Beach Energy Limited (BPT.AX) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by. And welcome to Beach Energy Limited FY '20 Half Year Results Conference Call. [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 today, Mr. Matt Kay. Thank you. Sir, please go ahead.

Hello and welcome to the FY '20 half year results presentation for Beach. My name's Matt Kay. I'm the Managing Director and Chief Executive Officer, as you know. Joining me on the call today is Morné Engelbrecht, our Chief Financial Officer. We also have a number of executives in the room who are able to answer questions later on. So the format of today's presentation is we'll run you through the results presentation. And at the end, we'll open up the lines to Q&A. So let's move to the presentation. Slide 2 includes our disclaimer, which also includes oil price and ForEx assumptions used in our FY '20 guidance as well as reserves disclosure. If you move to Slide 3. Beach is more than halfway through its most ambitious and exciting year of organic growth in the company's history. In August last year, we outlined our biggest ever drilling program, which would see Beach participate in wells in the Perth Basin, Otway Basin and, of course, the Cooper Basin. Since that time, we've also added the Great South Basin in New Zealand by the farm-in of the large Tawhaki prospect, which is currently drilling. Our aim, as always, is to unlock the value of our assets and increase shareholder value. We do this by strategic and targeted investments in basins with a proven track record and excellent growth potential. To ensure our investment program presents a value proposition for our shareholders, we maintain a razor-sharp focus on execution. I'm pleased to report to you today the execution of our record investment program is going extremely well. We completed 105 wells in the first half with an 83% success rate. Western Flank oil output has ramped up as forecast, and we're now producing above 22,000 barrels of oil per day from our operated assets. That success means we need to invest more in our infrastructure, and we'll talk about that a little later. The Victorian Otway Basin, as you know, is a key growth asset for Beach. And we've kicked off the journey: the first of 11 planned wells to refill the Otway Gas Plant. Black Watch-1 is currently drilling, and we should hit total depth in about 3 weeks. The Ocean Onyx semisubmersible rig is also scheduled to arrive next month after completing refurbishment activities, and it will begin by drilling the Artisan-1 exploration well. On the exploration and appraisal front, we announced a number of key successes in the first half, including field extensions in the prolific Bauer oil field; an overall Cooper Basin exploration and appraisal success rate of 66%; a material gas discovery at Beharra Springs Deep in the Perth Basin, in the same King -- Kingia Formation at the nearby Waitsia gas field; and a further gas discovery in our South Australian Otway acreage at Dombey-1. We are strongly encouraged by these results, and we've moved quickly to progress plans for further exploration and appraisal in the Perth Basin and the SA Otway, including contracting the Easternwell 106 rig. In short, drilling success is breeding more opportunities to reinvest our capital. On the operations front, I'm very pleased to say our operations team had done a stellar job in the first half, with facility reliability averaging above 98% across all of our assets. The standout for me in the first half is the successful shutdown of our Kupe asset in New Zealand. That means a major shutdown that was performed on time, on budget with no recordable safety incidents. That's the first major shutdown performed by Beach since the Lattice acquisition. Our facility reliability helped Beach achieve first half production of 13 million barrels of oil equivalent, with oil production on track to hit our initial guidance range of 8.7 million to 9.2 million barrels for the year. I won't steal too much of Morné's thunder, but I'm pleased to report we generated underlying EBITDA of $622 million in the first half and underlying net profit after-tax of $274 million. The 2% decline in underlying NPAT is an excellent result given it includes the impact of the sale of 40% stake in the Otway Basin. On a pro forma basis, our first half underlying NPAT was 9% higher than the prior corresponding period. Our interim dividend of $0.01 per share is unchanged from the prior period as we continue to prioritize total shareholder returns through value-accretive investment. Let's go to Slide 4, which outlines our safety performance. As we've said many times, safety is always our primary focus within Beach, and it drives our behaviors at all levels across the business. From a safety performance perspective, there was an increase in minor injuries, such as trips and sprains, reported in the first half of FY '20. As a result, a comprehensive review of common causal factors has been completed, and appropriate actions have been implemented. We continue to work closely with our workforce and our contractors to ensure all activities are completed safely. We've had another very good half year from an environmental performance and process safety perspective with only minor loss of containment events being recorded. Total crude spilled is lower than last year and is comprised of a low number of minor spills. Let's go to Slide 5. Our operational excellence program continues to deliver results as is evident in our field operating costs, which had continued to trend downwards in the first half of FY '20 to now reach $9.10 per BOE. As I mentioned earlier, the Kupe shutdown was completed on time, on budget and with no HSE incidents. That's an excellent outcome by the team. And importantly, facility reliability returned to pre-shutdown levels soon after restart. Our facilities achieved an average reliability of over 98% in the first half, and we're targeting to maintain or increase our reliability levels over the remainder of FY '20. Our operations team continued to work on optimizing our activities to minimize production interruptions. The past few months, our Victorian operations team completed the engineering and regulatory work required to shift some of our Otway Gas Plant shutdown activities to later in the calendar year. That nets an overall reduction of 5 to 6 days and saves around $4 million. As you know, we have a target of $30 million reduction in direct controllable operating costs by the end of FY '20. And we're tracking really well, reaching $28 million of sustainable annual cost savings by the end of the first half. On Slide 6, before I hand over to Morné, I wanted to touch on our East Coast Gas portfolio. This is an area, as you know, with considerable debate amongst investors and analysts and, in particular, the subject of the recent reduction in spot prices and how that may impact Beach. I won't be able to answer all your questions on this subject because of confidentiality clauses under our gas contracts. However, what I can say is we, like everyone else, have seen an increase in the availability of a low-priced spot gas over the past 6 months, coinciding with the decline in spot LNG prices. Most of this gas, of course, is available for sale in Queensland. So movement of the gas to southern markets that Beach operates requires transportation through the pipeline network. So this begs the question of how much cash Beach sells into that spot gas market. And the answer is very little. Almost all of Beach's gas is contracted under multiyear gas sales agreements that have no pricing linkage to the spot market. In the first half of FY '20, less than 1% of Beach's East Coast Gas sales were sold into the spot. Over the remainder of FY '20 and through FY '21, we expect spot sales to remain below 3% of our East Coast portfolio volumes. We've contracted additional volumes in recent months, including our equity share of BassGas volumes over calendar 2020 and 2021 and 94% of Western Flank volumes over the same period. As you know, we have a large number of gas sales agreements with Origin Energy associated with the assets we acquired as part of the Lattice acquisition more than 2 years ago. Some of these contracts have repricing clauses, and the first of these, associated with Victorian Otway, is up for repricing from 1 July 2020. The repricing process with Origin in relation to this contract has now commenced. As most of you would know, generically, pricing events and repricing events in Australian domestic gas contracts refer broadly to similar contracts in the same market. So I won't comment on individual contracts we have other than to state the obvious: they are typical Australian domestic gas contracts. As a reminder of the process, if both parties cannot agree on an outcome, then it moves to arbitration with the final price updated, in this case, to 1 July 2020, if the outcome occurs after that date. I will now hand over to Morné to run through our financial results in some more detail.

Thanks, Matt. Good morning, everybody, and thank you for joining us today. As Matt noted in his summary, we are very pleased with our financial performance in the first half of FY '20, taking into account we sold a 40% stake in the Victorian Otway Basin in late FY '19. In the first half of FY '20, Beach reported $900 million of sales revenue from sales volume of 13.4 million barrels of oil equivalent, which is 3% higher on a pro forma basis if we adjust for the Otway sale. Our ongoing focus on operating margins saw Beach report first half underlying EBITDA of $622 million and underlying NPAT of $274 million. First half EBITDA was positively impacted by approximately $25 million relating to the unwind of the Lattice GSA liabilities, and we expect a similar contribution in the second half. This is a material step-down from the prior corresponding period where the unwind of the GSA liabilities contributed almost $90 million to EBITDA. Operating cash inflows of $351 million was a strong outcome, considering it included cash tax payments of $238 million. Turning to Slide 9. This is a summary of the first half financial highlights compared with the first half of FY '19. The key movements between the 2 periods was driven by the sale of 40% interest in Victorian Otway Basin assets partly offset by a 4% increase in realized oil prices and a 6% increase in realized gas and ethane prices. As Matt mentioned in his introduction, first half underlying NPAT was up 9% on a pro forma basis. Our balance sheet remains in a very robust position with reported net cash position of $60 million at the end of the first half despite high investing activity and a material cash tax payment. Furthermore, the Board has approved the payment of an interim dividend of $0.01 per share fully franked. Turning to Slide 10. This is a bridge from first half FY '19 underlying NPAT of $279 million to first half FY '20 underlying NPAT of $274 million. Although NPAT was broadly unchanged, there were a number of key differences between the periods. Profits were impacted by the Otway sale, higher tolls and royalties associated with our Cooper Basin production and resulting higher tax. This was offset by lower net financing cost, ancillary payment of $0.5 billion of debt and lower depreciation. I also wanted to highlight the financial impact from our adoption of AASB 16 from 1 July 2019, which cover how leases are treated in our financial statements. In a nutshell, the new standard are an accounting change only with no cash flow impact. Lease payments, which will be -- mainly relate to the leasing of drill rigs, offices and helicopters, are shifted from operating expenses to depreciation and interest expense. Furthermore, the balance sheet is grossed up with the recognition of a lease asset and liability of around $100 million. There's also an associated positive EBITDA impact of $20 million and broadly offsetting the increase in DD&A of $20 million. Further information relating to the impact of AASB 16 on our financials can be found on Slide 37 of this presentation. Turning to Slide 11. This shows the movement in our net cash position in the first half of FY '20. Operating cash flow, excluding tax, was the biggest positive contributor in the first half of FY '20 at $589 million. The biggest outflows related to our expanded investment program of $440 million and cash tax payments of $238 million. The cash tax payment in the first half represents the finalization of FY '19 tax payments as well as provisional payments for the first half of FY '20 for both Australia and New Zealand. We closed the half year with $95 million in cash, net cash of $60 million and total liquidity of $510 million. To summarize then on Slide 12. Beach's balance sheet remains in a very strong position with $60 million net cash and access to over $500 million in liquidity. We believe a strong balance sheet is important for the company as we execute on our growth strategy. We believe this to ensure we can weather periods of heightened oil price volatility as challenges such as the coronavirus add further uncertainty to global economic growth. Our net cash position, combined with our gas business, provides Beach with a natural hedge against this volatility. As we've said before, FY '20 gas revenues will cover all of our forecast operating cost, and we expect gas revenues will increase in the coming years as we target higher production and benefits from increased exposure to market prices. At Beach, we pride ourselves on a low-cost operator model. And our operational excellence program continues to deliver outstanding results with facility reliability above 98%, and our team continue to optimize our work programs to maximize facility uptime and reduce costs. Beach is a growth company, and our priority for capital allocation remains growing total shareholder returns via value-accretive growth investments. We are undertaking significant organic reinvestment this year in high-returning projects across our portfolio, and we continue to screen new opportunities that meet our strict investment criteria. I would now like to hand back to Matt to run through guidance and the assets. Thanks, Matt.

Thanks, Morné. Before we update you on our growth projects, I want to run through our updated FY '20 guidance, beginning with the summary on Slide 14. On the production front, we've narrowed production guidance to 27 million to 28 million barrels of oil equivalent and increased capital expenditure guidance to $875 million to $950 million. I'll speak to both of these in more detail shortly. Underlying EBITDA guidance has been narrowed to $1.275 billion to $1.35 billion, partly impacted by the narrowing of production guidance but also impacted by a sharp reduction in Brent oil price assumptions for the second half of FY '20. Underlying EBITDA guidance is positively impacted by the unwinding of liabilities associated with our gas sales agreements to the tune of $50 million, unchanged from prior guidance. DD&A guidance has also been narrowed to $17 to $17.50 per BOE. Both EBITDA and DD&A are also impacted by the application of AASB 16 accounting standards. Let's move to Slide 15. To make things easy for investors and those on the call, we have provided a bridge from first half to second half production. We forecast an increase in the second half production relative to the first driven by a number of factors. These include: higher sustained output from our Western Flank oil assets; contribution from our growth investments outside of the Cooper Basin; a reduced impact from planned maintenance, that is, we don't have a major shutdown in the second half; and a new gas contract with Alinta Energy at BassGas. Overall, we're extremely pleased with the progress across our asset base. I have no doubt the natural question on your minds is why we're no longer expecting to hit the top end of our prior guidance. And that can really be answered for 2 reasons. One, customer demand. As is standard in many gas contracts, our customers have a degree of flexibility in any year in terms of the total volume of gas they can nominate. After a very strong year for gas demand in FY '19, customer demand has been lower in FY '20 largely driven by the availability of lower-priced gas primarily out of Queensland. We expect our customers will continue to utilize contract flexibility as spot gas prices move around, but our contracts are underpinned by take-or-pay obligations that ensure most of our gas available for sale is sold every year. Secondly, Black Watch timing. The same rig that is drilling the Black Watch development well in Victoria was used to drill the Haselgrove-4 and Dombey-1 wells. The duration of those wells was longer than anticipated. We had to deal with strong winds with the rig when we arrived in Victoria, and we elected to undertake some rig maintenance, resulting in a rig spudding Black Watch around 2 months later than originally anticipated. And fortunately, that means that Black Watch well following maintenance has actually performed well. So the timing of first gas from Black Watch has moved from what we had expected in March 2020 quarter to now being the June quarter. We move to Slide 16. I'm pleased to report that the Beach Energy Board has approved a further increase in investment to support and accelerate our growth activities. As I mentioned earlier, drilling success breeds more opportunities, and that creates the need to reinvest in our business. And these include: an increase in Western Flank infrastructure investment following the success of the recent development and appraisal drilling activities; contracting the Easternwell 106 rig to drill 2 additional Haselgrove appraisal wells following our success at Dombey; long lead items associated with the planned Perth Basin drilling campaign in FY '21, following the success of Beharra Springs Deep; potentially significant Tawhaki exploration well currently drilling in New Zealand; and the higher spend [ well at ] Cooper Basin joint venture primarily to support the success of higher Western Flank liquids oil aimed through Port Bonython; and as mentioned a moment ago, the duration of the Haselgrove-4 and Dombey-1 wells in the SA Otway is longer than initially forecast, resulting in a minor cost overrun. Overall, we now expect to invest between $875 million and $950 million in FY '20. Almost 84% of this spend is directed at growth investment, and more than $500 million is directed towards bringing new gas supplies to the East Coast gas market. Let's turn to Slide 17. The key focus for Beach in the first half of this year is to continue our appraisal of the Western Flank, increase oil output through the application of horizontal drilling technology and remove infrastructure bottlenecks. In addition, we've been preparing for further exploration drilling. As we have reported in our quarterlies, our development and appraisal drilling program has once again delivered some outstanding wells. On the production front, first half Western Flank oil output increased by 44% on the prior period to reach 3.4 million barrels. We set the bar high internally to reach this level of production, and the team has delivered. The chart on the bottom right of the slide shows how we've doubled oil production from our operated permits over the past 18 months, and we're now in excess of 22,000 barrels a day. Overall, we drilled 46 wells at a 72% success rate. We're not concerned by the slightly reduced success rate here as we made a deliberate decision to get more aggressive with our step-out appraisal wells to find the field limits. This means we can now move to harvest mode on our fields more rapidly rather than having to invest more in rounds of appraisal drilling. Our appraisal campaign has identified new development well locations, meaning we can move to optimize oil extraction from our fields. On Slide 18, I know we talk a lot about Bauer, and the field commands our attention. It just continues to deliver. In the first half of FY '20, we completed the second round of appraisal drilling. The map on the left is of the top McKinlay structure and the field limit before and after the most recent appraisal drilling. What this shows is an extension of the field limit in the northern and southern parts of the field. So what does this mean? It means there is more structure with oil potential that needs to be drained. It also means that the structural extent of the Bauer field is still not fully known, and that's a good problem to have. So we need a third phase of appraisal drilling to further understand the structural extent of the Bauer field. We're planning for this in the third phase in early FY '21. In the first half of FY '20, we drilled 7 horizontal wells in the Bauer field. We've discussed the benefits of horizontal wells over vertical wells before, and we've had some standout results to date. One well I want to point out is the Bauer-39 well labeled on the map. This well was drilled from west to east and continued drilling while it remained in reservoir. In other words, the horizontal development well also had an appraisal component to it. It's fair to say the lateral section was drilled much further than we had expected, drilling over 1,500 meters of McKinlay reservoir with 90% pay, lifting the southeast portion of the field. The well has been on free flow, but we anticipate a 30-day initial production rate of over 2,000 barrels of oil a day on pump when it's converted in coming weeks. Let's go to Slide 19. This slide outlines our planned focus areas for the remainder of FY '20. One the 2 rigs we have operating in the Western Flank will be dedicated to exploration and appraisal drilling, including 2 exploration wells, Sellicks South and Glenelg North, towards the end of the financial year. It's good to be back drilling Western Flank oil exploration wells, and we expect to drill a number of additional prospects in FY '21 and beyond. Our other rigs will be dedicated to development drilling to maximize our oil production from ex PEL 91 and 92 as long as possible. This will see 10 Bauer lateral wells drilled in the second half. As we outlined earlier, to support our higher fluid volumes, we'll invest a further $30 million into more artificial lift and surface infrastructure. Let's turn to Slide 20, which outlines our Western Flank gas business. Operationally, we've had a very solid first half with production up 8% on the prior corresponding period. As you know, we produce very liquids-rich gas from our Western Flank fields. So we remain focused on optimizing liquids production through the Middleton gas processing facility. In fact, our average liquids content is 50 barrels a million per standard cf from the Lowry wells, and we've tied in during the first half of FY '20. We have a number of development and appraisal wells we can drill in ex PEL 106 as well as 5 planned exploration wells in ex PEL 107. Our aim is to keep the Middleton facility full for longer while optimizing liquids production and evaluate the potential expansion, subject to exploration and appraisal results. Let's go to Slide 21. The Cooper Basin joint venture has had a very strong year with the drill bit, with Beach participating in 53 wells at a 92% success rate. The joint venture enjoyed some really encouraging exploration success in Southwest Queensland in the first half. A recent well, Leghorn-1, recently came online at 12 million standard cubic feet of gas per day on a 30% [ charge ]. As we've mentioned in our guidance section, operator Santos has outlined plans to increase maintenance costs, which is largely directed at Port Bonython, given the high liquids sales we have out of the Cooper, particularly from the Western Flank. We're a big believer in the oil potential in this joint venture acreage, and we're pleased to say that the venture is planning to drill up to 29 oil wells in the second half of FY '20. Slide 22. Over in the west, it's been a very exciting and busy first half of the year for Beach. At Waitsia, we reached FID, as you know, for Stage 1 expansion, which will increase output from 10 TJs a day to 20 TJs a day when it's completed in early FY '21. As a reminder, it also means we'll be fully connected to the Dampier to Bunbury pipeline from early FY '21. We know that you've been very patient waiting for news on Waitsia Stage 2. We're also obviously aware there's been a lot of speculation in the press surrounding potential commercialized outcomes for Waitsia. And I do risk disappointing you today when I say that I'm not going to be discussing commercialization plans until we have firm agreements in place with the relevant counterparties. However, I will trot out the old line again: you only get to sell the gas once. And we are being patient, ensuring that we maximize value for our shareholders. And I'll say again, all options are on the table. As commercialization discussions continue, we haven't been sitting still with fleet activities and the EPC tender process now complete. All this is predicated on the joint venture led by our operator Mitsui reaching FID. We continue to target FID on Stage 2 by the end of FY '20. Let's go to Slide 23. You probably know by now that Kingia Formation is turning out to be a very prolific play in the Perth Basin. To date, there have been 3 valid tests of the Kingia Formation in the basin running at a 100% success rate. In the first half of FY '20, we drilled the Beharra Springs Deep exploration well, which flow-tested at up to 46 million standard cubic feet of gas per day over a 225-minute interval on a tubing constrained test. To put that in context, the reservoir potential is similar to that, that we've seen at Waitsia-3 and Waitsia-4, which flowed at higher rates on test but with a larger-diameter tubing. As you heard earlier, we've moved quickly to secure a rig to drill additional follow-up exploration and appraisal wells subject to JV approval. We commenced the acquisition of the Trieste 3D seismic survey, which is designed to high-grade some exploration targets for future drilling. We plan to have interpretations ready in the first half of FY '21. The joint venture is considering further seismic acquisition in the future to ensure most of our acreage is covered by high-quality 3D. Slide 24, moving back to the east. We've talked about Black Watch where drilling is underway, and we've already reached the 5,500-meter mark in the planned total measured depth of 7,200 meters. The rig drilling Black Watch will move to the enterprise location for enterprise exploration well after Black Watch is complete, and drilling should be underway in the June 2020 quarter. The Ocean Onyx semisub is scheduled to arrive in Victoria in March for its 9-well campaign. We will begin with the Artisan exploration well, which will be drilled ahead of our Geographe and Thylacine development wells. As we outlined at our site visit in September last year, these are the first wells to be drilled in our Victorian acreage for more than 5 years. Our goal is to refill the Otway Gas Plant to its full capacity with the lowest unit technical cost gas and keep it full for as long as possible. So the journey is now well and truly underway. On Slide 25, we summarize the results from the Dombey-1 well in the South Australian Otway Basin. More work needs to be done to determine the field size and commerciality, so we're considering a 3D seismic over the area. As we touched on earlier, we've secured a rig to return to the Haselgrove field shortly to complete testing on the Haselgrove-4 well and drill a further appraisal well. I'm very pleased to announce that the new 10-terajoule a day Katnook gas plant is now officially up and running, its first gas sales achieved from the facility this week. The gas processing facility was partly funded by a federal GAP grant and adds a new source of gas supply to the local community. If you jump to Slide 26, we touch on our progress in the Bass Basin with a recent wire line program, adding around 19 million standard cubic feet of gas per day. Meanwhile, progress continues on the Trefoil concept select, and planning is underway to acquire 3D seismic over the nearby gas discoveries. On Slide 27, another really good 6 months operationally in New Zealand, with the highlight, as I've said a number of times, being the Kupe shutdown and the subsequent fast ramp-up to pre-shutdown levels thereafter. The joint venture has approved the reperforation opportunity, which, if successful, should increase output ahead of the completion of the compression project currently underway. And last but not least, on Slide 28 and 29, let me touch on our frontier exploration program. As we announced in December, Beach farmed in to the high-impact Tawhaki exploration well in the Great South Basin in New Zealand. For approximately $25 million investment, Beach has a 30% interest in the well, which is targeting a 470-square kilometer undrilled exploration prospect. Drilling commenced in January, and we anticipate a result before the end of the month. In around 12 months' time, we expect to be back in New Zealand drilling the Wherry prospects. Beach is operator, and planning is going well. On Slide 29, you see the Ironbark prospect, which is on track to commence drilling by operator BP towards the end of calendar 2020. This very large, undrilled structure sits out in the back of gas fields supplying the Northwest Shelf that targets the same reservoirs as those in production at Gorgon. So within 18 months, Beach is participating in 3 high-impact exploration wells. If you look at Slide 30, you will see a summary of our current planned rig activity over the next 18 months, showing an increasing level of rig activity outside of the Cooper Basin. In short, it's an exciting time to be at Beach. Slide 31. It shows our updated well count that we expect to complete in FY '20, which is largely unchanged from our prior guidance. All up, we expect to participate in around 191 wells this year, including 9 outside of the Cooper. So you've seen a lot of slides. Let's close out on Slide 32, today's key takeaways. The 8 messages I want to leave you with are: one, the business is in excellent shape, and we're executing very well on our growth program; two, from an operational perspective, we're operating our assets at target reliability levels and completing our major shutdown activities, such as Kupe, on time, on budget and safely; three, we had a very busy 6 months with the drill bit, completing 105 wells at an 83% success rate; four, we've had success on the exploration and appraisal front at Bauer, Beharra Springs Deep and Dombey, and we're moving quickly to follow up on all 3 results; five, we forecast higher production levels in the second half of FY '20 as we start to see contribution from our growth activities in our asset base; six, we're in for a very busy 12 months with the drill bit as we move to drill important wells in Victoria, South Australia, Western Australia and New Zealand; seven, Waitsia Stage 2 has made good progress, and we continue to target a final investment decision by the end of this financial year; eight, a strong balance sheet position combined with stable cash flows from our gas business give us confidence to increase investment to support and accelerate our growth. So that marks the end of today's presentation, and I'd like to open up the lines now for Q&A.

[Operator Instructions] Your first question today comes from the line of James Byrne from Citi.

My first question is around the Western Flank infrastructure investment. I think the market and certainly us at Citi attributed volume growth with this successful appraisal drilling but perhaps have been a bit blindsided by the associated step-up in CapEx to handle the additional fluids. The IRRs that have been quoted to the market in the past were very high, and I'm wondering whether they, in fact, included that CapEx or not. And I also wondered about whether -- your message is, effectively to the market, of strong free cash flow generation in future years. So why did you choose to not disclose to the market the price tag associated with a success like this? And can I perhaps afford you the opportunity now to disclose any further CapEx increases associated with similar successes in the near future?

Yes. Sure. And I'm happy to answer the question. Look, I think the answer here is we've had a very successful period on the Western Flank, and it does continue to surprise us on the upside. I think if you look at the chart that we showed where we've literally doubled production in the Western Flank for the last 18 months, that's a really strong outcome for us. What that naturally drives, though, is further investment both from a subsurface perspective and a surface perspective to maintain that production and, obviously, evacuate it out to market. So yes, there is more CapEx than we had initially expected. That's part of the fact that we're actually getting better results as well than we initially expected. So it's success breeding more CapEx, if you like. In terms of the rates of return, the rates of return are so high here when we're talking in the hundreds of percent that, that additional $30 million of capital really doesn't make a dent in it whatsoever, frankly. So these are still incredibly high-returning assets. And the answer is they're really easy investment decisions for us because they are high returning, and it is growing the business in a way that we couldn't find anywhere else in the world, frankly.

Got it. All right. Look, perhaps I'm nitpicking here, but I note the drilling costs and schedule overruns in Victoria and the associated Black Watch delay. I can say they're small in dollar terms in the context of the overall CapEx budget. But nonetheless, I would have thought they were relatively straightforward wells to have drilled. My question here is just trying to understand from you what controls you have in place to ensure that the organizational capacity exists to execute on what's effectively record CapEx program and particularly in the context of the upcoming offshore drilling. Do you think that investors should be quite comfortable with your ability to execute?

Yes. Good question. I think investors should be very comfortable. We have said and we explained, I think, in some detail with our site visit to the Otway that we now have all the seats full in terms of the capability and capacity that we need to execute our capital program. And investors who attended that session got a chance to meet a number of those individuals. So we're very comfortable with the team. But the issues around the drilling cost overruns, obviously, we had success at Dombey, which creates an extended period for us. When we took the rig across to Victoria, we had very -- a very high wind period. So we lost just over a week in terms of our wins. We've also had sidetracks on those wells that we've been performing in the South Australia Otway and Dombey as well. So that extends the period of time that we were drilling. And I would say, obviously, with Black Watch, that is a very large well. That's a 7,000-meter well. So what we wanted to make sure was that rig was absolutely ready from a maintenance perspective to conduct that. It's probably a little bit more maintenance than we'd expected, but we're pleased we've done it because since that rig has been drilling, it's performed very well.

Got it. Okay. Last question for me. Just in terms of the gas in Victoria, let's suppose that volumes disappoint or you didn't have success with the drill bit at Enterprise or Artisan. I was hoping you could help us understand at what point your revenues aren't going to cover the higher fixed costs there at your infrastructure. I don't necessarily expect you to indulge me in what your provisions assume in terms of abandonment timing but just helping us understand the risk there that if there was disappointment, at what point does it no longer make sense to keep that plant operating?

Gee, we're a very, very long way away from that type of discussion and decision, frankly, we're a mile off of that. So obviously, we have a large campaign coming up with an 11-well program. The vast majority of those wells are development wells, which means they're relatively low risk. I said low risk, not no risk, but they're relatively low-risk wells. The exploration wells are relatively low risk for exploration, obviously, again, not no risk but low risk. So we're very comfortable with our program there. I'd also flag that we have told the market that the vast majority of our CapEx this year is targeting more than 50%, 5-0, rates of return. That obviously includes the Otway CapEx. So it's certainly a long, long, long way from being marginal. So at the moment, we're very comfortable with the program we have and the amount of gas we think we're expecting to get. So we're certainly not in a wind-down position on Otway, not even close.

Your next question comes from the line of Ben Wilson from Royal Bank of Canada.

I just had a couple of questions about your Tawhaki well in New Zealand. Good pronunciation, by the way. One, on -- are you going to put target size or predrill estimates on it? I see your JV or your operator has mentioned some very big numbers overall in the block but just not sure about this prospect specifically. And secondly, is there anything you've seen that gives you comfort that it might be liquids rather than gas, which is more prone in the area? And lastly, I just saw, I guess, the snafu on the BOP, whether that's factored into your cost estimates for the well yet.

Yes. Sure. Look, happy to answer all 3. So look, this is a basin that we've known for a long time, Tawhaki, we've been looking at for around 9 months, so we understand it reasonably well. No, we're not going to give you predrill volume metrics. But I think when we say that the mapped closure is 470 square kilometers, that's a fairly good indication that this is a potentially very, very large opportunity. We think it's probably more liquids-prone. But obviously, the drill bit will tell us that. We're not that far away. In terms of the tube that we had on the rig, so they test blow-out preventers, and the blow-out preventers tripped. That's good to know that they work. So there's no risk whatsoever at the time to any of the individuals on the rig, and there was absolutely no risk to the environment as well. So it's good to know that the BOPs work, albeit we'd prefer they didn't trip. That will probably, and this is ball park numbers, cost us in the order of an extra circa $3 million, I suspect, at the end of the day. But still early days, we're still working through that.

Okay. That's great. And just lastly, does the gas discovery represent a failure? Or given the scale of the closure you're thinking, is there potential over this gas?

Given the size of the closure, we'd be happy with any discovery.

Your next question comes from the line of Sam Samter (sic) [ Mark Samter ] from MST.

Close. That must be my brother. I've got 3 questions, if I can. First one, on the $20 million of extra maintenance spend that has surprised you guys, at least it seems, from Santos as operator. I mean Santos had been definitive for the last couple of years. And they reiterated this guidance twice in the last 2 months. But they're spending USD 300 million in the Cooper Basin. Actually, to be honest, when you look at their numbers, and I get these things aren't perfectly linear in the last 2 quarters, first half '20 for you, they spent about 65% of that full year number. So I'm just curious why this number has come as a surprise to you. Should the inference be that you had been assuming less than Santos' guidance that they've been giving for some stage?

No. Look, Mark, I wouldn't call it necessarily a surprise issue. It's the differential in timing between us being on a financial year and Santos being on a calendar year. So that means the timing that we receive their budget process is obviously different to the timing of our budget process. And obviously, our market guidance comes out of our budget process. So this is new definition that we've had through the Santos budgeting process. We support the spend. And frankly, as we mentioned, a lot of it is driven around Port Bonython, of the fact of we've been so successful in terms of, not only out of the basin but particularly the Western Flank, with how much oil we're delivering. So that means we need more maintenance, particularly at Port Bonython.

But for Santos, I do mean Santos told us numerous times in the last couple years they'll spent $300 million a year for the next 5 years. That's not -- I'm just trying to understand if you had been assuming previously lower because...

So our guidance comes out of the definitive budget process -- which it has to exist, the budget process -- which leads to joint venture approvals and obviously then leads to the AFE process.

Okay. Okay. And I guess moving on to guidance that you've given historically. I noticed there's not the free cash flow guidance chart in this presentation anymore. When we think about FY '21, obviously, you got Otway maintenance in there and maybe some Otway drillings drifted into there, too. I know you're not going to say much on the Lattice reopening. Or obviously, you did talk about the risk of it going to arbitration as well. But I mean unequivocally, Victorian prices have -- contract prices have come off since you gave that guidance. Under the same macro assumptions, do you still wanted to stand by your $200 million free cash flow guidance for FY '21?

We'll come out with an update on our 5-year outlook in August in a more definitive way. I wouldn't agree with you in relation to the Victorian gas pricing perspective. There is a strong differential between spot pricing and term contracts in terms of delivery, tenure and delivery locations. So I certainly wouldn't agree in terms of softening on longer-term contracts. So that for us...

Sorry, Matt, I interrupted you. But so you -- I mean you put up, in the last couple of presentations, the average $9.71 payout you obviously quoted historically. You don't think contract prices have come off at all because I guess, I mean everything I hear certainly says -- I completely agree that spot's not the same as contract. But it's only everything I've heard. So just don't you think that contract pricing have softened?

Yes. So we don't quote a specific number. What we do is point to the ranges that the ACCC uses. And as I've said many times, we don't use those numbers in terms of our future guidance. We use bottom ends of ranges when there are ranges in the market. So that's what we've guided towards previously.

Okay. Okay. And I mean -- just sorry, just one more on the free cash flow guidance number for FY '20. Obviously, by the time we get to the results, they'd have already happened. We've obviously got the extra CapEx. Has there been any changes in your guide's view of the operating cash flow that previously underpinned the FY '20 free cash flow guidance? Or should we effectively just lop the extra CapEx off that number?

I think the issue at the moment is any -- obviously, cash flow guidance is dependent upon many factors. It's going to depend upon what happens with oil price, which we've seen come off pretty rapidly as a result of the coronavirus.

I'm sorry, on guidance not changing macro assumptions. You provided the guidance on a set of macro assumptions, that same assumptions.

Sorry. What we give to the market is what the numbers are that we're using in our guidance. What actually will eventuate over the course is obviously, there's many metrics that will impact. Coronavirus obviously wasn't in our forecast, so there will be an impact around oil pricing, dependent on how plants perform going forward. So what we do is we disclose to the market what numbers we've used to come up with those guidance numbers. It's obviously then up to others to determine what they think the actual numbers will be. And there's obviously many changing pivotal points.

Yes. So we won't go into -- I was asking for -- if it's still under the same assumptions, but we'll move on then to last question, if I can. You spoke about lower customer nominations. This year, as we look and think about that price, right now, obviously, customer nominations are the lever your buyer has to pull. Can you give us a step for this year how close to the maximum downward nominations they can make [ by bid ]? Or if they're much more flexible then to nominate lower, I guess, if they're not happy with the pricing outcome or...

No. Unfortunately, as you know, Mark, I can't disclose the details of the sales contracts. And if I was to do that, I'd be disclosing the details within the contract. So unfortunately, I can't.

Your next question comes from the line of Adam Martin from Morgan Stanley.

Just back on the sort of CapEx question. Obviously, it increased. How much of that CapEx is timing? So how much does that impact the '21 CapEx numbers that you've put out there previously? And also, what extra do you get, if any, on that 5-year forecast in regards to production or EBITDA?

That's a good question. The majority of it is incremental, and it's because of the success that we've had. So if you recall our 5-year planning assumptions, we didn't assume any exploration success other than the risked volumes out of the Cooper and also out of the Otway. So therefore, the discovery that we've had in the Perth Basin and the discovery that we've had in the SA Otway is incremental. It's a great news outcome. Tawhaki is obviously incremental as well. And the bulk of the Western Flank, and, therefore, associated Port Bonython CapEx, is incremental. But obviously, what you're getting from that is we're getting more volumes through the Western Flank, which, as I said earlier, are incredibly high-returning volumes. So that'll pay out very quickly.

So we should see higher production come through? Is that -- in August. Is that the right way to think about it?

Yes. Correct. So I don't want to state the exact volumes and numbers. So obviously, we're working through a 5-year planning process right now. But what I am saying is the benefit of some of that additional spend has come from new discoveries that were not in the previous 5-year outlook. So yes, there'll be benefits coming from those new discoveries.

Okay. That's good. Second question, just on costs. If I look at your Slide 5, the cost sort of momentum seems to be slowing a bit. Those costs obviously exclude various things. If I just look at your accounts, costs are actually up a bit based on sort of how I work it on a per BOE basis. But what's your sort of sense in terms of where you actually are on the cost-out phase? Is it sort of coming to an end? Can you just give us a bit of insight there, please?

Thanks, Adam. I'll take that one. Just from an overall field operating cost point of view, obviously, on that slide, you see the great outcome from the underlying operational work that the guys have been doing in terms of reducing the cost there. From an overall perspective, you see that what's playing in there is the overall product mix. So we get more oil, obviously, flowing from the Western Flank and, with that, carries more tolls and tariffs that come with that. And obviously, that comes with it higher revenue and then higher-margin volumes as well. So I suppose, although you see an uptick in the overall costs, they relate to driving higher margins and higher cash flow from those volumes as well.

Okay. No, that's good. And then final question, probably back for Matt, just regarding this sort of Origin repricing. Obviously, global gas prices are low. Domestic price has been high. It's starting to come down. When are we going to get a sense of when that's actually concluded by? And when will we actually sort of see what price comes through the portfolio in terms of quarterlies or whenever else?

Yes. It's a good question. Obviously, global prices don't directly impact the reopen and/or the spot prices, as I mentioned earlier, but I can't give you too much details on it. What I can tell you is the ball has started rolling. If we were to go through an arbitration process, I suspect, ballpark, that would be more than 6 months to undertake. And the result then gets backdated to the required date in the contract. So we'll keep the market updated at material change points. We're not intending to do every dance move. But obviously, when it's material, we'll keep the market informed.

Your next question comes from the line of Saul Kavonic from Crédit Suisse.

Three questions, if I may. I'm sorry if I'm repeating earlier questions. So just a bit more clarity. On the increase in CapEx we saw, and I'm talking specifically about Western Flank, Cooper Basin numbers, just to reiterate, is this going to result in an increase in production beyond the original -- the 5-year target that you set last year? Or is this incremental CapEx just going to be there to meet the same target?

Yes. So I think, obviously, we will guide properly to revising the 5-year outlook. We're working through our 5-year plans right now. What I can say is from a general point of view, the performance of the Western Flank drilling this year has exceeded our expectations. So we now have to work through what that means for reserves, and we've got to work through what it means for production. So I can't guide too much until we've done all the work. But at the moment, what I'm saying is there are positive outcomes. And as I've said earlier, these are relatively modest numbers compared to the top 3 returns we're getting off of the Western Flank.

All right. On the production guidance, being the 27 million to 28 million barrels, now that's obviously now -- I just checked that that's after deferring the Otway maintenance into the next financial year. So I mean just on some rough numbers I do, on a pro forma basis, that suggests the guidance would be 26.5 million to 27.5 million. Why is it -- and again, my question is why is it so low? You've a couple of months' delay at Black Watch and lower customer nominations. So does -- is that something not originally considered within the original guidance range?

Yes. I think that the main issue is around -- the 2 areas we've pointed to is, one, is the delay at Black Watch, the other area that we've pointed to is nominations. So they are the 2 key drivers. I think your numbers might seem a bit high on the other adjustment. But if you want to take that off-line with Nik, I think he can probably give you a bit more discussion on that.

Yes. Sure. And just lastly, moving to the Perth Basin. We've always had the really good Beharra Springs result. Can you just perhaps outline what the drivers are for spending additional exploration CapEx there in the near term? Just given the amount of reserves you've already got at Waitsia and the time there still is to go there and developing that, what's the driver of doing that CapEx spend now as opposed to waiting for a few years?

Oh, I think you'd only do that CapEx spend, Saul, if you are very confident of commercialization in the basin, and we're very confident of commercialization of our gas in the basin.

Your next question comes from the line of James Redfern from Bank of America.

James here. Just 2 questions for me, please. Just going back to the Tawhaki well in New Zealand. It's a high-impact well. So I'm just wondering what your internal probability of success is for that well. Are we talking about getting a 1 in 5 probability of success? And I've just got one more on Waitsia after that, please.

Yes. I'm going to talk rough, rough view and try not to get kicked under the table by the Head of Exploration sitting next to me. I think we've been pretty clear in the market that we're not a company that targets 1 in 10, 1 in 15 wells, that we prefer 1 in 4 wells or better. So you can expect that's in that sort of range. Obviously, what that means is there is more likelihood that we'd rather not. So this is exploration. So we've got to be realistic. But it's an incredibly large structure. So that's what's driven us towards at this point. And we know the basin well enough as we've done about 9 months of work on this opportunity, Tawhaki.

Okay. Great. And then just on Waitsia Stage 2. I understand you made the comment that you can't provide a lot of detail at the moment. Can you just -- just in terms of what's been publicly announced, just if you could please remind me. So we're talking about a potential project of between 100 and 250 TJs a day. And I guess, the size of the facility or the project will depend on how much gas you can sell at appropriate prices. Is that correct? So we're still talking of that wide range there, depending on the end market demand. Is that right?

Yes. Correct. So that's what we've done all of our engineering studies on and progress towards. So we're ready to move very quickly once we hit -- green light points at FID. And the other point I'd obviously note is that Phase 1 expansion includes interconnection to the Dampier to Bunbury natural gas pipeline, which is important.

And so I guess what we're really waiting on is for Beach to announce some binding or, I guess, heads of agreement -- gas sales agreements for possibly 200, 250 a day. And then that will sort of be a segue into the FID for 250 a day. And I guess the only market -- the only customer you could take, that would be potentially the Northwest Shelf, if they were happy to buy your gas and then send it offshore as LNG. Would that be fair?

Yes. So as I said, we'll disclose more once we're at minding points in any discussions that we're currently having, and we're having multiple discussions.

Your next question comes from the line of Daniel Butcher from CLSA.

Just curious on the Cooper Basin CapEx, especially the $30 million in the Western Flank. I know you had answered a question on this before. But is some of that cost increase for water handling attributable to higher water cut on the existing production base? And can you maybe just remind us about what the water cut is in the sort of existing fields and where it's trending to at the moment?

Yes. It's Geoff Barker here. Basically, we're currently running at about 90% water cut overall in the Western Flank. So we're not seeing any change in that trend. What we're seeing is better-than-expected success from the drilling results that we've had that have required additional infrastructure to handle the production. So it's a good news story. And relatively speaking, compared to the total investment that's being made in the Western Flank, those expansion costs -- the facilities' expansion costs are very minor.

And does your modeling anticipate a much larger increase in that in the near term or medium term in terms of water cut, sorry?

No. No. Well, basically, we are in an area with strong water drive fields. So the baseline production will continue to have an increasing water cut, but we're replacing that with new low-water cut wells all the time. That's the objective of the drilling program.

Okay. And then just finally, most of my questions were asked but just on Black Watch. Obviously, it has a significant impact on your guidance. I'm wondering whether you can disclose what sort of initial production rate you're assuming in your guidance for that well.

No. We haven't disclosed initial rates to the market, but I think you can probably back-calculate from the amount of period that we've talked about.

Right. Yes. And maybe a final question, just on -- you've obviously got a lot of organic opportunities on your plate. If oil stays at $55 rather than recovering to sort of $60, $65, does that put a -- is that sort of take M&A off the cards for the near term? Or are you still open to that, given your cash flow impact, of where oil prices are right now?

I think what we'd flag is we're a highly robust company given the amount of gas business that we have in our portfolio now. So our gas business, as we've mentioned previously, covers the totality of our operating cost as a business. So we're highly robust with the high rates of return on all of our assets, including our gas assets. So that means we're able to spend. It also means if the right opportunities arise, we're able to take a good look at them, particularly when we're sitting [ on net ] cash today. So volatility is something that we're comfortable with because we've got a business that can handle it really well.

There are no further questions at this time. I would now like to hand the conference back to today's presenters. Please continue.

I think that closes us out. So I appreciate everyone's time. And obviously, please feel free to follow up with Nik and the team in relation to any further questions you have. And for those that we're going to see on the road in the next couple of days, look forward to catching up. Thank you.

Cheers.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating, you may now disconnect.