Mick McCormack - Managing Director and Chief Executive Officer Peter Fredricson - Chief Financial Officer Ross Gersbach - Chief Executive of Strategy and Development Rob Wheals - Group Executive, Transmission Sam Pearce - Group Executive, Networks and Power Nevenka Codevelle - Company Secretary and General Counsel

Paul Johnston - RBC Capital Markets Simon Chan - Merrill Lynch James Byrne - Citigroup John Hirjee - Deutsche Bank Peter Wilson - Crédit Suisse Ian Myles - Macquarie Group Nik Burns - UBS Investment Bank Nathan Lead - Morgans Financial Rob Koh - Morgan Stanley

Good morning, and welcome to APA's 2017 Full 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 Ross Gersbach, Chief Executive of Strategy and Development who will be presenting our financial results and strategy in detail. I also have some of my executive team here to assist in answering any questions, in particular Rob Wheals, Group Executive, Transmission; Sam Pearce, Group Executive, Networks and Power; and Nevenka Codevelle, Company Secretary and General Counsel. Turning to Slide 3; as usual, I'll kick off with an overview of our results for the financial year 2017, highlighting key activities and achievements. Peter will then run through the numbers in detail, including our FY'18 guidance, before Ross concludes with APA's outlook and strategy in the context of the dynamic energy market that we operate in. What we've done in FY'17 confirms that our long-standing strategy of delivering connected and sustainable energy solutions that are safe, reliable, innovative and cost-effective achieves a better energy future for Australia and all of our stakeholders. At the end of the presentations, we'll take questions from analysts only due to time constraints. I've set aside time outside of this call today to talk to media individually. Let's turn over to Slide 4. We have a clean result, with no significant items in either this or the prior year's results. It's great to be able to report increased metrics across the page. Revenue increased by 14% for the period, and EBITDA increased by almost 11% or $140 million. Net profit after tax increased by 32%, and operating cash flow is also up 13%. APA's board declared a final distribution of $0.23 per security yesterday, taking the full year 2017 distribution to $0.435 per security. That is an increase of 4.8% over last year. Distributions per security have increased nearly 23% over the last five years. In addition, franking credits of $0.02 per security will be allocated to this final distribution. Now turning to Slide 5; the slide shows the high-level snapshot of our results. APA's interconnected energy infrastructure across the nation continues to deliver reliably and cost effectively. In particular, FY'17 saw further increases in the number of multi-asset, multiservice contracts that we have with our customers. We continue to add strategically important assets and expansions to our network of energy infrastructure assets as we invest to insist -- to assist our customers in getting energy to their customers and operations across the country. Our centralized Integrated Operations Center facility continues to generate operational safety and financial benefits from having real-time visibility across transmission assets throughout Australia. Integrating engineering, commercial and system operations in daily decision-making has allowed for better outcomes for our customers both, business as usual and during unplanned market disruption periods. In order to deliver operational efficiencies, the network's business is also moving to a national functional structure from what was a geographical division of diverse responsibilities. APA's pipeline of projects, excuse the pun, reached a new high during FY'17, as we announced $1.2 billion worth of new committed projects. As you can appreciate, capital-intensive projects take a long time to agree with customers and get to a point of signing, so it is a testament to the APA team for their tenacity and ability to have achieved such a significant level of project agreements in just 12 months. Despite the environment-depressed commodity prices and much noise from energy policy discussions, we've worked consistently with our stakeholders to bring these projects to commercial reality. I think the commercial negotiation of $1.2 billion in new committed projects in a single year is proof that we continue to work together with our customers and other stakeholders to deliver more energy reliably and affordably. I will elaborate on each project a little later, but first, I'd like to touch on the some of the immediate impacts we are making in the East Coast market. On Slide 6, we have listed the tools that APA has at its disposal that are enabling a more liquid and affordable gas market. We are focusing on the East Coast of Australia, given all the media headlines on this side of the country. To the left is the infrastructure. We've been investing for years to create, expand and increase capability of our pipelines and other energy infrastructure on the East Coast of Australia. We are continuing to invest in that infrastructure with more connections to come. And to the right are the services or what I call the smarts of the business. Ongoing investment in and development of both the infrastructure and services is required to achieve the best possible and most effective solution. Our asset footprint, diverse skills and innovative service solutions allow us to be well positioned to facilitate a better energy future for Australia, and we continue to invest in both energy hardware and our smarts to the benefit of both our customers and, ultimately, all energy users. Turning to Slide 7. The commissioning of three LNG export projects at Gladstone changed the demand and supply balance of gas on the East Coast as these projects have resulted in the trebling of gas demand almost overnight. This occurred against the backdrop of production forecasts turning out to be quite optimistic. Thus, shortfalls have needed to be met from the domestic market, and we saw gas moving in a northerly direction for export. In recent months, however, we have been able to facilitate agreements to reverse that flow south, delivering more gas for domestic users in the southeastern part of the country. We have recently entered into an agreement with one of the gas-fired power stations in Queensland to facilitate electricity generation at that plant. We have entered into a new contract with the Roma Brisbane Pipeline that will support gas being delivered over 2,500 kilometers in South Australia to the Pelican Point Power Station. Flexibility in our existing contracts on the South West Queensland Pipeline has seen that pipeline flow in a westerly direction towards the Southeast Australian domestic market for a number of months now. And the same for the Moomba Sydney Pipeline going forward, taking more gas down south to domestic markets. And we have reached agreement with two industrial consumers on the Victorian-Northern Interconnect that will take gas from Longford to Sydney. We've entered into short-term contracts with a number of our customers that will see cheaper gas delivered -- a cheaper gas price to users. Without APA's investment in both the physical infrastructure and system smarts, these solutions would not be available to our customers, policymakers or the market as a whole. So let's move on to talking about long-term investments that enhance the East Coast group. We have been working with gas producers to connect more gas to the market because more gas suppliers can solve the gas price crisis and bring energy costs back down. I'm on Slide 8. The Reedy Creek Wallumbilla Pipeline will enable APLNG, one of the three LNG projects at Gladstone, to bring gas directly to the Wallumbilla gas hub, and from these, into the domestic market. It's only 50 kilometers in length, but it is a big piece of pipe with 300 terajoules per day of capacity. And that's bidirectional capacity. The pipeline has the potential for significant impact on the East Coast gas market, enabling APLNG, which is already a major player, to participate more flexibly in the domestic gas market. Next, I'll talk about the Orbost Gas Processing Plant in Victoria, shown at bottom right-hand side of the slide, where we have partnered up with Cooper Energy. Cooper Energy is now proceeding to arrange funding for its part of the project. When the upgrade is completed, it will mean that nearly 70 terajoules per day of gas can be provided into the East Coast market from Cooper's Sole Gas field. There is also scope within the agreements for the plant to process gas from Cooper Energy's nearby Manta gas field and other fields that currently lie in the area offshore Victoria. This is a classic example of how APA continues to grow its portfolio by leveraging its assets and expertise. In New South Wales, the Western Slopes Pipeline will connect Santos' proposed Narrabri Gas Project into APA's Moomba Sydney Pipeline, and from there, the greater East Coast grid. This project remains subject to project FID. However, it must be noted that the Narrabri Gas Project has the potential to supply an additional 200 terajoules of gas per day. That is equivalent to 50% of the average daily demand for gas in New South Wales or around 11% of the total East Coast gas demand. It's ironic that the State of New South Wales, which is struggling the most to get access to domestic gas supply, has, according to Santos, enough natural gas to supply half its own needs. Policy must be made on the basis of facts and evidence. The science exists and appropriate processes and policies are in place to ensure that gas production can occur safely. I have no issue at all with environmental and other approvals being run on projects on a case-by-case basis. However, blanket restrictions that affect all projects, regardless of environmental merit, are heavy handed, unjustified and ultimately hurt consumers. We do need more gas supply to get to market, and simply unlocking the reserves that Australia has will achieve that. There are other opportunities that we continue to talk to our customers about. We have two separate memorandums of understanding with blueEnergy and Comet Ridge. There are significant gas reserves in the Bowen and Galilee Basins in Northwestern Queensland that could be unlocked into the East Coast gas markets. Additional gas into the market will ultimately put downward pressure on energy prices in domestic markets, including for mining and manufacturing operations across the nation. And what about power generation? We've announced three renewables projects and one pipeline plus power generation project, as you can see on Slide 9. The 80-megawatt Emu Downs wind farm that we acquired in 2011 is being expanded with the addition of a 20-megawatt solar farm as well as the 130-megawatt Badgingarra Wind Farm on an adjacent site. Both sites will leverage existing operational and on-the-ground resources. These projects have been six years in the making. We have also been working with Synergy and Alinta Energy as off-takers to these projects, but also, with the Western Australian Government and other stakeholders such as Western Power to get these two deals off the ground and the electrons into the market. This area near Perth is now an envied precinct servicing the Perth market with Mondarra Gas Processing and Storage facility and the Parmelia Gas Pipeline. Over on the eastern side of the country, we have started building the Darling Downs Solar Farm. This is where our customer relationship as well as knowledge of the ARENA funding process gave us competitive advantage. Despite being on the other side of the country, the solar farm will have the benefit of sharing expertise with our other renewable and gas side power generation assets across Australia. These renewable projects reflect execution of APA's strategy to invest in and operate energy infrastructure with long-term off take arrangements with high quality customers. The Yamarna Gas Pipeline and Power Station project will deliver reliable and sustainable energy to the remote gold mining operations of the Gruyere gold project, which is jointly owned by ASX listed Gold Road Resources Limited and global miner, Gold Fields Limited. This transaction builds upon APA's existing gas-transmission assets in this region. Goldfields Gas Pipeline, the Murrin Murrin Lateral and the Eastern Goldfields Pipeline will take gas some 1,500 kilometers to an area so the mine and the communities there can enjoy safe, reliable and cleaner energy versus the trucked in diesel generation option. It further leverages our skill in aiding and building gas fired power generation assets and converting gas into electricity at the 45 megawatt Yamarna Power Station. All of these projects are about APA achieving growth that will deliver interconnected, reliable and cost effective energy to our customers. Of course, we cannot achieve our growth strategy if we don't do the basic things right. I'm on Slide 10 now, and would like to take -- make some comments on our health, safety and environmental results. APA continues to target being a Zero Harm workplace for its employees, contractors and the broader communities in which we operate. Our injury performance this year continues to show a downward trend that is supported by the strong focus we place on health and safety throughout APA. This was the first year of our newest three year HSE Strategic Plan that aims to develop a HSE framework with systems and initiatives to prevent harm to our people and to deliver a sustainable future. We made significant progress with a number of the HSE Strategic Initiatives, including continuing the development of our SafeDrive+ program. APA also received the Australian Pipeline and Gas Association's Health & Safety Excellence Award for its SafeDrive+ Arrive Alive program. The lost time injury frequency rate at the financial year end was 0.52, down from 1.01 in the last financial year. There was one employee and two contractor lost time injuries during the financial year. The total reportable injury frequency rate for FY '17 was 7.5, a significant increase from 10.41 in FY '16. On the environment front, APA successfully completed the delivery of its two year environmental strategy and improvement plan during FY '17. This consists of initiatives that were aimed at enhancing APA's environmental management and was delivered on time and on budget. The initiatives have delivered an improved framework that standardize environmental management across APA and is also integrated with our Safeguard HSE management system to ensure consistency and ease of managing environmental risks at APA. One of the initiatives involved the development and implementation of the Environmental Training and Awareness Package. Online training was completed by all employees, with additional face-to-face training sessions to over 600 operational employees. I'm very proud to say that the success of the Environmental Training and Awareness Package was recognized at the 2007 LearnX Impact Awards. Our Enterprise Asset Management System is an integrated asset management system to enable us to deliver energy reliably and safely to our customers. It is a set of standardized processes and systems for managing and monitoring all of our assets. Through the EAM system, we gather and analyze data on our assets that allows us to plan on asset-managed cycles and make informed risk-based decisions that will sustain and improve our asset performance. Operational excellence is an important part of APA's business. Our ability to look after our people, assets and the environment will ultimately affect our organizational strategies and sustainability objectives. I'll now hand over to Peter to take us through the financial performance for the year.

Thanks, Mick, and good morning, everybody. Just moving to Slide 13; as Mick has noted, we're generally happy with the solid result that's in line with our expectations and guidance. We're seeing growth across revenue, EBITDA, net profit after tax and operating cash flow, all leading to growth in distributions for securityholders. The growth has come across the board with full year contributions from assets acquired in FY'16 and around 3% year-on-year organic growth from the remainder of the asset portfolio. We've spent close to $1 billion with suppliers and service providers, paid almost $200 million to our employees and contractors. We paid $0.25 billion in various taxes and imposts, including payroll tax, stamp duties, GST and company tax. And we paid as much in distributions to our securityholders, who provide us with 35% of our funding, as with interest to lenders who provide around 65% of that funding. All up, we are proud to be a significant contributor to the Australian economy, generally, and the energy sector, specifically. Moving to the next slide; growth in EBITDA for the year was across the board in FY'2017. The addition of the Diamantina and Leichhardt Power Stations added to Queensland's performance. The Ethane Pipeline added to the -- added positively to the financial outcome in New South Wales. Victoria was somewhat flat year-on-year, but this was not unexpected given it was the last year of the current access arrangement. And Western Australia continues to benefit from the addition of new customers, with the full-year contribution from the Eastern Goldfields Pipeline, and new customers, including the Granny Smith mine, which is now bringing gas all the way through the Goldfields Gas Pipeline to its gold mine off the EGP. The Mondarra Gas Processing and Storage Facility expansion that was completed in FY'16 also contributed more to the bottom line in WA in the current year. Energy investments were down year-on-year, but only because the previous year included both Diamantina and Leichhardt Power Stations and the Ethane Pipeline, which are now part of the energy infrastructure total. Just as important as all of the operating performance, corporate costs were returned to pre-FY '16 levels. Without the $13 million-odd of one-off costs that we incurred and talked about in FY 2016 and with increased focus on ongoing cost control, we anticipate corporate costs can be kept at or around these FY '17 levels going forward with the current business mix. Over to the next Slide 15. The risk return matrix of our business has generally not changed over a number of years now. We continue to work with our customers to provide them with what they're wanting, access to infrastructure at affordable prices. Our business remains one that is characterized by longer-term contracts in excess of 12 years on average in FY '17, underwritten by highly creditworthy counterparties, with more than 92% of our customers retaining investment-grade credit ratings, and well diversified over energy, utilities, resources and industrial sectors. The results in FY 2017 continue the theme of APA not relying on any one customer, any one asset, any one state or any one sector of the economy to deliver low-risk sustainable and predictable returns. Notwithstanding our change to CapEx guidance last year, growth CapEx again finished the year close to $300 million, and total CapEx and investment finished in the previously referenced $300 million to $400 million range. The more important aspect of the CapEx spend in the 2017 financial year was the announcement of some $1.2 billion of projects from the $1.5 billion that we did guide to at our last annual results presentation this time last year. Mick's already spoken about the main projects that make up the $1.2 billion, and we have spent close to $60 million in FY '17 on these projects already. Stay-in-business CapEx has kicked up in FY '17, with major scheduled maintenance on the Diamantina power assets undertaken during the year. Owning more of this sort of dynamic kit along with the likes of our gas processing and storage assets and our renewable energy assets will see SIB CapEx at higher levels going forward. However, even at numbers of up to $100 million per annum, this is not significant in the context of owning and operating some $20 billion worth of energy infrastructure assets as we do today. The acquisition, along with our 50-50 joint venture partner, REST, of the Origin Energy underwritten Mortlake Pipeline was the only significant acquisition during the year. Moving to Slide 17. As we have already noted, last year, we noted that we were coming off the back of a significant period of expansion for a number of customers, but that we were expecting some $1.5 billion of new projects across pipelines, renewables and the midstream sector to come through in the following 3 years. At the time, we noted that we were confident in the numbers. The timing, as normal, would be at the behest or would suit the timetables of our customers. And so it has proved in the 12 months since July last year, we've announced approximately $1.2 billion of new projects, all underwritten by long-term contracts with our customers. As I've already said, we have already commenced work on a number of these projects, and we'll spend in the order of $800 million on them in FY 2018. The important thing from our point of view is that these projects, whilst delivering little in revenue growth for us in FY '18, nevertheless add around $70 million of new revenues in FY '19 and $200 million in annual new revenues thereafter when all are fully commissioned from 1 July 2019. We continue to work with our consumers on yet more projects that we believe will come to fruition in time and deliver sustainable, low-risk, long-term growth for APA. We continue to underpin our growth strategy with a capital management strategy that supports that growth as well as sustainable increases in distributions for our security holders and maintenance of our Baa2 and BBB investment-grade credit ratings. During the year, we issued $200 million of seven year bonds in the Aussie MTN market and the equivalent of AUD1 billion in long 10 year bonds in the U.S. 144A market. The March 2017 issue of -- in the 144A market was particularly pleasing, with a book in excess of $4.4 billion offered which we were able to price another strong offshore debt issuance. As a result of this debt capital markets activity during the year, we have repaid some $380 million of USPPs that came due during the year, and we have reduced our drawn Aussie dollar bank debt to null at year's end. We now have some 1.5 billion of cash and fully committed undrawn Australian dollar bank facilities available to help fund the business and, in particular, the $800 million of growth CapEx program that we have in front of us for FY 2018. Moving to Slide 19. The debt portfolio remains in a strong position, with around 94% of all drawn facilities at fixed rates or hedged into fixed rates out as far as 2035. With average tenor of seven and half years and ongoing strong metrics relative to the requirements for maintaining our stable credit ratings, we remain confident that we can continue to access longer-term global debt capital markets as and when we need to, to fund repayment of facilities that are coming due or ongoing growth in the business, as needed. Within the senior debt portfolio, only the Japanese yen issue AUD125 million equivalent is due for repayment in FY '18. As Mick noted, the distribution for the year increased close to 5%, whilst we also paid around $20 million in cash tax that has resulted in the enhancement of that distribution payout, of $0.04 per security and franking credits over the full year. Our policy remains to grow distributions sustainably over the longer term, whilst taking into consideration the need to fund growth that is underwritten by customers and that delivers new revenues to the business over the long term. With $800 million of growth CapEx in FY '18 that will deliver growing revenues in FY '19 and beyond, we see the increase in distributions to $43.5 per security for the year just completed as supporting that policy but also enabling the retention of funding that will contribute to significant value growth for security holders going forward. On Slide 21, in respect of FY '18 guidance, we expect EBITDA to fall within a range of $1.475 billion to $1.51 billion. As noted earlier, a reasonable amount of FY '17 growth CapEx is on projects that are just beginning and will deliver new revenues in FY '19 and beyond as these projects are commissioned. We've clearly succeeded in locking down a program of asset expansions that will see new revenues come through in FY '18 and -- sorry, in FY '19 and FY '20 of the $800 million of underwritten capital spending in this coming year. As is always the case, the range in EBITDA is generally attributable to the discretionary business that we -- that our customers do with us during the year, but we feel comfortable with this range and that new revenues will begin to flow off this year's capital projects in 2019 and beyond. Expected distributions in the order of $0.45 per security reflect a lower level of growth in EBITDA and the funding of the significant organic growth program that we will deliver -- that will deliver new revenues in FY '19 and beyond. In respect of CapEx, we will spend the majority of that $1.5 billion that we spoke of last year in FY '18. With $800 million committed in FY '18 and $150 million more committed to FY '19 from these specific projects that have already been announced, we can again see in the order of $300 million to $400 million annually of growth CapEx over the following two to three year period beyond that. That capital spending will add to the $1.2 billion already announced and will continue to grow value for security holders in APA. With that, I'll hand over to Ross. Many thanks.

Thanks, Peter. I'm going to round off this morning's presentation with an outlook of the industry, including gas policy developments and our strategy. As you've heard from Peter and Mick, APA's outlook remains robust to continue to pursue our growth strategy, but the energy industry is going through a period of change. APA will continue to work with all its stakeholders, including regulators, governments and customers, so that gas and energy in general is more available and affordable. Let's move on to Slide 23. Gas is critical to Australia's energy security and affordability. It's an essential fuel in Australia's energy mix as a cleaner, abundant fuel source. This is confirmed in the Finkel review. And as the chart at the bottom left hand side of the slide shows, gas fired electricity is cleaner and more affordable than black or brown coal fire generation. Moreover, gas generation can come online quickly to meet peak demand and has historically been dispatched at lower prices than other peak generation such as hydro. So how do we keep prices down? Mick has outlined earlier this morning what APA has done to assist in bringing gas prices down, that are in deals with customers to bring cheaper gas to the domestic markets. But in the long run, more supply does need to come online. Long term investors on the call are well familiar with APA's views on this. Australia has sufficient and significant gas resources. What we have is a gas price crisis. This was the natural economic outcome of insufficient supply as well as more expensive gas production because the industry has had to drill in tighter places to get that gas out of the ground. Connecting more gas resources will definitely help with putting downward pressure on prices, and that is what APA does and continues to do well. Nevertheless, the talk of the gas crisis has put a spotlight on the pipeline sector. Over the last two years, our sector has been the subject of at least five major regulatory reviews, and we do understand the government's desire to reduce energy prices overall. But this has resulted in numerous regulatory reform interventions thrust upon our industry at short notice and with limited consultation. I will briefly focus on some of those areas. The Gas Market Reform Group has established a scheme on pipeline information disclosure and an arbitration framework which came into effect on 1st August. This group has also been tasked with establishing a secondary pipeline capacity trading platform. The trading platform builds on the work that APA has done to develop innovative capacity trading products for shippers to readily trade their capacity. The Gas Market Reform Group is also implementing the earlier decision by the COAG Energy Council to put in place an auction process for contracted but unnominated gas pipeline capacity. APA is working to ensure that the ultimate design of the auction and the pipelines and capacity which will apply are operationally feasible to execute and consistent with the policy decision to establish the auction. The time and effort that has gone into these reviews will not bring back the days of $3 gas. Pipeline tariffs make up around 8% of the delivered price of gas to the residential consumer. There has been no increase in real terms in tariffs since 2002, notwithstanding a trebling of delivered gas prices during that time. We are not the problem here. Slide 24; let me touch on a bit more detail on the Gas Market Reform Group. The information disclosure and arbitration framework involves requirements for information on unregulated pipelines to be published on each pipeline operator's website, including details of available services, pricing, pricing methodologies, cost of service and average prices paid by current shippers. Included in this will be detailed financial reporting, which will also be made public, the details of which are yet to be determined. In addition to these new disclosure requirements, pipeline operators will be subject to a binding arbitration regime. Under this regime, an arbitrator can determine the terms of pipeline access, including price, where parties have been unable to agree terms commercially. The arbitrated access prices require to reflect cost including our commercial rate of return, prevailing market conditions for funds and risk. We believe the scheme has been rushed into place with limited consultation, so it will invariably raise issues in its application. Most immediately, the issue is whether the range of flexible services across APA's East Coast Grid that we have been providing our customers can continue to be offered. The second issue is the impact of the regime on incentives to invest, both on the part of pipeliners and foundation customers. It's still early days, and the practical effect of the regime is uncertain, but one thing is for sure: we will continue to work with our customers to provide them with the services and energy solutions that they need to get gas to market. Naturally, the best outcome for all parties is where the pipeliner and the customer reach commercial agreement without arbitration. I'm pleased to say that already since the new rules were introduced, we have successfully agreed transactions with a number of customers for transportation of gas on our pipelines, with many more requests received and under negotiation. Moving on to our strategy that's summarized on Slide 25; APA is committed to delivering energy solutions that are safe, reliable, innovative and cost-effective. Our commitment is to ensure that our customers can meet their business' objectives, our security -- security holders earn secure and predictable returns, our employees work in a safe and stimulating workplace, and the communities and environment that we operate in benefit from the value-add of our services. Gas is critical to Australia's energy security and affordability both now and into the future. Yes, we have seen gas demand treble on the East Coast, but we are doing all we can to connect more resources to domestic energy markets. We are also investing in renewable and power generation to contribute to Australia's cleaner energy future. Today, we will post on our website APA's climate change statement. The statement targets the recommendations set out by the Task Force for the Climate-related Financial Disclosures recently. In the longer term, as international and domestic carbon prices and markets mature, APA's energy infrastructure assets will play an important role in reducing Australia's carbon footprint and helping Australia to meet its global commitments, as energy consumption shifts from carbon-intensive fuel such as coal to more carbon-efficient fuels such as natural gas and renewables. The $1.2 billion of growth projects that we have announced over the last 12 months show there is appetite as well as stakeholder support to continue to invest and innovate in energy infrastructure across the country. APA will continue to focus on growth of gas across gas transmission pipelines, gas-fired and renewable power generation and midstream energy infrastructure assets. And as previously flagged, we will continue to explore potential opportunities that may exist in North America. We will also continue to do what we do best at the core of our business to strengthen asset management, development and operational capabilities whilst maintaining financial strength, flexibility and capability. Thank you. And I will now hand back to Mick.

Great. Thanks, Peter and Ross. And with that, I'll open the line up to questions.

[Operator Instructions] Your first question comes from Paul Johnston with RBC Capital Markets. Please go ahead.

Just a couple of questions. Firstly, just on Slide 17, and thank you for the additional disclosure and information on the slide. It's very helpful. But just in terms of revenue contributions you present on the bottom of the chart, are they cumulative numbers or -- so in other words, that FY '20 of $200 million, do I think about in reference to FY '17 or do I add those numbers together?

Now before you do, you -- the FY '20 $200 million includes the $70 million that we would have earned from the contracts that started into the phase on -- in the first year, so yes.

Got it. So it's cumulative. Okay. No, that's helpful. And just on the stay-in-business CapEx lift up, Peter, can you just give a bit more color around that in terms of what's driving that? Any particular asset or nature of assets that you wanted to call out there in terms -- that there's some generation assets or is it some of the older pipeline assets that's triggering that lift in stay-in-business CapEx?

No. It's -- look, it's across the board, really. This business, over the last four or five years, we've spent in the order of $20-odd-million a year in technology as much as anything else, so that -- we're doing more and more of that. We don't expect to be spending more than that annually going forward, but -- so you can look at that as a base of stay-in-business CapEx as we look to -- Mick talked about the EAM system. We've got upgrades in GISs and SCADAs and all those sorts of things coming, and we're quietly working our way through a program of those sorts of things on the business and technology side of things. The pipeline side of the business is not a significant contributor to stay-in-business CapEx, and we don't expect it to be. Generally, we deal with expenditure on pipelines by way of expansions more than anything else. But we do own more rotating kit these days. The Diamantina Power Station was the major contributor to the uptick in FY '17 as it's gone through its first major refit. And those sorts of assets will continue to deliver those sorts of requirements going forward. So gas processing facilities, gas storage facilities, renewables, renewable electricity, blades that turn on top of pylons, replacement of solar panels. Those sorts of things that are things that are going to contribute more to stay-in-business CapEx going forward than we've seen in the past where we've typically had mainly a portfolio of pipelines.

Great. And just one final one on the [indiscernible]. Just on policy and the regulatory side, Ross, you made some comments there around the final rules that came into effect fairly quickly and maybe not much consultation on some sort of changes towards the end there. What do you think your options are sort of from here? I guess one that, sort of, I was thinking about anyway was the potential for APA and maybe other pipeliners to submit rule changes to the AMC maybe in short order to try and bring about some changes to those rules that did seem to come into effect with not as much thought as possibly could have happened.

Yes, thanks, Paul. I'd better do something to add to my work rate this morning, so I might answer that one. Look, on the face of it, we've been through a lot of consultation, and I've been on the record that I've recently amounted to being expedited, truncated, all that sort of thing. Look, frankly, it is what it is for the time being. The point that we've been trying to make with the presentation today is that, yes, be that what it is, we're just getting on and doing what we've always done because what we've always done has got us here. So we continue to do deals with customers, work with our customers, what's their energy issues, let's put up some smart energy solutions for them. So that's the focus, and that's coming through -- I hope you can -- I trust you can see in the results today. As to the detail of what is happening with regulatory policy and whatnot, it's simply too early to tell what the impact is because we just haven't seen it. I've made the point in recent times that I didn't see the rules in respect to the arbitration process until they'd been legislated and I'm not alone there. So yes, it is what it is. We've made much ado about it, but we are where we are, and we'll focus on doing what we're doing to grow the business. And Ross, do you want to add anything to that?

No, I just -- just really, we're focused on making sure it works as well as possible. We have a lot of work to bring together to release by the 1st of February next year on what our pricing principles are our approach to it. And -- but ultimately, our focus will be on avoiding that arbitration process and reaching commercial conclusions with our customers prior to that.

I'll just add one more comment, if I may, Paul. It seems to be lost on a few people that this calendar year we've seen gas reverse flow from going north to Gladstone to now reversing and going Southeast into the Southeastern market. So with all the reforms and meetings and whatever have you -- and I'm just quoting the Minister, Josh Frydenberg, from Monday. He noted that the spot price of gas had halved in recent months. So this is all about highering the delivered price of gas, and I think APA and, indeed, the industry is starting to see that -- some of that happen.

Your next question comes from Simon Chan with Merrill Lynch.

Two questions from me today. First one, can you just give us a feel, I guess, of how we should think about the returns for some high-risk projects versus your lower risk ones? Like, for instance, how does the return on, say, $300 million for Orbost differ versus $300 million for a solar farm or a lateral off an existing pipeline?

Simon, I honestly don't think that these things are any different in the context of the way we've thought about investment for our customers over many years. We look at the nature of the customer, the nature of the asset. We've got some basic hurdles that we need to get over, and then we sit down and we assess the risk to us as a business of the type of asset that we're dealing with, the type of contract, the length of contract, the type of customer, the credit quality of the customer, and we'll look at that from that perspective. I don't think you can say that there's a different return profile per se that would be material between one asset and another. It is about the various different risks that apply to that -- each individual investment. And it's very difficult for us to give you guidance and say, Well, our renewable asset would be x, and our processing asset would be x plus or minus something. There's a lot of things that come into what we will do here and what we accept with a customer and where the risk lies. And so very difficult for us to give you any guidance in that regard that's specific.

I mean, the other way to spin the question, though, is can investors expect higher returns for, say, a midstream project relative to your traditional lateral project?

Yes. Look, I think that's certainly generally what you would expect.

To put that into context, Simon, we're talking APA relativities here. We're not talking double. We're not taking on huge amounts of risks. We're not turning ourselves into a Penny Dreadful gold miner.

No, I certainly hope not. Just my second question. I noticed your gearing's at 67.4% now. And in the notes to the accounts, you kept your target consistent at 65% to 68%. As you said before, you've got a massive CapEx year coming up, and I know you've got a lot of liquidity. But how serious is this 65% to 68% gearing target? Or is there a chance that you'll just change it to make sure you fall within the range?

I mean, we look at these sorts of things on an ongoing basis. We're serious about maintaining our BBB and Baa2 ratings. That's what we need to maintain the metrics around, and we feel confident that we can continue to do that. In the past number of years, we've looked at very many different ways of ensuring that we maintain those metrics, and the 65% to 68% that we've given the market has been a sort of a proxy or a rule of thumb for where we sit to be strong BBB, Baa2 rather than using the rating agency methodologies for -- and leaving the market to work it out. So look, going forward, we think we've got good flexibility in the business, we've got good operating cash flow coming through the business and we're not expecting to throw that all out the back door. So from our perspective, we're pretty comfortable with all the numbers we've got out in the marketplace today.

Your next question comes from James Byrne with Citigroup.

Two questions from me. Firstly, I just picked up on the call the statement that you view the risk return profile for your business as not having not really changed over the last few years. My first question is, in the current regulatory landscape, where there's legislation being passed without consultation, and by your own admission, too early to assess the impact of some of that legislation, I'm just wondering how you can say that the risk return profile hasn't changed for this business.

Yes. We're talking about how we invest and what's in front of us, and it simply hasn't changed.

Sure. But presumably, the returns on your investment now clarify a risk.

James, I think the -- I think that we've said for a long time that -- and we use the word generally as well, not -- rather than specifically. Generally, the risk return profiles haven't changed because over many years, we've had -- we've owned regulated assets as well as unregulated assets. We've done deals with customers that have not been -- in the last three or four weeks, we've done deals with customers that we've continued to -- that are similar to the sorts of deals that we've done in the past. The risk return profiles there have not been changing. Sure, a different regulatory environment going forward may have some impact, but as we sit here today, we are still seeing the majority of our customers with credit ratings that are investment-grade credit ratings. We're still seeing the majority of our revenues coming from the big end of town, from the top 10, 15, 20 customers rather than a broader range of customers. We're still seeing deals done in sectors that are looking for more capacity. And it's in that context that we've said we believe we've got a risk return profile that's pretty similar.

Sure, okay. I'll ask my second question then, which is around the gas markets more generally. As you've noted already, seeing much more rational behavior by the LNG players that are arbitraging international and domestic gas markets. I think everyone on this call is going to have their own view on the feasibility of LNG imports into this country. But if that project was to move forward, what I wanted to understand from you is how you're thinking about the potential risks to your pipeline portfolio, particularly if you could address, firstly, any disintermediation of your pipeline network by customers, given diversity of supply increases; and secondly, any impacts to your pricing power across your network.

They're big words, aren't they? Look, I'll just make it real simple. The -- we view the potential for an import terminal as simply another source of gas, so the economics around that is in the hands of others, and we're happy -- very happy to work with others to see another source of gas come into our or get hooked up to our system. And whether the -- any such potential facility is based in Melbourne or Sydney or Adelaide or Brisbane or wherever, presumably that gas will need to get to other places in the country, and that's where the network will come in. So we -- I don't want to disappoint you or sound smart with the answer, but for us, it's as simple as that. It's another source of gas, and we'd rather have another source of gas and -- than not, particularly given the state of the market right now, James.

Sure, okay. But don't you see a risk that haulage, particularly through its Southwest Queensland pipeline, could be reduced if LNG imports proved to be cheaper than LNG players redirecting volume into the domestic market, for example ?

On the face of that, it's certainly a possibility. But then you've got to get into how much. We're talking large volumes being imported. We're talking volumes just to satisfy margin or peak demand. There's a lot of -- yes, I mean, that's what you said is certainly possible, but again, we see it as an opportunity, first up.

Your next question comes from John Hirjee with Deutsche Bank.

A question, if I may, on your guidance. At -- the guidance for FY '18 implies about 0.3% to 2.7% growth year-on-year. Compare that to FY '17, where you got 10.5%. Could you just help us unpack a little bit about how that guidance was derived? For example, are you -- what are you assuming for the draft decisions made on the VTS and the Roma Brisbane Pipeline, for example?

Yes, John, the -- look, let's talk about FY '17 first. I mean, FY '17 growth of 10%, we had about 3% organic growth across the asset base. The rest of the growth there came from a full year of Diamantina and Leichhardt Power Stations, a full year of 100% ownership of the ethane pipeline. Prior to FY '16, we owned 6% of the ethane pipeline. So the -- it's a little bit -- you can't look at FY '17 as being a pointer to the growth that might be expected for the business in FY '18 because we don't have a number of assets coming through that we've acquired during the FY '17 year that will deliver us a year-on-year kick-up. Even the Eastern Goldfields Pipeline in FY '16 we only got six months or six and a bit months of revenue; FY '17, we get a full year of revenue from that. So a lot of that 10% growth in FY '17 came from the lag effect, if you like, of us investing over '15, '16 and into '17. And we've got less of that lag as we tried to sort of point out in that Slide 17, we've got less of that lag flowing through into FY '18. Look, in respect of the various assets that are coming up for access arrangements, very difficult for us to talk about what the specifics are around those, but I think I would characterize it as saying this. What we have seen in the two access arrangements that are coming to their end, Victorian Transmission System and Roma Brisbane Pipeline is access arrangements sit at historically low interest rates and historically low return rates. And what we're not seeing is material changes from a negative perspective in respect of that. So the conditions, the market conditions, the economic conditions in the market should be reasonably similar, so I wouldn't have thought that you'd be wanting to look at it in too much different from that, to be fair.

Another question, if I may. Again, you highlighted that 100 million stay-in-business CapEx is likely to be the norm going forward. In addition, you mentioned your corporate costs are likely to be baselined at FY '17 levels, and you believe you can contain them. In terms of the 100 million, which is actually going to be a step-up from previously, should we expect that sort of to maintain for several years or just the next couple of years?

Well, I think we said up to. I think the words I used were even at levels up to $100 million. It's not huge in the context of $20 billion worth of assets. And I think stay-in-business CapEx is the sort of thing that you might want to -- I'm not sure how you're going to run your models in respect to these sorts of things, but we're not going to give guidance in respect to stay-in-business CapEx the way we do in terms of growth CapEx. So if you're going to run a number between 50 million and 100 million, presumably you'll run that over the longer term, I don't know. Some will run it over a shorter term, but we're going to have more of these sorts of assets over the longer term if we continue to invest the way we've been investing. And we've said that strategically, we like renewables, we like midstream assets, we're happy to own generating if it's underwritten by long-term contracts with highly creditworthy counterparties. And so those are the sorts of things that are going to give us that sort of levels of stay-in-business CapEx that are higher than what they have been historically.

Your next question comes from Peter Wilson with Crédit Suisse.

If I could just ask another question on the arbitration framework. I don't want to dwell on it too much, but there does seem to be a bit of a change in tone with respect to comments this morning and, Mick, your comments recently in the press versus the prior messaging. I mean, your prior messaging, if I understood it correctly, to the market was that you were happy that a market outcome had been diluted. So I'm just curious, what exactly and specifically is it that changed in the final rules that you were either unhappy with or surprised at?

That's a fair observation, Peter. Back when -- six or eight months ago, the arbitration process was pretty much, in using my vernacular, commercial arbitration processes. So we weren't too concerned about that because we had never faced an arbitration in the 30 years that I've been -- 30 something years I've been in the business. So it was all about facilitating a negotiated outcome, so happy with that. And to have a timing on that, great. Where we got to is really heading down the path of a sort of de facto regulatory sort of process with some -- involving an arbitrator that is going to use market-based returns. So I'm not -- I'm just simply making the observation where we started from, when the original verdict and direction, from my perspective, hasn't ended up there.

Okay. And I mean, you've got a very strong remaining contract duration. And there's likely to be, I guess, a period of time where the industry kind of works out what this new arbitration framework means and before anyone actually tries to use those new powers. How do you actually expect it to play out? And when do you actually think it might bite?

Well I think the first comment to be made is, you've mentioned the word industry, and the whole matter has arisen because industry has seen, ultimately, delivered gas prices doubling, trebling, quadrupling, so that's where government and others have got involved. And I'm reason -- I'm somewhat pleased to be making some observation today that what we see is the delivered gas prices into the Southeast, at least on the face of it, are on the way down, which is what politicians and others and industry, what we all want to see happen. So where it all ends up, Peter, I simply don't know. I mean, this is just a factual observation, but we don't know because we haven't been there yet. Who understands the rules? Certainly not me, just haven't been there.

And just on that point of -- this will be my last question. Just on that point of lower delivered gas prices. I was interested that you called out that you've signed a couple of recent short term contracts at a discount to the published tariff. Can you maybe just give a flavor of what was driving that? Because, I mean, if I'm not mistaken, historically, you've always priced short term contracts at a premium to published tariff.

I'm going to ask Rob Wheals to comment on that.

Yes, Peter, it's Rob here. Look, that step reference in the presentation is more to do with working with our customers as we always do, understand what their particular needs are, in time frames, looking at the term of the deal, looking at the terms of the deal and other characteristics, and then reaching commercial agreement. I think you might be referring to shorter-term services or flexible services that might traditionally have been priced at a premium to longer-term therm. But in the context of this, this is more about, as we always have, working with our customers to reach a commercial outcome that suits us both.

Your next question comes from Ian Myles with Macquarie Group.

Just in terms of your flexible revenue, is it right to say it's around about $32 million? And I guess I wonder, under this auction process, how much of that $32 million is possibly at risk through people selling the capacity via the auction?

Well, Ian, the answer to your question is, in FY'17, I think that number is sort of about right. In FY'16, it was different. In FY'15, it was different again. And the answer to your second question is that no one can sit here today and determine how much of our flexible revenues are subject to an auction process because not all of our flexible revenues might be in the future as part of that flexible -- part of that auction process, if there is indeed an auction process that sees any revenue go to anyone other than us. So I mean, we're not trying to not answer your question, mate, but the answer is that we've always had in -- within our guidance a risk to some of our revenues that might come and might not come, a risk to revenues that might not come because other customers decide to do other things between themselves. That position hasn't changed today. It's not changed by any auction process that might be put in place by others, the reason being we've always had a process where we can -- where customers can do things outside of our systems as well.

You made a comment about the Victorian-New South Wales Interconnect. You've gathered a couple of new customers there. Have you actually -- are you saying it's expanding that interconnect further, or is it just replacing existing volume?

It's just the normal course of business, talking to our customers about they need. Where we've got available capacity, we come up with arrangements that suit their needs. So those comments there were not -- in that particular slide, were not made in reference to any further expansion.

And then on your hybrid...

Myles -- Ian, sorry, that's not to rule out the possibility of future expansion of any asset. And that's -- the whole point here, we're not sitting here today with a capital program that says, in FY'23 we're going to spend $100 million on expanding XYZ asset. Like a normal corporate might have a spending plan that they're going to open 15 more stores because that's part of the expansion strategy. What we're doing, and this won't change in our business, if we need more capacity through the Victorian-Northern Interconnect because our customers want it, we'll build it. And if we want more capacity or need more capacity on any particular pipeline because our customers want it, we'll build it for them. And that model has not changed, that model will not change as far as we sit here today.

No, that's fine. I didn't think that had changed. In terms of your hybrids, is your intention to keep those hybrids, or are you wanting to actually retire them? And I guess, how does that affect your -- those gearing ratios of 68 -- 65% to 68% given the hybrids count for a portion of portion of equity?

Well, no decisions have been made on that, Ian, and we'll make decisions when it's appropriate time to do that. So we'll leave it at that.

And one final question. In WA, Mondarra sits really close to the Perth basin, and you guys weren't chosen as one of the counterparties to potentially provide services there. Is that indicative really how the market in the midstreams becoming fiercely competitive through from other participants out there?

Ian, it's Ross. Certainly, there are competitors in that space, but we look at each opportunity and put our best foot forward, and sometimes we win, and sometimes, we don't.

Your next question comes from Nik Burns of UBS Investment Bank.

Look, just two from me. First of all, on your growth CapEx guidance post FY '18,. So you have $800 million outlined for this year and then $300 million to $400 million per annum for the following couple of years. Just wondering what assumptions are underpinning that $300 million to $400 million. Is there including some assumption around Western Slopes, or is it include -- is this a risked number for you? And I guess, based on what happened in your guidance for FY '18, is there upside risk to that number?

I think it's going back to what we've done historically. We sit down at this time of the year and often during the year and look at all of the projects we're talking to people about, look in all -- look at all of the discussions that we're having with all of our customers. And we probability weight what we think is going to happen and the time frame we think it's going to happen in. And last year, as we sat down and talked about this, we weren't as confident in terms of the timing to say $300 million to $400 million this year or even -- or any more. We certainly weren't confident to say $1.2 billion this year but -- or $800 million, but we knew that those projects were around, and we've been working on them for a long time. We've done nothing different this year other than the fact that we are probably more confident that there are certain things that will pop into the book in 2 to 3 years' time as we keep going forward. But we're not talking about specific projects within that. I think that we've got a track record of delivering on our guidance and being quite accurate with it. We've sat down again this year, and we're comfortable to go back to that $300 million to $400 million over the next 2 to 3 years in the context of everything we've discussed and we discuss internally.

Okay, that's great. And just in relation, I guess, in terms of future growth as well, we've seen some recent PPAs for renewables below $60 a megawatt hour. Returns at those levels must be pretty tight. Do you see this trend continuing? Just wondering how you see yourselves positioning against, I guess, companies who have got access to relatively low cost of capital. And does that sort of -- if that trend continues, do you see that, I guess, your positioning here is more around the gas side? And I guess you flagged here there is a requirement going forward for renewables to offer firming capacity, and you see the role more around that side?

It's Ross here. On that renewables, certainly, the renewables that -- projects that we've been successful, they're certainly not at the sort of levels that you're suggesting that's out there, and we're quite comfortable with those. The renewable projects that we've been successful on, we had been working -- we had worked on those for quite a while and developed some competitive advantages around that, and that's what turned those into success. We're not going to invest in these crazy returns that I suspect are being looked at, at the moment on some of these projects.

Your next question comes from Nathan Lead with Morgans Financial.

First up, just obviously, Slide 17, with the revenue disclosure there. Just obviously at the different mix of projects to your existing LNG infrastructure business, which runs at margins of, what, 82%. Could you just sort of give an idea about what sort of margins that overall group of assets might generate?

No.

Can you say whether it's higher or lower than the existing asset base?

Nathan, I think we've sort of had that discussion earlier on that at the end of the day, we're trying to be helpful here, but we've got to be very careful. All of these contracts are signed with individual customers, and there's confidentiality involved in everything we do. So at the end of the day, we've got a broad portfolio of transactions here that include pipelines, includes renewables at prices higher than what Mick talked about and includes midstream assets. And all of the customers, the different types of customers, all of the assets are in different places in the country and the different risk profiles to the asset, so it's very difficult for us to generalize in any area like that. We've tried to give you guys a sense of what's happening here, and that's about as good as we can do to be fair.

Okay. One for Ross. Just in terms of that commercial arbitration framework, there's this reference in it to a depreciated construction cost as the basis for asset valuation. Can you just sort of give me your take on that? Is that a concern versus, I suppose, the regulatory approach with the regulated asset base growing with inflation, et cetera?

That's one of the areas we're obviously considering is to what actually that means. It's a very vague concept, and that will develop over time. But it is quite a vague concept, as I set out.

And finally, Peter, just obviously, you started paying tax this year. Could you just sort of just give us an update, given all these projects that are coming through, what you're thinking about your tax profile going forward?

I don't think it's changed from what we've said in the past couple of years. We think that, that number is sort of around up to 50 million is not a bad number. If you have a look at the accounts, I think the liability, the cash liability is something in the order of $30 million, $40 million higher this year. So that gives you some guidance.

Your next question comes from Rob Koh with Morgan Stanley.

Just going back to the flexible and as-available services that you've had a lot of success with. You had also had a broad idea of incorporating them in contracts. And just wondering if that trend is continuing, or does this introduction of auctions maybe disrupt that?

Rob, it's Rob Wheals. Yes, look, as far as flexible and as-available services, more and more -- more so at the request of our customers, we've been integrating them into what's becoming more of a trend around multi asset services and contracts with multiple services. So that's generally been the trend. As to what might be the impact on that going forward with the introduction of, as you said, the auction process, I think like we said earlier in the discussion this morning, it remains to be seen how that's going to work out going forward and how our customers see that as a secondary market service with respect to your primary market services, which has more value to them.

And I'll just add a comment, Rob. That's been one of the concerns for me with all the regulatory sort of issues floating around. It come down to two things: one, the incentive to continue to invest, that's got to be right or we won't do it; and equally, with the flexible services. If we're not going to get paid for it, the desire to actually do it is probably going to wane somewhat, so that's going to be a loss to the market.

Yes, yes, rightly so. I understand. If I can also switch to your power business, which is now almost up to 800 megs, so getting quite sizable and very successful. Is there a point at where you -- with which you can leverage that scale into the next stage of that business? Or should we think of it more as just incremental customer-based projects coming to work kind of stuff?

It's Sam Pearce speaking. The -- it's incremental. We will continue to apply our strategy that we have been successful on in finding the right projects that meet our strategy and meet our customer requirements. And we'll -- we've been very successful in the last 12 months or so on those, and we've got a number of opportunities that we'll keep looking at going forward.

And I think, Rob, as Sam's suggesting, we've started from pretty humble beginnings with that part of the business. But as it's got bigger, albeit incrementally, we've grown the skills base in APA, so now that's a core skill when we've got the balance sheet and, et cetera, et cetera, to take on any size of any power project that might come our way.

Yes, okay, cool. Would that include a coal-fired power station?

No. That's a smart idea. No, I hadn't. Thanks, Rob. I knew I come to work today for some reason. No, you can probably rule that one out.

There are no further questions at this time. I'll now hand back for closing remarks.

Great. Thank you. Look, and as that's the last question, thank you very much for participating in this morning's call, and we look forward to catching up with many of you in person over the next few weeks. So thank you again and we'll see you shortly.