AGL Energy Limited

Good morning, everyone. This is Chris Kotsaris talking from the AGL Investor Relations Team.

Welcome to AGL's Half Year Results Presentation for the Six Months Ended December 31, 2019. Agenda for this morning's presentation is as follows; our CEO, Brett Redman, will shortly present an overview of our results and the business update.

Then be followed by our CFO, Damien Nicks, who'll present more detail on the results before handing back to Brett to comment on our outlook. At the end, we will open for questions.

[Operator Instructions] I'll now hand over to Brett.

Thanks, Chris and good morning, everyone. Our 2020 half year results reflect a disciplined approach to executing our strategy and operating the business amid increasing challenges.

Profit is down year-on-year as per our guidance but we are nonetheless, tracking ahead of our expectations. We are making our portfolio more resilient and growing our customer base or delivering disciplined cash and capital management outcomes.

Underlying profit after tax was down 20% in the half, primarily due to the outage of unit 2 at AGL Loy Yang, increased appreciation following record levels of investment in recent years, and the impact of market headwinds relating to the wholesale energy process and reduced gas volumes. We have declared an interim dividend of $0.47 per share consistent with our policy of paying out 75% of underlying profits over the full year.

Throughout the period there have been many positives; evidence of how we are building a stronger broader business amid ongoing uncertainty of our sector. Customers are responding positively to simpler crossing and the investment we'd made to make it easier for them to do business with us.

Energy customer accounts were up again in the period by $36,000 to more than $3.7 million. The acquisition of Southern Phone as is another 160,000 broadband mobile services; and our reinvestment in large business electricity customers is also delivering growth.

In generation, our output was up 3% in the half despite the Loy Yang outage, reflecting our efforts over the past 12 months to invest in plants availability and coal supply. We're also expanding and modernizing our energy portfolio.

We announced two major grid-scale battery deals in the half at Wandoan in Queensland last month, and with Moaneng across New South Wales in October, and we commissioned the first new gas capacity in the national electricity market for seven years at Barker's Inlet in South Australia. We refined our growth strategy to focus on connection orchestration, trading and supply, and generation.

We've made targeted acquisitions in support of our strategy by Perth Energy and Southern Phone. Our continued strong cash position, both from an underlying performance and capital discipline point of view, has enabled us to complete 51% of the share buyback we announced in August 2019 while maintaining ample headroom to support investments in the business.

We're announcing today that we expect underlying profit after tax refi '20 to be in the upper half of the $780 million to $860 million range to which we guided last August, while noting that headwinds remain as we look ahead to the FY '21. I'll now cover our key metrics for safety, customers and people.

These are trending in the right direction but there is always still more to do. In safety, the total injury frequency rights for the half has marginally improved across employees and contractors at 3.5 per million hours worked, but it is still too high and requires continued focus and investment.

For customers, net promoter score is substantially improved compared with recent years although disappointingly, the score did not improve over the past six months. Our objective remains to continue to improve and we're encouraged that our net promoter score surveyed against specific events and transactions is positive and trending upward overtime.

There is no new data on engagement for our people with the next enterprise-wide survey scheduled for the second half. Now to the financial highlights of the result; statutory profit was up 11.4% to $323 million, reflecting a lower negative fair value movement than in the prior corresponding period, just a lower short-term forward electricity process year-on-year.

The reduction in underlying earnings was consistent with the guidance we gave at the 2019 full year result in August. There was a material impact from the Loy Yang outage, depreciation and market headwinds, as I've already discussed.

And despite resilience in the period, average wholesale electricity prices were still down, customer pricing has come down on average, and gas volumes and margin are down in a tight operating environment. Consequently, underlying profit was down 19.6% to $432 million.

The cash result benefited from a strong underlying performance and a reversal of net margin calls in the period. The interim dividend declared is 15% lower than the prior corresponding period, this is a smaller reduction than for underlying profit, in part because of the benefit of the share buyback reducing shares on issue.

Return on equity was down 1.9 percentage points to 11.2%, reflecting lower earnings again with some mitigation from the buyback. My next slide covers the Loy Yang outage in more detail.

I think we turned utility safely to full operation, we are now in a position to confirm the financial impact for this year, and estimate the insurance proceeds that we expect in next year. To recap, after the initial generator failure in May, it became apparent following a full assessment that a full generator repair and state of rewind would be required which would take seven months.

Although we completed the repair and rewind process larger than schedule in mid-December, following the initial return to service we found cracking in one of the units too cold reheat heaters which meant we needed to undertake more boiler repairs before we could return the unit to full service. The final impact of the outage to our FY '20 underlying profit after tax will be within the $80 million to $100 million range we've provided in August.

The reason that the earnings impact was so large as it has a loan marginal cost as a result of supplying its own brand coal; so any loss of generation translates to significant loss of cash margin. We expect to receive the benefits of insurance claims in FY '21 and expect the net benefit to be broadly consistent with the quantum of the FY '20 impact.

Looking ahead, the insurance market is becoming harder for ageing thermal coal assets; this means AGL will pay rising premiums at the same time as retaining greater risks through higher deductibles. My next slide focuses on the resilient performance of the rest of our fleet.

Total generation sold to the pool was up 3% to 21,793 gigawatt hours. Our increased availability and output enabled us to offset some of the extended costs of the Loy Yang outage.

At the same time, wholesale electricity process were stronger than we expected, albeit they were lower on average than the prior corresponding period. The biggest improvement in output was at our Black Coal plants driven by operating investment in plant availability and removing bottlenecks from the coal supply chain.

The calendar year just ended was a record for coal deliveries to AGL Macquarie of more than 13 million tons, up by more than 1 million tons; this is a result of our major focus on working with train rail operators to improve the availability at our anti-unloader. More capacity gives us more opportunity to use lower costs contracted coal and reduce our use of more expensive spot coal.

Elsewhere in the portfolio, there was some reduction in hydro output following high generation last year and drought-related constraints. Generation from our wind assets was up as a result of output from Silverton and Coopers Gap.

I'll now turn to my CEO's scorecard which covers our strategic priorities of growth, transformation and social license, as well as the operational goals which I've already discussed. We presented our growth pathways of connection, orchestration, trading and supply, and generation at the Investor Day last October; we have acquired Perth Energy and Southern Phone in support of this strategy.

Our core energy customer base is now up more than 100,000 accounts over the past 18 months, and is bolstered by the platform for multi-product retailing which Southern Phone provides. This is one way we are transforming the business building a broader customer base more resilient to a transitioning bracket, but at the same time as we expand and further diversify our generation fleet and becoming a leader in both residential and grid-scale battery projects.

In social license, we are a founding member of the energy charter reporting publicly on our ongoing commitments to improve affordability and service delivery for our customers. We have supported our people and communities through the recent bushfire crisis, and we know that this is only heightened financial market and other cycle [ph] concerns in relation to climate change.

So I'm pleased with the progress we are making in delivering on our commitments to enhance reporting under the task force for climate-related financial disclosures framework. And I continue to believe that developing new energy supply is the best way that we can support lower prices for customers over the long-term.

And with the development of Coopers Gap, Silverton and Barker's Inlet, we have delivered $1.6 billion of new plant. Now let's focus on our growth strategy.

Connection is primarily about exploring opportunities in mobile, broadband and the connected home as data and energy continue to converge. Our acquisition of Southern Phone has provided us a scalable platform on which to build a multi-product offering.

Orchestration is primarily about the value we can create through a network of distributed energy assets. Our virtual power plant continues to expand, trading and supply is about our DNA in trading energy and all its forms, our proposed LNG jetty at Crib Point is a key project in which we see enormous potential to make the gas market more dynamic while our growing grid-scale battery portfolio builds optionality into our electricity portfolio.

Generation is about developing flexible, dispatchable assets that can support the ongoing transition of the grid to renewables. We're proud to have commissioned Barker's Inlet.

We have added the Kwinana Swift power station to the portfolio by the Perth Energy acquisition, and we are progressing approvals for the New Castle power station. At the same time we're continuing to invest in our core asset base to improve its flexibility and reliability, and in November, we will reach the halfway point in the 100 megawatt upgrade of the Bayswater power station.

My next slide looks at the growth momentum we're seeing in our core energy customer base as we progress our journey to becoming a multi-product retailer. The chart to the left shows that we have achieved net growth of 102,000 customer accounts in the 18 months to December 31, 2019.

Overall churn in market activity has reduced, with customer retentions down over the 18-month period reflecting higher levels of customer satisfaction. We've also seen a reduction in ombudsmen compliance of 16%.

The customer experience transformation program is delivering better service and customers are responding positively to simpler offers. We now have 750,000 customer accounts on our simple AGL's essentials plan, and call center volumes are down 21%, and we're staying focused on providing all customers with the best rate for them.

The chart to the right shows where more growth can come from. Our core energy customer base is increasing from a mature position and there are pockets of meaningful growth opportunity as we sell more services to more households in more places.

Throughout our customer base, there are considerable opportunities to provide more customers with services such as rooftop solar batteries and demand response. Western Australia remains a growing market for us; and of course, there is data with 160,000 services Southern Phone provides giving us a platform for multi-product offers nationally.

Now let's turn to transformation and specifically, our progress in batteries. As we said at the Investor Day, we are now at the dawn of the battery age, and we are taking a leadership position at both, grid and residential style.

This market is now the tipping point with the opportunity to leverage following technology costs and government support for investment. The Wandoan South battery partnership announced last month with Vena Energy will be one of the largest battery projects in the country, complementing our energy position in Queensland through the Coopers Gap wind farm.

We announced in October our innovative derivative agreement with Moaneng giving us a call on capacity at a fixed price at 450 megawatt batteries throughout New South Wales. We're already operating the Dalrymple battery on the York Peninsula in South Australia, and we're progressing potential projects at Broken Hill [ph].

Our virtual power plants, residential and small business battery program now has more than 1200 participants and capacity of greater than six megawatts. Consumer interest is accelerating and we are responding; for example, through the very competitive Tesla Powerwall offer we launched earlier this year.

Another way we are getting customers access to smarter energy solutions is via demand response. Today, we are announcing we will expand our peak energy rewards program to other states before next summer following successful trials in New South Wales and Victoria.

The power program with 8,000 customers in New South Wales and the support of ARENA, AEMO, and the state government enabled customers to earn bill credits by reducing their energy usage at coordinated times a day. On average, participant saved 30% on their usage during peak events.

The expansion is entirely AGL funded and follows the successful expansion into Victoria in December. There is no cost to customers for participating in the program.

Transformation is also about flexible generation supply. We were delighted late in January to accept full operational handover of the Barker Inlet power station adjacent to the AGL Torrens site, near Adelaide.

BIPS, as we call it, is a flexible 210 megawatt geofuel Gas peaking power station with fast-start generation suited to an increasingly dynamic market. It assists in balancing the steep movements as it can occur in wind and solar supply, and is flexible - the flexibility frees up gas for use in other parts of AGL's portfolio.

The proposed [indiscernible] units will occur starting later this year through to September 2022. That is consistent with the deferral that we've put in place last year to help offset the impact of the Loy Yang outage over summer.

In social license, I want to acknowledge the efforts of our people in supporting our customers, communities and each other during the recent bushfire crisis; this response began at the start of the crisis last November. The AGL portfolio has performed strongly on extreme heat days that we experienced throughout that time.

We have supported affected customers and the communities around our assets with prompt provision of targeted financial assistance. More than 173,000 of our customers have been directly affected by the fires, and we've put in place targeted debt waivers, forgiven fees or pause billing for those affected.

We've also given $150 credit for all volunteer firefighters. To-date, the building measures we've put in place amount to about $3 million in customer relief, with about a further $1 million committed through donations and work with our community partners is ongoing.

Many of our own employees, families and communities were affected because the main Southern Phone operations ran out of Maria in New South Wales; although I'm relieved to say none of our people were harmed and our assets have not been damaged. I will close this section of the presentation with this slide showing the executive team that's now in place at AGL.

When Marcus Brockhoff [ph] started as Chief Operating Officer in April, combining leadership of our wholesale markets and group operations units in the integrated energy business; the team will be fully in place. It's a team with a breadth of skills, combining deep energy experience with broad customer technology and finance expertise.

I'm excited about what Marcus is going to be able to achieve leading the new combined business, and I'm encouraged by the way Christine is delivering growth and operational improvements in customer. Not only is the team, my team now stable after a period of leadership change, it is ready to deliver with edge.

And I'm looking forward to what we can achieve. I'll now hand over to Damien.

Thanks, Brett and good morning, everyone. I'll start by explaining the reconciliation of statutory profit to underlying profit in the half.

Significant audience in the period comprised of costs associated with acquisition of Perth Energy in September 2019, and the partial impairment of their part investment which reflects revised market pricing, marginal loss factors and generation assumptions for some of the past sites. The loss in the fair value of financial instruments of $92 million in the period compared with a loss of $251 million in the prior corresponding period reflects movement in wholesale process.

Now let's look at underlying profit across the group in more detail. The period-on-period $105 million reduction in profit reflects issues we flagged to the market back in August.

The largest of these was the impact of the Loy Yang outage which had a total portfolio impact consistent within the $80 million to $100 million range we provided last August. A total negative movement in wholesale electricity gross margin of $50 million shown here reflects the offsetting benefit of a strong generation performance.

The other large impact we forecast in August was higher depreciation. This was $80 million pretext in the half reflecting recent investments such as customer experience transformation program, and capital expenditure on major outages and lot of timing [ph] activities on assets nearing their end of life.

Note that the first half impact makes up much of the pre-tax increase of the $100 million dollars we forecast for the year. That step-up in depreciation had already started to take effect in the second half of last year.

Therefore, the period of period change will be less in the second half of FY20 then the first half. Nonetheless, full-year depreciation may come in about the amount we forecast as a result accelerated depreciation associated with unplanned CapEx on outages at both Luoyang and Bayswater.

Elsewhere, the biggest movements were the decrease in gas margins due to lower volumes and lower Ico market margins on lower Elric prices. The strong offsetting factors in the period where a consumer electricity gross margin supported by stronger volumes and customer numbers despite the introduction of default pricing.

Operating costs were broadly flat, savings in customer markets offset increased plant availability and digital capability spend. Net finance costs with down find your time at the hybrid notes in June 2019.

Tax expense was down primarily because of lower profits. I want to take a moment to talk about the second half.

As a strong first half implies a lower result in the second six months of the year. Although we expect wholesale electricity margin to be high in the second half, now Luoyang Unit Two is back in service.

We expect generation elsewhere in the fleet to pull back a little. And we've experienced a number of small outages in recent weeks, combined with the impact of ongoing market price headwinds.

In addition, we expect ongoing impacts in consumer electricity from customers moving to allow it right products as well as the timing impact of the accounting treatment of bad debts which always whites to the second half. Finally, ongoing pressure across the guest portfolio, as well as the usual seasonality impact from lower volumes in the second half.

Turning now to electricity portfolio performance, pleasingly, the 3% generation increase was coupled with increases in customer volume across all categories. Consumer volumes increased in line with a continued growth in average customer accounts with weather impacts negligible to consumption.

Large business saw increases in customer load in New South Wales and South Australia, a result of customer account growth following the renewed business development effort. Wholesale customer consumption was up slightly on aggregate.

On the right-hand side of the page, you can see the wholesale electricity margin, reflecting the Luoyang outage and offsetting performance elsewhere. The increase in consumer margin reflected a lower transfer price because of lower wholesale prices.

The group operations cost increase reflects the availability investment and depreciation trends upgrade sleep [ph] disgust. There is enhanced disclosure in the portfolio manager reporting section of the operating and Financial Review on fuel and generation running costs, as we flagged investor day last October.

We will continue to evolve these disclosures for the full year as part of our approach to integrated reporting. The gas volume reduction is consistent with recent trends with a continued decline in large business and wholesale customer volumes due to the loss of customers amid continued tight supply conditions.

Lower consumption led to a reduction in consumer volumes. A lot of customer accounts were up.

Consumer margin was impacted by a combination of these lower volumes and customers switching to lower price products during the period, including the introduction of the guest safety net to reward loyal gas customers with lower rates. Also, a large business continues to experience a loss of customers as a result of tight supply conditions.

Please note for completeness we are now including guest production and storage earnings in a guest portfolio margin. These earnings improved due to reduction in cost and increase guest sales at the mobile joint venture.

Looking at operating expenditure in more detail, last year's full-year results, we said we're going to have year on year savings and we're still on track for that, excluding the impact of newly acquired companies. At the half, we are flat excluding the impact of Perth energy optics, meaning we are offsetting inflation.

The savings are largely due to customer markets, the largest benefits being the non-recurrence of major debt forgiveness initiatives we undertook in the prior corresponding period. Lower market activity also met lower variable costs supported by the benefits of an investment in the customer experience transformation program.

Offsetting the savings we had increased spending group operations because of the Luoyang outage and the continued deliberate investment in plant availability. We've also created the future business and technology unit which is driving deliberative innovation, long-term business development, ongoing digital transformation and data analytics capability.

This expenditure will be offset in margin growth and see gains over time. Finally, we continue to see increases in insurance and regulatory costs reflecting our aging, similar assets and the heightened regulatory environment.

The net cash outcome of $135 million is a record that the first half driven by strong underlying cash generation working capital improvements. The positive impact from margin calls reflected the recent day traces in the electricity process, meaning we needed to keep a lower margin balance in relation to our net cell position in futures markets.

The movement in other working capital also improved reflecting reduced inventory growth at IGR Macquarie as a result of a call supply chain efforts, and positive time impacts between the periods relating to the purchase and surrender of green certificate. The text cash flow of $5 million net of tax installments and a refund receipt for the prior year, as well as the utilization of tax losses at Luoyang.

Cash conversion, excluding margin calls is close to 100% consistent with a historical performance, as you can see on the graph to the right. My next slide is a good visual representation of capital management and financial and funding position.

We've now undertaken just over half of an app share buybacks, and we intend to complete it in the second half market conditions permitting. As a result, net borrowings have increased.

We undertook our first sustainability link loan in September 2019 following the repayment of the hybrid in June of last year. We might tend to scope to invest in the existing business and new growth opportunities while continuing to manage capital efficiently.

I will close my comments by providing an update on the plans for enhanced TCFA reporting. We committed last year to provide an analysis of at least one scenario in which the objectives of the Paris Agreement emit, and global warming is kept to no more than 1.5 degrees above pre-industrial levels.

This is one bookend of the scenarios we're modeling. The other thing no change to current policy settings in Australia.

Other scenarios were modeling reflect other potential pathways to deliver meaningful emissions reduction. In all cases, will be extending our modeling further than before, at least to 240 and using comparable verifiable data from the IPCC and AEMO as starting points for modeling with KPMG assisting us as an independent advisor.

The resilience of our business to the physical risks of climate change is also being considered in our scenario analysis and reporting. I'll now hand back to Brett to wrap up.

Thanks, Damien. I'll now wrap up by providing an update on our current views on the wholesale electricity and green certificate markets and on our fuel cost outlook.

You recall we spiked our full-year result in 2009 saying about how these market headwinds would affect our earnings in the short to medium-term. I'll start with the wholesale electricity market.

Although down on average on the product corresponding period, spot process, in fact proved reasonably resilient in the half, and we were able to benefit from this because of our strong generation performance. However, there has been a sharp contraction in flat swap process in recent books.

And as a result of low approved process in the first quarter of this calendar year tonight. The first quarter is often a volatile month the spot prices because of the emphasis on system availability over summer, so the current flat swap pricing may be slightly depressed compared with a three-year view.

But while that may mean some risk to the upside in the short-term, the long-term trajectory remains for prices to continue to trend down as more supply comes on and demand remains flat. We expect over the next few years processes to try it in the $60 to $90 per megawatt-hour range.

In the green certificate market, where the large scale renewable energy certificate process has been resilient other recent months, the first outlook remains prefer the falls. We still expect certificates to maintain some value and we are watching the market closely in the context of demand for carbon offsets, which may create a conceptual floor for Elrick process.

Now, I will turn to a few cost outlooks and our evolving sourcing strategy for black coal and gas to mitigate impacts from material contracts and market price trends. As we've discussed, gas input costs lower in the half because of lower volumes, meaning we sourced a greater proportion of guests from lower costs, legacy contracts.

While constantly contracting is lower at present, and it has been for some time as a result of a fall in global gas prices, it is still materially hard than at a time when we struck these all the contracts. As a result, the outlook for I guess sourcing costs to continues to average up in coming years.

We continue to look at the most efficient ways to source gas to support the lowest possible prices for our customers and to increase competition in this market. We're progressing the proprietor’s crude point LNG import terminal, working through environmental approvals, and expecting to reach your final investment decision during the 2021 financial year.

When we do come to that decision, we do expect the timing of delivery of first cast and the overall costs of the project will have been impacted by the increasing complexity of the project since its first inception. Nonetheless, even with potentially lighter gas and higher costs, the economics of the project remain potentially very compelling.

Our average cost to black hole in the half just gone was greatly aided by the call supply chain improvements I discussed earlier. I'm confident the investments that we've made in logistics management over the past 18 months will continue to benefit AGL.

Nonetheless, escalation will still occur on existing contracts. And there are gradual step-down in volume from the very cost-competitive legacy contracts we acquired with makara [ph] generation in 2014.

Of course, black coal services AGL McCory, not ideal Wang, where we provide our own brand coal at a very low marginal cost. So, the market headwinds in our traditional business remain.

But we are executing our strategy and operating the business in a disciplined way against the challenges. Building a brick by small diverse business, characterized by many relatively small initiatives is all about growing our resilience in this transitioning world.

If I reflect on our progress in recent months, we are now connected to more than 27% of Australian households and I'm confident we will continue to expand the breadth, number and quality of our services. We've added broadband, mobile and battery offerings to our core electricity and gas services.

And this will enable us to provide more value to existing and new customers. Geographically, we are more diverse than ever, with a meaningful presence in Western Australia, an increasingly physical presence in Queensland, and a stronger regional presence to build on via Southern Phone.

Finally, as our traditional base for generation fleet approaches the end of its life, we are developing a more modern, more distributed portfolio of nimble, more dynamic energy supply using fast start gas, batteries and other technologies. It remains an exciting time to be in the Australian energy industry, and I'm confident AGL with its broadening customer base and asset portfolio is extremely well-placed to thrive.

To close; the outlook reflects our solid performance relative to the known challenges. We expect underlying profit after tax for the full year to be in the upper half of $780 million to $860 million range.

This reflects the offsetting impact of our strong portfolio performance in customer growth on the impacts of the Luoyang adage depreciation and market headwinds that we expected. Those headwinds remain as we look into it FY21 but our cash generation continues to be very strong, supporting our robust financial position and the anticipated completion of the share buyback.

We'll now take questions.

Thank you, Brett. [Operator Instructions] Our first question comes from Tom Allen from UBS.

Please go ahead, Tom.

Good morning, all and congratulations on the solid first half result, obviously, amid fairly tough market conditions. First question, can you please provide some further detail on the bottlenecking work undertaking to get better call supply into the margin assets, and what work you've done to optimize the physical dispatch out of those margin assets?

Again, I'm interested in whether there's new arrangements you described with rail operators will continue and is the higher output from those assets of the first half than you run right to expect going forward.

Thanks for the question. Yes, it was a lot of work done not only with the rail companies on sort of improving the supply logistics, but there is maintenance strategy and operating sort of strategies put in place within the coal yard and coal belt handling systems to improve not only availability and reliability, but to removing single contingency failures and just optimizing the whole operation and maintenance of the coal yard and coal handling systems.

And then Richard can sort of comment on some of the work we did with the rail transport system.

I thought that we - cancelled training so we actually don't end up losing the work we've done; so it's always cost coals [ph]. So it's a real focus, making sure we could actually take all the trains that are coming in and get them to sign and that allows us to really improve both output at the McCorey side and pickup generation but really keep our lowest price coal coming into the portfolio by not canceling train services, bit of assets through my team and Doug's time just to really work out the value of those investments and make sure the plant could take the coal when they arrived.

Okay, I think that's clear. So that sounds like that this should be a new run rate, I guess on that physical output from as McCorey assets going forward.

Looking at your coal supply charts on Slide 36 of your presentation, you're forecasting relatively flat Matt, Jen customer loads from a flat FY21 to FY22. And then not that one of your units it would bill will close in March '22.

Do you think that the base would have been better ramp up that put an offset that impact?

Those forecasts when you look at the level of win penetration; the issue that we have with on the Liddell units is they're not very flexible. So they actually take a lot of when the wrong base load generation, so we'd run them and just run them flat, right?

When we take our Liddell units off by actually means a lot of days water units are actually doing the offloading to actually make space for the middle unit to run flat. So we're reducing that offloading off the base, what is through that period.

It will be driven by the level of wind penetrations that market so it's all subjected to change anyhow much renewables gets pulled into that market up into that.

The next question comes from Ian Myles from Macquarie Group. Please go ahead, Ian.

Hi, guys. Chris excellent results as well.

Can you talk about on the generation side Newcastle when you need to make a decision? And I think last time we spent lots of talk about hydro.

I barely saw a word hydro in the presentation. Is this sort of an update where those plans are?

Very good questions and I think in terms of Newcastle, I kind of remember what we've said in terms of Tom, your feelings towards the back end. What you saw in the early 21, I think it is that we'll be getting to on a five-day point there.

We're actively out talking to potentially PC suppliers and looking at crossing port. So that's a big area of focus.

Look, just to probably preempt a couple of questions. In this presentation, we've rearranged a little bit just some of the growth pipeline things that we've been presenting for many years; so we just felt some of the slides were getting a little bit tired and we've brought a few things into focus for this presentation like the batteries work.

[Indiscernible] remains a major focus for us. In the previous pipeline slides and presentations, it was always something that was going to take some years to develop.

You might have seen the owners of the [indiscernible] talk about some of the challenges that we've had in trying to settle arrangements there. So I'm saying that in the funnel of opportunities become a little more difficult in terms of bringing forward.

On the other hand, I think Muscle Brook in New South Wales remains an excellent spot for us to be looking at. But that one's more phase more for the mid-2020; so pumped hydro, my mind very much up there with batteries.

But in a speed to execution sense, batteries represent something you can get market much quicker than what padrone is because hydro is a much longer more convoluted approvals process and business case preparation versus a battery site simplistically, you can get up and running quite quickly by comparison.

And just on the battery side, can you - you talked in the past about burning cost of battery [ph] being $20 to $30. Now I appreciate batteries are so complicated base, but are they - in assigning of the KPIs which you are achieving, are you still expecting that that is the sort of price you're getting or are we saying that decline?

I think what I found interesting with batteries is a year or two ago, I talked a lot about I thought that'd be on balance sheet, I thought about them in relatively simplistic terms and that's somewhat reflected in what you're asking me there. And the lived experience with the other battery projects that coming through, things like FCAS [ph] services are becoming a big part of the revenue and profit streams to make those critical projects work.

So, in these early days of the dawn of the battery age, some of the early projects are much more complex bundle of revenue lines and profit streams to provide different market services as they get up and running. I think once we get a few years in and the cost of batteries comes down to reliance upon government subsidy becomes a lot less and if you like the first movers have picked up the things like the sky service benefit, and the lighter movers are more focused on the time-shifting of energy.

And the benefit who comes with it will see it start to be more focused on that comparison, the gas peaking, if you like. In a costing sense; so, I think that sort of $20 to $30 is still not an unreasonable number that thinking about, it will narrow from there.

[Technical Difficulty] So, if you could imagine, renewables is going to be a lot cheaper and the burning cost is going to be a lot more expensive; it's not just a $25 price per say, it's a bundled price.

Okay, that's good. But the orders of magnitude of the same, the detail that was swirling around in a project by project sensors, we're getting these things moving.

Thanks for you. The next question comes from Rob Koh from Morgan Stanley.

Please go ahead, Rob.

Good morning, guys. Thanks very much for the pressure.

And let me also congratulate you on the final result. Can I just make sure that we understand how the 80 to 100 mil Luoyang impact is reflected in these results?

I guess does that include the little extra delay in January? And also, when we turn to the insurance recovery next year, which you said you should you're expecting to receive all of that.

Does that mean that you're climbing the full 80 to 100 or what I guess I'm estimating as a net impact of closer to 50, if that makes sense?

Thanks, Rob. So, I'll just briefly talked about it.

The number of given you is for the full impact that FY20. So it does include that small period in January, noting it wasn't big.

When you think about from an insurance perspective, what we're saying is the insurance broadly offset that impact noting that the outage went from the '19 year into the '20 year as well. And obviously, that's also going to be net of deductibles.

Okay. So does that mean that you're climbing the full 80 t0 100 plus the little bit NFR '19?

Or are you climbing the net impact because you've obviously reduced that net impact through the extra generation [indiscernible]?

So just to be clear, so the impact of Luoyang will be the overall impact but it was out of the market, we had offsetting generation, the rest of the fleet. So that's offsetting the result for the half.

When we think about the insurance climate, just noting it is subject to ongoing commercial and sensitive matters with the insurance. That will be the client on the outage for Luoyang over the period of '19 and '20.

Okay, all right. Thanks, Damien.

And another question if I can, thanks for the extra color on fuel procurement over the next few years and the gas of the culture. It's a clear.

Can you remind us how much gas contracting you've got left to do?

I'm looking at Richard but I think we as always will somewhat dodge that question because of the commercial sensitivities. But Richard, do you want to give a more elegant audience?

We have been active in the market. We've been buying gas to fill the gap.

We've also left a little bit of spare in, given where the prices up. So with the portfolio just changes over time, I think the current fall in the gas prices is likely to sustain for a little while, given what's going on the international markets, we will use that opportunity to pick up some more gas.

But what we're trying to focus on is, if we can source gas, where can we sell it to? And how easily can we sell it?

So, we'll look at things like business customers and trying to push some more gas with the business customers and if the gas price will pick up some regeneration. We're not buying a fixed volume because we can flex the portfolio around what gases are available on what prices both throughout generations, our business customers late.

So in answering your question, we've got adequate gas in the portfolio and we'll adjust our buying depending on market conditions.

The build I'd sort of put on that answer to is we've been talking about it for a little while now. What we're seeing in the gas market, I think is a market trading much more like the electricity market nowadays.

So while we have still some really nice significant legacy contracts that will go on for many years, so people were saying them from presentations in years past, the old KGC positions are still there, and they're very competitively priced those contracts. For the rest of the portfolio, you're seeing it more moves to bit like in the electricity market, where it's more on a three-year horizon with the decline sort of through that horizon, and constantly layering in from different sources.

And the way we've been positioning our portfolio with a particular emphasis on story. So Wags is really starting to come and why not is starting to really come into its own over the next year or two.

We've got the Newcastle guest storage facility, other optionality like that. We're leaning into storage and optionality that allows us to have a flexing wrong portfolio.

So it will take time for gas price market change to roll through that portfolio, but it will be rolling through not dissimilar to what happens in the electricity world nowadays.

Okay, right. And that's not a dodgy answer at all.

Thanks very much. It's very helpful.

Just a final question, I guess you could refresh management team now all in place for coming into place. And should we be anticipating any kind of segmentation of the accounts?

What you will expect for the end of June will be simply in summation, if you like, of proof box of wholesale that's how we'll look at reporting 30 June but you will still see the details of proof box and wholesale.

Thanks very much for Damien because this will come up a lot. I would think of it as just adding a new subtitle of wholesale and operations with assignment made tile, rather than I rearrangement of the detail, which I know creates issues of just keeping the spreadsheets off today.

Thanks, Rob. And next question is from Pete Wilson from Credit Suisse.

Please go ahead, Pete.

Good morning. A comment on operating costs if I could, so they are up 5% of your strip-out PSAP [ph] one-off.

I mean it's fair to say this missing targets was said a few years ago, and we're still not getting any benefit from the significant capital investment in digital amante [ph]. So I'm just wondering whether we should all start reassessing expectations for declining total operating costs in the next few years.

I'll take that one, Pete. Look, what we've said and continue to say, we will have year-on-year cost savings as you look forward to the end of this year.

We are seeing the benefit of the work we did, particularly digitization of CXT coming through and customer markets. And combined with that because of the law of market activity ensuring you're starting to see that flow through the books that insurance down around by 16%.

And we are managing hundreds of millions of transactions per item. So that digitization is absolutely important as we continue to look forward and evolve our products and services.

I would say that the money we spent on CXT and other system upgrades is paying for itself and will continue to pay for it as we look forward.

I wish we say that because on the waterfall you put in on Slide 22, the only negative cost is reduction in market activity and then only the other ones are increasing cost including investment in digital data and RT. Where are the savings in CXT in that waterfall?

I think much of them coming through that reduction in market activity we haven't hasn't said broken there any further, best way of seeing it because things like call volumes are down, I think 19% in the call center. That's one of the big ones.

And that piece, therefore, because digitize means we can start to really see that costs come out of the organization.

In effect, fair chunk of that just reduced market chin?

It's absolutely a combination of both. And we've always said that market activity as it comes out before a cost will also reduce at the same at the same right.

Okay. So in FY21 we should still be expecting a reduction in total operating costs.

Shouldn't we?

The customer box business. Yes, that's right.

The entire business?

We're not going to come into FY21. What I've always said is we'll have year-on-year cost savings for this year.

We will provide guidance into the markets when we get around to the August results.

Okay, fine. Thanks.

Good morning, everybody. Just a question about the insurance climate, this might be a relatively simple question; but do you intend to include that in underlying earnings for whatever guidance you might provide for '21 which would therefore main - it's one when $80 million to $100 million in 2020 costs and add that amount into next year so it could be an uplift in the order of about $160 million to $200 million in an underlying impact, everything else being flat?

I'll pick that one up. In absolute isolation, directionally that would be correct in the sense of having Loy Yang to running the full 12 months next year as it will clearly step up earnings and banking the insurance premium next year which we will include in ordinary results because we'll be flagging it well in advance, and it's really the recovery of a loss of operating profit over the last little while.

But I just caution as you're thinking about it - we also see the wider thematic of our business and the headwinds that we've been exploring in detail for some time now. So I just caution overemphasizing one part of what will be a complex transition of numbers from this year to next year.

Yes, got it. But it will be included in underlying, so - like, we can make assessments of what we think, possible process is going to do and margins are going to do and everything else but in terms of being included in underlying that we - you will include it in underlying earnings?

Yes, that's right. So in a simple fashion, in fact, in a simple answer, when you do your waterfall [ph] from this year to next year, you should include an underlying and estimate of insurance recovery subject to settling and recovering from the insurance company but that's our expectation.

Okay. The other thing I just wanted to ask is we've seen a notable slowdown and the rollout of renewals; partly due to the marginal economics, we've been reading all sorts of newspaper articles about these things struggling under the economics - the economic outcomes.

And additionally, perhaps exacerbating these problems are the issues in terms of getting connections for the grid and MLFs and all sorts of stuff like that. I was just wondering, in the context of the comments you made about wholesale prices continuing to be under pressure; do you think that there is going to be a continued rollout of renewables on the basis of those marginal economics?

I do. I think compared to what we might have forecasted a couple of years ago for this moment coming, I think we're seeing a lot less renewable projects coming through because I think the next - I will guess couple of years it will be colored by those that are looking to build renewables, trying to work out what the economics of connection will be.

So - and that's sort of moving beyond the more usual discussion about what do you think price will do and how does your project stack up. So because of the struggles with all new renewables projects, including our own that we've been completing through the past in recent months are struggling to get on and are struggling to maintain their forecasted loss factors, they are forecast in loss.

It's introducing a lot - large amount of uncertainty in the business cases when new projects are being proposed; and that really weighs on project, so only the really best projects there are sort of making it through I suspect investment committees in different organizations, whereas before the more average ones could get up because you have confidence around the loss settings and risk factors. Inevitably, less supply coming on must mean less downward pressure in the shorter term on pricing but at the same time, you know, what you're also seeing is the emergence of lower priced gas into the market.

And I think that's going to have the sign with no greater impact on those forward price outlooks because suddenly local LNG producers, in particular, are trying to work out what to do with gas, and you're seeing more of it starting to be pushed towards gas bar generation. So I think the reduction in gas prices that are starting to emerge will have a balancing effect maybe - compared to what a slower take up with renewables might have been doing in forward processing.

Okay. Maybe just one last, if I can just throw in another question.

Given what gas prices have done, would you not think to contract as much as possible at current prices?

There is always the - what you would like to do and what's available in the market; so I'll use the electricity market as an analogy. There are moments in time when you look at the forward curve three years out and think, "Wow!

That's just moved $20; I think it's just over moved and it doesn't make a lot of sense. I want to go out and fill my boots at that price."

And the reality is, there is not a lot of volume necessarily available; it's potentially the same thing in the gas market. The gas that we might need in the very short-term to the extent there is a gap, we've got the spot markets as much as the contracting markets where we can fill that gap where we look at pricing two or three years out.

And this is hypothetical; even if we think that we might like to fill up on what might look like cheaper prices, it doesn't mean producers are necessarily going to rush to offer those prices. There is often a question of liquidity in the forward price outlooks that you see, and different participants in the market waiting for better days whether that's up or down in price, it depends on your viewpoint.

Okay, thanks so much.

Thank you, Chris. Yes, just a quick question on - sliding there at Crib Point [ph].

And you're talking about the timing and cost that's likely to be impacted by increased complexity, and now you don't have the additional late event, I'm talking about the timing of when these things come on and the cost of them before I think you talked about FY '22 as far as Crib Point and $250 million. I'm just wondering, when you talk about and what's changed there and is there enough updated kind of timing and cost of that project?

I think the main thing there is, it continues to - I guess, take longer than we might have expected to adding four months ago. As we move through approvals processes and get all the underlying agreements and alike that we need in place to progress that project.

And we haven't recrystallized what we're saying in time and cost at this moment, so we're not really at a position to provide a fresh forecast. The next milestone is in April/May where we put on public exhibition, the environmental impact statement; that will be the crystallization of the current phase of working with different government departments for approvals.

So once it goes on exhibition, it will go through a process of taking onboard public comments and public hearings; and then it will move into the final stage of both, department and ministerial sign-offs but loosely might take through to the end of the year. So I think until we see the next milestones as when we go through public exhibition and get a sense of - where the project is sitting.

And then finally, when we get - what I hope to see is fire approvals around the end of the year and any conditions that might come with those approvals. I think we're signaling that we are seeing a longer timeline than what we had seen in the past, and inevitably, that must weigh a little bit on cost but we're not at a point yet to crystallize it.

I will say though, I continue to think that this is a really good quality project and the reason I think that is the Southern market; when you really bring it back to what the customers and markets made, the Southern market needs more gas, it unquestionably needs more gas and this project represents a good way of getting that gas to market. So I continue to believe that this is a project that will see the light of day but it's a journey - and it's a journey that's very respectful of the local community and what we need to do to get that project approved.

All right, thank you. And just one quick one, just related to that operating costs under the waterfall and some of the increase in costs as the investment in digital and data, and the product or technology.

So if we're already getting an uplift in DNA through the customer experience transformation and there is other uplift in operating costs; I was just wondering what parts of the business is that increase in cost coming through that $12 million and the $5 million on that slide?

So, Damien here again, James. Look that is largely sitting in what we call the future business and technology area whereby we continue to put resources in there and the ongoing digitization, product development but also the analytics capability.

As tested earlier, we have hundreds of millions of transactions a year and that for us is a way we think there is real value to go after. Ultimately, the benefit will then flow through to - if you like, the customer markets and the group operations passing the business as we continue to work your way through the use of data and analytics.

Thank you.

Thank you. Just a quick question on the second half additives that were mentioned; notice that the output from Bayswater seems to have been a bit low over the last few weeks.

Is that related to backing out Liddell potentially being preferenced in terms of output? I think Richard mentioned that before or is that an ongoing mechanical issue?

Look, I think - now in the last week or two we've had a couple of outages [indiscernible], and I think you've had two or three data once in the last 24 hours. Look, I would see that as more in the wreck-mole [ph] of running our plants; there are moments in time when just normal outages, if I can put it in that way of all the plant can sometimes coincide.

And so we've just had - after a very good run in the first half, in the last few weeks we've had a couple more - the normal outages that are relatively short-term in nature, coming through in that plant. Again, broadly, the devil's always in the day challenge, describe it as reasonably normal; and by and large, the group ops team have done a great job on the really big days in the market, and just sort of lean into those plants and nurse those units when we need to - to keep them available for in the market where we needed it.

Which means right now there is quite a benign price in the market; whether its benign prices roll down, we're taking the opportunity to be a little extra cautious as we're seeing potential outages to just tighten a few things up.

Okay, thanks. That's it for me.

Thank you.

Thanks. Good morning.

Just a quick question on gas business, and obviously, stocking and rig contracting has obviously been - rig contracting maturity process; we put a size that acknowledged squeeze on that part of the gas business. I guess you've contracted your two contracts with the Gibson Basin JV last year, pretty near the peak of the pricing cycle.

Should we think about where prices are now? Does - I mean, clearly that puts downward pressure on wholesale prices at FY '21.

Should we think about that being more than negative than the ability for you to potentially buy some cheap gas on the market and push it into some of your contracts? I guess i.e.

since you started this Gibson Basin contracts; has your outlook for FY '21 for the gas business go better or worse given what's happened to that process?

Look, I think we're possibly getting into an element of detail that we don't normally forecast. What I would say is, a little bit like my comments earlier on about how the gas markets taking on lot of similar characteristics to the electricity market.

We're both purchasing and rolling two or three years since - we're also selling in a role in two or three year sense and so we have - so you know, are coming through on similar timelines. And we're managing a portfolio where we had a couple of contracts picked up at the moment in time that you mentioned but we have other longer term ones that remain at lower cost and other sources of supply.

But Richard, did you want to add?

Just add to what Brett said, we've got a portfolio of gas contracts, some of them more expensive, some of them shaping with pickup as we go, as we build to following matchups where we solve. But fortunately, we're not stuck with some major upstream production with very, very high costs associated with them; so we have fairly good position to flex the portfolio.

Okay, thanks.

Thanks, Chris. Just a quick one.

With the change in wholesale prices, mine standings that kind of gets reflected annually through tariff adjustments for residential customers. I remember back in 2017 when electricity prices took off, there was other guys who was talking about a delay of - for business customers; it's kind of three years for that to flow right through to business tariffs.

Is that still the way to look at it for - with wholesale prices going the other way now is that still the way we should look at business tariffs and how they get passed through?

I'll take that one. I think when you think about portfolio, what we were saying in the past was - we mentioned business customers signing up from anywhere one to three year deals, depending on which time of contract they are on.

Therefore, every three years they were recontracting, so that's that position; whereas consumer customers are - we're recontracting that process every year as opposed to therefore wholesale process which we used to say overlook 7 to 10 year title [ph]. So that was the conversation, that hasn't changed, depending on the length of the business customer contracts will depend how often they are recontracting but I think that's a reasonable assessment.

No, this is the opposite in some ways to what we were talking about a couple of years ago as processes were arising. On Slide 20, we gave a breakup of where volumes come from.

And it's a good way to think about it, we're looking here optically about a third or little under a third of consumer sales - consumer sales pricing is reset once a year. Obviously, it's caught up a little bit in demo and video processes nowadays but it kind of resets once a year.

Large businesses customers typically contract two or three years; so that would take two or three years to fully flush through any change. Wholesale customers, which are a large chunk there, they include things like the desales [ph] and the smelters, there are examples where they have very long-term contracts that might have things like CPI style adjusted and other adjusted in them but they move very slowly compared to market move.

And I think that's still the same way as the wholesale market is starting to resettle down, the same way we described how to think about it going up is probably valid in how to think about it as it starts to settle.

Thanks, guy. So despite prices being high, business customers with still - there is no real change to that two to three year average kind of contract length?

No. I don't know Christine, if you wanted to add to that?

So still - there is still typically contracting on that kind of horizon.

Okay, sure. And then, just one last quick thing if I can - just in terms of the wholesale portfolio; I think that you talked a bit about the availability of hedging even if you wanted to do it, a little bit earlier answering another question.

But was it - was there any additional hedging from a wholesale perspective taken out - kind of looking into FY '21?

Well, I would say we would never answer a question detail on how we're hedging. I'd simply think about it as - on the three year horizon, as you get closer to now within the one year out, we typically are fairly highly hedged.

We are managing risk at the edge of the three year horizon, it tends to trial-off quite a bit and in between is a never ending review if you're like the trading team - about how to make sure we're managing risk and the wide frame [ph].

Okay, thanks. Thanks very much, everyone.

Thank you very much for having me on. Just a couple of questions; the battery projects that you've identified at Broken Hill and Liddell - what's going to be the context for those and judging by your earlier comments on the conference call, Brett, it seems to be basically about the storage and arbitrage.

And do you have any sort of time factor on those?

So, I think what colors - almost all new generation projects of all stripes; I mean - as generally, each project will have a unique story and makes it a little harder to answer questions in a sweeping sense, so you tend to have to be a little bit project specific as to why they might get up. Broken Hill; that's an example of - we've got a bunch of renewable generation at the end of a long skinny line at Broken Hill that's struggling with loss factors to get on to the grid.

So I see most likely a business case emerging there that will be partly stabilization services, and partly, just time shifting energy into different parts of the day where currently there is a lot of renewable energy getting choked; and if we can move some of it to different times of the day, we should see a business case emerge there. Look, Liddell is kind of at the opposite end of the grid, if you like, it's right in the middle of lots of transmission and lots of generation; so there I suspect while there will be some stabilization that might be a new business case, I would speculate that we might say it's business case looking more into time shifting and intraday trading almost to make that one work.

But Broken Hill is probably more advanced because I think the market need is crisper and clearer. So I would be more hopeful that one cracking through sooner rather than later.

Liddell being much more in the center, therefore the market need is lesser, it might take a little longer to get the economics of that one working.

Is there a timeframe though on the Liddell's battery in the sense that you're closing down or tend to close down the last two units by 2023; so presumably it would be in place by then? And one, on the subject of Liddell, I wonder if you can offer any comments on the late report from the task force which identified $100 million a year cost to keep two units open?

On the timing for Liddell battery, I don't have a particularly exact data, I've seen in early stage if your lack of assessment. I think as we go through Liddell closure, that will be part of the triggers in the business case to make it work.

I'd like to see if the battery project is up there sooner rather than later, but I emphasize its early days and some of the shifting sands that are going on in batteries right now is full in cost. And if we suddenly see a step forward in cost in batteries, we'll be able to move quicker.

If it takes a lot longer to see cost spoil [ph], it might be a little slower. But I don't want to directly couple it with Liddell closure simply because I'm hopeful of seeing it happen sooner rather than later, so we're looking into the opportunity there.

On some of the recent press around Liddell, I don't want to particularly comment on some of the numbers and things that are being talked about in the papers. All I'll say is we've been very upfront with both, the public and government about the age of Liddell and the challenges that we face operating that plant.

We've responded to requests from government and look very, very hard at extending Liddell and as a result we've extended it from 2022 to now 2023; so that gives the market another summer to prepare for change there. Longer term, we previously publicly talked about very large amounts that would be needed to spend to make that site safe and to deal with some deep operational issues that are around safety and around just continuing to allow to operate given that's a 50-year old plant and our belief that we're not seeing that as economic moving forward.

So nothing's really changed in where we're seeing that plant shift, even as we continue to engage very proactively, very collaboratively with both, state and federal government, in talking about where that site sits, answering questions that were asked where the policy of answering any questions the government asked us while at the same time just planning full transition on that site.

Okay, thank you. And just one point of clarification, sorry if I'm taking too much time but just the proposed last Liddell battery; I can't quite remember what it was now but doesn't [indiscernible]?

It's more generic but on the site itself, I think simplistically, I could see thing located on the Greater Macquarie site. We've got a lot of land there and there is a lot of transmission lines obviously connecting into that site.

So I'm not sure when you're done [ph] - I'm not sure what we've actually roped off a particular point on this side - I would say probably inside. I'm inside, so sorry - we saw that much.

That will be the natural place for it whereas the pump hydro in that region must be driven by where the mine voids that we can use to do pump hydro and twice a bit away from our Macquarie site as possible.

Okay, [indiscernible]. Okay, thank you very much.

Thanks, Chris. Let me have another one.

So, I just wanted to ask a question; I guess it's following on a bit from Bruce's question about how the repricing flows through the book. So a drafted demo actually has an increased wholesale cost allowance across New South Wales; and I know that you guys have actually lowered your internal transfer price.

I'm just wondering if you could give us some color on how we should be thinking about that demo repricing impact through the book?

I think you're talking about the transfer price between the two previous halves because I'll be transferring the price if you do it in the back half, it went from about $93 down to $90 between the two halves. And when we look forward, we'll - well the draft team is now out so that will then form part of our pricing going forward into July 1 but that work is still to go forward if you like.

So, I think you're comparing transfer prices from previous halves; we will obviously then have to look at what our wholesale pricing is as we look forward.

Yes. Okay.

Thanks, Damien. Appreciate it.

Thanks to you, Rob. And thank you everyone for being on the call.

We appreciate your interest and your time, and we look forward to meeting many of you over the next few weeks. That ends our call now.

Bye.