Vector Limited (VCT) Earnings Call Transcript & Summary

Good morning, everybody. Welcome to Vector Limited's conference call and webcast to discuss the company's financial and operational results for the half year ended 31st of December 2021. [Operator Instructions] I must advise you that this conference is being recorded today, and I'd now like to hand the conference over to Vector's Chair, Jonathan Mason, who will take you through the call. Please go ahead, Jonathan.

Thank you. [Foreign Language] Good morning to you all, and welcome to this event. My name is Jonathan Mason, and I am Vector's Chair. Today, we are going through Vector's results briefing for the half year ended December 31, 2021. Joining me on the call are Group Chief Executive, Simon MacKenzie; and Chief Financial Officer, Jason Hollingworth. We intend to use this time to provide you with insights into what we see as the key aspects of the results rather than a detailed line-by-line read-through. And this will give us more time for Q&A with you all later. I will begin today's presentation with a summary of the dividend for the half year and a brief comment on overall business performance, then hand over to Simon to provide more detail. Jason will then go through overall financial performance at a group level, then hand back to Simon to comment on segment financial performance. Simon will also then make a short statement about Vector's outlook, and then we'll be happy to take your questions. So first, on the interim dividend. The Board is determined that the interim dividend is $0.0825 per share, equal to last year. The dividend is partially imputed at 10.5% and will be paid to shareholders on the 8th of April 2022. Despite the ongoing uncertainties and challenges that have arisen because of COVID-19, the group has delivered a steady start to the 2022 financial period. Net profit after tax was $115 million, up $13.4 million or 13.1% compared to the prior year. We are continuing our strategy of investing in infrastructure and complementary innovative technologies to deliver for our customers across the group and unlock opportunities to help decarbonize our energy systems in ways that are equitable for customers. I will now hand you over to Simon to talk through an overview of the performance of our businesses in the first half of this financial year. Simon?

Thanks, Jonathan, and [Foreign Language] everyone. Before I get into the details of our businesses, I'd like to comment on some of the highlights from the half year across the group. We've continued delivering against our objectives during the first half of our financial year while also responding to the evolving challenges from COVID-19. Throughout the changing alert levels and now the traffic light framework, we have maintained our focus on delivering essential services for our customers and making progress against our symphony strategy. We've completed our largest ever study of customer behavior with a 2-year research project on electric vehicle smart charging that will help us plan for the electrification of transport. With high levels of customer satisfaction throughout the trial, the results are extremely pleasing as they illustrate the benefit to customers and networks of smart technology that makes the most of existing infrastructure to help deliver affordable decarbonization of the transport system. Another highlight from the past 6 months has been our announcement of our strategic collaboration with X on network virtualization and simulation technology, including the virtualization of the electricity network in Auckland. These tools will help us and other transmission and distribution operators simulate the likely impact of increasing solar, electric vehicles and other new technologies customers seek to connect to the energy system, thus helping us proactively invest and manage the networks to maintain a reliable and affordable energy supply. The strategic collaboration with X is part of our shared vision to reimagine the design, management and operation of electricity networks, get ahead of increasing demands with clean energy and transform the network in order to support decarbonization. Together with continued progress and our strategic alliance with Amazon Web Services to build the new energy platform, these initiatives reflect strongly our strategy of looking for the best partners from around the world to work with on transforming our energy systems and creating new platforms for customers and other operators globally. Now on to business performance. We added 6,603 new electricity connections. This was a more modest increase than last year where we saw 7,777 new connections. We also added 1,731 new gas connections, again, a slightly lower increase than last year when we added 3,027 (sic) [ 2,027 ]. That takes the total electricity connections to 596,396, up 1.7% from 586,480 a year earlier. While total gas connections were 117,628, up 1.9% from 115,432 a year ago. Both electricity and gas volumes have been impacted by COVID-19. Volumes transported across the electricity network fell 0.3% to 4,313 gigawatt hours from 4,324 gigawatt hours a year earlier with lower business volumes being partially offset by higher residential volumes. Auckland's gas distribution volumes were down 7.9% at 7 PJs from 7.6 PJs a year earlier. Total SAIDI minutes, which are measured across a regulatory year beginning April 1, 2021, are slightly favorable for the 9 months ended December 31, 2021, when compared to the same period last year, while still within the year-to-date regulatory threshold and notably favorable comparable to other years. In the first half of financial year '22, gross regulated CapEx increased by 3.8% to $163.1 million compared to $157.1 million a year earlier. CapEx net of capital contributions was 14.4% lower than the prior year at $91.2 million. CapEx continues to be at historically high levels due to investment to improve the reliability and resilience of our network as well as higher growth CapEx reflecting the continued growth in connections and infrastructure projects. In the 6 months to December 31, 2021, we have installed 10,273 additional advanced meters in New Zealand and 50,481 additional advanced meters in Australia. Our advanced meter base grew 7.9% to 1.93 million from 1.78 million the year before. We have now deployed more than 447,000 advanced meters in Australia. In the first half, metering CapEx increased by 3.3% to $84.5 million with a high level of spending, reflecting the continued deployment of new advanced meters in Australia, the 4G modem replacement program, rollout of advanced gas meters and an increase in stock levels to help mitigate supply concerns given COVID-19. The Ongas LPG business was also impacted by COVID-19 during the period with Bottle Swap 9 kg volumes down 5.1% to 356,098 bottles from 375,271 a year earlier. LPG sales were mixed with bulk volumes higher and cylinder volumes lower. Overall, LPG sales were up 6.2% at 25,240 tonnes and liquigas LPG tolling volumes were down 1.4% to 54,489 tonnes from 55,239 tonnes a year earlier. Natural gas volumes were down 2.1 petajoules to 2.9 petajoules from 5.0 petajoules in the prior period, mainly due to the loss of a major customer from June 2021. So now I'd like to hand over to Jason Hollingworth, our CFO, to go over further details on overall group performance.

Thank you, Simon. As you've heard today from Jonathan, group net profit after tax was $115.5 million, which was $13.4 million or 13.1% higher than the prior year. The result was largely due to higher capital contributions, gains on the sale of the 50% share of Treescape, lower interest costs, being partly offset by lower network and gas earnings and higher depreciation and amortization. Total capital expenditure in the period has been $266.4 million, an increase of $5.7 million or 2.2% on the prior period. The increase reflected continued investment in infrastructure to support Auckland's growth, rollout of 4G modem upgrades across the New Zealand advanced meter base, deployment of additional advanced meters in Australia, and increasing stock levels to counteract the risks associated with production shortages linked to COVID-19. Operating cash grew by $12.3 million to $283.6 million from $271.3 million a year earlier, largely due to an increase in capital contribution and other receipts for lower interest paid, partly offset by higher supplier costs and the distribution of loss rental rebates to customers in the current period. Regulated adjusted EBITDA for the 6 months to December 31 was down $10.4 million to $185.5 million against the prior 6-month period. The decrease in adjusted EBITDA was largely driven by the prior year release of loss rental rebates, which has been utilized to mitigate the impact of volume reductions on distribution revenue as a result of COVID-19 as well as to offset against what would otherwise have been larger price increases from April '21. The prior year impact of retaining the loss rental rebates and lower gas volumes this year were partly offset by higher electricity revenues due to higher recovery pass-through costs and connection growth. Adjusted EBITDA for the gas trading business was down 16.4% to $12.2 million from $14.6 million a year earlier. The result was mainly due to the impact of the higher cost of LPG product, which has only been partially recovered through increased customer prices. The higher cost is a result of the lift in the Saudi Aramco price of LPG, higher ETS prices and a stronger U.S. dollar, all contributing to an increase in the cost of gas. This has been partly offset by an improved performance from the natural gas business. Adjusted EBITDA from the metering segment was $86 million, up $2.9 million or 3.5% from the year earlier, with gains coming from the continued rollout of advanced meters, particularly in Australia. Group net profit after tax was $115.5 million, which was $13.4 million or 13.1% higher than the prior year. The result was largely due to high capital contributions, gain on the sale of the 50% share of Treescape, a positive fair value movement in consideration and lower interest costs being partially offset by lower earnings and higher depreciation and amortization. Gross CapEx was up 2.2% to $266.4 million. And net CapEx after deducting contributions was down 7.3% to a $194 million. Stock levels increased by $16 million in order to counteract risks associated with global production shortages, which has also contributed to the year-on-year increase. Economic gearing at December 31 was 56.9%, and Vector's rated BBB, stable outlook, by Standard & Poor's and Baa1, stable outlook, by Moody's. During the period, we issued NZD 225 million of 6-year retail bonds, and we repaid NZD 150 million of the USPP. $307 million of perpetual capital bonds are due for rollover in June 2022. I'll now hand back to Simon to talk about our business segment financial performance and outlook.

Yes. Thanks, Jason. So excluding the one-off price increase offset from the prior period, revenue was higher because of an increase in net connections, an increase in recovery of pass-through costs, other prior period adjustments. Gas revenue is down because of lower volumes. Capital contributions were up 4-point -- sorry, 42.1% to $71.9 million, driven by Auckland infrastructure development, increased residential subdivision activity and continued connection growth. Regarding the recently released gas distribution draft Default Price Path by the Commerce Commission, we're pleased the commission has acknowledged the transition to a low carbon economy and the need to balance the objectives of government, customers and gas infrastructure owners around the use of natural gas with incredible emission reduction pathways. However, there are still items that we believe need to be addressed. Nevertheless, enabling an accelerate to depreciation of gas assets is especially critical in this next 4-year DPP period for our ability to recover our investment in order to lessen the risk of bigger price changes for gas customers further down the track. The Climate Change Commission's final advice to government recognized the complexities of a transition away from the use of fossil gas, and we await decisions from government now due in May that will hopefully shed some light on the gas transition. We continue to collaborate with the other gas infrastructure operators, the Commerce Commission, the government, MBIE and to seek a transition plan that works for customers, government and investors alike. A final decision on the next gas DPP is due on May 31, 2022. The draft Commerce Commission decision allows for a starting price adjustment that will see approximate 12% increase in maximum allowable revenue, this impact to be spread over the DPP period, the impact on financial year '23 is a circa $8 million uplift in revenue and circa $58 million over the DPP3 period. A key driver of the increase in maximum allowable revenue is an adjustment factor, which will see an acceleration of depreciation, which has the effect of speeding up capital recovery. Turning to gas trading. Bottle Swap volumes were down 5.1% to 356,098 bottles swapped or sold with the result being impacted by COVID-19 restrictions. We saw a strong performance from the natural gas business, where higher market prices have improved margins. With respect to metering, earnings were up 3.5% to $86 million. We have now deployed more than 447,000 meters in Australia and then continuing to roll out advanced meters in Australia. I'd just like to especially recognize the team in Australia through delivering a really good pleasing volume of meters in Australia, given very challenging COVID environment over the -- leading up to Christmas. Continuing the rollout of a modem replacement program in New Zealand with approximately 78,000 replacements already completed to date. Looking ahead to the rest of the year, we are expecting Auckland growth to continue. With that continued growth, new connections and infrastructure activity remain elevated, necessitating significant capital expenditure. We are on track to deploy between 105,000 and 115,000 meters in Australia and 20,000 to 30,000 meters in New Zealand, this is net of replacement meters. In the gas business segment, we are facing challenging oil and ETS prices. And based on the half year result and those forward-looking statements, we are providing adjusted EBITDA guidance of between $505 million and $515 million for financial year '22. This does not factor in any worsening impact of COVID-19, such as extended or frequent lockdowns, supply chain disruptions or impacts on our workforce from isolation requirements. Before I'd like to hand back to Jonathan, I'd especially like to thank our Vector staff and service providers for the efforts in this half year. The period has been very challenging with continued disruption adjustment due to the change in COVID-19 requirements, not only here but in Australia as well. And we're extremely pleased with the resilience and dedication our staff has shown and continue to show as we're navigating through a changing COVID-19 environment. Now, back to Jonathan.

Thank you, Simon. In closing, I'd also like to thank Simon and his executive team and everyone at Vector, our staff at Vector and our field service providers for their work and commitment as we continue to progress towards our vision of a new energy future. Recently what was at Hurricane Dovi just a week or 2 ago showed how dedicated these teams were. And now, Simon, Jason and I are happy to take any questions. [Operator Instructions] So, questions?

[Operator Instructions] Our first question comes from Andrew Harvey-Green at Forsyth Barr.

I have about 3 questions, I'll go through them one at a time. The first question just around, I guess, the gas distribution network and, obviously, you sort of kind of signaled what is a default price path but also, I guess, those longer-term risks around that business going forward. What are you thinking about your sort of medium to long-term? Is CapEx in that business [indiscernible]?

Simon, why don't you take that?

Yes. Andrew, with regards to projections on CapEx, we have changed our capital contribution policy. So we are not funding any new connections. So that's 100% funded by customers wanting new connections. So our gas CapEx going forward will be just limited to economically rational replacements and/or security and reliability. So we will see a drop against prior asset management plans, levels of expenditure, primarily due to the effect of not doing the customer connections.

Okay. Second sort of gas distribution-related question is just around what you're seeing, I guess, on connection growth. I guess when we look at the operating steps, they were down a little bit, but so was electricity in a relative sense, there wasn't too much of a movement there. But I mean from, I guess, speaking to developers, are you seeing much of a drop-off in interest in gas connections at this stage?

Look, I think this -- it would be fair to say that we do see some drop-off in interest. But equally, it's not as much as people may speculate as we saw there. We still have had a reasonable number of new gas connections. It is also fair to say that some existing parties actually is looking to transition off gas in large-scale kind of areas. But by and large, we see the numbers being reasonably kind of consistent and hard to completely distill at this point in time given COVID delays with regards to new builds and developments.

Yes, okay. Next question is just around inflation. And obviously, I think that's reasonably topical across the market. In terms of your business on the cost side, what sort of inflationary pressures are you seeing? And given you've got inflation uplift factors that come through in the regulatory revenue in particular, do you see inflation as a net positive or net negative or neutral?

Yes. Well, we're certainly seeing -- yes, certainly seeing the inflation come through in construction activity and resource costs and also as I'm sure many are facing, the cost pressure on resources is pretty high, obviously, because of labor shortages in the market and low immigration. So we're definitely seeing those through. We're seeing price increases come through in materials from overseas, which is pretty much a combination of inflation offshore as well as supply chain costs. So as you'll appreciate, Andrew, what that does do is it makes in the electricity business, for example, or the regulated businesses that is -- obviously just increases the cost of the capital projects and in turn that actually can put some downward pressure on the total number of projects that we would be able to do under the capital allowance envelope that the Commission has given us under the bulk price path, would be one example of that. With respect to the indexation issue, then obviously, that is a reversal from what we've been experiencing over the last 10 to 12 years, where we've been on the wrong side of those forecasts. So any inflation numbers of the actual inflation that comes in above what was used in the DPP forecasts by the commission is obviously in our favorable ones, which goes into the RAB by virtue of indexation of the regulated asset base being higher than the inflation level. Jason might have something to add to that, if there was anything else, Jason?

No, I think that's good, Simon. The key thing is we do have protection also in our metering business. We also have CPI protection in those contracts with various forms.

And my last question is just around metering. And I guess, in particular, just a comment around New Zealand meters going up 20,000 or 30,000 net of replacement meters. So just wondering what is the volume of replacement meters. And you're talking about replacing smart meters here, I assume. So presumably, they're only around about 11, 12 years old, is that correct?

Jason, do you want to take that?

Sorry, Andrew, I'm not sure where you're getting up us replacing smart meters from in New Zealand because we're not doing that. There's new connections and new people joining the network, which we're adding new smart meters on for. But we're not replacing existing smart meters. There's a modem upgrade program as well, so we are upgrading the communications network on our existing smart meters, and we are spending capital on that over the next 3 years, but the actual meters themselves aren't being replaced.

The only thing, Andrew, that I'd add to that is we are replacing some meters, which are not smart meters, is what we would close up by them and we're replacing what was known as the Arc meters that was deployed down in the Christchurch area back in the day by Meridian. And so those are at the end of their life, and those are the meters we're replacing with smart meters that we have deployed across the rest of the country.

Our next question comes from Phil Campbell at UBS.

I just had one question around the gearing. I'm just wondering if Jason could just remind us, for the rating agencies, what the FFO to debt threshold is and just where you are at the moment in relation to that?

Jason?

Yes, like S&P report, I think that recently had us at over 12%. The floor is 11%. So yes, we're tracking over that, but that's -- I think S&P report that every 12 months. The last report I saw had been -- had our numbers and were forecasted sort of over 12%. So -- yes, so there is [ more capacity above the limit before ].

Okay. Great. And then just the second one was just on the loss rental rebate. Just I'm assuming most of those being distributed back to customers? Or was there any benefit of those in the results?

Jason?

Yes. So one thing we're doing, Phil, is through volume shortfalls on our electricity network, we are retaining loss rental rebates just to mitigate that impact. So that -- so we have retained a small amount in the period, but it's purely to do with volume mainly due to COVID and the bulk of them are being sort of being retained on the balance sheet as we've done in the past.

Right. And then just my last one was just around the…

Sorry, just to clarify that, that's because when there's a volume shortfall, it translates into an underrecovery of the allowable revenue. So rather than putting that through as a price risk to customers, then we just use the loss rental rebates to top that up to achieve the allowable revenue.

Are you able to give us an idea how much that was Jason?

Yes, someone will probably message you. I can give it to you a minute, Philip. I just don't have it in my mind at the moment, sorry.

And just a very quick last one was just on the Aussie metering guidance. I think that's a little bit of a slowdown. Is there a kind of a COVID impact incorporated within that? Or was that just kind of being a new kind of run rate?

Yes. No, absolutely COVID related. Obviously, the challenges throughout New South Wales has been pretty material through leading up to Christmas last year. So we definitely saw a slowdown in the ability to deploy meters because of the COVID situation in Australia.

Right. But if we're kind of assuming, doing forecast for FY '23 and beyond, we probably assume the rate would kind of go back up a little. Would that be fair?

Yes.

Assuming no more disruptions from COVID.

Yes, I think that would be fair in that range, yes. Just to go back to your question on the loss rental rebates, it was $4.8 million.

Our next question comes from Grant Swanepoel at Jarden.

Just to -- I want to just clarify the loss rental rebate. Is that $4.8 million, is that compared to the $15.5 million in the PCP?

I think the PCP had 2 components in it, Grant. So there was a volume component in it as well. So I think it was more like $19 million or something for the PCP comparison.

Okay. So that's $15 million different. So my first question is on LPG. That has quite a big knock, $6.5 million down. Is that because one of your competitors has upstream LPG and is not taking the price increases?

Simon -- or sorry, Jason, do you want to take that?

Yes, I'll take it. It more reflects, Grant, that we -- it just takes time to put prices through to customers because our contract terms vary. So we just can't put all our prices up to reflect our increased input costs. The market typically trades at that international price, but we just can't push prices up immediately, given contracts that are in place. So that's the main issue. It's just the contracted nature of our revenue streams.

Okay. So we should see an uplift coming through and a bit of recovery of that shortfall.

Yes. We're putting our prices -- it's probably a 12-month process by the time we work through the contact book, yes.

And then my final question. I'm sure I could have worked it out myself, but hopefully you guys could solve us for me. The gas price reset, of the $49 million revenue uplift over the next 4 years, with the WACC actually having gone down slightly, how much is explained by accelerated depreciation?

Jason, do you want to track it down this time?

Yes, look, I don't have it on my fingertips, but most of it will be the accelerated depreciation, Grant. So yes, we're moving up about $8 million.

Okay. So the rev will decline quite a bit over this period.

Yes.

[Operator Instructions] Our next question comes from Eamon Rood at Energy News.

On the smart EV trial that's ramped up during the period, do you have -- what's next for Vector in the smart EV and electrification of transport area? What are you going to use the results of the trial for going forward?

Simon?

Yes. Obviously, that was a pretty significant trial. What it definitely did demonstrate to us is that it totally made sense to be able to have what we would primarily look at residential EV chargers connected to a smart digital platform, which enables customers' vehicles to be charged in a managed way so that they don't all come on to the system at once and create peaks, which causes inefficient capital investment. So the next steps are, we're looking to collaborate with potentially other parties to build out the platform because we'd say that this was a platform that has operated on, [ for all intents and purposes ] was an alpha platform for simple terms and just look to then collaborate with others about building out the platform, which could then be utilized not only across our network, but across other networks so that smart electric vehicle charging can be managed right across New Zealand to enable an affordable transition as opposed to the counterfactual being a very expensive transition through inefficient peaks being created by EVs plugging and seeking charge at the same time.

Could I just add in, Simon, that we look at the big picture and look at with decarbonization, an expected 40% to 50% increase in electricity demand on our network. That 40% to 50% is a big number, happily occurring gradually, although exactly what the pathway is, it's highly uncertain depending on when we buy EVs. And the other worry that we have is so that won't be evenly distributed across Auckland. There will be certain areas with more intensity of EV purchases than other areas. So we are working very hard to have the network ready that Simon referred to when Auckland residents want it. And that will -- that does create challenges though, and specifically, the need to manage EV charging times. Does that make sense between the 2 of us?

That makes sense. Just one quick follow-up. When you talk about collaborating with other parties on building a platform for this, is that -- will be that similar to, say, what you're doing right now with Google X and AWS? Or would it be more like a form of JV? Or are you open to partnership arrangements?

Yes. Look, it's fair to say that the platform that we would be hosting this on or the development of the specific functionality would be on what we call our DERs platform or distributed energy resource management platform that we have up and running already. But when we're talking about collaborating with others, look, we primarily see that is with the retailers, New Zealand retailers and also possibly vehicle manufacturers so that we can actually -- our interest is how do we make sure that we can schedule the charging instances so they don't all happen at once. It's not about basically changing prices in the market or anything like that. So what we mean by collaboration is being able to work with retailers and potentially other interested third parties that want to be able to put propositions to their customers about how they can manage the electric vehicle charging and maybe take advantage of pricing options that the retailer might have available to them at different times that can be integrated into the platform.

Thank you, everyone. We have no further questions. So I will hand back for closing comments. Thank you.

Excellent. Thank you. Look, I think with that, and hopefully, everyone had the opportunity to ask each question that you wanted to. We'll end the teleconference and webcast. But if other questions subsequently come up from analysts and investors, please call Jason. And for the media, please contact Matt Britton or call our usual media phone number. And thank you, everyone, for joining us on this Friday morning in New Zealand.