tier are 60% to 65%, 70%, and we've given a bit of -- we've given a steer in our annual reserves released today that at 65%, we well and truly covered that. At 60%, we've covered that. So that's actually why we back sold to that 220 petajoules of production or 200 petajoules of sales gas in the Jemena contract. But to get to your question also, we will be drilling -- so we have environmental approvals to drill a number of wells prior to receiving federal approvals, and we're in the phase where we're finalizing our fuel development plan, and clearly, the financing package has a role to play in there because we've got to agree a banker's case. So finalizing our field development plan which takes into account early drilling and then obviously the development drilling in calendar '19. So certainly, at the end of FY '19 we would expect to have some results that would play into the conversion of additional reserves into not only additional 2P, but 1P, but we'd also see FY '20 drilling out fundamentally the entire block.
Your next question comes from the line of James Byrne from Citi.
Congratulations on the debt facility, that's great. Just wanted to pick up on what Mark was asking about the competitive cost of that debt. Have you had to use the Cooper Basin as collateral in that RBL facility? Or is it just the reserves from Queensland CSM that's the asset-backed portion of the loan?
Yes, so it's senior secured debt in Cooper is included in that.
Got it. All right. Great. And then just on Atlas 2P reserves where you've got that 65% recovery back to target, if you have the data to inform you of what that target of essentially coming up with that target, why haven't NSAI use that data? Is that just because they've used well spacing from the wells in the adjacent acreage, and therefore, they're just being more conservative because you haven't drilled out the entire extent of that block?
That's exactly right. So if you look at the map on Page 5, I think it is, of the -- of our reserves release, we've been excruciatingly detailed in this release today because we wanted to make sure the market was fully informed of what a high-quality reserves position we have, number one. And we've broken out our CSG fields by Glenora and Eos, which would be our first development area in the Western Surat, other and also Project Atlas. But if you look at the math of Project Atlas on Page 5, you'll see a lot of well data to the north, to the west and a little bit to the south, which follows exactly the 2P reserves profile booked in the block. And look at the end of the day, we don't need to push the reserves number this year because it will come next year and the year after, so it's a 25-year project. So we're pretty relaxed from that front. And NSAI, as you know, has a sharing agreement across all of the operators in the Surat which is why they're used pretty universally by both banks and the producers themselves that we fully expect that block to be covered in its entirety with 2P reserves in the next year or 2 and the recovery factors to increase to the nearby analogs, which is 50%, 60%, 70%.
Yes, got it. So just to clarify, that original gas in place number is across the extent of the block?
That's correct.
All right. Got it. And then just a third question on Cooper oil reserves which were essentially flat, net of production, we saw Beach upgrading quite significantly in its western flank position and the Growler horizontal well that you've drilled is clearly performing pretty well. So I was just wondering why you haven't also upgraded your reserves there in your Cooper position.
That's a good question because the blunt answer is, we recognize the economics and potential of the field use earlier. And I think Beach took a more conservative view in prior years, and now fundamentally catching up is probably the easiest way of describing it. So -- and that's not a slight against Beach at all, it's just everyone has their own view on reserves. Our view is that the reserves of the asset base of the business need to be fully accounted for. And in the Cooper Basin, where you got high-margin barrels, you've got a high degree of certainty around oil in place, and then, again, you're in the, well, what do we think recovery factor is going to be over time and that's how you develop an undeveloped reserve base. So I think we're becoming more into line now.
Yes, I guess the Beach reserve upgrades really had 2 main components. The first was slower decline in those more producing fields; and then, secondly, the success of the horizontal drilling, which have been extrapolated into future opportunities. So given the fact that, that Growler horizontal well has done so well, I mean, I just sort of thought that you would, therefore, assume that you'd be able to replicate that success which should be upside to what you'd previously assumed in your current [indiscernible].
Yes, so there's 2 parts to that, James. There's production and there's reserves. So from a reserves point of view, once your field is economic, it's economic, and then there's no sort of kick up, if you're going to do 1,000 barrels a day or 10,000 barrels a day, it's still the same amount of oil you're expecting to get out of the ground at a particular recovery factor. So our reserves -- our undeveloped reserves position was always a bit higher than Beach's because we always had the expectation that we will recover those reserves over time through both enhanced recovery, whether it be more floods or the like, or also different types of drilling, whether it be horizontal wells or the like. So I mean, what's happening now is, it is fulfilling our own expectations from years gone by.
[Operator Instructions] Your next question comes from the line of James Bullen from Canaccord.
Just a quick question. Is there any color you can provide around covenants for this facility?
Yes, there's normal covenants. And you think about it in 2 phases, there's a development phase and then there's an ongoing production or after-construction phase. So you've got the normal covenants around your debt to equities and your liquidity covers, and then basically, you've got a reserve base covenant that sits on top of that.
It's a pretty vanilla reserve base land in the development phase.
Yes. And is there any penalties to refinancing or closing the facility earlier if you wish to have more cash flow flexibility in the out years?
Yes, so there's 2 things about it. There is the ability to expand the facility for certain reasons, but there's also no penalty on early repayment and there certainly is the option of refinancing that at the right time.
Great. And just on WSGP, with the reserve upgrade there and the way that the pilot is performing, have you revised your view of the peak flow rates per well?
So there's a bunch of work still going on. So revised sort of depends on what your last data point was. So given we've delivered both Phase 1 and Phase 2, it's been a bit of a moving phase because we've had our own views, we've had third-party estimator views, we've had analog data from Roma next door because we have that data sharing agreement with GLNG, as you may recall. So look, I would say that probably there or thereabouts. When we come to financial close, we would resolve to provide quite a lot more detail to the market on how we see investment going forward and also our well performance and reservoir performance over time. Because I think that's the appropriate time to provide a bit more color around that. But look, suffice to say, the blunt statements I made on this call, reservoir performance is going very well. The both independent technical experts that we've had looked at that and also our reserve estimators, which are pretty conservative by definition with NSAI, they all -- the feedback is reservoir performance is good. So what we need to do now is go from a small sample size of 30 wells and actually develop the initial phase of the field to get to that million barrels a year equivalent or 16 terajoules a day, which is the basis for this reserve based lend.
Great. But just to be clear, I mean this is a reserve upgrade based on reservoir performance, not the use of different prices?
That's exactly right. It uses a GLNG contract of the economics. There's been no change in that.
We don't have any other questions as of the moment. Presenters, please continue.
Ladies and gentlemen, thank you very much for listening, and we look forward to talking again at our full year results, the 21st of August. Thank you, and good morning.
Ladies and gentlemen, that does conclude our call for today. Thank you for participating. You may all disconnect.