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Ladies and gentlemen, thank you for standing by, and welcome to Senex Energy Q2 FY '19 Quarterly Report. [Operator Instructions] I must advise you that this conference is being recorded today, 30th of January 2019. I would now like to hand the conference over to your first speaker today, Mr. Ian Davies. Thank you. Please go ahead.
Thank you, Divina, and good morning all. Welcome to Senex Energy's Quarterly Results Conference Call for the Second Quarter of FY '19. I'm Ian Davies, Managing Director and CEO. And with me today is our Chief Financial Officer, Gary Mallett.
Good morning, everyone.
We're looking forward to providing an overview of what was quite a successful quarter on many fronts. Our gas production growth and project milestones were key outcomes of this quarter. Progress made has reinforced our confidence in successfully achieving our project delivery objectives for 2019 as we establish Senex as an important gas supplier to the east coast market. The key highlights we'll talk about this morning include a 33% quarter-on-quarter increase in Roma North gas production; financial close of our $150 million debt facility; financial investment decisions and sanctioning of our Surat Basin gas development projects; satisfying all federal environmental requirements to Project Atlas; and encouraging flow test results from what may be a material commercial gas resource in our Gemba field in the Cooper Basin. I'll give you a brief overview of these activities and then hand over to Gary for his comments on the financial results, and then we'll move to Q&A as per usual. Turning firstly to production. We recorded total volumes of 276,000 barrels of oil equivalent, which is broadly in line with the prior quarter. As I mentioned happily, Roma North volumes increased 33% quarter-on-quarter to 77,000 barrels of oil equivalent and there are a number of pleasing elements to this. Firstly, we're seeing improved well performance underpinned by successful ongoing well optimization activities with well availability above 90% for the quarter. Our longer-term objective is to maintain an average online rate at or above 95% as our understanding of the field and optimal well design, et cetera, continues to evolve. As well as higher uptime, our well deliverability continues to improve and production rates continue to ramp up. During the quarter, peak daily rates reached 5.7 terajoules a day. Following quarter-end, we're seeing 6 TJs a day, exceeded at times, and so steadily ramping over time as promised. Roma North production continues -- growth continues to ramp up in line with our expectations but also are in line with field -- the field performance is in line with our type curve estimates. It's also worth noting that the ramp-up has been significantly quicker than that experienced at GLNG's Roma field to the south. And of course, that field is producing extremely well now after the reliability issues have been dealt with. In the Cooper Basin, we recently commenced production from 3 new oil wells. These are Breguet-1; Snatcher North-1 discoveries, which were brought online during the quarter; and the Growler-16 horizontal development well, brought online in January. We also successfully drilled the Growler-17 horizontal development well subsequent to quarter-end, with production expected imminently. Together, Growler-16 and 17 drilled partial horizontal lateral sections of 2.3 kilometers and intersected total net pay of almost 1 kilometer combined. Aggregate initial production for Breguet, Snatcher North and Growler-16 was more than 1,800 barrels of oil per day at gross. We'll see the full benefit of this new production as well as Growler-17 production coming online over the coming quarters. So with continued gas production ramp-up at Roma North and the material boost to come from new oil producers in the Cooper, the outlook for second half production is encouraging. Another key highlight for the quarter was financial close of our $150 million debt facility. We've spoken previously about the particulars of the facility, but it's worth noting and reiterating that security -- that securing this low-cost debt funding allowed us to take FID decisions for both Project Atlas and Roma North and sanction their work programs. And as we have announced in October last year, these projects will deliver gas processing facilities with initial production capacity of 48 terajoules a day, associated gathering networks and infrastructure and approximately 110 development wells initially. Successful execution of the projects will deliver gas production of 48 terajoules a day, which is equivalent to 3 million barrels of oil equivalent per annum, ramping up through FY '20 and FY '21 with, of course, expansion potential. So now turning to project execution. It was a very active quarter with a number of significant milestones achieved. Firstly, Project Atlas, our top-tier dedicated domestic gas tenure in the Surat Basin. It was a rewarding quarter for Senex on the regulatory front. Following completion of field studies and submission of all state and federal environmental approvals, we achieved confirmation from the federal government that Project Atlas has satisfied all requirements under the Environmental Protection and Biodiversity Conservation Act, quite a mouthful, more simply the EPBC Act. This is a key milestone for Project Atlas and a great outcome for Senex, the subject of a lot of work internally. It removes a key timing risk from our project execution schedule while we continue to progress the remaining Queensland government regulatory approvals, which we expect in mid-2019. Other progress of Project Atlas this quarter also included the start-up engagement with domestic gas customers as promised, with discussions progressing very, very well indeed. Preparations for construction at the gas processing facility and pipeline also progressed, with Jemena continuing detailed planning approval for the 40 terajoule a day gas processing facility and 60-kilometer pipeline connection to the Wallumbilla Hub. Jemena remains on track for commissioning of the facility by the end of 2019. At Roma North, construction of the 16 terajoule a day gas processing facility is underway. We're now nearing completion of civil works and laying of the associated 5-kilometer pipeline. Arrival of a major processing equipment including compressors is expected soon, with the facility remaining on track for commissioning by the end of the 2019 financial year.With regard to drilling execution at Project Atlas and Roma North, we're currently at a tender of a drilling rig and associated wellsite services. We certainly remain on track to drilling initial 15 wells in Project Atlas in Q4 FY '19, immediately followed by the next phase of Roma North drilling and the remaining Project Atlas wells. So it's going to be a big year. In the Cooper Basin, we were very pleased by the flow test at Gemba-1 exploration well. The well was drilled in late FY '18, and this quarter we successfully conducted a 7-stage hydraulic fracturing program and a subsequent 7-day flowback. This recorded a stabilized flow rate of 8 million standard cubic feet of gas per day, around 8 terajoules a day in total. Now 44 million standard cubic feet of gas were recovered during the test as well as 88 barrels of oil, which obviously improves economics as we produce. We now look forward to the extended production test this quarter. This will involve isolated flow tests across each of the intersected zones to understand the reservoir and to determine how to produce -- how to best produce from the field. If successful, the Gemba gas resource represents an exciting addition to our growing gas portfolio. Also in the Cooper Basin, there was much activity in the free-carried western flank drilling program with Beach Energy. The exploration component of the campaign has now concluded for this financial year and have delivered 2 commercial oil discoveries and valuable appraisal data for calibrating subsurface models. As I've mentioned, the program also comprised 2 successful horizontal wells in the fantastic Growler field. Our teams are now reviewing results for the term and locations and timing of future wells with the free carry program with Beach to be completed in FY '20. So with that, I'll now hand over to Gary to discuss our financial results.
Thanks, Ian, and good morning, again. I'll begin with sales volumes and revenue. We saw sales volumes of 264,000 barrels of oil equivalent track in line with production. Revenue, however, was down 33% to $17 million, in line with the Brent oil prices. Brent oil started the quarter at USD 83 per barrel and finished at USD 54, representing a 35% decline which flowed through to our revenue. During the second quarter, we executed oil swaps for over 810,000 barrels of oil from FY '19 to FY '21. These were executed at prices between AUD 98 per barrel in FY '19 and AUD 93 per barrel in FY '21. Fully hedged cash flows commenced from Q3 FY '19. This hedging was undertaken to protect cash flows and liquidity during the upcoming period of increased capital investment in the Surat Basin. Senex will continue to adopt a proactive approach to hedging. We reported gross capital expenditure of $39 million for the quarter, which includes activity associated with the free-carried Cooper Basin program. On a net-to-Senex basis, $26 million of capital expenditure was incurred, which reflected increasing activity in the Surat Basin relative to the prior quarter. For the second half of FY '19, we expect a further increase in capital expenditure as drilling in the Surat Basin commences together with the continuation of the gas processing facility. As Ian mentioned, we achieved financial close of our $150 million debt facility during the quarter and we drew down an initial $35 million upon close. Details of this low-cost, senior-secured, reserve-based lending facility can be found in our announcement of 29 October 2018. With this debt facility in place, our liquidity position remains robust and we are well placed to execute our gas development projects. At the end of the quarter, we had net cash reserves of $39 million after debt drawdowns, available funds under our debt facility, significant free cash generation from our operations and attractive hedging in place to protect cash flows. On that note, I'll hand back to Ian to conclude the formal part of the conference call.
Thanks, Gary. So in closing, another very strong quarter for Senex as we moved firmly into gas project execution with gas production continuing to increase. It's now an understatement to say that 2019 promises to be a watershed year for the company as we establish Senex as an important gas supplier to the east coast market.So with that, very happy now to move to questions. Thank you, Divina.
[Operator Instructions] Your first question comes from the line of Adrian Prendergast from Morgans Financial.
Very good quarter. Obviously, with North Roma ramping up nicely, so very good to see. Just a really quick question. Just on -- obviously the expand -- or initial drilling in Project Atlas and just what you're seeing out in the industry any changes in cost pressures or cost structures you're seeing as you move forward towards that first 15 wells.
Yes. Adrian, thanks. Look, there's a -- we're at the tender now, so the proof will be in the pudding when submissions are back. We have a very good understanding of rig availability and also a decent understanding of current costs. And the cost announcement -- sorry, the guidance that we put out around our total cost per well of AUD 1.4 million, hopefully less, have certainly taken into account expected or potential cost inflation in those areas. We're seeing -- and this is across the board, we are seeing some wage inflation come through the industry, which is actually a good thing because there was obviously 3 years or so of mass redundancies and 0 wage inflation. So that's actually a positive for the industry and for Senex if you need a healthy vibrant industry where everyone is making money. And also, we're seeing some pressure on steel, on kit, so you're seeing good utilization being taken up across the board. And obviously, day rates, et cetera, are compensating for those wage increase and utilizations. Ultimately, we're very comfortable with where we sit, but we're seeing the sector return to a bit of health, which is good.
Fantastic. And just one more quick question. Just as you said in the release, you're out there talking to new customers now or customers for the new gas. And is this very early on obviously, but is it shaping up the way you would expect? Or conditions again changed at all?
Yes. So obviously, with the oil price, LNG prices and net -- or net back prices track oil, Brent [indiscernible], whatever -- however you want to use it; and the ACCC obviously, publishing markets provides a pretty transparent market at both Wallumbilla and Moomba. And also you've got the short-term market operating now, albeit low volumes, but it's still another market. So the transparency is actually there. Prices are still strong and will remain strong because the fundamentals of gas supply aren't changing. I won't sort of go into Victoria and New South Wales and supply pressures and the like. You've heard me rant a lot about that before and nothing's changed there. But let me say, and we've said it in the quarterly but also in my preamble to this Q&A, we have commenced detailed discussions with customers. There are many customers requiring gas from the start of 2020 onwards, and we've had some great discussions. I won't give a blow-by-blow on commercial discussions, albeit to say it's coming in line with expectations, and both volumes materially exceed what we are capable of producing from our acreage and prices are what you would expect.
Your next question comes from the line of Andrew Hodge from Macquarie.
Just 2 quick questions. One was if I compare your realized oil price for the quarter of $78 a barrel, it's a bit lower if I look at it by comparison to Cooper. And I just wanted to check to see -- you've got a note there about accounting accrual. Is that just the costs that's paid in first or you guys haven't loaded a boat? And then I've got a second question after.
So with our revenue, firstly, you'll see that we did take out a hedging program, but that will kick in really from Q3. There was a small amount applied in Q2, but that will start kicking in from Q3. And that covers around about 60% of our oil-linked production, so that will give you a guide going forward. Can't compare it to Cooper, but a large amount of our revenue after production takes some time before it actually gets priced when it's shipped out of Port Bonython. So you tend to find that a big chunk of our quarter's revenue is basically priced off the borne price at the end of December. And you'll know that at 31 December, we're sitting at around $54 here, so that takes up quite a large chunk of our revenue recognition period. So there is then unders and overs, and there will be unders and overs going forward as well. And you'll notice that the price has risen a little since 31st of December, so that does include accruals as well, which swings and have roundabouts and balance out over time.
Okay. So I guess just that the gap, this particular -- like normally they track relatively closely. Just it looks like that the gap this quarter had gotten much bigger, and so that's why I just wanted to check, like it's almost $15 a barrel.
It could be timing of sales, but I can't comment on Cooper.
Okay. And then the second question as well was just in terms of the CapEx spend and the profile for you guys over the course of this year. The next drawdown on the debt as part of the drilling program, I just wanted to see if we can get a sense from you guys about the -- you guys have kind of released on timing previously about when you guys expected the spend. Just wanted to check to see like how you guys are kind of thinking about that in terms of your position of cash at the moment.
Yes, so it's Ian here. The statements we put out previously around drawing down over the next 18 months or so and then paying back over the following 2, 2.5 years post that haven't changed, the exact timing of drawdown per quarter, per half, et cetera. Obviously, we're at the tender for a very material portion of cash spend, which is the drilling rig and associated wellsite services. So we'll have a far better idea of that timing and quantum and how it draws down because there's actually quite a few moving parts in that. And we expect that to be -- the half year will certainly have more information. It's probably a better time to give an update there. But we're certainly on track with the previous comments that we've given, albeit there'll be movements from quarter-to-quarter. But we expect the vast majority of spend this calendar year and a very, very large year in terms of execution drilling, if not all, most of the wells and all the infrastructure put in place also for gas sales -- to actual gas sales from the end of FY '19 for Roma North, where the construction facility -- the compression facility we finished; and the end of calendar '19 for Atlas, where Jemena's construction of the compression facility we finished.
Okay. And if I can ask just one more question, Ian, just with Gemba. Like -- obviously like the results there are looking pretty good. And I just wanted to -- do you have a sense for even potentially what like the resource size could be there?
Yes. Look, it's a bit of a range and this is why we're doing the EPT, the extended production test, per zone because the downside of a great result like 7 zones coming in producing 8 million scuffs a day when only 50% of the well is unloaded from frac fluid is you're not 100% sure where it's coming from, you're not 100% sure how big it is per zone. So you got to test every -- each individual zone, which we're doing imminently. So over the next -- yes, it's notionally 10 days a zone. But if you get more -- if you get the information you needed, it'll be less. So in the next couple of months, we'll run all that information out and we'll be in a much better position to understand field size and what the commercialization of that field is should it come in the way we expect.
Your next question comes from the line of James Bullen from Canaccord.
Congrats on that ramp-up, and WSGP certainly exceeded my numbers. Just in the Cooper, I was wondering how the Growler-16 horizontal result compared with your expectations.
Thanks for that. Look, Growler is proving to be -- it just surprises to the upside. It continues -- it's one of these fields that just gets better and better. And you can see this is the third -- we have had 3 horizontal wells now, first of which produced extremely well; and the second of which, it came in above our P50 but within the range so a very good result, and that's the one you're referring to. And Growler-17 is coming online imminently, so we're expecting a good result there also, albeit probably with slightly less volumes than Growler-16 because of the placement of the actual well itself. And the execution from the team has been flawless. We've landed them exactly where we wanted to and really honing our skills in, in this development part of the field.
Great. Around the exploration program, obviously having more failures during the quarter. What is that doing and is it changing anything within the exploration program at all? Or is it more...
Yes. So we're about -- we have 33% success rate, which historically is actually where things sit. So it's not bad from that point of view. Of course, we would have preferred more, but I think we said right at the start of the program, if we can get 2 successes, then that's hitting the basin average. And they are exploration wells, as you can tell from the 4 that didn't -- or 3 of the 4 that we P&A-ed didn't hit hydrocarbons. One did, but it just wasn't commercial. It was touch and go, but it wasn't commercial, so we P&A-ed it. So does it give us more information? Of course. You'd expect during the exploration that every well is a good well. But obviously, the commerciality of this area to the later down different parts, what we have seen is around our Snatcher field, the northern extension of that field looks excellent. And we'll be doing some more work there also. So Snatcher North has been an unmitigated success and looks to be quite a material extension. So look, things are progressing well, albeit hopeful, and we would have preferred 1 or 2 more exploration wells to come in, but that's the way the cookie crumbles.
[Operator Instructions] I would now like to hand the conference back to today's presenters. Please continue.
Thanks, Divina. Ladies and gentlemen, thank you for your interest in Senex, and good morning.
Ladies and gentlemen, that does conclude our conference for today. Thank you for participating. You may all disconnect.