Annual Results Announcement Transcript (PDF)

Meridian Energy Annual Results – 24 August 2022 – LIVE TRANSCRIPT

+Speakers:

+Neal Barclay, Chief Executive

+Mike Roan, Chief Finance Officer

Neal Barclay

Welcome to Meridian’s 2022 annual results presentation. I’m Neal Barclay, Chief Executive and as usual I’m joined by our Mike Roan, our CFO.

I’ll start by calling out a few of the highlights:

EBITDAF lifted by 2.5% and underlying net profit after tax was flat year on year. Not exactly numbers to write home about but as usual the weather provides some context for the result.

Hydro inflows for the year in total were about average, but we didn’t - and never do - receive a nice constant flow of water into our catchments. Hidden within the average numbers was huge volatility and that included the lowest Q3 inflows into the Waiau catchment for 90 years. During that time generation through the Manapouri Power Station was severely curtailed. In fact, for much of April,

Manapouri, which has a capacity of 847MW, was operating at around 80MWs.

So, given the vagaries of the weather, I think our Team did a very good job delivering positive financial movement compared to last year. Noting that this year also included a full 12 months of the repriced NZAS exit deal.

The good news is, all droughts eventually end. We’ve had plenty of rain in our catchments over the last few months, and we are heading into FY23 with better than average storage in the tank.

The sale of our Australian business was probably the most significant achievement for the year. We realised a $214m gain on sale. And more importantly the sale proceeds of $740m have substantially boosted our balance sheet capacity to invest into New Zealand’s renewable energy future.

And our retail business has continued to excel and take market share from our competitors. Over the last 3 years, we have added an equivalent of half the Tiwai smelter’s demand to our retail business. We set out to do that, and the Team have absolutely smashed their targets.

Our people, their safety and their wellbeing will always be front of mind for me.

Our reported injury rates are declining and fortunately none of the injuries suffered by people working for us have had lasting impacts on their lives.

But our near miss reporting tells us that our risk exposure is still high. We see this, most obviously, in relation to the Harapaki construction project. Harapaki is a challenging work site and has experienced difficult construction conditions. So, I want to acknowledge the massive safety focus our project and contractor teams have established at site.

I’d also like to call out the work we are doing supporting our people’s wellbeing. We have developed a Care Team process that wraps support around people in our business who are struggling. Our aim is to ensure they have the time and support necessary, to heal and return to work. Our Care Team programme was recognised at this year’s Safeguard Awards as New Zealand’s best wellbeing initiative.

Our overall level of staff engagement did slip during the year, but we understand where and why the decline occurred, and we are working to address staff concerns. To a certain extent the downward trend is a sign of the times, and we remain in the top 25% of large New Zealand employers, from a staff engagement perspective.

All employers are facing significant challenges retaining and attracting new people to their workforce. Mike will outline some of the things we have done this year with remuneration, to ensure our people feel valued. Of course, remuneration is only one aspect of our overall employee value proposition. Tikanga, belonging and flexibility are also important foundations to our workplace culture and continue to require focus and improvement.

The exit out of Australia means we can point all of our strategic focus back home. The prospects for growth in Aotearoa are huge and will help fast track this country’s decarbonisation.

There are still lots of large moving parts, but the strategic options are becoming clearer for us. The

Southern Green Hydrogen opportunity has two highly committed and credible counter parties shortlisted. Process heat electrification is becoming more viable with lifting ETS prices and a tenfold increase over the next 4 years, in the Government Investment in Decarbonising Industry Fund. And

Rio Tinto seems clearer around how a New Zealand presence can support their own decarbonisation objectives.

In the meantime, we have made great progress building our book of Wholesale hedge contracts to manage our portfolio risk. The swaption deal with Contact, that we announced last week, means our hedge book is in good shape and our risk position for 2023 and 2024 is sorted. What happens beyond 2024 will depend, to some extent, on what happens with the smelter, and what happens with Southern Green Hydrogen.

Our development team has done a huge amount of work strengthening our development pipeline.

And that will bring technology and geographic diversification to our business, well beyond just this decade…more on that shortly.

This morning we announced a $53m, or 13%, increase to the Harapaki capital costs, which now total

$448m. Critically, this additional spend maintains the original, first and full power milestones, in mid

2023 and 2024 respectively.

Like many current projects, Harapaki has encountered significant inflationary pressures. But the bulk of the additional costs relate to the weather conditions experienced during the first year of construction. I can’t believe my home province turned on such rubbish weather and the rainfall at site during most of the construction season, set records for that time of year. As a result, we’ve lost all the contingency in our schedule, and we are left dealing with very sodden ground conditions. So, we’ve taken the decision to invest in a substantial upgrade and strengthening to our roading design.

Better-quality roads have enabled us to continue construction through winter and keep the project on schedule. It should also reduce maintenance costs over the life of the project. I’m comfortable we’ve made a sound trade-off decision.

Also on the upside, longer dated forward prices have firmed. So, we expect the wind farm will realise better price capture, at least in the first few years of its operation.

As I mentioned earlier, our development team has been hard at it, advancing our portfolio of future generation options. But we need to move even faster and so we are increasing our investment support for that team.

Ruakaka energy park will be our next development. We’re currently tendering for the battery and expect to receive consents within the next couple of months. We plan to commence build in 2023 and complete construction during 2024. I’d love it to be sooner, as the system is experiencing regular peak stress events during winter months. But as I’m sure you are aware, international supply chains are stretched, and we have work to do to manage cost escalations and delivery time frames.

We will, however, get it done. And we’ve also secured a second battery option site at Bunnythorpe.

The Ruakaka Energy Park solar farm consent is expected to be lodged in early 2023, with construction complete in early 2025. We are in the process of acquiring an additional parcel of land adjacent to Ruakaka to lift the capacity of the solar farm to 100MW.

We’re also preparing to lodge the consent application for the Mt Munro wind farm later this year.

We expect that project to follow closely on the heels of the Ruakaka developments.

Beyond that, we have a more sizeable pipeline of secured options and advanced prospects for multiple solar and wind sites, mostly in the North Island. And we need more.

Our aspiration, our obligation and our plan, is to ensure we create enough capacity to build our market share of New Zealand’s future renewable electricity requirements.

As an objective, ‘building our market share’ doesn’t sound all that aspirational. But when you consider that building our market share means, building the equivalent of between 15 to 20

Harapaki sized power stations, over the next 28 years……, well it looks bloody tough. But tough or not, it is necessary - and we need to get a wriggle on.

The growth in our retail business has all come from hard-won market share gains. And having the best customer retention rates in the industry has helped maintain the momentum. But there is no shortage of competition, and we are driven to continue to innovate and to lead.

During the year we established a new Energy Solutions team. Their mission is to advance options for distributed generation, and commercial demand response solutions for customers. We believe there is massive scope to add value to customers, and the system as a whole, by providing innovative technology solutions beyond traditional energy retailing.

That team are also leading the deployment of our network of EV chargers. We currently have 61 charging stations in 30 locations, making us the 2nd largest provider of public charging in NZ. And we have a further 82 charging stations committed and awaiting construction.

We have made good progress selling our certified renewable energy product. Our commitment to customers who purchase these certificates is that we reinvest the sales proceeds into decarbonisation projects for others – and that is what we are doing. A good example is a project to support Kidscan to start electrifying their vehicle fleet.

And to tidy up our underlying customer technology stack, we expect to complete the migration of the Meridian customer base to the Flux platform by the end of this calendar year. I seem to recall possibly saying that this time last year. But we are truly down to unpicking the last set of complex

C&I customers. Interestingly, the hardest segment to sort out are customers with unmetered services.

Now we are all acutely aware of the pressure challenging wholesale conditions are putting on large customers as wholesale prices tend to feed through to their pricing quickly. But mass market prices continue to trend below CPI and in real terms, they have been declining for more than a decade. All of the evidence tells us strong competition is working for customers in the New Zealand electricity market.

That said, we know many kiwi households still struggle to pay for their power. So this year our

Customer Team launched a new Energy Wellbeing Programme. This is a pilot programme aimed at reducing the impact of the four key drivers of energy hardship on our most vulnerable customers – financial, housing quality, energy supply and energy efficiency. We’re building the knowledge of in- house energy wellbeing specialists and partners, to look at the whole picture for individual customers. And to support them to progress up the energy wellbeing spectrum. We’re finding we can make a difference beyond the boundaries of energy supply, and our ambition is to scale the programme up for much greater impact.

As you would expect, we have been very focussed on moving forward with our NZAS exit mitigation plans. And we have no intentions of buttoning off our efforts.

NZAS have begun exploring options for the smelter’s future beyond 2024. That process has a way to go, and I point out, there is a massive gap between the terms of the exit deal, we negotiated with

NZAS in January last year, and what we consider to be a sustainable contract for electricity in New

Zealand. Only time will tell whether that gap can be bridged or not.

On the mitigation front, as I mentioned earlier, we have built out a new drought hedge package that improves the diversity and carbon efficiency of our hedge position.

In April, Transpower exceeded expectations by completing, ahead of schedule, the project to materially enhance the transmission export capacity out of Southland. I remember in 2020, when we started to talk to NZAS about an extended exit deal, the Clutha to Upper Waitaki Lines Project was scheduled for completion in 2024. So, the National Grid operator has done a great job bringing delivery forward. And, whilst I’ve never done it myself, I imagine installing 142km of transmission line duplexing, through some very challenging terrain and conditions, is no mean feat. Hats off to them, they got it done.

I’ve talked to the expected battery milestones earlier. While we see this as primarily supporting the north flow of electricity, it will also play a role in grid and regional supply stability. The electricity system needs this type of investment, and we are moving as quickly as we can.

We have customer commitments that get us halfway to our 600 GWh process heat electrification target. We are also talking to a number of those customers about demand response opportunities.

The concept is, if the customer can introduce electrode boilers to displace their thermal boilers, but keep their thermal boilers available to burn biomass when electricity supply is challenged, then we are willing to buy that demand response capability from them for good value. It creates a real win/win outcome.

H2 is all go. We are working with the two shortlisted parties – Fortescue Future Industries and

Woodside. We expect to choose one party and agree terms for the development stage of the project by the end of the year. From there, some real money will start to be spent building to a final investment decision in 2024, and likely commissioning in 2027.

There is scepticism around Green Hydrogen, but there are aspects of the Southern Green Hydrogen opportunity that are unique and make a lot of sense.

We already have existing hydro backed, high-capacity renewable energy available. And in that context, there is significant value in the demand response, that the hydrogen facility can offer the electricity market. We believe this will materially enhance the overall project economics.

Green hydrogen is a tomorrow’s technology. Global growth projections are mind blowing. New

Zealand’s domestic projections for hydrogen demand are likely to exceed the capacity of Southern

Green Hydrogen by a few times. So, we see the project as also creating a foundation toward energy independence for our country.

Datagrid have announced Otago University as the first anchor customer. And we understand consent for the site construction will be filed before the end of the year. Also, the supporting fibre connectivity is planned for completion in 2025. A phased build profile is likely to be modest and in

10MW increments. But DataGrid believe the facility could still meet their 100MW aspiration.

So, to sum up, we have made solid progress from where we were 18 Months ago. Ironically, NZAS choosing to terminate their contract with us has driven us to act. And as a result, I think the strategic options in front of Meridian and New Zealand today, are stronger than ever.

The government’s Emissions Reduction Plan, released in May unpacks more detail on how New

Zealand will meet its first emissions budget for 2022-2025. The plan caps emissions at 290 million tonnes over that period, which represents a reduction of 4% over the current trend.

Supporting this is a climate change package from the 2022 Budget, totalling $2.9b over the next 4 years. 40% of that is earmarked for transport, including increased support for low and zero emissions vehicles. The clean car discount and a low-income ‘cap and replace’ scheme, are strong targeted policy interventions in our view. Along with the sizeable uplift in industry decarbonisation funding, that I mentioned earlier, and reforms to the emissions trading scheme, everything is pointing to a significant and positive uplift in future electricity demand.

And in that context, probably the single biggest regulatory risk in our sector relates to changes occurring through Resource Management reform process. The new framework for consenting is emerging through various consultations. It is a very complex interplay between the Natural Built

Environment Act (NBEA), the Spatial Planning Act and subordinate instruments that will be created under the new legislation. These include the National Planning Framework and Regional Spatial

Strategies.

As currently drafted the NBEA would impose significant hurdles for many large infrastructure projects. The draft NBEA introduces environmental bottom lines that must be adhered to and are unable to even be mitigated. It seems highly likely that many renewable development projects, or existing schemes that must be reconsented, will encounter an environmental bottom line. That will make them hard or impossible to consent. We believe this would cause a massive own goal for our

Country.

We don’t believe that is the Governments intent, and we are engaging with the relevant Ministers and Officials to ensure the issue is addressed before the new RM framework comes into force. I do stress that we are not looking for a free hit for renewable projects. But the framework must allow for the localised environmental impacts of projects to be balanced against the climate benefits that renewable energy brings.

The changes necessary in our sector over the next 30 years are significant. And we think it is important that the industry has a semblance of a plan to show how that change can be efficiently managed, whilst enhancing the energy trilemma. Meridian is part of an industry group including generators and lines companies who have commissioned Boston Consulting Group to develop a roadmap to achieve a low carbon energy future in line with New Zealand’s zero carbon commitment.

The findings from this work will be published over the next two months, and we believe it will provide a credible contribution to the Government’s energy strategy work.

And hopefully, this is the last time I feel the need to comment on transmission pricing reform. In

June the High Court dismissed Manawa’s judicial review of the Electricity Authority’s reform process.

Not long after, Nova indicated they will take this to the Court of Appeal. But the appeal is on quite narrow grounds, and we are hopeful the reforms, in all material respects, will be in place in April

2023.

Now, on a like with like basis, Transpower’s indicative modelling suggests Meridian’s transmissions costs will reduce under the new TPM. But this will likely be negated over time due to cost escalations in Transpower’s operations and as further investment in the grid takes place. And if you consider the growth necessary to enable decarbonisation, I’d suggest we are at the low point in the cycle as far as transmission costs go.

I’ll now hand over to Mike to talk through the numbers

MIKE ROAN

Thanks Neal, and thanks everyone for joining the call this morning. Before getting underway I have to say that I love that slide. Meridian does have the power to make a difference and beyond building renewable generation, I cant think of a better way to do that right now than supporting EV uptake.

This move to embrace electric mobility is a necessary revolution if we are to tackle climate change.

I’d recommend that everyone to jump on board, whether it is a car, bike or scooter and it is something I am quite proud that we can support.

Now you can’t quite see it on the slide, but I also like the catch phrase on the side of the car as well -

“Goes like the Wind”.

If you stop to think about it, it is pretty clever.

Anyways, back to the financials.

As always, I will try to provide a little more insight than you might see on the slides directly so that you get something from listening to me (as opposed to just reading the slides later). So, into EBITDAF and operating cashflows.

As you saw on the highlight slide that Neal talked to, we chocked up another solid year, financially.

And while some may report on the Net Profit after Tax figure that comes later in the pack, it would be a bit disingenuous of us to use that figure as a headline as it contains the MEA gain on sale which is a one off so it does not compare directly to the last financial year.

So, while NPAT is important, here we start with EBITDAF as it provides better insight into our operating performance (at least in my view).

And the 2.5% lift in EBITDAF that you can see on this slide is not easy to do as our operating teams will attest to.

But once again, they delivered superbly this year.

Now of course a simple statistic like that glosses over a year that was both exhilarating and a bit nerve wracking, particularly if you were a farmer down Southland.

I’m not sure if we have anyone on the line from down that way but I doubt you would immediately remember the last time the deep south experienced a drought like that one. It was the real deal and had a major impact on lifestyles and the production of white gold.

Someone told me that there was one upside in that Summer extended late into April and that is unusual for Southland. But I would rather it rained a bit more myself.

Someone else told me that the last time a drought of that scale was seen in Southland was pre-Tim

Shadbolt.

Now I did a bit of googling on that claim and given he moved down that way in 1993, it could be a bit suspect.

But if I give the drought an energy context, we usually produce 1400GWh of electricity from

Manapouri power station over the January to April period. This year we produced just 760GWh.

That is 640GWh of lost production or the equivalent of shutting Auckland electricity consumption down for a month!

So the Southland drought was large.

And regardless of how I frame it, the point is that it would be understandable if I was presenting

EBITDAF that was lower than last year.

But I am not as Chris Ewers and the wholesale team kept us in the game and when the rain returned to Southland late April, they put the foot down and delivered.

It didn’t hurt that Lisa Hannifin and the Retail team had been working closely with customers to help moderate the impact on them, and us, but it was that wholesale team that came through in the end.

So $709m it was and operating cashflows, which is my personal measure of performance ticked up by 7% as well.

For those that were on the Interim call in February, you may remember that following the sale of our

Australian business we adjusted our dividend policy.

I was careful, then, to note that the majority of the proceeds from that sale would be plowed back into the NZ business given growth forecasts but that, subject to operating results, we had latitude to consider a progressive dividend as well.

To reflect this sentiment, we lifted the FCF payout range to between 80% and 100% and, secondly, we dropped SIB capex – as captured within the dividend policy - from $65m to $50m.

We said we would revisit those changes, most likely in 2024 or when we had a better handle on

NZAS mitigation outcomes.

As a result of the above, we have lifted the final ordinary dividend from 11.20 cps to 11.55 cps to be paid on 23 September.

In turn, that lifts the full year ordinary dividend to 17.40 cps imputed to 79%.

And we will retain the dividend reinvestment plan, but as with interims, those that opt in won’t see the benefit of any discount to the market price of Meridian’s shares.

I’ve already talked a little about the year that was from an operational perspective, so I won’t repeat that here.

Rather I will point out that our Retail team continue to grow their financial contribution within the business but that the financial contracts entered into to support that growth cost more than they did last year.

Overall, Energy Margin or the results delivered by our generation, wholesale and retail teams, lifted by $28m on last year.

And this flowed through to EBITDAF (as you would expect).

Now this slide is not all about the $$$, well it is but it also gives me the opportunity to digress and talk a little about how the market structure in our sector also delivers great outcomes for customers.

First off, the World Energy Council again ranked NZ’s electricity market as one of the best in the

OECD across three measures – resilience, sustainability and low cost - and New Zealand is one of only three non-European countries in the top 10 out of the 127 countries they rank.

At the same time, and as Neal mentioned, the data that the Ministry of Business, Innovation and

Employment produces, shows that residential customer costs per unit remain lower today in real terms than they were in 2013.

Not bad.

In fact, pretty bloody awesome.

The NZ electricity sector punches well above its weight internationally and when you compare consumer experience here to Oz, where electricity markets have failed consumers at times, it is hard not to be proud of this performance.

I would also point out that confidence in the wholesale spot market continues to grow as evidenced by the massive increases in volumes traded on the ASX futures exchange. Last financial year there was over 90,000GWh traded on that market or more than twice the total physical consumption of electricity in NZ over the same period. This is an increase of over 20,000GWh on FY21.

Now you only use that futures market if you have confidence in the price formation process captured in the wholesale market (as you rely on it to settle contracts).

The combination of an effective spot market and a liquid forward market is often overlooked by commentators but is an important measure of confidence in the sector (and the prices that emerge).

And then you move to investment.

Course, this is the most important feature of any market – are participants either adding (or removing) supply and/or demand in response to price signals.

Well, given market prices, over $2.3 billion has been invested in new renewable generation that will help decarbonise the economy and this is going on without any government incentive and in advance of any meaningful growth in demand.

And as a collective, the World Energy Council view, MBIE’s stats, forward market activity and investment, they are pretty impressive stats. And taken together, they suggest that the electricity sector is helping kiwi businesses compete on the global stage while attracting new business to the country as we step into a future that will be very different to the one we have seen over the past 10 to 20 years.

I back us to do that, grow our competitiveness as a nation that is, but our sector will only play a supportive role if consumers continue to see good outcomes and if the high global ratings and recognition NZ receives in this respect is retained.

I hope that diversion was useful but now I am going to come back to operating costs.

There is always a bit more in this one than I think is necessary - so long story short - operating costs lifted by $10m over last year (or $17m if you strip out the MBIE holiday pay provision) but as you can see, other than for changes in accounting, lifts in insurance premiums and COVID-related costs; money was spent on staff and growth activities like our development team and Flux. These are areas that our investors would want us to spend money on in the current environment.

At interims I said that we expected to spend between $215m and $220m. And we spent $218m. Last comment on this slide. While it isn’t captured, we have retained an elevated provision for doubtful debts as we enter FY23. At $8m, it is lower than the $9m provision held at the end of FY21 but it is higher than normal.

Short and sweet here.

Total capital expenditure for the year landed at $175m, the top end of the range presented at interims.

SIB capex didn’t change materially, but Harapaki spent approx. $86m to stay on schedule…..and navigate the abysmal weather that the Hawkes Bay is renowned for in Summer.

And while I am on Harapaki, I do want investors to know that we have a cracker team up that way working hard to land that wind farm. Harapaki Project Manager Rob Batters probably didn’t appreciate the size and nature of the challenges that he and his team might face, but with the steadfast support of Chris More, Guy Waipara and the fella sitting next to me, they are doing a great job in challenging circumstances.

If you were wondering what the remaining $49m of growth capex was spent on, it was largely land to support and extend the Ruakaka Energy Park and a new battery site near Palmerston North.

Costs are going to lift in FY23 as well, there is no doubt about it.

As you can see here, FY23 operating cost guidance for the Group is $242m to $247m. That suggests a $24m to $29m lift in operating costs year on year.

What you may not be able to see is where costs will rise. So I will provide a little more detail.

First up, staff costs will lift by a little over $8m this year. In order to retain, and attract people where necessary, rem was increased across the Group by 7%. With low, no or reverse migration forecast it was our view that retaining and motivating our people this year was a priority.

Second, we are spending more to build capability in the development team again this year and also within our subsidiary Flux. We have lifted spend by $7m across those two activities so that Flux can grow into Australia now that the Meridian migration is largely complete and so that we can continue to extend the pipeline of development options here in Aotearoa in advance of decarbonisation led demand growth.

Last, FY23 will see a full year of Masterton call centre costs. That cost had historically been eliminated but now that the team has a contract to support Power Shop Australia, it will show up in operating costs directly.

Of course, that cost – approx. $6.6m – will be recovered through the contract we have in place with

Shell so there will be revenue offsetting it.

All other operating costs will be held flat to FY22.

The capex forecast also lifts this year driven by the rump of Harapaki spend. The forecast range for this year is $410m to $435m broken into SIB and growth capex as you see here.

And we will introduce a new forecast, to add a little more visibility.

It is a total cash forecast for our generation team.

When I say total cash, I mean the combined operating and capital costs for that team and in FY23 I am forecasting it to land between $83 and $88m.

There is nothing wrong with a little more visibility.

As the two graphs show, our preferred measure of performance, underlying Net Profit after Tax lifted marginally on last year.

I am sure that this makes sense given we saw a lift in EBITDAF.

And as I mentioned at the start, while Net Profit after Tax lifted by 55%, when you strip out the

$214m MEA gain on sale, it lifted by 9% driven largely by year on year fair value movements of treasury instruments.

As shown here, these non-cash items continue to move materially year on year. My simple message is that financial performance in FY22 was sound.

At the start of my speech I briefly mentioned that our balance sheet is particularly flexible following the sale of our Australian business - but that is not news, unless you have been living under a rock.

We do have a tranche of the Green NZX listed Retail bonds maturing early 2023 and we will likely replace those with a sustainability linked bond, but I will save my thunder on that until we actually make the call.

So, I don’t have too much to add to the statements captured on this page.

Therefore, I will finish as I started.

We have delivered another sound result for investors in Meridian and as importantly we are well placed to navigate future challenges with a strong balance sheet and formidable operating teams.

FY23 is shaping up to be interesting already but I will hand back to Neal so he can make a few closing comments.

Back to you sir.

NEAL BARCLAY

Thanks Mike.

In summary to me, I believe the business has performed well and we’ve had a successful year.

Certainly, if you think about it in terms of executing on our strategic intent.

We successfully exited an ever increasingly risky position in Australia. And for good value.

We have made material progress with our NZAS exit strategies. That said, I have concluded we need to adjust our language on NZAS. From where we are now, whether the smelter stays or goes has become much less relevant in my view. More importantly, we have become deeply engaged in supporting customers to decarbonise and grow demand for renewable electricity in Aotearoa. And we have become deeply engaged in forging ahead as a leader in the emerging global market for

Green Hydrogen. We are no longer focussed on mitigating some form of smelter exit. We are focussed on playing our part to grow a zero-carbon economy.

To support that future demand outlook, we’ve made great progress building out our pipeline of renewable development options. Clearly though, this is an area we need continue to increase our level of investment.

And, lest we take it for granted, we have continued to execute extremely well supporting and growing our customer base.

Ok, that is us done. We can now move to questions. And we’ll start by taking questions form the room here in Wellington.

Q + A

> First question from me,

> Do you mind introducing yourself?

> Andrew Harvery-Green. First question is around the smelter, and I thought it was quite conspicuous you didn't talk about the fact they have recommenced negotiations. And also probably what I'm most interested in is your views and thoughts on the implications on the EA intervention.

> NEAL: OK. I alluded to the fact that the smelter had recommenced the process. To look at their prospects beyond 2024. We are now involved in that process, any conversations as part of it will be under confidential agreements, so we would be able to see much until it is concluded. I think the key point from our perspective is we have been pretty open and public with what the conditions we would like to see before we consider an extension beyond 2024. And we have no intention of resigning from those sorts of conditions.

> 2nd point was the EA. We are not 100% aligned with their concern. But having said that, the nature of the urgent code amendment that they introduced, last week, we don't think that causes us a problem. We actually think the staged exit deal with Rio Tinto, which was a unique transaction and done for a particular purpose, which was to buy time, not only for the

Southland region but our electricity sector. Is unlikely to be repeated. Even that contract passes the test that they have introduced through the code amendment. So whether it needed to happen or not, is neither he nor -- in their. I don't think it will be a major issue going forward. And certainly any contract we are looking at in the future in relation to the other large potential customers being NZAS or hydrogen.

> 2nd question I had was around your spot options. I think you indicated you are more cover to the end of 2024. We heard last week from Genesis, they have a new product which is being launched early next week.

I guess you will probably wait and see what it is, but at the moment, am I right in saying that you don't see, foresee any need to probably take additional cover? Unless maybe it is dry.

> MIKE: You are right, Andrew, we went through a pretty lengthy process to secure cover for 23, 24, recognising the Genesis swaption terminated at the end of this year. Genesis was part of that process. We have gone in a different direction. It will be interesting to see what the product actually looks like. But we are set for 23-24. Of course we might have a look at it, but as you say, 25 is too early to call, so we will see what happens between now and 2025. But we feel pretty good about our

23-24 position.

> The last question I had was around the development pipeline. It sounds like you are almost guaranteed to go ahead with the battery, the solar, and Mt Munro. Beyond that, there is a gap there.

How should we think about some of those other options even further out? How far, what do secured options actually mean? And actually the ones beyond that, what stages of we actually talking about here?

> NEAL: We haven't moved to financial close on any of those projects, but it's clearly our intention, we know enough about the economics to be confident we will move to that point. But that will happen over the next year or 2. Beyond that, a secured option for us is a group of landowners, so we have access to the resources, exclusive access. To firm them up obviously we have to take them through the design phase, but given it is a consenting process, and once you've locked in place the consent, you have a live option you can execute on. We have been reasonably conservative with the pipeline in terms of how we schedule the delivery of those projects. Because we would like to accelerate them. Faster. And as I indicated, I don't think, I hope, it is unlikely the consent framework in this country is going to get any easier. So the sooner we get them into that process, the sooner we will get them out, and into a buildable form.

> That's all from me, thanks.

> Morning team. Probably going to cover a lot of the same ground Andrew did, but maybe to start with something different, you highlighted when you talked about the HVDC charges going forward that there is the importance of driving the growth capacity,. From your perspective, specifically the

HVDC capacity is very important to how the financials and business work. Are you confident that the

HVDC in its current form, without major investment, will last you through to the 2030s?

> It will require investment. I think that is clear. I understand, and I am not across the detail fully, but Transpower are looking at a tactical project that would increase capacity on the DC potentially up to 200 MW. Roughly in that order. And that could occur within the next 5 years. So we would be supporting them to get on and do that. I think it's, and I have said this plenty of times, but I think transmission is the single biggest enabler of competition in our market. And with the level of growth that we need to build into, we are going to have to come up with a mechanism that allows transmission to get there, probably before time rather than just in time. Because just-in-time will likely be too late. And constrained potential renewable development.

> So, we're right to think then, if they do proceed with the 200 MW, and you have the 100 MW battery, are we getting close to a realistic 1400 north?

> We believe so. We have also given ourselves another option on batteries, and other parties are looking as well. I think you are starting to get into the realms of a significant lift in HVDC capacity, which would mitigate any loss of NZAS.

> And then I guess there is the risk or liability question, pretty confident about that as well, with that work. That's useful, thank you. I'm very interested in your comments about the team putting together some of the decarbonisation response ideas, but also demand response thinking beyond the next 2 years,. What do you think the target for demand response capability is? And how much are you bringing to market, what proportion you think the market need for demand response? Is going to be there.

> First off, the significance of demand response we see on hydrogen opportunity, and that is potentially up to 600 MW. The work we have done has been peer-reviewed by concept consulting which suggests that would meet about New Zealand, 40% of New Zealand's dry year cover, necessary to cover a drought. We haven't put a clear target, but I think there is a lot more potential with large industrial customers in the country. We haven't put a clear target on that yet because we are still discovering and don't have a working example of it. But it is possible. And it works, from what we have seen, it can work for both customers in itself. When you're talking about large-scale thermal plant being kept in reserve for using biomass, then you get into biomass availability. But even if you were burning coal at times of Hydro drought, that would still be a much better outcome than burning coal all year round every year. On top of that, I think the market in terms of mass- market, availability, in terms of demand response, is totally untapped. We've relied on ripple control, and really basic, almost -- brutish mechanisms in the past. We think the future is about enabling customers through technology in their own homes to participate in the electricity market, and be rewarded for that. So I can't give you any numbers yet, but I can tell you it's getting a lot of focus and it's where we see the future.

> I presume, thinking about your capital involved, will your capital potentially be involved, as a cost or an outlay, to help with those boiler?

> Yip

> Okay, great. That's one place. In terms of cost of biomass, if it is biomass, what price do you think you could pay up to you, if you are interrupting exported timber, are we talking mid $20 a gigajoule range?

> Probably need you to get to talk with the team working on it.

> Thanks. OK. Just a question than about how we should look at your demand profiles. A detailed question. Is that the built start dates you have, pinned on that timeline?

> No, that is the delivery dates. Are you talking about the pipeline? That's when we would expect them to be delivering, first or full power.

> The last one for me, if we think about, you have given on the diagram, date for FID on hydrogen.

How long should we think it takes between FID, and actual first hydrogen and full power?

> We've never built one before, but the expectation is that if we can get to FID early 23, 24, then mid 27 is feasible. There is a lot that goes into it. And it may be that the actual build profile is phased.

So you have 200 MW, 200, 200. I might as well touch on it now, but there is potential that both the smelter and hydrogen are part of New Zealand's future. And as part of that potential, we need to build a lot more renewable energy, particularly in the South Island, but we think we have time to get on and do that.

> Fantastic, thank you.

> Hi, I just want to touch quickly on the development thing and Capex pipeline. Just clarify in terms of possibilities of bringing forward the project, you mentioned the constraints. Are there any other constraints you see around capacity wise, and just following on the cost increases that you are seeing, Is Harapaki a good indication, are we expecting more costs increases going forward, and in terms of expectation around funding, if FY23 Capex, obviously you have the sale process, just any guidance on debt vs sales proceeds?

> I will handle the first questions and then handover to Mike. In terms of capacity constraints, yeah look the resource consenting process is by far the largest. Beyond that it is beyond our own capacity constraints, that is why we are signalling we're investing more in our developing team, we now need more capable people, the people that we have now are doing a fantastic job but they are stretched so to progress a project through to the build, we need more concentrated capability there, so we have to build and develop that within our own ranks. So recruit people or develop within our own team.

> Your question on cost increases, I think you mentioned Harapaki specifically, whether that would translate to other projects, I think the costs that we have seen with Harapaki is pretty specific, the majority of it is roading, there are a bit of inflation too, there are inflation pressures seen in the wider market, as we know we are looking at other initiatives and the cost of investing in wind, solar, or battery technologies have risen as well. So the cost base for new investment is rising, but the price curve is reflecting that. You see ASX moving to accommodate those prices. So those projects while the cost base changes, the revenue changes as well. They look reasonably economic. It is hard to tell generally beyond that, the big one that I signalled today was cost in us, the people. And I think everyone is feeling that. And it feels like it is going to come down to migration settings, so are we going to have people coming into New Zealand with skills that we can use to offset some of those pressures? It is a harder one to call, I might be the wrong person to answer it. The funding mix, as I mentioned we have a retail bond that rolls off next year, that we will replace. So we will properly go to market between 150 to 200 and million. When we've got a retail bond that rolls over the following two years as well So we will see what we do with those and subject to the investments that we will make. Balance sheets all set, we don't have funding constraints.

> Thanks.

> I think we can probably go to anyone who has a question online.

> Good morning Meridian team. I have a question around Mount Munro. It seems from your competitors, they are talking about 30% increase in the cost associated with wind, is this what you're also seeing, you said you have an economic handle on your new builds?

> We have not gone out to tender for it, grant, but certainly indications that you are talking cost increases circa that. I mean civil does play a strong part, and one of the interesting things about

Harapaki, was that it was built on the mountain range, in a pretty challenging environment, as we come out of the hills, some of those risk start to dissipate a-wee bit, but wind costs, commodity costs across the board have escalated, how long that is going to stick around for, it is change in a hell of a hurry, it could change back. We've all seen these cycles shift of it shift around, so we've still got to discover fully what the cost implications are

> Thanks, Neal. Just on justifying the Mount Munro build, you talked about demand response and the marginal supply needing full capacity, what do you guys think of the long run marginal cost changes based on your view of what the marginal supply will be over the next few years, and does that increment from the old $80 long run marginal cost we use to use justify new wind builds?

> It is moving around, Grant. I think that is the best answer. You now we have used 80 bucks a

MWh previously and quite consistently for a long time, and that was recognition that the cost of the new technology, supply lead technology was falling, just becoming more and more efficient. But we have seen the same thing that you have. Our long-run forecast is lifted, and you mentioned 20%,

Grant. They can move in that realm, but there is an interesting dynamic emerging between I will call it long-run prices, it is how quickly can you build renewable assets into this market versus relying on some form of thermal backup, and that is a little less clear than what it was. And Neal points on the

RMA being constraints, in terms of getting the projects away, these renewable projects away, it could have a big impact on price that anything else. So I will forward curves are showing a reasonable difference subject to your ability to develop for scenarios in the future.

> Can you elaborate a bit on how you see the world playing out in the NZ market in the next 10 years in terms of what the new marginal supply, when you're talking biofuel at $20 a gigajoule and how does demand response shape up to that and do you see demand response as the marginal supplier?

> Grant, I don't think we have got there is a simple answer. We are in the process of exploring arrangements with smaller industry that's decarbonising. Whether we continue to get demand response in 25, for example from a peaking asset, or extend the exisiting arrangements that we have entered into with Nova and Contact, as opposed to engaging with those consumers. You have heard where we would like to go, which is consumer engagement in this market or customer engagement in this market it is very important for its function and the transition that's underway. So we are engaged with them as deeply as we can, but we just do not have the answer in terms of are they going to provide the marginal source of demand, and flex in the short term, in the long term there is no doubt. Is that transitions into more residential demand flexibility as opposed to industrial demand flexibility what we have are considering for 25 and 26, the technologies that are supporting that residential demand flexibility are exploding. And you see examples of them all over the world where consumers are getting paid for providing that service.

> Thanks.

> Just moving onto solar. It appears from your competitors that the near-term economic risk are around securing land, which is getting more expensive. My question around the Taranaki 200 megawatt options that you have at the back end of the decade is that pushed up because you are worried about economics of solar, that it is not stacking up and you have not secured land at this stage?

> It is based on our view if we stack all of the projects up based on what we grant on what we know the cost would look like. There is still a large range of uncertainty there, where that one fits into the merit order.

> Thanks Neal. And last question on keeping the smelter around, you indicated there is a large gap between the old contract and where you think a new contract would fit if you wanted to play in that game and you have started negotiations with them, is that commentary on the large gap just trying to highlight the old contract was a really deep discount contaract and has nothing to do with your early conversations with them around a gap that's developed already.

> I will repeat what I said previously, there are four conditions that we would consider, working with the smelter beyond 2024, one is they do need to show they have a committed environmental remediation plan, now we're not going to be the arbiters of what an appropriate plan looks like but we will look to local council and iwi to inform us whether that plan is acceptable to stakeholders, 2, we need to see a long-term commitment to New Zealand, and I said 15 to 20 years, I think it needs to be at least that, and we can't have this sort of one year exit stuff, so managing that credentials will be interesting. Three, we think because they have been and possibly will be, a large chunk of electricity sector, they need to find ways to work more in sympathy with the electricity sector, so that is where we expect the smelter to bring back the demand response type options and ideas, and there are some available to them, and I think they are thinking about that more strongly these days.

And lastly, price needs to be more sustainable. The price in the staged exit deal, a cents in the dollar type transaction as we've said many times, it is not something that is sustainable for the long term, it is nowhere near reflective of the marginal costs of new generations to support that facility, if there is an element of realism on the Rio side on what they have to pay for energy, then things might happen, if not I think they'll struggle.

> Grant, just picking up on your last point, two things, one we have seen your numbers, so we know your view on what a reasonable contract framework might look like, but 2, really clearly we are not trying to signal that there is a gap in any formal conversation with Rio Tinto. That is not what we are trying to say today, we have not had those conversations. If we do, and assuming that we will, we probably will not share them with the public. So we will work with them to see whether something satisfactory can flow from those conversations.

> Good point, Mike. Conversations are at a very early stage.

> So the comments from the smelter about three months ago, a couple months ago, about wanting to have some certainty Southland before FY23. Is it still realistic?

> You probably have to ask them, Grant. I don't know if we have Rio on the line. Sorry about that.

Where there is a will, there is a way. If people are serious about providing stability and security and confidence, then there is no reason why we can't get their. But we do what we need to do, Neal just mentioned it again, we have been pretty clear for the last 18 months what we feel reasonable looks like, but until we get into the conversation, we don't know. Three months is a long time, and if you use it wisely.

> Thanks very much.

> Cheers, Grant.

> Good morning Neal and Mike. Thank you for taking the questions. The first one from me just on wind. Can you give us a feel on what your current mean wind generation is across your portfolio, and noting the variability in the last 2-3 years. Has there been any change in thinking>

> I might have to get you the actual number.

> Capacity rates have been about average. We had a couple of issues with one of the wind farms in particularly, Te Apiti, and we've just completed 1/2 life refurbishment, so we have the availability rates at that site up from, they were languishing in the mid-50s, up into the 90s. It was nice to have that done. But we would need to go back and check. We have not seen, I don't think, I wouldn't call it a structural, but a climactic shift in the wind environment in New Zealand.

> We'll come back to you, it has moved between 11 and 1300 gigs per year. Probably a little higher than that, possibly.

> That's useful. A 2nd question on your opex post Australian sale. Are there any stranded corporate cost that are washing around there, that you might be able to tidy up over time? I know you have given lot of detail for the opex for the coming year, but I'm thinking, 2 or 3 years out, are there any costs that you can strip out that have been stranded post that sale?

> Not related to an MEA. We have 2 contracts in place with Shell, one with the Masterston call centre, and one with Flux. So subject to how they play out, we might need to make some changes.

But we are building a relationship with them, hope they are interested in those products long-term.

So that might be one. Other than that, there is nothing longer term that we haven't already worked our way through. We are in a bit of a transition, so we have transitional services arrangement with them over 9 months. Where we are providing them with a couple of services through the next couple, but largely done, but nothing meaningful.

> OK. And back on NZAS, it's been done to death, but can you give an update on Potline four and the suspension of that line and what -- line, and whether or not the operations have obviously been rolled into negotiation, and the chances of that coming back online.

> It has come up in the initial conversations. So we will see what that means for any longer term arrangement. Again, given it has been suspended now for all of 22, most of 21, and would only run through, October. I think it is unlikely that it comes back for those last couple of months. But again, I can't talk for Rio, the contract facilitates them, bring that back service for a couple of months. They could run it after that, but they will be running it on spot. As opposed to contracted. So we will see.

I'm sure it will be part of a conversation.

> OK. Thanks. Last one from me on wind. There is been a lot of question, for 18 months, a lot of discussion about why that is. You have raised domestic constraints that are operating, allowing wind to get away. Mercury raised the issue around OEM capacity issues, that change in demand, and how relevant is New Zealand to the global OEM players in wind at the moment.

> We haven't run into that capacity problem in the past. But the world is changing as we speak.

Because we haven't gone into a tender process on another windfarm, we can't make a firm call on that. I would have thought New Zealand would still remain relevant in the global context just because of the quality of the wind resource we have here. We always have iconic type project status, to be attached to New Zealand projects. Why aren't more windfarms being built, if I was being brutally honest, I think probably 5 or 7 years ago this industry lost its mojo around the likelihood of demand growth. The world has changed a hell of a lot since then, and it takes a while, probably a good 10 years, to get a wind project from concept to understanding the wind resource, through the consent process, and then design and build. We took the foot of the pedal, not just

Meridian, but the whole industry. 5 or 7 years ago, and it has taken every bit of time to get that momentum back up. I say by the back end of this decade we should be in full flow again. That is certainly what we intend, who we intend to be.

> thanks very much Neal. Thank you.

> There are no further questions from the front lines. Please continue gentlemen. Thank you.

> NEAL: Thank you for the questions, and hopefully the analyst’s workload will reduce over the coming days, I think Big Wednesday is about the end of it. But anyway, thank you for your attendance, and good luck, and have a great rest of the day. Cheers.