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Edited Transcript of AGL.AX earnings conference call or presentation 8-Aug-19 12:45am GMT

Full Year 2019 AGL Energy Ltd Earnings Call

Sydney, NSW Aug 15, 2019 (Thomson StreetEvents) -- Edited Transcript of AGL Energy Ltd earnings conference call or presentation Thursday, August 8, 2019 at 12:45:00am GMT

TEXT version of Transcript

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Corporate Participants

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* Brett Redman

AGL Energy Limited - MD, CEO & Director

* Chris Kotsaris

AGL Energy Limited - Senior Manager of IR

* Damien Nicks

AGL Energy Limited - CFO

* Richard Wrightson

AGL Energy Limited - Executive General Manager of Wholesale Markets

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Conference Call Participants

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* Baden Moore

Goldman Sachs Group Inc., Research Division - Research Analyst

* Daniel Butcher

CLSA Limited, Research Division - Research Analyst

* Ian Myles

Macquarie Research - Analyst

* James Byrne

Citigroup Inc, Research Division - Research Analyst

* James Nevin

RBC Capital Markets, LLC, Research Division - Senior Associate

* Mark Samter

MST Marquee - Energy Analyst

* Peter Wilson

Crédit Suisse AG, Research Division - Associate

* Robert Koh

Morgan Stanley, Research Division - VP

* Tom Allen

UBS Investment Bank, Research Division - Director in Equities Research & Lead Analyst of Utilities

* Giles Parkinson

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Presentation

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [1]

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Good morning, everyone, and welcome to the webcast of AGL's 2019 Full Year Results. We're pleased you could join us. This is Chris Kotsaris speaking from the AGL Investor Relations team, and in a moment, our Managing Director and CEO, Brett Redman, will present today's key updates shortly before our CFO, Damien Nicks, goes into more depth on the financials. Brett will close out with the market update and outlook and we will then take questions. (Operator Instructions)

I'll now hand over to Brett.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [2]

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Thanks, Chris, and good morning all. I'll begin by summarizing the results, some announcements we are making today and our market outlook. It was another strong result, reflecting the resilience of our portfolio and customer base at a time of increasing headwinds. There is no question those headwinds are becoming stronger in the 2020 financial year, but we are investing in our customers, our energy portfolio and in growth, and we are in robust financial shape, hence, our ability to fund the share buybacks we're announcing today.

In the 2019 financial year, underlying profit after tax was $1.040 billion, up 2% on 2018 primarily driven by our electricity business. This has enabled us to declare record dividends over the year of $1.19 per share, including today's $0.64 final dividend. Annual dividend had increased by more than $0.50 per share since we introduced the new dividend policy in 2016.

Our focus on fairness, simplicity and transparency for the customer continues. We are announcing today the extension to gas customers of our automatic loyalty discount for households and small businesses on standing offers. This follows the provision of the Safety Net to our electricity standing offer customers in the 2019 financial year.

We're seeing 3 new major generation projects coming to production, the Silverton and Coopers Gap wind farms and the Barker Inlet gas-fired power station, and we have a further $2 billion of energy supply projects in development.

We have also announced today the acquisition of Perth Energy, operator of the Kwinana Swift gas-fired power station and Western Australia's third largest electricity retailer to business customers. And I'm delighted that we are seeing increasing customer numbers again off the back of the considerable investments we've made via the customer experience transformation program over the past 3 years.

Our guidance for the 2020 financial year is for underlying profit after tax to be in the range of $780 million to $860 million, a material reduction on 2019. This is driven by 3 key factors: the impact of the extended outage of unit 2 at AGL Loy Yang that began in May; the step-up in depreciation expense following the high levels of investment we have been making; and the operating headwinds we communicated back in May. Those operating headwinds are lower prices for wholesale electricity and renewable energy certificates, increased cost for both coal and gas and the impact of the introduction of default pricing for retail electricity. Nonetheless, our financial position remains strong, and we have ample headroom in both the fund investment and a buyback of up to 5% of issued share capital over the next 12 months.

Let me now turn to the 3 key operational goals linked to the CEO scorecard we introduced at the half year results. We're encouraged by the improving feedback we're receiving from our customers and our people, but we're disappointed that our safety performance didn't improve in the period.

The total injury frequency rate per million hours worked increased to 2.1 for employees and to 3.6 including contractors. While severity of injuries continues to lessen, we still want to see a reduction in total frequency.

Customer satisfaction as measured by Net Promoter Score improved to negative 11.1 at the end of the period from negative 22.5 at the same time last year. There's still a lot to do on this front, but the trend is promising.

On the employee front, we took an additional engagement survey in May following the first in 3 years last September. The results show a steady improvement as we aim to return to and ultimately exceed best employer standing.

This slide provides a brief summary of the financial results, the key driver of which was the performance of our wholesale electricity business. Similar to the half year, the strength of the wholesale electricity market impact statutory profit as a result of the mark-to-market of hedging instruments. The 2% increase in underlying profit was consistent with our guidance. The strong performance in electricity offset the impact of customer affordability initiatives, a deliberate increase in plant operating expenditure and a decline in gas sales volumes to business customers. This forecast at the half year results, the second half is weaker than the first half. Our cash performance was also impacted by rising wholesale electricity prices in the period as a result of higher margin calls. Dividends, as I have mentioned, have increased strongly in recent years and were up $0.02 per share for the year. Return on equity was again strong at 12.5%.

My next slide recaps the growth strategy we set out at the half year. We introduced then our 3 growth areas: one, optimize our existing portfolio for performance and value; two, evolve and expand our core energy market offerings; and three, create new opportunities with connected customers. We have been active in all 3 areas.

The Bayswater Power Station upgrade is underway, although the recent outage at AGL Loy Yang means the Loy Yang upgrade we announced in February will now start later than originally planned.

Barker Inlet will be coming into operation over the coming months, while the PARF wind projects are nearing completion. We're progressing our 2 pumped hydro options and the Crib Point LNG jetty proposal. And as announced today, we have expanded our footprint in Western Australia with the Perth Energy acquisition.

We have recently launched a bring-your-own-battery initiative, giving customers access to payments when they connect their batteries to our Virtual Power Plant, and we will soon launch a similar offer to new battery buyers.

And of course, we have been active in our exploration of how best to establish a presence in broadband. The takeover offer for Vocus earlier in the year was a result of considerable customer research into what customers want from AGL and how we could add value. We're confident AGL can continue to evolve as a multiproduct brand across energy, data and related products and services.

The Perth Energy acquisition is a strong strategic fit for AGL. The business is the third largest electricity retailer to business customers in Western Australia, selling about 1,400 gigawatt hours of electricity a year as well as 1.1 petajoules of gas. It operates the 120-megawatt Kwinana Swift Power Station, adding further flexible gas generation to the AGL portfolio, which we see is having increasing value in the WA market. More broadly, this acquisition provides greater flexibility for our WA wholesale gas contracts and strengthens our competitive position in gas retail in the state where we now have 43,000 customers.

My next slide picks up on the continued investment we need to see in the national electricity market. We must not lose sight of the sheer scale of the opportunities as the industry transitions to more use of large scale renewables over the coming years.

Bloomberg New Energy Finance forecast $130 billion of grid scale and $70 billion of behind-the-meter investment is required in generation and storage between now and 2050. As this transition occurs, the first opportunity is in the flexibility of our existing thermal fleet. We are continuing to plan responsibly for the coming retirement of our oldest plants at Torrens Island in South Australia and Liddell in New South Wales as reflected in our announcement last Friday. But our remaining thermal fleet, Bayswater and Loy Yang A, are among the NEM's youngest, highest quality and cheapest to run plants so will be around the longest. That's why we're investing in making them more flexible and spending more on maintenance.

Renewables will continue to penetrate, but renewables alone cannot fully replace capacity without firming to smooth out their inherent volatility. As the market transitions, AGL has an opportunity to play a key role as an enabler, transitioning our portfolio focus from energy to capacity assets. Flexibility in storage will be increasingly important in a market that requires more responsive assets. As we said at the half year, we are serious about storage, and that means pumped hydro, more grid style batteries and continued expansion of our behind-the-meter orchestration and distributed energy capability and service offerings.

We have a proud heritage of Australia's largest private developer of renewables. We now want to build on that heritage and become the biggest developer of the firming capacity that backs up that clean energy.

Our development pipeline now stands at $2 billion. That excludes Silverton, Coopers Gap and Barker Inlet which are now at or near completion. Our attention is now on developing potential pumped hydro and gas firming products in New South Wales and South Australia and delivering our coal power station upgrades. The map on this slide has been updated since the last result to include the Kanmantoo Pumped Hydro option we have secured in South Australia.

As announced in June, we have delayed the timing of our expected first gas from the Crib Point LNG import jetty as we work through environmental approvals.

This slide addresses some of the challenges and complexity of managing our fleet as it transitions over coming years. The chart on the left shows generation sold to the pool in 2019 financial year, which was at near-record levels of approximately 44 terawatt hours. The continued running of AGL Torrens, a big year in Hydro and the start of commissioning of new wind projects all contributed to this performance.

The chart also shows how even when major planned or unplanned outages occur, our total output is generally quite consistent. We are managing our aging thermal fleet by investing significant amounts in to maintain its performance. Total combined operating and capital expenditure was $1 billion in the 2019 financial year, the highest ever. We had some good outcomes such as the completion of a major overhaul of Bayswater Unit 1 and the best reliability output at the Loy Yang mine in 6 years.

Due to the age of the fleet, there will always be outages, planned and unplanned, which could result in loss profit, as it will this year with the unit 2 outage Loy Yang. This outage will extend 7 months and require a full rewind of the generator, so it will have a profit impact at the upper end of our original forecast. The unit has been out of service since 18th of May 2019, following an electrical short internal to the generator, which caused consequential damage to stator and rotor components. The duration and cost of repair reflects the unique original technical design specifications of unit 2 and the extent of damage. We don't expect to recoup materially any cost for our insurance until next financial year.

Now turning to our efforts in delivering simplicity, fairness and transparency for the customer and the extension of the Safety Net for gas customers. In the 2019 financial year, we delivered lower electricity tariffs across all states, put in place the Safety Net ensuring all electricity standing offer customers got a discount after 1 year, and put in place a $50 million support package for vulnerable customers. We also saw a strong uptake of the new AGL Essentials product which now has 300,000 customers. We have announced today that we will offer a Safety Net to residential and small business standing offer gas customers from 1 September. The measure will ensure these customers who've been with us for more than 12 months are automatically receiving a 5% discount without having to shop around.

Today, 12% of our gas customers are still on the standing offer, of which 145,000 have been with us more than 1 year and will benefit from this initiative.

Before handing over to Damien, I would like to reflect on the performance over the year in the context of my priorities and operational goals. At the first half year results, my first as CEO, I introduced 3 strategic priorities: Growth; transformation; and social license; and 4 operational goals with the firm targets. The 3 strategic priorities will always overlap. Our ongoing development of new energy supply represents growth investment as well as transformation of our portfolio and is integral to our social license as we invest in Australia for the long term. Other achievements I've been particularly encouraged by in the social license area include the refresh of purpose and values, which has been of immense importance to our workforce, and the progress we are making on fairness, simplicity and transparency with customers. These priorities and goals are unchanged as we progress through FY '20, and we will continue to use them to guide our decision-making, our remuneration objectives and to monitor our performance.

I'll now hand over to Damien.

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Damien Nicks, AGL Energy Limited - CFO [3]

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Thanks, Brett, and good morning all. I'll begin with a quick explanation of the reconciliation of statutory profit to underlying profit for the year. There's been no additional significant items since the half year results. There were gains on the sales of the national assets and the development rights over the Yandin Wind Farm, which were largely offset by the impairment when we closed out the residential installation operations in September 2018.

The loss in the fair value of financial instruments of $139 million compared with the gain of $562 million in 2018 primarily reflects movements in wholesale electricity prices. Higher forward electricity prices at the end resulted in a negative fair value movement in AGL's net sold electricity derivatives. Underlying profit after tax increased 2% to $1.040 billion.

Now let's look at underlying profit across the group in more detail. We find the most useful way to look at this waterfall is by the electricity and gas portfolios rather than by operating segment as the portfolio view eliminates intercompany movements. The year-on-year increase in group profit was $22 million, underpinned by strong result in our electricity portfolio which was up $83 million. This reflects a strong wholesale market and the flexibility of our fleet. Therefore, our focus on optimizing our assets for performance and value. There was an increase in revenue from large business and wholesale customers as a result of higher contract rates.

Lower network rates and lower volumes resulted in lower network costs. The improved result in net portfolio management was largely because of increased surplus generation sold into the pool at higher spot prices. This more than offset reduced revenue from residential and small business customers, increased gas and black coal prices and the increased operating costs and depreciation of the thermal plants. Our gas portfolio was marginally down year-over-year as we continued to experience the effects of increased wholesale gas prices and decreased large business customer volumes.

The other AGL section of this reconciliation was down $52 million year-on-year. We've highlighted the reclassification of certain fees, charges and recoveries to consumer gross margin in FY '19. This was in order to improve consistency of revenue and cost allocation in our consumer business as we move to a single enterprise resource planning system. The impact on a segmental level was a reduction of operating costs and increasing consumer gross margin within Customer Markets, which we have normalized for OpEx reporting purposes.

There was also a reduction in other margin and income due to the divestment of national assets and Active Stream in the prior year. Net finance costs were down because of lower average borrowings.

Now an update on operating expenditure. You'll recall at the half year, we deliberately adjusted our focus to disciplined and value-driven spend in our plants to drive margin, mitigate risk and optimize for performance. The decision to increase expenditure in our plants was deliberate but measured. Nevertheless, we continue to drive operational cost improvements and business efficiencies.

Costs were slightly down year-on-year. And after taking inflation into account, we managed to achieve ongoing business efficiency savings of $78 million, slightly higher than the $60 million forecast at the half year results. This included labor savings as a result of the Loy Yang transition and the reorganization programs from the prior year and efficiencies achieved through the Customer Experience Transformation program.

Offsetting these were increased costs related to our customer affordability initiatives and increased well expenditure at the Moranbah joint venture. As we look forward to FY '20, we expect to deliver modest year-on-year cost reductions, and we continue to focus on improving our plant performance and managing the reliability risk of our aging plants.

This slide shows how the investment in our customer base is delivering strong results. Market activity remains intense, but our key indicators are showing positive signs relative to the rest of the market. Although still elevated, churn has decreased and so have acquisitions and retentions compared with FY '18. This is a sign of strengthening customer loyalty. And if this trend continues, it ultimately means a reduction in cost. It's encouraging to see that our consumer accounts are growing, increasing 66,000 over the past year, reversing the trend of the previous few years.

The 2 states driving this increase are Victoria, where we gained 38,000 customers; and Western Australia, where we gained 22,000. The Customer Experience Transformation program has contributed to our improving metrics and is helping drive operational efficiencies.

Total digital sales have increased 98% since FY '17, and we're seeing encouraging outcomes in eBilling and reductions in call volumes.

As we continue to drive digital adoption and enhance the customer experience, we expect further savings to materialize.

Let's look in more detail at our depreciation and amortization expense for the year and for the outlook for FY '20. As a result of our significant capital investment over the past few years, our depreciation and amortization has been rising. The $57 million increase in FY '19 was largely driven by increased investment we've been making to our thermal plant and the change in depreciation method used to our hydro assets.

The increase from FY '19 to FY '20 again reflects the investment in thermal as well as full year impacts of amortization of our digital transformation projects and the beginning of the Barker Inlet Power Station's depreciation. The increase in FY '20 of $100 million will have a downward impact on our after-tax profit of about $70 million.

This slide shows how we performed in the generation and sale of electricity during the year. Generation of 43.7 terawatt hours were at a near-record levels despite the outages during the period. This reflects the flexibility of our portfolio, highlighted by the increased generation of the hydro assets.

Residential and small business customers sales were not materially impacted by weather, with a small decrease in volumes resulting from lower average consumption due to a change in customer mix by state. There was an increase in customer numbers in Victoria where average consumption is typically lower than upstate, but decreases in New South Wales where average consumption is higher.

Large business customer volumes were flat, which is an improvement on the decrease we saw at the half year, resulting from some strong customer acquisitions and retentions. Wholesale customer volumes were marginally up from the existing customer base during the year.

I've already described the strong performance of the electricity portfolio. This slide shows margin at a segment level. Consumer margin was up due to a transfer price realignment from wholesale electricity and the reallocation of fees and charges, although as noted on the previous slide, volumes were down. Large business margin was down due to a change in customer mix. However, there was an improvement on the first half results due to customer acquisitions.

Eco markets improved due to higher generation from our hydro and other renewable assets and lower prices for on-market purchases. The group operations cost increase reflects the OpEx and the depreciation trends I've previously discussed. The decrease in gas sales volumes continues to be driven by decline in large business volumes in a supply-constrained market. Consumer volumes were also slightly down due to milder weather in Victoria and change in customer mix. There was increase in customer numbers in Western Australia but a decrease in New South Wales. Wholesale customer consumption from existing contracts increased, which more than offset a decrease in demand from AGL Torrens.

This slide shows that our gas margin has decreased. The impact of the decline in large business customers' gross margin more than offset the increase in higher contracted rates to wholesale customers. The small decrease in consumer gross margin was driven by existing customers moving to lower-priced products.

Turning to the cash flow. The trend we saw at half year has continued with our otherwise strong result being impacted by the increase in margin calls. Similar to what we saw in FY '17, this is due to the impact of higher wholesale forward electricity prices on our futures market positions. Because we manage our net long physical generation position through taking a net short contracting position, as prices rise, our positions lose value. This means there's a negative mark-to-market impact in the statutory profit and a negative cash outflow for margin calls. Margin calls generally reverse through cash receipts as positions unwind, and we expect to recoup the majority in FY '20 and the balance in FY '21. AGL is, in effect, a market maker in the electricity hedging market which relies on the liquidity we provide. We always and will continue to endeavor to provide that liquidity.

Other working capital was an outflow compared with an inflow in FY '18 due to an increase in renewable energy certificate purchases and this coal stockpile at AGL Macquarie. Income taxes were up $104 million as AGL Loy Yang commenced paying income tax as of FY '19. However, it continues to recoup tax losses.

Our capital expenditure of $939 million for the year was a record, the most significant portion was the $382 million invested into our core thermal assets to support their ongoing operation. In addition, Barker Inlet Power Station is on track to be delivered in FY '20 with the bulk of capital expenditure, shown here in orange, having been spent in FY '19.

As the dark purple indicates, FY '19 was a significant year for systems development as we have largely completed the customer experience transformation and ERP upgrade programs. You can see that there is ongoing investment in our systems in future years.

Overall, the outlook for the lower CapEx reflects some of these major programs coming to completion, although I note the FY '21 and FY '22 numbers did not include major projects yet to be approved. There are fewer planned major outages scheduled in FY '21, hence, the lower forecast for sustaining CapEx in that year.

I'd like to finish by talking about how we look at capital management. Our financial position is enabling us to return cash to shareholders through a buyback and still maintain scope to invest in existing business and in new growth.

I will start by walking through the past year, how we generated cash, how we used cash and how that influenced our financial position and funding ability at the end of the year with strong operating cash inflows, as I've already discussed, and some minor divestments during the year.

Our record levels of capital expenditure represented a significant cash outflow as did the redemption of $650 million of hybrid notes. We maintained our dividend policy and paid the highest dividend in AGL's history. We ended the year with a very strong balance sheet and an increase in our funds from operations to net debt ratio to 45% and theoretical debt headroom of about $3 billion to $4 billion.

As per our capital allocation principles, in the absence of these growth opportunities, in the short term, we returned excess liquidity back to shareholders. That is why today, we're able to announce a buyback in FY '20 of up to 5% of our shares, which is expected to be accretive to earnings per share.

Growth continues to be a priority, and we'll still have ample headroom to fund opportunities as they arise.

I'll now hand back to Brett.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [4]

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Thank you, Damien. I'd like to finish today's presentation by commenting on current market conditions and the outlook for AGL. We have previously noted that we're expecting challenging conditions and mentioned the specific headwinds likely to impact our FY '20 results. I'd like to spend time over the next few slides explaining these headwinds in more detail, including what we are doing about them.

We are well placed to push through this challenging period and set AGL up for long-term success. Firstly, I would like to cover the wholesale market and what we are seeing with forward electricity and renewable energy certificate prices.

Electricity forward curves are in backwardation as new generation projects are coming online and demand growth stays low. LREC prices have dropped significantly since the end of last year and the forward curves suggest that further reductions are coming.

As AGL contracts for FY '20 and FY '21, any backwardation of curves have been the year-on-year decrease in our wholesale electricity margins. Lower LREC prices means revenue received per certificate will decrease more than the costs to generate, and any margin flowing through eco markets will reduce.

We don't expect wholesale electricity prices to rise again to the levels of the past few years. The best way for AGL to prosper in the transitioning market is to invest the flexibility of our portfolio so we capture value more effectively. This includes our existing thermal assets, new gas peakers and securing options for hydro and storage. AGL expects underlying demand for renewable development to continue to be strong regardless of any changes to current growing scales. We've shifted in recent years to short-term PPAs to help manage risk as wholesale prices fall.

Moving on to what we are experiencing with our sources of fuel. We have spoken many times before about the tightness of the gas market and the effect on supply and prices, AGL's benefited from long-term legacy supply contracts signed when gas was at a much lower cost. These contracts are now maturing and need to be recontracted at market prices. This compresses our gas portfolio margins and increases fuel costs for our gas generators.

The tightness of supply has already resulted in a reduction in large business sales volumes. AGL's strategy in wholesale gas remains to benefit customers by mitigating supply uncertainty and providing optionality. We are securing supply with the development of Crib Point, and our gas storage positions increase our flexibility. We continue to recontract where possible. Our investment in flexible gas peakers combined with Torrens' 8 units progressively closing over the next few years means our gas demand for generation will reduce.

Black coal prices have risen over the past few years. AGL Macquarie benefits from legacy coal contracts. While these contracts aren't maturing yet, they have stepped down in volume, and any excess coal purchased to satisfy loaded market rates is well above this price.

AGL continues to optimize its coal delivery process to maximize volumes it receives under its legacy contracts. With AGL's ability to stockpile coal at AGL Macquarie, there's optionality around timing of entering into long-term contracts.

Now turning to retail. Both the Default Market Offer and the Victorian Default Offer were implemented in July 2019, representing a partial return to price regulation.

Because AGL has been proactively implementing customer affordability measures, we were well placed when regulation came into effect. Nevertheless, there will still be an impact on customer gross margin in FY '20 due to a reduction in standing offer prices. We anticipate more customers moving to competitive offers during the year which will further compress margins. Our customer base is strong and it continues to grow as we invest in it and develop new products, which should translate to reduced costs from increased customer loyalty over time. This customer base is a solid foundation for us as we continue to invest in distributed energy and explore multiproduct offerings with the connected customer.

I will close with a summary of our guidance for the 2020 financial year. The reduction in underlying profit after tax to between $780 million and $860 million have 3 key drivers: the Loy Yang Unit 2 outage; depreciation; and the operating headwinds I have discussed. We expect the impact of the Loy Yang outage to be between $80 million and $100 million after-tax, at the upper end of our initial estimate. The higher depreciation expense reflects record level of investment and is expected to deliver an after-tax impact of about $70 million. The operating headwinds in wholesale electricity, renewable energy certificates and fuel costs are likely to endure, with the LREC cost particularly impactful in FY '20. The share buyback will result in higher interest costs but is expected to be accretive to earnings per share. Guidance is subject to normal trading conditions and our usual disclaimer.

To close, we're clearly now experiencing a change in conditions after a period of very strong performance driven by major investment decisions we made several years ago. During the last few years, we've delivered strong profits, a material increase in dividends and we today announced our second share buyback in 3 years. We are now facing a more challenging short-term earnings outlook.

And as we look to the long-term opportunities that exist as our sector transforms, we should feel confident. We have a 3.7 million strong customer account base, which is growing again, churning less and telling us we're improving on what we deliver. We have the country's largest and highest quality electricity generation portfolio, an exciting development portfolio and deep and valuable intellectual property in energy trading. We're going to lean into the opportunities in our industry, and we back ourselves to make the decisions that will drive the next phase of AGL's growth.

Thank you for your time, and we'll now open for questions.

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Questions and Answers

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [1]

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Thank you, Brett. For those listening to the live webcast, thank you for your patience. We just had some difficulties loading up the slides. [We also] stick to the quality, but that should be fixed by the time [of replay].

(Operator Instructions) So our first question comes from Ian Myles at Macquarie.

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Ian Myles, Macquarie Research - Analyst [2]

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You talked a little bit about the additional flexible generation. Can you give us some timing when the FID for some of those hydro and Newcastle electricity [market]?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [3]

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Ian, I think the best guide is in the slide we put in there that showed the development pipeline, so -- was it Slide 10, which is typically sort of the guide as to when we expect projects to occur. So some of the pumped hydro projects are a little ways off. They are more in the feasibility study stage. The most immediate project is the Newcastle gas peaker where we're actively advanced in getting EPC offers in on that. The approval I think are pretty much done for the site. So by the end of this year, we should start to be in a position to look at that from an FID point of view. In between those events, surely, we'll continue to look at things like batteries and both at a high-end level and the grid-scale level, but that will be more into the next couple of years.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [4]

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Thanks, Ian. Our next question comes from Rob Koh from Morgan Stanley.

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Robert Koh, Morgan Stanley, Research Division - VP [5]

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Can I ask a question about costs? And I know that you inherited some targets, so -- and there's been media reports that you've brought McKinsey in. So I'm just wondering if you can give us some color on how we should be thinking about your cost initiatives over the next few years. And also, I guess a bit of a specific question, on Slide 17, which is the FY '19 cost bridge, there's a one-off $42 million saving. I'm wondering if you could tell us what that is, and I guess that's something that we should be putting back in for FY '20.

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Damien Nicks, AGL Energy Limited - CFO [6]

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Thanks, Rob. It's Damien Nicks here. I'll take that question. Why don't I first talk about the one-off savings. The one-off savings, there's -- 3 parts of that is the Active Stream, the national asset divestiture piece, that sits in there, so they're a one-off. What is also in there and was included in the slides is that the reallocation of fees and charges have gone to 1 ERP. So they won't be there going forward, but we've quite deliberately taken amounts to obviously not record that benefit. And then if you think more broadly, OpEx going forward, as we've talked to the market at the half year, we are absolutely focused on ensuring, yes, the folks on disciplined spending at our plants to maintain both -- mitigate the risk of plant performance but also really stepping up floor performance going forward. So what you can expect, therefore, is modest year-on-year cost savings where we are focusing on delivery around up to the [6 key] benefits and also the benefits coming out of our ERP transformations.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [7]

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Thanks, Rob. Our next call is from Pete Wilson at Credit Suisse.

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Peter Wilson, Crédit Suisse AG, Research Division - Associate [8]

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I was hoping that you could give us a little bit more color on the transfer price realignment between wholesale and customer and consumer. Was that electricity? Was it green in other costs? And where would we see it come through the line items?

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Damien Nicks, AGL Energy Limited - CFO [9]

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I'll take that one, again. Look, that was largely in the second half of the year and primarily -- or related both black and green costs, with a significant movement in those prices in the second half. We made the -- that adjustment to half 2. So that's why we always suggest look at the overall portfolio reporting. That eliminates any of the intercompany or transfer price movements, but that was certainly something we did in the second half of H2.

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Peter Wilson, Crédit Suisse AG, Research Division - Associate [10]

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Is there anything a bout the methodology that you can share with us to help us understand it? Or is it just completely arbitrary now -- from now on?

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Damien Nicks, AGL Energy Limited - CFO [11]

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As you think what's happened with LREC prices in the second half, if you think what happened with black prices when we thought about Victorian pricing, that's what's driving that change.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [12]

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I think the -- what's important, no change in method. The halfway mark, recognition that, particularly things like grain prices had changed materially and what was a reasonable transfer price under the same method at the beginning of the year, at the half year needed to be tuned. So it remained consistent, if you like, rather than move away from what we always do.

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Peter Wilson, Crédit Suisse AG, Research Division - Associate [13]

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Okay. One thing that you say is no change in method, then the next was there is a change? So I'm not quite following the methodology.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [14]

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Perhaps we'll come back to you separately on that one.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [15]

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Thanks, Pete. Our next question comes from Dan Butcher at CLSA.

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Daniel Butcher, CLSA Limited, Research Division - Research Analyst [16]

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I just had a question on churn rates. Obviously, Alinta, a couple of days ago, it's in the paper saying, they'd think churn rates fall about to half in some cases although it's still early days after the new VMO and DMO. Was wondering what you're seeing in terms of churn in Victoria over the last 6 months and in the NIM ex Victoria in the last month or so. I know that you said your churn rates are down, but you said the market's flat, which seems to completely -- what I'm literally saying is explain what you can sort of flesh out a bit.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [17]

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I think, Dan, probably part of the answer is sort of distinguishing pre-30 June and post-30 June when the VMO/DMO came in. So pre-30 June, you can see, I guess, we published a full year number, but the second half churn I think was wildly different to the full year results. Post-30 June, there's definitely been a slowdown in the market. So I think a lot of consumer are both taking some confidence in the DMO and VMO -- VDO, sorry, and DMO benchmarks mean that there's less urgency for shopping around than they might have had before, whilst at the same time, they're just absorbing what it all means. But I think that the Safety Net that we did at the beginning of -- towards the beginning of the year at electricity, the Safety Net actually that we are putting out today for gas and the VDO/DMO was meaning it's allowing customers to feel more confident that they're on a reasonable deal, and churn has probably backed off around 1% or 2%, maybe 1% in the first month of this new year. So a little bit early days. Small reduction, not huge reduction.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [18]

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Thanks, Dan. Our next question comes from Tom Allen at UBS.

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Tom Allen, UBS Investment Bank, Research Division - Director in Equities Research & Lead Analyst of Utilities [19]

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So it's clearly a difficult environment for the management to source large attractive growth opportunities. You mentioned just now in response to Ian, I think it was, that by the end of the year, you'll be getting closer to FID on Newcastle power station. Can you confirm that it's only the development approvals? Or are there other specific policy settings and/or access to a certain gas price you need to commit capital to Newcastle or any other investment in new firming generation?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [20]

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So if you like, we've allocated the capital, but we still need to make sure that the business case fully stacks up. So as we get towards the end of the year, we're going to be looking at what are the costs offered to us from EPC contractors, where do we sit in a gas book sense, and the importantly, where is market price today and where do we see it heading.

So like with any final investment decision, we will wait until the last moment to make sure we take account of all conditions and then make a final decision on that project once we have all the information in front of us.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [21]

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Thanks, Tom. Our next question comes from Mark Samter at MST Financial.

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Mark Samter, MST Marquee - Energy Analyst [22]

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Just a question, Brett, you did kind of loosely touched on some of the FY '21 headwinds that you faced. In a place currently where I'm wrong as I'm sure I am, as a simpleton, it looks to me -- I mean, clearly, the pressures in gas do intensify as the supply rolls off, but listed pretty much all the headwinds that you highlighted in FY '20, if anything on average, intensify. Can you just give us a bit of a color around -- obviously, we've got to add back in the Loy Yang outage from this year, but ex Loy Yang, is there any reason to believe headwinds in FY '21 in dollar terms would be less than the headwinds you are near we're seeing in FY '20?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [23]

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So Mark, the line was a bit shaky, but I think the focus was on how do you think about FY '21 in the context of what we're saying about FY '20.

We obviously don't project beyond the coming year in any kind of detailed sense, but what we are seeing is settling back of the market. So the big change in the last 12 months, particularly the last 6 months, has been in green/red prices. That change, by sustainably happening during FY '19, is featuring quite strongly in the FY '20 outlook. We're also seeing or the forward market is pointing to declining electricity prices. Some of that coming through in FY '19, so appearing in FY '20. But if that trend were to continue, then you would extrapolate what it might mean to our electricity margins further out. But it depends upon your view of the longer-term electricity book, but some of the effect is in there in FY '20. If the market fell further, then clearly, that would roll forward.

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Mark Samter, MST Marquee - Energy Analyst [24]

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And can we touch on cash at all? I mean, obviously, you start putting up the supply chart, but there's not very much supply added, particularly at Crib Point, it gets [delayed]. How should we be thinking about that pressure?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [25]

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Why don't I get Richard Wrightson, our EGM of Wholesale, just to answer on our gas book?

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Richard Wrightson, AGL Energy Limited - Executive General Manager of Wholesale Markets [26]

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Hi, Mark. As you know, we're working through a process of replacing the gas book. We obviously have contracts that come through, and we noted a change from the cost base of the gas book going into next year. We're in the market for more gas. We manage those margins very tightly. The performance of the gas book have actually been very good in declining volumes and pushing the margins up. We will obviously be replacing gas in the book at higher costs than historically. So it's obviously to going to roll through in time. What will be important is how we monetize that gas and through what routes to market and how efficiently we can do that to see the overall impact on the wholesale gas book. But you're right to draw the conclusions that as the older contracts drop off, we'll be replacing them and replacing them with contracts that will be at higher prices than they've been historically. That was reflected in the forecast for this coming year.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [27]

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Thanks, Mark. Our next call comes from James Byrne at Citigroup.

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James Byrne, Citigroup Inc, Research Division - Research Analyst [28]

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I just wanted to ask about costs a little bit. I'm wondering whether there's any upside risk here to cost out particularly from retail in a partially regulated environment. You said it's early days, but churn's backing off. Are you seeing price dispersion narrow which might exacerbate that? Are you seeing a reduction in discounts not only in electricity, but gas as well? I'm just trying to see whether there's actually some upside here.

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Damien Nicks, AGL Energy Limited - CFO [29]

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James, I think the short answer is it's possible in the sense that we've allowed for a little bit of that in anticipating what the VMO and DMO -- VDO and DMO, sorry, should -- could do or should do to the market in the coming 12 months.

As I said in answer to an earlier question, out of the gate, we're already seeing a drop of 1% in churn. So that kind of change, you wouldn't expect a huge read-through on OpEx. If you saw material drop in churn, then I would say that's not necessarily factored into to the OpEx outlook and there's always opportunity if activity levels dropped to do more than just what we're building in here which is the benefit of all the structural changes that we've been doing post the CXT project that we ran and the PT3 project that we ran, where we're just coming off the back of having invested hundreds of millions of dollars, that [$450 million] in total consistent development. We're factoring in the structural benefits of those changes, but activity level change, a big shift is not necessarily in the outlook.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [30]

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Also from another James, James Nevin at RBC.

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James Nevin, RBC Capital Markets, LLC, Research Division - Senior Associate [31]

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I'd just like to ask about -- so you talked about returning excess liquidity to shareholders. But even with the buyback, you still have kind of ample headroom, and talking to kind of $3 billion to $4 billion of them headroom. And when you look kind of the debt -- the CapEx kind of -- investment pipeline of kind of like $2 billion, that's quite for the long dated like hydro completing in FY '25, '26. I'm wondering is there some stage where your kind return to -- is there some sort of like a normalized targets, kind of gearing levels that you look at? And is that tied to any size -- you talked a bit more about you moving into that broadband space. When you kind to finalize how you move into that area, if it's via an acquisition, whatever way, will that be a trigger for maybe some normalized level of debt?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [32]

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So I think, James, and I'll let Damien also comment, but I think what we're doing in capital management is in many ways, continuing to roll forward on the principles we talked about before. But it is a balancing act. On the one hand, we can see huge growth opportunities in the longer-term outlook for this market, including some of the things. And we obviously had a look at Vocus a little earlier on and that didn't go forward, but we can see both in emerging markets and in traditional areas, opportunity to invest sensibly on strategy shareholders' money.

On the flip side, it is a choppy short-term outlook. So that makes it harder, if you like, as we try and think about with confidence what's the right next investment that we do. So even though maybe some of those bigger things haven't come through quickly, you continue to see smaller things appear like the Perth Energy investment, $100-odd million there, that we've announced today. So we're continuing to navigate that middle part where we first run the business well. We manage balance sheet around our credit metrics. So we continue to try and drive towards being a Moody's Baa2 credit rating, which gives you railway tracks where balance sheet gearing should sit. And within those railway tracks, we're clearly above or below, however think about it, but we have excess liquidity compared to those railway tracks.

Today, we reached a point or the Board reached the point in the last couple of days that we felt that without an immediate large acquisition or large use to that cash, it was appropriate to return some of it to shareholders through the buyback. And we continue though to develop our growth opportunities going forward so that our priorities remain make the cash, see if we can invest it profitably for shareholders on strategy. And then if we find that we are not able to do that, then return it to shareholders as we are doing in the share buyback now.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [33]

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Our next question comes from Baden Moore at Goldman Sachs.

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Baden Moore, Goldman Sachs Group Inc., Research Division - Research Analyst [34]

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Brett, I was just wondering if you could provide a bit more commentary on your outlook statements, where you said the consumer margin compression is anticipated over the next 12 months to continue. I guess that means you'll still be cycling down of the consumer margin through FY '21. I was wondering how long you thought it would take to reprice or find that rebased consumer margin.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [35]

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I think, Baden, it's an ongoing thing, and it's not trying to dodge the question, but the market environment, I guess, is relatively fluid, both around what state and federal governments are doing with things like VMO -- and sorry, VDO and DMO and also where competition is heading as well. I would say there's an immediate effect of the introduction of the VDO and DMO in the beginning of this new financial year, call it, in the order of low tens, low tens of millions of dollars, the part of that outlook commentary that we're giving. And then there remains something that is not an overwhelming amount, probably not overwhelmingly more than that affect working in the edges of those customers keep shopping for different deals. There are always some customers that are on higher, older pricing or lower discounting from years past that can potentially move to lower discounting or lower fixed-rate products. But I see that more as a smaller rather than a huge effect into the future, and it will flex up and down according to market conditions.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [36]

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Our next question comes from Giles Parkinson at RenewEconomy.

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Giles Parkinson, [37]

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Just couple of questions. The conference call kind of broke up when you were talking about the New South Wales hydro project, so maybe just a little bit on that. And secondly, I'm just wondering, your graph that shows future developments, if you look back 6 to 12 months ago, there's a few grid-scale batteries scattered around the players, 1 in the Hunter Valley, 1 up in Queensland, next to Coopers Gap, but I don't see them anymore. I was wondering if you could talk a little bit more about that, whether you don't quite see the technology measuring up or representing the opportunities.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [38]

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No, happy to, Giles. And I think the way to think about it is at the Macquarie conference presentation a couple of months ago, we had a slide headed "we're serious about storage," and that's unchanged. And so we're leaning heavily into a future that's going to need a lot of flexible generation. A big part of that is pumped hydro and a big part of that is battery. So the pumped hydro projects, we're very positive about the projects in Muswellbrook in New South Wales and one down in South Australia. We're kicking off all the feasibility work for it. And so you should see that as something which will take a while to get all the ducks in a row. But in my mind, it's less a question of if and more a question of when those projects emerge as the markets needs them.

On the battery projects, I'm not sure if on this particular slide we included them in the past. I can recall, might have been in the Macquarie presentation, we had things like potential Macquarie or even Liddell -- the Macquarie site for a battery project. If it's not having it there, it's more oversight than conspiracy. Macquarie is a natural place for a grid-scale battery installation. That's something we're continuing to look at. It's part of that broader battery thematic that talk about that batteries are coming. It's a question of their economics and how quickly do the cost for batteries come down. As they come down, different sites will become more economic, and you'll see them kicking off. So that's a big part of our future. It will phase with cost.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [39]

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Our next question comes from Dan Butcher at CLSA.

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Daniel Butcher, CLSA Limited, Research Division - Research Analyst [40]

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It's sort of maybe ask, in terms of your new power stations, you're looking at building other investments as well, what sort of return on capital do you expect for those sort of on a stand-alone point of view and sort of how you think about and sort of supporting your overall Retail portfolio as well in terms of returns you might get from those? Given we've seen pretty low returns on -- especially on some of renewable deals being done recently.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [41]

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So thanks, Dan. So again, just take the opportunity on the more immediate projects that we're looking at. The next one is Newcastle gas peaker, where we're firmly committed to try to make that project work. So we're continuing to get the numbers assembled for that and doing everything we can to get that up and running. Our investment criteria is unchanged. So it remains at 12% hurdle rate. Even when you see us engage in renewables projects, our piece of the pie, depending on how we engage in those projects, still achieve that hurdle rate for AGL. Different participants in the market will seek different returns on capital or view things through different risk profiles. But from the way we are operating the business, we continue to see that style or that level of return investment. So it continues to be part of the mantra of investment discipline as we go forward.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [42]

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Our next question comes from Mark Samter at MST Financial.

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Mark Samter, MST Marquee - Energy Analyst [43]

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Can you hear me a bit better on this line then? Or is it still breaking up?

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [44]

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Go ahead.

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Mark Samter, MST Marquee - Energy Analyst [45]

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Just a quick question. I think it be relatively easy for people to dismiss the high CapEx -- sorry, high D&A as noncash, but obviously that was cash at one stage. And if you look at FY '20 CapEx guidance, it's 100% higher than you're guiding to FY '20 CapEx a couple of years ago. When we think about that vast increased level of CapEx you spent on the business over the last couple of years to increase D&A and yet earnings are still obviously declining pretty materially, how should we contextualize? Have you got the returns on historic CapEx that you expect to do and therefore the conclusion is actually the underlying business has performed yet worse still or maybe some of the returns on that recent CapEx been a bit more disappointing than you would've hoped?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [46]

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So Mark, I think there's 2 parts of the question. We address the first part, which I think coming up in the 1 or 2 places maybe, is our actual CapEx spend much higher than what we've flagged in previous year's presentations. The -- so put against or you could say, yes, but the real answer is no in the sense that we don't forecast on approved growth projects. So if you look at the growth, the forecast slide, sorry, for CapEx that we've included in this pack in 25, we again show lower -- purportedly lower CapEx in future years but with a very clear statement. It doesn't include growth projects that are yet to get passed, FID are yet to be approved. And as I've said in, actually, in previous results presentations, I'd love the idea of coming back in the future and showing you a graph with a much higher CapEx spend if it's off the back of growth.

So to answer the second question, broadly speaking or -- not broadly speaking, all of the growth projects that we've been doing when we go back and do post investment reviews are comfortably holding their investment expectations so that those sort of hurdle rate returns we're expecting are continuing. So part of what you're seeing in that step-up in depreciation, some of it is just investment in growth projects which is great, some of it is where we've been investing in sustaining CapEx which is about keeping old plant running. There has been some uptick in the last few years around that in the cash spend which is driving an uptick in the depreciation coming through. Again, it's deliberate decision at the beginning of my tenure as CEO to lean into a bit more spend in OpEx and CapEx for sustaining purposes for those plants, and that is part of what's coming through in the depreciation number.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [47]

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Our next question is from Tom Allen at UBS.

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Tom Allen, UBS Investment Bank, Research Division - Director in Equities Research & Lead Analyst of Utilities [48]

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If management still believe in the convergence of energy and data and that strategy hasn't changed, can you share what you learned from your short pursuit of Vocus that might influence any future interest in growing your data services business?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [49]

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Absolutely, Tom. And as always, in these things, what breaks above the surface appear short and what happened beneath the surface, I can assure you, is a long gestation project process of thinking about the opportunity and how we go about it. So we remain committed to the idea that data and energy is coming together, and there are products and services emerging there that makes sense to our customers because that's what our customers are telling us. We continue to look for opportunities. Vocus was clearly a very large nut. It was a reflection part of the Australian market. If you strike out in a direction, sometimes it's hard to find opportunities because there's a small number of players. And that's going to either push it to go to something larger than perhaps ideal or maybe smaller than perhaps ideal.

Vocus has come and gone. We've emerged out the other side of that. Still comfortable with the strategy and the rationale of what we were doing there. It was priced in a value that effectively meant that, that didn't work. So we are continuing to look at what other products and services that our customers are telling us that they're looking for in this space. We're continuing to advance internally, work on how do we bring that forward. And I'd like to think in the coming months and years, you see us continuing to lean into that space in a sensible, disciplined manner.

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Tom Allen, UBS Investment Bank, Research Division - Director in Equities Research & Lead Analyst of Utilities [50]

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Okay. That's helpful. If I can be taking that one step further, can you rule out any continued interest in the smaller subset of Vocus' asset?

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Brett Redman, AGL Energy Limited - MD, CEO & Director [51]

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I think -- the best way to answer it, apart from the usual standard decrease increase and better way, we don't comment on M&A, is to say -- a more nuanced answer is we come out of the other side of what we did with Vocus feeling like the strategy was right, the thinking was right, the rationale was right. It was the price that was wrong. So if you put that together, you would say never say never on looking at subsets of assets and different assets that exist out there simply because if you weren't open to it, you'd be saying my strategy was wrong, my rationale is wrong. So that means that never say never in all sorts of assets and services that might be there. The more specific question though is, do I think that we're out there, we're prosecuting some of the things that were there. Vocus -- I would guide you to Vocus' comments. I think that's the right place to direct these questions, their public statements around they're getting on with the running their business for the benefit of their shareholders, and I respect that management team for it.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [52]

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And our last question comes from Rob Koh at Morgan Stanley.

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Robert Koh, Morgan Stanley, Research Division - VP [53]

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So I want to ask a question about LGCs and possibly also bring Perth Energy into the question. I guess you've highlighted a number of times the headwind from LGCs and in the past, you suggested you weren't interested in a short surrender trade strategy. It kind of looks from Infratil's accounts that Perth Energy actually made quite a bit of money from an LGC transaction, which may well have been a short surrender transaction. I just wondered if you could give us a sense of your strategy and thinking has changed on that front.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [54]

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Well, I'll let Richard answer, but let me say, at a macro sense, the valuation of Perth Energy is in a complicated mucking around with timing of LGCs. So whatever they've done in the past is their business, not ours. On a future-looking basis, we think that's a really nice plant for the portfolio in a good kind of nut for the WA business. In terms of that, we're just thinking about the LGC market generally. I'll get Richard to make a comment.

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Richard Wrightson, AGL Energy Limited - Executive General Manager of Wholesale Markets [55]

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Yes, Rob, we have rules out doing shortfall strategies previously -- short-surrender strategies. They have had their own way of managing the book. We will look at their book once we own that book and look at the best way of optimizing that. A bit like, Brett just referred to them, we're not ruling anything in there particularly, but we will have a strong preference for meeting our requirements in the year as they occur.

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Chris Kotsaris, AGL Energy Limited - Senior Manager of IR [56]

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Thanks, Rob, and thanks, everyone, for being on the call. This is the end of the webcast, and we'll be looking forward to meeting with you over the coming week as we meet with analysts and investors. Thanks, again, and very best. Bye.

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Brett Redman, AGL Energy Limited - MD, CEO & Director [57]

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Thank you.