Good morning, and welcome to APA's 2019 Half Year Results Presentation. I'm Mick McCormack, APA's Managing Director and CEO. With me in our Sydney office is APA's Chief Financial Officer, Peter Fredricson, and together, we'll take you through the presentation and results lodged with the ASX this morning. I also have my group executive team here to assist in answering any questions in particular, Ross Gersbach, Strategy and Development; Rob Wheals, Transmission; Sam Pearce, Networks and Power; Kevin Lester, Infrastructure Development; and Nevenka Codevelle, Governance Risk and Legal. And the only one missing is Elise Manns, I might have mention her. Oh, sorry, Elise is here. Look like applying for a job or something. Right. I'll start the call today with an overview of APA's results for the first half of FY '19; Peter will then run through the numbers in more detail, including our full year guidance for 2019 before I conclude with some comments on our outlook. We'll then take questions from analysts and investors who are on the call. Questions from media will be addressed during the media interviews following today's results. Looking at Slide 4, a brief summary of our first half financials. A solid set of interim results that confirm we are on track to achieve full year 2019 EBITDA guidance. The results are in line with our expectations, and despite the market possibly thinking we may have been distracted last half with the CKI transaction, our results show that we've remained firmly focused on getting on and running the business despite the additional corporate activity going on. APA has always been an active business, you just have to look at our growth record over the last 18 years. Indeed, you have to say one of APA's key strengths is that both the business and the 1,800-or-so people that work for us, dealing with change and managing multiple large-scale projects at any one time, is business as usual for us. Revenue looks good and pass through revenue was up 6.1% and for the first time, tipped over the $1 billion mark for the half year as a result of new assets coming online and contributing new revenue. We remain confident that the significant revenue uptick in the order of $215 million per annum will occur from 2020 or FY 2020 as a result of the $1.4 billion-plus of growth CapEx investments since FY 2017. Net profit after tax was up 27% and EBITDA grew 4.3% to $787.7 million. Operating cash flow was up 1.7% to $470.2 million, but OCF per security was down 3.9%. This was due to the adjustments in the first half FY '18 for the issuance [indiscernible] securities in 2018 following APA's $500 million [indiscernible] program to date. The board this morning confirmed the interim distribution for our investors of $0.215 per security, and an increase of 2.4% or $0.005 per security over the previous corresponding period. And we're able to attach franking credits of $0.032 per security to the interim distribution to be paid in March, which again, is good news for our investors. Given the solid first half results and looking ahead at the second half forecast, we are happy that we will deliver another set of solid results for the full year come June 30. Turning now the Slide 5. So how have we delivered these results? Importantly, we put our customers front and center of our business, and ask them as well as ourselves, what is needed from APA to provide more flexibility and services to Australia's energy market? What improvements to our processes and systems can remake that will have a benefit for our customers? And we've had this approach for many years now, which results in a 3-year program totaling over $1.4 billion of committed capital organic growth projects. With many of those projects now commissioned, the incremental revenues are no starting to have a positive impact on our numbers. The new Reedy Creek Wallumbilla Pipeline in Queensland, which is underwritten by a 20-year contract with APLNG, had its first full half period of contribution, providing APLNG with flexible access to the domestic gas market. In Western Australia, the new Mount Morgans Gas Pipeline has made a big difference to the reliability of power, availability, generation and cost for the Dacian Gold Mine. It might be only 4 kilometers in length, but its significance and benefit lies in its connection to APA's 1,200-kilometer interconnected grid that is now providing a reliable and cost-effective supply of gas to several mine customers in the Goldfields region. 130 megawatts of new solar renewable energy is contributing new revenue for APA in the second half with Emu Downs in WA and Darling Downs in Queensland now fully operational. Importantly, the new energy sources are providing synergy and origin energy, respectively, with access to renewable energy that their portfolios were seeking as well as the large-scale generation certificates required under Australia's renewable energy target scheme. In preparation for new gas to flow from Northern Territory sources into Eastern Australia in the second half of FY '19, we've readied the Carpentaria gas pipeline by making it bidirectional during the first half. This is already providing the tight East Coast gas market with more flexibility in where gas supplies can be sourced from. In addition, we are in the process of reviewing pipeline capacity on the Southwest Queensland pipeline and move them to Sydney pipeline in particular, as this has become well and truly the gas highway that supports Eastern Australian domestic energy requirements. Access to new gas supplies is also critical to put downward pressure on domestic gas prices, and we continue to work with our customers, Santos in New South Wales on the Western Slopes Pipeline project, and AGL in Victoria on the Crib Point Pakenham Pipeline project. Both of these APA projects are subject to FID approval of the gas projects by Santos and AGL, respectively, but we continue to work alongside our customers to progress those potential new gas supply sources. From an internal perspective during the half, we continued our dedicated focus on improving safety metrics and improving on FY '18's performance. The large amount of growth projects worked in recent years has made an increase in contractor usage, and with that has come some challenges in ensuring there that our safety management is consistent with APA's stringent standards of processes. Pleasingly, for the half, we reported a significant improvement in our safety metrics period-on-period, with lost-time injuries reducing from 7 to 3, and medically treatable injuries dipping from 19 to 16. However, Zero Harm remains our target for anyone working for APA. Turning to Slide 6 and a review of where our 3-year committed CapEx program is at. Firstly, you can see from the slide that our growth has been both Australia-wide and asset-diverse. And it's the combination of these factors that has added to the depth and diversity of APA's energy infrastructure portfolio and their resilience to dynamic market conditions. We're not sector-specific, asset-type, resource, state or customer dependent. I've long talked about APA's growth focus through leveraging our expertise as well as APA's existing asset base, and the projects on this map are testimony to that successful strategy in action. Looking at Western Australia as an example. Since 2016, we've added just over 500 kilometers of new pipeline connected to the Goldfields Gas Pipeline. Additional compression, some looping, as well as a power station to provide services for four new customers in that mining region. Each customer had specific needs which we've been able to tailor our system to, but the linchpin of this expansion has been in leveraging the Goldfields Gas Pipeline. For APA, this type of organic growth not only benefits our customers [indiscernible] this part of the Australian outback now rely on uninterrupted supply of gas for their operation 24 hours a day, seven days a week but it grows our portfolio and we add value to the long-term existing assets within our portfolio. The majority of the CapEx projects remaining under the three year program are either in commissioning phase or heading towards commissioning in this current half. The Orbost Gas Processing Plant will be the last of the projects to complete. It's been a huge refurbishment project and testament to our very experienced infrastructure development team headed up by Kevin Lester. We're on track for commissioning and expect to deliver on spec gas from July. That asset is well located and holds excellent potential to produce new gas sources well into the future in support of gas exploration in the Gibson basin. And with that, I'll hand over to Peter.

Thanks, Mick, and good morning, everybody. I'm on Slide 8. As Mick has noted, we are pleased that the half year result has delivered as we expected and as we guided to in August last year. The result shows the stability and predictability of the business as notwithstanding to seek our proposal that was on foot for the vast majority of the time. Our 1,800 people delivered a solid result across the board. Generally, the energy infrastructure assets portfolio has performed well, delivering an increase in EBITDA of in excess of 5%. Interest expense has come down as we have dropped off some more expensive debt, such as the whole -- a whole half year without the subordinated notes. And the increased capital expenditure on major projects has seen a somewhat higher level of interest capitalization year-on-year. Tax expense continues to rise as you would expect against rising profits, and operating cash flow has increased notwithstanding an increase in tax paid during for the period, with the only impact on operating cash flow per security being the issue of the new securities at this time last year when we raised $500 million of new equity in support of that $1.4 billion-plus growth CapEx program. We've seen revenues start to flow from these projects but we will see larger inflows in the second half and in FY '20, as previously noted. Moving to Slide 9. The energy infrastructure portfolio has delivered 5.8% growth overall as particularly in the East, we continue to see the benefit of the East Coast Grid and the large number of multi-asset, multi-service contracts now in place. The only meaningful reduction in EBITDA was in Victoria due to a lower amount of gas-powered generation, and where the VTS saw a new access arrangement that came into effect on the first of January 2008 -- 2018, deliver a first half result that had lower revenues than the previous access arrangement in the 6 months to the 31st of December 2017. Corporate costs have delivered a negative impact for the half as we booked in the order of $11 million of costs associated with the CKI proposal and with the Managing Director's impending retirement. Absent those costs, the annual corporate cost run rate continues around the $60-odd-million a year that we have delivered to over the past couple of years. Slide 10 is new to the presentation deck this half. In response to feedback from investors and analysts, we've tried to give you more detailed information with this set of results. We will look to maintain this level of information going forward as we are of the view that it will help investors better understand where the growth in our business is coming from. The waterfall shows the extent of tariff escalation from CPI related adjustments. Foreign exchange impact year-on-year in respect to WGP revenues and EBITDA; EBITDA contributions from new assets commissioned in the period; and new contract or renewals achieved throughout the reporting period. You will see from this slide the fact that variable revenues are down by around $7 million period-on-period, in part due to a reduction of non-firm services but also due to customers shifting services from variable to firm. We've always said that variable revenue was neither predictable nor taken for granted in our business. We also don't try or don't rely on it for our growth. The result shows growth from new assets, tariff escalation, new and renewing contracts plus modest increases in asset management and investment income, combined with foreign exchange gains realized in the WGP revenues, more than offset reduced variable revenue and those once-off corporate costs within the reporting period. One of the more pleasing aspects of the result is that when we exclude the once-off corporate costs, EBITDA grew by 5.8% over the previous corresponding period, demonstrating solid growth and ongoing momentum in the business. All of which leads to the confirmation of our low risk business model on slide 11. With an excess of 94% of revenues coming from investment-grade counterparties and 92% of revenues coming from capacity charges, regulated and contracted fixed revenues, we have continued to drive business growth without changing the mix in these areas in any material since over a significant period of time. Likewise, the industry breakdown has not changed materially over the last 4 or 5 years as we have added significant growth in the infrastructure portfolio. All in all, the average contract tenure remained above 12.5 years, and all other qualitative measures remains maintaining historic levels, and this as you can see what APA will deliver over the long term. From an owner and operator of energy infrastructure underwritten by long-term contracts with highly credit worthy counterparties, investors have seen growth filter through into financial results without any material change to the longer-term, low risk investment profile. Slide 12 is another new slide that is looking to concentrate on what has been happening in the commercial space, that is our business especially since the introduction of the GMRG rules in 2017. Since the 1st of August 2017, we have signed some 120 contracts for services with customers across our gas transportation network. Of these, 30 relate to contracting the firm's services with existing customers across our infrastructure. The other 90-odd contracts have been for new services or non-firm flexible services or other variations such as the addition of a new delivery point across the East Coast Grid in particular but across the whole portfolio in general. This confirms that we are getting on business and delivering what our customers want with renewals and new contracts across the business. Notwithstanding that renewal contracts are generally for shorter periods than the new contracts that support significant capital spend, the growth in the business has seen the revenue weighted average term of contracts continue at levels above 12.5 years in FY '19. Turning to Slide 13. We've spoken a bit -- we've spoken a lot in the last 12 to 18 months about the growth CapEx programs that we have in front of us. Before August 2016, we were spending between $300 million and $400 million a year on growth CapEx. Then in August 2016, we said we thought it would be around $1.5 billion over the next 3 years. We were uncertain as to the timing but we were sure that those projects were there and that growth was there. Our customers need the infrastructure and we're happy to build it, own it and operate it if they are there for the long term. With $260 million spent in the first half, we're confident that the $425 million spend we guided to in August last year will complete in FY 2019. That would complete that $1.4 billion-plus spend, but beyond that, we remain confident of our $300 million to $400 million per annum of growth CapEx over the next 2 to 3 years, at least. Again, we have a track record for delivery of not only the financial results but the assets to enable our customers and APA to grow. You've seen this slide, Slide 14, since August 2017, and there have not been a lot of changes to it. The main changes are clearly in respect of completion and commissioning timelines. And in the first half, we made significant progress towards commissioning the Yamarna pipeline and associated Gruyere power station going down the solar farm and the Badgingarra Wind and Solar Farms. We have around $14 million of EBITDA in the first half from assets that had not contributed in the prior corresponding period, and we will see revenues flow in over the remainder of the financial year that will bring us to around $70 million of revenues in FY '19 from these new assets. This is marginally below the $75 million in revenue that we had guided to for these assets previously in FY '19, but the differential is timing to flows only, and we will ultimately pick up these revenues through the duration of the relevant contracts. We remain, though, comfortable that the EBITDA contributions in FY '19 will be at or around the numbers originally expected, and it is in our guidance confirmation later in the presentation. I'm now on slide 15. The half year was relatively quiet from a capital management perspective as we put in place 2 new $500 million syndicated debt facilities for periods of 5 and 5.5 years, respectively, out to July and December 2023. Through the CKI proposal timeframe, we saw both rating agencies put our ratings on positive outlook due to the credit support that would've come from the higher rated CKI if the transaction had have closed. When the proposal was terminated, both rating agencies were -- both ratings were returned to stable outlook, reflecting the fact that we remain in a comfortable position from a balance sheet and rating metrics perspective. During the period, we did unwind the cross-currency interest rate swaps that had converted the 2022 euro issue we undertook in 2015 into U.S. dollars. We reset those euros into Australian dollar liabilities. Received $151 million in cash and we're then free to convert all Wallumbilla Gladstone Pipeline revenues from March 2019 to March 2022 into Aussie dollars. We put in place forward exchange cover in respect of net revenues out to June 2021 at this stage, and as a result, we have locked in around $18 million of cash -- $18 million of cash flow benefits relative to the previous position over that period of time. The second half, we'll see more activity as we have some $600 million of U.S. private placements and Maple Bonds to repay over the coming months. With some $1.2 billion in committed and undrawn bank facilities available to us, we see no rush in this regard, but expect that we will issue longer-term bonds at some stage in the next 12 months to further turn out those facilities. Moving to Slide 16. The debt portfolio remains very efficient, with average tenure of 6.4 years and average cost of around 5.5%. You'll see the green and gray bars on the maturity profile here, $300 million of USPPs under FY '19 and into FY '20, and $300 million of Maple Bonds in the FY '20 zone. Ultimately, we see the capability to issue 7-year bonds into FY '26, 10-year bonds into FY '29 or 12-year bonds into FY '31, all dependent on available markets and pricing. APA has a 144A program, and both an AMTN and EMTN program in place, each of which gives us access to the most liquid debt capital markets globally. We remain of the view that we can issue into longer-term bond markets in any of the aforementioned tenures at Aussie dollar swap rates that are below the cost of debt that we are repaying over the next 6 months. Looking at Slide 17. As with the last couple of years, in FY '18, APA was a cash taxpayer. All in all, we paid some $52 million in cash tax for the FY financial -- FY '18 financial year and we expect cash tax in the order of $65 million to be payable in respect of the FY '19 financial year. Cash tax paid and to be paid allows us to attach $0.032 per security to the interim distribution, meaning that $0.074 of the APT profit distribution will be franked, with the remainder of the distribution being unfranked APT distributions after pass through profit distributions and a capital distribution from each of the 2 trusts. As per our distribution policy, the distribution is fully covered by operating cash flow that includes growth that is substantially in line with the growth in operating cash flow and it reflects the fact that we look to retain operating cash flows in the business to assist in the funding of our ongoing commitment to growth CapEx. So finally, as for the guidance on page -- on Slide 18. All of the financial results that you've seen today allow us to reconfirm guidance for the full year in line with the guidance ranges that we confirmed after the announcement of the termination of the CKI proposal in November last year. EBITDA will fall into the upper end of the range of $1.55 billion to $1.575 billion. Interest costs will settle towards the lower end of the $500 million to $510 million range. Distributions are expected to settle at $0.465 per security for the full year, so that drives an expectation that the final distribution should be in the order of $0.25 per security. Franking credits for the full year will depend on what credits over and above the interim $0.032 per security can be allocated to the final distribution in September. As we've already noted, we are confident that growth CapEx will settle around $425 million for the full year. So with that, I'll hand back to Mick, and I look forward to take questions at the end of the presentation. Thank you.

Thank you, Peter. Let's now turn to Slide 20. Without opportunities, customers and consumers, we wouldn't have a business. It's their demand for services and their specific requirements that drive our operations. And in this dynamic energy market, our customer satisfaction continues to be a critical factor to the delivery of our growth strategy. For some time now, we have been looking at how we can continue to improve the services we offer and how we deliver them to customers. There's always room for improvement and our customers have told us so. We have very strong relationships with our customers, many of whom we have been working with for decades now. That longevity and familiarity allows for a very honest relationship. And so when we undertook a survey of our top 20 customers last half, we got some very honest and valuable feedback, confirming the things we do well and highlighting the areas where we can and must do better. In this next half, we'll be rolling out our customer promise, that is what our customers can expect and should expect from us. The APA customer promise is all about ensuring that the whole of APA not just our customer-facing staff, put our customers first. And we can only do this well if all our people truly believe that what's good for the customer is good for the business, and where the customer is at the heart of all our decisions. The APA's promise aligns with the recently launched whole-of-industry initiative, the Energy Charter. APA is one of the 17 foundation signatories for the charter and has been instrumental in developing this principle-based approach by the energy industry to put customers and consumers first in our respective businesses. Each signatory will be held accountable every year by having to submit a publicly available report against the charter's principles and a plan for how we are meeting or making progress towards the charter commitments. Reports will be evaluated by an independent panel and other stakeholders and evidence-based measures and metrics are required. So a fairly robust and public process that customers will have access to. Nevenka Codevelle, our Group Executive of Governance Risk and Legal is the Chair of the Industry Working Group, and is on this call if you're after some more detail on the charter during question time. Turning to Slide 21, and my last slide before we open up to your questions. I'll give you an update on APA's due diligence work in North America, given that it was put on hold during the first half with the CKI proposal in the pipe. APA first advised the market that we were exploring opportunities outside the Australian market in August 2017 on the full year results call. Specifically, we indicated North America as the target focus, following a global review of possibilities. We do continue to see ongoing growth opportunities within Australia, which we've clearly demonstrated over the last 3 years by our investment of over $1.4 billion in new organic growth projects, all underwritten by long-term contracts with highly credit-worthy counterparties. But APA has a long-term outlook and therefore, it's only prudent that the company looks ahead of what other opportunities may meet our long-term strategy, whether that be new markets or new technology. This is exactly what we have done over the last 18 years. That is why we now have an interconnected grid of gas pipelines, delivering reliable service flexibility across Australia. So the objective for APA looking globally is still the same objective that we've had domestically, that is looking at gas infrastructure businesses that would provide a strong platform for future growth and development and to have a similar risk profile to our current business. So with that, I'll hand the meeting back to our operator to open up the Q&A session.

[Operator Instructions]. First question comes from Ian Myles, Macquarie.

First question for you, just a quick one on SEA Gas. That was 1 contract which went through a major recontracting. I was just interested to know how the revenues on that contract sort of turned out post the sort of recontracting and change in volumes on that pipe.

Ian, it's Ross Gersbach. Yes, we're pleased to renegotiate new contracts on that, and they're broadly in line with the revenue that we expected at the end of the foundation contracts.

Okay, and just two other questions I just want to go through. Firstly, I'm a bit confused when you talk about the extension of your contract lives to 12.5 or a bit over 12.5 years in that chart, or I think on the news chart which you've done, which is great info on Page 12, sort of increased that. And in the commentary which you made, you're saying most people are signing contracts which are shorter. How does the math work that, that contract than your average revenue tenure is growing?

Well, Ian, I mean, what you got to keep in mind is this. As we sit here today, and I'll sort of try to keep it simple, but as we sit here today, we've got a contract, let's call it, that is due for repayment or is due to end tomorrow. And we've also just entered into a contract that's a 20-year contract. So the average of those 2 contracts that the revenue is even or is the same in those 2 contracts is 10 years. But if the revenue on the contract that's terminating is higher than the revenue in the contract for 20 years, then the average of those contracts on a weighted average basis is less than 10 years. If the revenue on the 20-year contract is higher, then the average is higher than 10 years. And so all that happens here is that we're replacing contracts that are in last year's calculation of, let's call, it 12 -- it was close to 12.5. To be fair, I think we were talking 12.5 last year. We're replacing the contract that's in there that might have 2 or 3 months, with a contract that might be 3 to 5 years -- 3 or 5 years. So it all -- I mean, we've got a spreadsheet in the ether somewhere in the commercial team that run this, and each one of our contracts sits in there with the level of revenue, and these are the numbers that pop out. But the mathematics will keep it generally up at that sort of level if we are adding longer term growth contracts of reasonable amounts of revenue, which we have been doing, of course.

Okay, that's great. Wallumbilla Gladstone Pipeline, you've taken a U.S. dollar hedge and brought it back to Australian dollars, and I think that allows you then to move to a different currency. Are the average for rates you put in on the slide pack on Page 34, is that what you're now applying to the conversion for the whole of the pipeline? Or is that for just the component which is being converted back? I just got a little bit confused about the wording in your document.

Sorry, about that. So, you'll have seen the $0.6716 and the $0.7301 before. Well, in fact, you've seen the $0.6716 before. And as we unwound, what we did was we took the -- and when you, in the previous results, you've seen the $0.6716 and the numbers before that, what we said is that the revenues from March 2019 through to March 2022 were in a designated relationship with the U.S. dollars that we had converted to euros, the EUR 700 million through that process. What we did then was we unwound that hedge, converted the Aussie dollars -- or the euros, sorry, from U.S. dollars back into euros, and then back into Aussie dollars. We got $151 million as a result of that transaction. That money came into the bank and is available to us to use over the next 4 years. It increased our liability for debt by about $180 million in respect to -- out to 2022 if we compare the rate we've hedged the euros back to Aussie dollars at versus the $0.78 that everything is otherwise in our Aussie dollar book set. So what you've been seeing before was all those revenues in from 2019 through to 2022, at $0.78. Remember, when we said we had those -- we had the hedging plus everything else at $0.78, now what we've done is we've hedged the FY -- the second half FY '19, the first half, all of FY '20 and all of FY '21 at those rates, $0.7301, $0.7192, $0.7199. The balance of everything else which is still in the designated relationships with U.S. dollar debt is still determined at $0.78.

Okay. So going past in FY '22, unless all else failing course at $0.78?

That's correct, yes. And this just reflects what we said at the outset was the dynamic nature of this stuff. As we get into March 2019, what we were going to be doing is we were going to be taking a month's revenue out of that designated debt relationship, convert it into Aussie dollars and having to convert some of the liability into Aussie dollars. So we did that all in 1 hit back in September last year because of what it gave us from a funding perspective. And I think we're better off to the tune of about $18 million, $20 million over the term in respect of that debt.

That's great. One final question. On the -- you talk about the expansion of -- consideration of expansion of the MSP and Southwest Queensland pipeline. Just wondering how of that falls in with the consideration of the LNG terminal, which you guys are potentially developing for AGL, and whether there's a need for both, in your views.

Ian, it's Rob Wheals. Really, what that comment is reflecting is discussions that we are having with customers and what we've seen in the market. And we can only respond to what our customers want. They will be weighing up where they're going to get the gas from or what their transportation requirements are and whether or not they will be accessing gas from proposed terminals or not. But just to summarize, we talk to our customers and respond to what their requirements are.

Your next question comes from Jay Byrne, Citi.

Just firstly on the American acquisition, thanks for the disclosure there. I was just wondering if you might be able to help us understand the materiality or the thought that it would need to be a sizable enough acquisition to get a foothold in your chosen market but clearly not so large as to bet the company. So if you could help us there understand the reality, that would be helpful.

Look, it's Mick. I'll pass it over to Ross, but you've actually answered your own question, that's exactly what I was going to say. It's not we're getting out of bed to go over to the U.S. and spend $50 million. Equally, we don't want to look at an opportunity in the U.S. that is transforming APA from an Australian-based company to something headquartered in upstate New York. So it's got to be big enough to move the dial, but not so big that it will cause APA indigestion. Ross, do you want to add something?

Yes. The thing I'll is we're looking for a platform on which to grow, and that will direct us to the top of assets. We just don't want to go and invest in an asset that doesn't have a logical growth path from that point.

Got it, okay. That's helpful. Secondly, AASB 16 looks like it's not adopted but as I read the notes, the financial statements, it looks like the materiality isn't going to be that large, but presumably, no impact to your credit metrics. Just wondering whether there would be a bump at all to your adjusted gearing, and whether you will in fact, increase your gearing target when you adopt AASB 16, or whether you're going to hold that flat.

No. I think the right of use in respect of leases is something like $50 million. And you sort of put the other sides to that sort of stuff, it's not going to move the dial at all. So we're not at all concerned about it. The issue for us in terms of this is, the only thing we've got really is some real estate around the country with office blocks and stuff like that, office buildings, where we're renting space and motor vehicles. There's nothing really else that falls into this space.

Got it. Okay, helpful. And then just a last quick one. 6 months ago at the result, you've said you'd had line of sight on new projects for essentially a potable testable opportunity in the market of $4 billion across pipelines, renewables and gas processing. I guess renewables is looking a little bit harder than maybe the industry would have thought last year. I'm wondering whether that's still the right number to think about. And I acknowledge that you've said you probably got line of sight straight $300 million to $400 million of CapEx for the next few years.

It's Ross Gersbach. The renewable industry update here is struggling because of a lack of policy in terms of the type of investors such as APA looking for certain cash flow. So we will continue to look at the renewables, but changing our risk curve to match the uncertainty in the market at the moment is unlikely.

Okay. So if you were to see a policy setting that you are comfortable with at the conclusion of a federal election, then you'd probably be more willing to allocate capital? I appreciate that's a pretty open ended question.

Yes. We certainly would allocate. I mean, we like renewables, they give us consistent risk return profiles. There were ones we've invested in to date and if we can replicate more of those, then we'll certainly will under a clearer policy framework.

Your next question comes from Rob Koh, Morgan Stanley.

Just a quick -- I would acknowledge it's a very nitpicking style question. The previous color on sustained business CapEx levels was in the order of $100 million a year. And in this year, you're kind of saying $100 million-plus. I'm just -- I just want to make sure we are understanding that correctly, if we can.

Rob, you've been looking at our wording, like you look at the info in a few minutes and keep looking for subtle changes in language and finding them. We probably need to be more careful. I think what we've said in the past is that we tend to think that we'll average $100 million-odd in sustained business CapEx over the longer term now that we own some -- a lot more sort of rotating kit, with things like Diamantina and wind farms, et cetera, et cetera. I think we're at about $60 million so far this year and we may come in a touch over $100 million. We're spending $30 million to $40 million a year on technology as much as anything else. So there's a lot of stuff that falls into this nowadays but no, I think what we've said is we'd expect to average over the longer term $100 million. And sorry if the plus sort of sent you off on a bit of a wild goose chase.

No worries at all, Peter. I guess you don't leave me too much to question so I got to look hard. Okay, next question, and I don't necessarily -- we can always take it off-line, but the restructure for the euro-dollar hedge, Peter, that you did, and that's obviously got the cash benefits, as you've explained. Was the catalyst for that really just the cash benefits, and that's a kind of ongoing source of optionality for your post-2022?

Yes, it is. And we've sort of said in the past that this is a dynamic type of an environment for that particular debt and the revenue that it's sort of in a designated relationship with. We'll look at it on an ongoing basis and see when the benefits arise for us. What we know is that -- and to be fair, the P&L impact of that loss that goes up and down because of that $0.78 and off the end of 2021. If you looked at it now and put $0.78, we'd arguably have less revenue in the P&L. We wouldn't have less revenue though in a cash flow since. So all we've done is we've locked the cash flow in for the next few years, and we've locked the rate in that would have been better than the $0.78 that you would have seen otherwise. Sure, it's not as good as the $0.67 that we're booking this year but I think the U.S. dollar -- sorry, the Aussie dollar to the U.S. has been under $0.70 less than 8% of its total life. So anything that you've seen when we first got this stuff locked away was absolutely the best you could've gotten, and $0.70 looks like a pretty good number to us. But we'll continue to look at on an ongoing basis, and if things work for us, we'll do it. Otherwise, we'll approach the next slot, which is, I think in 2025. We'll approach that and work through the monthly unwinding as the strategy outlined.

Just a question on the customer promise, and you mentioned that you surveyed your top 20 customers. I guess, given that you're not primarily a retail business, we'd probably be disappointed if your customers loved you or probably looking for more relationship and mutual respect. If you -- could you give us some color on the kinds of criticisms that they had of you, fair or otherwise?

Thank you, it's Rob Wheals. Look, generally speaking, as Mick said and I think you've we've alluded to, we have good long-term relationships with our customers. They've been there for many years. The value the grid, they value of the flexibility that we can offer them but as the gas market gets more complex, services and the delivery of that gets more complex, they're looking for us to be more nimble, be more responsive and make sure that our systems, process and people can accommodate that. But it's just about consistency all the way through. And we've got some great feedback from them, both good and bad, and I think that's all -- feedback is the breakfast of champions, and we know we can do better.

Last question for me, and if the answer is no comment, I completely respect that. I guess, with the CKI process now terminated, just wondering if it was contemplated or explored, whether there are any scenarios where APA assets could have been divested to allow the transaction. Obviously, part of the initial proposal was some WA assets, but could it have gone further than that?

Rob, it's Mick here. This is speculation after the fact. Who cares? It was not divested the treasurer on national interest grounds. So knowing CKI as well as I know them, I'm sure they would've turned over every rock possible to get that transaction done. But you're on up against politics and that's the outcome, full stop.

Your next question comes from Joseph Wong, UBS.

Just a question on FY '19 at the second half. If I just look at the first half numbers and annualize it and take out the $11 million for corporate cost related to the C5 bid and it was kind of upper end to E, that kind of takes you to $1.59 billion. Just wondering, is there any headwind we should expect in the second half of the year?

No. We've given you the guidance that we have and we're pretty comfortable that we'll fall within that range between the call it, $15.625 and $15.75. So it's not -- you can't always just sort of annualize these things like that, so I apologize. When we tend to be very clear in our guidance, and we're pretty happy with what we've done here today.

And then second question is with regard to I guess, growth CapEx, you iterated that growth CapEx will be $300 million to $400 million after FY '19. Just wondering if you can give any more color in terms of where or which sector looks more attractive to you. Is it more on the processing clients or is it possibly in potential minority stakes in LNG processing?

No. Again, what that is, is that that's sort of going back, I think, to our pre-August 16 guidance where typically, what we've said is we've got a huge number of projects on our radar that we're talking to various customers about. And hence, the $4 billion that we talked about. I think when we talked about them in August last year, we said something like $2.54 billion of those were gas pipelines. But we're continuing to talk to customers about that $4 billion worth of stuff. And we've said that, that 3 to -- that, that -- those discussions give us confidence that we'll get $300 million to $400 million of growth out of the discussions that we are having on an annual basis. And so, as we sit here today, we're not thinking that we'll spend x on something specific in FY '20 and y on something specific in FY '21. What we've said is that we think that we'll generally get $300 million to $400 million. And I think we tried to do in that history of sort of talking about our CapEx is just confirm to the market that we've said that for a long time, and that's what's actually happened. And so that comes from the discussions that we're having from customers and with customers on an ongoing basis.

Your next question comes from Peter Wilson, Crédit Suisse.

A quick one on guidance. Can I just ask, how much of the additional $11 million in corporate costs were baked into the original guidance?

Zero. Absolutely nothing, Pete.

Right. Can you comment on maybe what in your portfolio has performed better-than-expected then, given that you're coming to your top half even incurring those costs?

I think, we're pretty comfortable with the portfolio across the board. Maybe Rob might comment but I don't think anything outperformed anything else. As we said, Victorian Transmission System was off relative to previous periods. We knew that was the reason -- we know that was going to happen. So when you look at what's happening to regulated assets in this country, you expect access arrangements that follow to be -- to give you less revenue than the previous ones. So that's not a surprise to us. Everything else, I think, is pretty much operating across the board pretty well.

Peter, Rob here. I'd add to what Peter has said is there's no one particular thing that has driven the difference. It's just a little bit of outperformance across the board.

Great. The contract renewals, so you mentioned you've had 120 contracts renewed or varied for the total value of $130 million in revenue. A big chunk of that, I believe, is the announcement you put out towards the end of December, which was a $90 million revenue recontracting and new services, $40 million of which was recontracting and $50 million was new services. Can you just unpack that a little bit for us to the extent you can? Give us an idea of what were the new services? What's the kind of feed that those things are providing? Any context on how the pricing of the recontracted services went?

Peter, Rob. I'll pretend to answer that question. Just by way of clarity, we've entered into, since the beginning of the new rules brought about by the Gas Market Reform Group, 120 contracts, which could be -- or a mix of renewal of existing firm service contracts, to which the number is 30 over that period from August '17; and the remaining 90 relate to additional services added, new contracts entered into new flexible services, extensions, changes in receipt points and delivery points. So those are all contractual changes. The thing I'd draw your attention to is that $30 million of that $120 million from the period 1 August, '17, relate to material renewal of firm services over that time. And your question, how much of that -- what was the nature of that renewal in terms of price? What I can say is that the lion's share of that majority well in excess of 90% was done at the same or similar pricing terms of the expiring contracts. What I would say is also don't mix the other statements that you might have read around $130 million of other renewal and new services over a 3-year period, that's just 1 example of what we've done with a number of customers. It doesn't give you the value of the $120 million or the value of the $30 million that I referred to earlier.

Okay. And the $50 million of -- in revenue from new services from the agreement announced 19th of December, can you give us an idea of what those new services were?

That's a combination of transportation and a big part of it is new storage services on our grid.

Okay. And last one, the $8.6 million that you -- for Slide 10, the $8.6 million from new contracts expiring renewals, can you unpack that at all? Is it East Coast, West Coast, Queensland?

Sorry, can you -- 8-point sorry?

Slide 10 in the EBITDA bridge, you've attributed $8.6 million of the EBITDA gain is new contract expiry and renewals. I'm just wondering if there's any color you can give? Is it kind of -- is this West Coast, is it East Coast? Where is the positive effect coming from?

It's all pretty much East Coast, I would've thought, off the top of my head here. But very little has been renewed, if you like, on the West Coast in the past 6 months. It's very difficult, Peter, just to break something of that amount of money down without identifying who the customer is. And we've got huge confidentiality agreements within these clauses within these agreements. So what we've tried to do is give you a sense as to where the growth is coming from. What that's saying is that, in respect of contracts that expired and renewed, we're getting $8.6 million more revenue than we would have been in the past. Sorry, EBITDA, EBITDA.

Your next question comes from Michael Morrison, Deutsche Bank.

Just with the new contracts and renewals, have there been any customers that went to use the new arbitration system to negotiate the new or the changes or new contracts?

It's Rob answering your question. No is the answer.

No is the answer.

Thanks, Mick. Sorry, I'm just -- I've got a really crackly line, it's so difficult to hear you. And can you give us a bit of an update on the capacity trading platform due to kick off in March?

Yes. The new capacity trading and also auction platforms, so there's 2 platforms that will be in place. That new market starts in the 1st of March, so 2 weeks away. We've been working along with the industry and the Australian energy market operator through market testing. And that's gone, for the most part, well. And I think the whole industry is ready for a 1 March start. From an APA perspective, we feel pretty confident that we'll be ready for the operations 1 March.

The big question there to be answered with much interest, is who actually uses it?

That was the next leg of my questions. What type of volumes do you think might go through?

This is my answer: zero.

Zero, that's pretty good so far. Just to expand a bit on the earlier question on the U.S. There's certainly lots of big projects on the East Coast of the U.S., big pipeline projects and transmission projects that are looking for additional partners. Would you look at chunky assets like that or are you looking more, say, in the gas gathering or midstream space?

There's the difference between definitions of midstream between what we use here in the U.S., but we're certainly looking more at the traditional gas transmission assets and distribution.

I think as Ross said earlier, we're wanting to get the right business, if you like, that provides us an opportunity to develop the business over here rather than a joint venture or a part of an asset. So that's probably about it.

And the last one for me, just can you give us a little color around the WORM project?

Can you unpack the WORM project please, Rob?

The WORM project is an abbreviation for the Western Outer Ring Main, and it's approximately 55 kilometers of pipeline, on the main throughout Victoria, outer Victorian system, which once constructed will ensure that there's sufficient line packed closer to the city will support security, supply and also power generation in the Victorian market.

Okay. So reasonably small.

Your next question comes from Nathan Lead, Morgans Financial.

Just a further -- just on the new assets, you're saying that they're going to contribute $70 million in FY '19. Maybe I missed a bit, but how much did they contribute in revenue in the first half?

If you look at that 13.8 and divide it by about 75% or just about 75%, I suppose, that will show you what it's got. Sorry, the only reason I said it is I don't really have it off the top of my head.

Yes. And the $215 million of incremental revenue, that's purely margin-generating revenue, isn't it? There's no like pass-through elements, et cetera, to that?

No. That's what we've said now for a couple of results presentations. That $215 million of revenue is what we expect to be approximately, the annual run rate of revenue from all of those projects that you see on that list. So a full year's annual revenue from each of those projects should add to $215 million a year. So it's not $215 million over the $70 million. The $70 million is already is part -- is some of those projects and a portion of the year for some of those projects. What we're saying is that $1.4 billion worth of projects we think will give us annually. And you'll see from the slide, we expect to be fully commissioned on everything by 1st of July. Annually, it should give us about $215 million of revenue.

And can we use the same rule of thumb, Peter? The 75% EBITDA margin applied to it?

Again, Nathan, that's the number we've sort of talked about over the last 18 months-or-so since that slide's been out. When you do look at our assets, we tend to be between sort of that and maybe a little bit higher in terms of EBITDA operating margins.

Yes, I just wanted to check and make sure that hasn't changed. Next question, statement of cash flow. As I'm looking at the investing area, it looks like there's a $125 million loan going to a related party. I didn't see any chat on that in the briefing, so could you just provide a little bit of color on that, please?

Yes. It's sort of we didn't really chat on it because it's not that material to us. But what we did during the period between the 1st of July and the 31st of December is that between ourselves and risk, we decided that with RISC being our partners in the CS joint venture, we decided that we would take the banks out of the funding of that business. If you think about what banks are doing in this market and some of the pressure the banks have been under, looking to move funding away from the sort of smaller corporate area, possibly more towards domestic business where they've got better margins, we were seeing that reflecting in higher cost for CS that we just didn't think were warranted, given the nature of the 2 shareholders. So we decided that we're better off to take the banks out and RISC on ourselves jointly funded CS going forward.

Is that going into senior debt or shareholder lines and you're going to put senior in later?

No, there's no debt in the business. It's in the senior debt.

Okay. And just a final one. Just Ross, just on the North American market. I mean, North America is U.S. and Canada. Can you sort of talk about what you see as being the material differences between those two markets, if there is any?

We can talk about North America, but I have to say, FX at the moment at the U.S. and we only have a small team. And we look at the U.S. first and if we need to look at Canada then we will. But there's certainly more opportunities in the U.S. in terms of the depth of market versus competing with some of the big guys up in Canada. And we quite like the gas supply dynamics and the regulatory environment in the U.S.

Your next question comes from Rob Koh, Morgan Stanley.

Sorry. I think I might have pressed that one twice by accident, so no additional questions. Sorry, about that.

That wraps up all the questions I've got for you today.

Okay. As Rob said a second ago, I think that's the last one, unless Rob's pressed the button again. Thanks very much for participating in this morning's results presentation. And the team and I look forward to catching up with you hopefully in person in due course. And if this is my last results presentation, thanks very much for that number 28, I think, many years of support for the business or most -- some of you -- most of you supported the business. The rest doesn't matter, does it? So all the best and we'll see you on the traps in the next few weeks, few months. Thanks, folks.