Tariff structure statement
We started a network tariff reform journey over three years ago, aware of the need to deliver fairer pricing signals relating to the use of our electricity network. This has led to the proposals now in our Tariff Structure Statement.
This page covers our engagement specifically around the Tariff Structure Statement.
October 2016 - our revised Tariff Structure Statement
We have provided the Australian Energy Regulator (AER) with a revised version of our Tariff Structure Statement, which covers our network tariffs out to 2020.
This has updated pricing schedules and some additional information requested by the AER. Please refer to this version if you are making a submission to the AER (due by the 25 October).
The AER will then make a final decision in early 2017, which will apply to tariffs from July 2017.
|Revised Tariff Structure Statement (PDF File, 735.3 KB)||13 Oct 2016|
|Supporting Information (Revised TSS) (PDF File, 1.3 MB)||13 Oct 2016|
September 2016 - an update on our Tariff Structure Statement
The AER made a draft decision to approve our Tariff Structure Statement in August.
Following this we held a webinar to go over the AER’s draft decision, discuss their requests for additional information, and also clarify some key matters.
The AER will make a final decision in early 2017, which will apply to tariffs from July 2017.
To find out more, watch the following video of the webinar or alternatively review the slide presentation, An Update: Ergon Energy's Network Tariff Structure Statement (PDF 3.9 mb).
Welcome to this afternoon’s webinar. Thank you for joining us today for an update on our Tariff Structure Statement.
We really do appreciate the time that you have given us through the numerous updates, because it has been a lengthy process to get this point.
So for those that are new to these updates….my name is Sara Collins; others of course I have been introduced to you before, and I’ll be facilitating today’s webinar.
I am joined this time by Ergon Energy’s Group Manager Regulatory Affairs, Jenny Doyle. Jenny’s been leading our network tariff reform agenda right back from the beginning in 2012.
So she is very familiar with all the changes and how we have got to the point where we are today.
So you’ll hear from Jenny shortly.
But before that, I do just want to give you some of the basics of the webinar tool that we are using.
When you started, you would have seen a Panel that you can see on the screen come up.
You can use that to manage your webinar session.
The little red arrow can be used to minimise the Control Panel of bring it back on line again. So if it is on top of the presentation you can move it to the side.
From the panel, you can control how you listen to this webinar. We have had problems in the past where we have had some sound issues. If it is at your end you can change over and try the alternative to what you are currently using.
So you can move from the computer to the telephone at any time. Just select the telephone option and call in on the number provided.
Or in reverse, you can switch to your computer speakers or headphones.
We have also activated our webcam temporarily, although I think that has just gone off the screen now… so you can see us. I’ll point this to Jenny in a moment so you can see her when she is speaking.
We’ll use that in the beginning and then turn it off so you can see the presentation as we go through.
You can… everyone is actually muted for the webinar so that we can get through the content, but you can ask questions during the presentation just by typing them into the Questions Pane, which I have shown on the slide.
As well as Jenny, we have additional support to answer the questions to answer the question as we go through. But we will stop for question time in the middle of the presentation… and then at the end.
If we are unable to answer your question then we will certainly follow up after the webinar if you pass on your email address. And we’ll pass on our email address at the end, and then we’ll converse with you with your email address.
During the session, we plan to ask a number of questions from you just to guide us on your perceptions. And show us where we need to focus the conversation.
I’d also like to let you know we will be recording today’s session so that we can provide it to anybody who has been unable to attend today so that they can catch on the update as well. That will be made available online.
So with that out of the way we’ll go to the agenda.
Today’s session will be a bit shorter than the previous webinars. It should only go for about 40 minutes. We’ve allocated about 30 minutes for the formal presentation and about 10 minutes for questions.
In terms of the agenda, we are not going to go over the detail in our Tariff Structure Statement, as this has been covered in other webinars.
We will give you an update of where we are in the process.
And then Jenny will cover our take outs of what the Australian Energy Regulator, the AER, has said in its draft decision on our Tariff Structure Statement
After this we’ll break to address your questions…
Then Jenny will then explain how were are responding to the AER’s request for additional information
And then cover off on a few points where you may need clarification so that you can participate effectively in the final stages of the AER’s consultation process.
We will then close, as I said, to take time for further questions.
If you are new to these updates, the background to all this, and the proposed Tariff Structure Statement can be found at the web site that you see on the screen there. There is that and all of the previous engagement we have undertaken.
I should point out though, for those that are new, that we are only talking about NETWORK TARIFFS… they’re just one component of a retail electricity bill…it is just the charge for the use of the network.
Well hopefully that covered all I need to do.
Before I handover to Jenny, I will just to a very quick poll to see who we have got on line. I will just do that now. And if you could answer that it would be very much appreciated.
We just want to know if you have you been involved to date in our conversation about our network tariff reform.
So there is the option of:
Thank you everyone.
A good two thirds have attended a previous webinar … thank you, thank you for coming back to this one.
We do have a handful, about 10% who have had now exposure until today.
So if we do cover something that you are not clear on, or Jenny covers something, certainly put the question in as we said or refer to the additional material after the session to follow up on your area of interest.
With that I will hand you over now to Jenny Doyle… but I will just switch this around so that I can get her on to the webcam so that you can be introduced to her.
It is not showing up on the screen…why is that?… I think you can see her but we cannot see what you are actually seeing. It has not shown up on the audience view. Of maybe it is because of the poll… I have not shut the poll. That is my fault.
There we go. Magic. The webcam is working. I will now hand you over to Jenny Doyle.
Thank you Sara. And thank you everyone for joining us.
It is great to see we have a mix of people who have been with us from the beginning of this journey and some who are new to the tariff reform process
As many of you will know we started a network tariff reform journey over three years ago now, very aware of the need to deliver cost reflective and fairer pricing signals in relation to our charges for the use of our electricity network.
This led to the proposals that we put forward in our Tariff Structure Statement at the end of last year.
Since then the AER has reviewed our proposals for our network tariffs out to 2020 and undertaken its own consultation process.
And, as Sara mentioned, in August the AER made a draft decision on our Tariff Structure Statement.
Overall they gave us a green light, which we are very pleased about.
Their approval through their draft decision means that they considered what we put forward in our Tariff Structure Statement or what we call our TSS, is compliant with the Rules.
They found it compliant both in terms of what it contains and how it reflects the distribution pricing principles.
I will share with you the key points that we took out of their response to our TSS in the next few slides…. but by way of introduction, I think you could say we received a solid tick for our consumer engagement and for our move to complement our tariffs with a dynamic demand management layer.
And we received ticks, with some suggestions and requests for additional information, on Cost Reflectivity, our Inclining Block Tariff and for Customer Support.
Although I will go through these at a fairly high level, I want to give you enough information to assist you if you choose to participate in the AER’s final step of its consultation process.
So if I miss something or I am unclear please ask me to expand as Sara has explained in the Question Pane.
As part of this final step, we are preparing a revised Tariff Structure Statement. You will be able to access this after the 4 October, before the AER’s deadlines for stakeholder submissions of the 25 October.
This process will also inform our annual Pricing Proposal for 2017-18… and the TSS will then frame our tariffs out to 2020.
I don’t want to stay on this point too long. I just want to acknowledge the role many of you have played throughout our customer engagement in developing our tariff reforms.
We started on this journey several years ago, and at that time the tariff structures were not too different from the structures offered 15 years earlier.
Since then, customer and stakeholder insights have been instrumental in forming our views on the appropriate path forward, and the tariff structures detailed in our Tariff Structure Statement.
This co-operative and constructive engagement process was noted by the AER.
They recognised that you, as stakeholders, were able to put forward your views throughout in the tariff development process. And although at times this has meant we have had to agree to disagree, I hope we have met your expectations in regard to explaining why we have not always been able to accommodate your position.
So here I just want to take the time to give a bif shout out for your assistance in this process.
Looking ahead, while we have established the 2016-17 year as our foundation year with the majority of our reforms now in place, we will continue to engage so that together we can build our collective understanding and promote the new tariff options in the TSS.
And we’ll even start looking beyond 2020.
In the AER’s draft decision they of course had a lot to say on cost reflectivity and our key reforms.
We see the concept of cost reflectivity as one that provides the right price signals to customers so that the choices each customer makes in using the network is reflected in the price they pay (and not in the price other customers pay).
Our new tariffs signal to customers the relative cost of their demand on the network depending on time of day and time of year.
In developing our proposal the potential cost of not undertaking reforms was modelled. You can see this illustrated in the graph on the left hand of the slide. If the legacy tariffs were to be maintained the modelling indicates the cost to customers overall would be significant… an increase of around 15% above CPI compared to moving to the cost reflective demand tariffs we have now introduced.
One of the factors that is driving this is cross subsidies.
A cross subsidy is created when customer behaviour reduces revenue but does not reduce our costs to supply, or visa versa, it increases our cost to supply but does not increase revenue accordingly. The first is illustrated to the right of the slide.
In their draft decision, the AER recognised this impact and have endorsed our TSS as complying with the pricing principles. They said…
“In terms of compliance with the distribution pricing principles, the tariff structure statement:
They went on to say that the TSS shows Ergon Energy has considered its forward looking costs of service and applied reasonable approaches to estimate long run marginal cost… or the LRMC..
Being aware of the impacts of inaction and creation of further cross subsidies the AER has also stated that the approach in our TSS, in terms of transitioning to cost reflective tariffs, is at one end of the spectrum – the least progressive – and they are looking for movement further along the spectrum moving forward.
The AER in its draft decision acknowledged the fact that our network is strongly summer peaking…and that demand in summer is more likely to drive augmentation.
They also stated they considered that we had sufficiently justified our charging windows.
This reflects the fact that we put significant work into analysing our demand profiles.
With cost reflective tariffs it is vital to correctly set the peak period to avoid over- or under-signalling the cost of peak demand.
In order to come up with the peak demand windows, we analysed the 30 minute load profiles of each of our zone substations.
This made it clear that these zone substations firstly could be grouped into mainly residential and mainly business segment datasets. This then allowed us to separate them, by these profiles, into weekday/weekend and summer/non-summer.
We outlined this process in our earlier webinars and details of this work is also fully documented and posted on our Future Network Tariff website.
It is worth pointing out that in the Ergon Energy seasonal time-of-use demand tariff structures across the Standard Asset Customers Small and Large, and our Connection Asset Customer class that our forward looking costs, our LRMC, is only recovered in the peak demand charge in the three summer months.
Our remaining costs, or our residual costs, are recovered in the other tariff components.
It is also worth noting that the demand component included in the non-summer months is part of this residual cost recovery.
As I said earlier, the AER endorsed the LRMC calculation that Ergon applied in its TSS. They agreed that the inclusions of a small percentage of our forward looking replacement costs was appropriate as modern assets often have a greater capacity than what they replace.
In fact, in the draft they were encouraging other distributors to adopt this practice in the future.
At present the default tariff for small customers supplied by Ergon Energy is the Inclining Block Tariff or the IBT.
In general this network tariff is invisible to small customers as the current default retail Tariff 11 is based on the Energex structure of a fixed charge plus a single flat energy charge.
This is done as part of the Queensland Governments Uniform Tariff Policy, as outworked by the Queensland Competition Authority… the QCA.
But getting back to the network tariffs, the AER agreed that fact that the IBT remains our default means that customers have to opt-in to access the cost-reflective seasonal time of use tariffs or the STOUD. In other words at present no customers will be mandatorily assigned to STOUD.
The AER also noted in the draft decision that our TSS has stated that we will be considering making the demand tariffs the default option for NEW customers with appropriate metering from 1 July 2018.
This consideration will be aligned with the Power of Choice initiative, which is aimed at making smart meters available to customers with meter supply on a competitive basis.
You can read more about that change on the Australian Energy Market Commission’s website.
In the draft decision the AER has noted the Rules requirement for the distributor to overlay broad based network tariff signals with localised demand management initiatives in areas where a network constraint exists.
The AER goes on to say that they think it is appropriate for distributors to outline their approach to integrate tariff reform, network investment and demand management.
This is an area where we think Ergon Energy has been very progressive. We call it the Dynamic Layer.
The AER has recognised this by noting Ergon Energy offers demand reduction incentives in, for example, South Mackay and Cannonvale.
The slide shows a ‘heat map’ identifying geographic areas in catchments where demand reduction or indeed distributed energy resources might be applied to defer or as an alternative to network investment.
This map is interactive so you can go online and have a looks at it. A state-wide view provides an overview of the current and potential future incentive areas. As you zoom in you’ll see more detailed information with different colour shading to show:
The aim of all this is to optimise the investment and minimise the cost to be passed to customers by integrating tariff reform and demand management.
In recognising Ergon Energy’s dynamic layer approach the AER stated that… while the rules require distributors to consider the time and location varying nature of network cost drivers, the difficulties with locational pricing suggest a larger role for demand management initiatives as a means to address demand pressures.
In the draft decision the AER noted customers will require ongoing education and support with respect to new cost reflective tariffs. And we whole heartedly agree that we are only at the beginning with this.
Our main initiative here, outside of our direct engagement and webinar program, is the deployment of a real life tariff trial – in partnership with Ergon Energy Retail – to enable customers to gain experience and understanding of the new cost reflective tariffs.
This is vital to remove some of the uncertainty.
We recognise that this has been slower to get off the ground than we first indicated it would be in our previous webinars.
We have undergone a major change to our billing systems over the last few months, and are still working through that. At this stage we are nearly there with the billing capability to roll out Tariff 14 but as you can imagine there is a lot going on in our organisation at the moment.
Once we have that resolved we will look again for an appropriate start date to take the tariff trial to external customers for both Tariff 14 and 24.
This is all being supported, of course, by the QCA creating these retail tariffs to reflect the structure of our network tariffs.
I am pleased to advise, however, as we stated at our last webinar, that the internal part of the trial is well underway. We have 88 Ergon Energy employee sites where smart meters have been deployed and a structured paper trial has commenced based on the residential retail tariff.
This includes nine trailblazer sites, which have already provided valuable learning. We are also working on an initiative to assist customers who don’t have a smart meter to assess their demand based on their current energy usage data. This in turn would allow customers to understand the STOUD tariffs – and to assess the potential benefit for them.
Okay, we’ll take a quick break now to giver Jenny a moment ot have a sip of water. I have got one question for you Jenny about the way the Community Service Obligation fits in with network tariffs.
So I will pass that through to you. If anyone else has questions, as I said put them in the Question pane and flick them through. We can either answer them now or as we go forward. So I will just pass back to Jenny to talk about the first one from Dominic, which was “Would moving the Retail CSO to the network level have a material impact on our forecasts?”
Thanks Sara that’s a very good question. The potential to move the CSO from the Retail business to the Network is a government policy issue so it is one we can’t generally comment on. In terms of our forecast we are conscious of the Queensland Productivity Commission’s recommendations to the Government in the draft report and it is something that we are continuing discussions with to understand any potential impacts and timing on our pricing signals.
And the Dominic has a second question there around “Are there restrictions on a customer reverting to their old tariff if they have opted to a cost reflective tariff?”
There is one restriction in terms of timeframes. Under the Retail Gazette you are only allowed one tariff change in 12 months unless there is a material change at the premises. But other than that there are no restrictions on reversion.
Another question here, which we will take before moving back into the presentation. “When will the trial for SME, the Tariff 24 trial commence and how do you get involved if you are interested?”
Maybe I will just answer that one. It is part of the plans, but as Jenny said we are working to get the billing process stabilised, in the mean time I can take details from anyone who is interested in that and we can touch base when we get a roll out plan for that. So I will email you Scott and put your name down on the list.
Okay I will hand back to Jenny and we’ll go through the last few slides.
Thank you Sara.
As Sara mentioned at the beginning the AER requested that we provide additional information to assist understanding in a few areas.
The first of these is in relation to our adoption of the average versus single peak half hour in establishing the demand charge for the new tariff for our small customers.
Ergon Energy actually moved to an averaging approach for the STOUD as a result of customer consultation during the tariff design stage.
Just to recap from our last webinar, for the small customer STOUD:
We look at the highest four demand days in the month, based on the demand in the daily peak demand window, then we take the average of these top four demand days.
If you want to understand this more, we outlined this approach in detail at our last webinar and it is fully documented in our original TSS.
In the draft determination the AER notes that at present no distribution network is able to fully match customer and network peak times via a tariff signal. Naturally, if you try and match a single half hour period to achieve a full match it is more difficult than with our averaging approach.
The AER noted that this approach may have the advantage of incentivising customers to minimise their peak demand throughout the billing period.
We will respond to the AER’s comments on this topic in our revised TSS.
The AER also requested further information around our ability to create end use tariffs for specific classes … for example irrigation customers.
We are carrying out analysis on this and will include it in our response in the revised TSS.
Another area that the AER requested that we provide additional information on is in relation to the introduction of an excess kVAr charge for Connection Asset Customers or our CAC customers as we call them.
We introduced an excess kVAr charge in 2015-16 for ICC customers to improve cost reflectivity of our charges.
Essentially this charge reinforces the price signal introduced by the change to the kVA tariff, which encourages customers to improve power factor and reduce their usage of network capacity.
A premise’s power factor is important because distribution systems must be designed to supply the actual power required and a low power factor means actual power delivered will be unnecessarily high.
The excess kVAr charge is to be applied against kVAr used by a customer that exceeds a permissible quantity. This is calculated by assessing what they would be entitled to use at their minimum compliant power factor while operating at their authorised demand.
This structure is designed so as to provide a network signal to the customer, not a penalty.
If you were in our last webinar, you will be aware we were intending to introduce the excess kVAr charge to our CAC customers in July this year. This was delayed at the request of the AER. Since then the AER has considered our position with additional information, which we will include in our revised TSS.
We now intend to introduce it in 2017-18.
In addition to excess kVAR, the AER has suggested that alternate control service prices be dealt with in brief in the main TSS document.
Ergon Energy will comply but will also provide comprehensive detail for the information of all stakeholders.
The last area that I want to cover is the handful of things that I think may require clarification. This is mainly for those who are thinking about making a submission to the AER on our revised TSS.
Firstly I want to clarify our position on opting in or opting out of cost reflective tariffs.
Just to explain the current default tariff for customers across all user groups are the legacy tariffs. So customers wanting to access the STOUD tariffs have to opt in. As I mentioned earlier for SAC Small the AER has noted our intention to shift to opt-out for new customers in July 2018 and that means for those customers the STOUD becomes the default.
For SAC Large our intention is to shift to opt out for new customers in July 2017… that is one year earlier. Both these changes are subject to customers accessing appropriate meters.
While on SAC Large, another area of clarification is that for SAC Large we currently use a kW tariff not a kVA tariff. We have signalled our intent to consult on kW/KVA/excess kVAr for SAC Large for our 2020-25 TSS.
Quite a lot of network analysis is required, however, to ensure the most efficient outcome for the SAC Large user group.
I’ll also mention again the issue of special end use tariffs for customers, such as irrigators. This too will require us to extend our current analysis, including gathering further relevant costs to be allocated in pricing any potential end use tariff.
One other thing to clarify again is the way we apply the LRMC.
As I mentioned earlier, it is only recovered through the peak demand charge in the three summer months – everything else is recovered in the residual in the non-summer months … and as I said during the presentation a demand element can be included as part of the residual structure.
Well that is pretty much all I wanted to go over today.
I have put the timeline back up so you can see that. This process will feed into our Pricing Proposal for 2017-18.
I should point out also that for the revised TSS, we will be updating all of the pricing schedules. Brendon Crown went through the pricing trends for each customer class in our last set of webinars on our Pricing Proposal for 2016-17.
The TSS will be all updated in line with this to give you full transparency of our charges out to 2020.
If after looking at what we presented today, and then our revised TSS, and you would like to make a submission we encourage you to.
We do have more time now also for questions…. Or you can find more information on our web page.
Okay. Thank you Jenny, on behalf of all of our guests that we have online. I think that was a great presentation of how things have progressed and the things we need to do to finalise our revised Tariff Structure Statement.
Which as Jenny said will be available for you before you are required to meet the AER’s submission deadline.
We do have time for questions. If anyone has any, please flick them through. If not we will wrap up earlier.
I do have the closing poll to put through so I will do that because we do not actually have any more questions… everyone is being kind to you.
Here’s one now. That’s good.
“Hi. Can I just to confirm the dates when Tariff 14 will be available. And is the plan to replace Tariff 11 with Tariff 14?”
That’s a very good question. So Tariff 14 is currently available in the Gazette but it is at the discretion of the Retail business whether that is offered. I don’t have the timing of Ergon Energy Retail business with me at this stage but we can get back to you on that. Whether Tariff 11 is replaced or not will be a question for the Queensland Competition Authority as they are responsible for setting and determining the retail tariffs.
Okay… a question here from Bruce Cooke…”If you use Energex’s tariffs does the STOUD have any impact.
So in terms of the retail tariffs…they are based on a mix of underlying tariffs. For Tariff 14 and 24 they are based on Ergon Energy STOUD structure but with Energex’s revenue applied to it. So the STOUD is reflected into the retail tariffs. It is Tariff 11 and 20 that are based on Energex’s network tariffs in their entirety. So depends which tariff you are on as to whether there is an impact from the Ergon Energy tariffs.
And at the same time as us doing tariff reform, Energex is doing tariff reform as well. So they are introducing similar demand tariffs.
Another question here from Tony Sheils. “Hello. Has the technology been developed so that the householder gets notified by smart phone that they are going to reach maximum demand?”
So that is another very good question, and I know our retail business and a range of others retailers are looking at range of technologies to support the customers that are moving onto the new tariffs with complex structures such as demand based tariffs. It will be up to the individual retailers as to what technologies they will provide as part of their package.
I am sure that is going to evolve quite dramatically as everything else does technology wise.
Another question here from Sarah Harlem. “Who will pay for the new meter required for the cost reflective tariffs?”
So for the STOUD tariffs customers require a smart meter, a remote interval meter. What a customer is charged will depend on the arrangement that each retailer has in place. Our retailer, Ergon Energy Retail is bound by the notified prices and any requirements of the Queensland Government. So I suggest it is best to contact our Ergon Retail counterparts to find out what the prices may be, if anything. And it may be subject to change with the changes as Power of Choice is implemented. All of those issues are currently being worked through.
That is very good. That’s the last of the question we have.
So I will just put the poll question up there just to get a bit of feedback on the session. I will launch that now. It is the same question that we have asked previously, which is “Did you find the webinar experience valuable?”
This is just to give us feedback. We are happy to have any anecdotal stuff to allow us to improve future webinars. We just think it is a great way to get out to a pretty broad audience.
So the responses are:
And a good chunk of you said it was very valuable. We really wanted to time it with your opportunity to do submissions with the AER.
And around 80% say if was of some value.
So thank you very much for that feedback.
We will just check we do not have any more questions. That’s wrapped up our questions and wrapped up what Jenny wanted to pass on so we will take the opportunity now to bid you farewell… And enjoy the rest of the day.
I should say we are still recording so if any you know could not attend I will send the email out to all of you so you have that link as well
Thank you all very much.
April 2016 - an update on our reforms
An early webinar was held in April to update stakeholders on our network tariff reforms.
This was when the AER was inviting initial submissions on the proposals in our Tariff Structure Statement. The webinar provided interested stakeholders the opportunity to learn more about the matters raised by the AER regarding our reform path in their Issues Paper.
To find out more, watch the following video or alternatively review the slide presentation An Update: Ergon Energy’s Network Tariff Reforms (PDF 3.8 mb).
Good morning everyone. Thank you so much for joining us today for this webinar, our update on Ergon Energy’s Network Tariff Reforms.
It’s fantastic the response rate we have had. We already have 35 attendees online and a number more to join us so thank you all so much for giving us your time.
Being just one part of the electricity story, network tariffs are normally a little bit ‘behind the scenes’ so to speak.
So, for those who are listening in for the first time, we’ll endeavour to explain things as we go along, including how they feed into the retail tariffs and all the choices that are available to our customers in regional Queensland.
And for those of you who have been engaging with us on the topic of network tariffs for a while, we will be going as we move along to some of the more complex parts of how our tariff reforms and how they have been developed. So that will probably cater for those who attended the webinar in November.
My name is Sara Collins; and I’ll be facilitating today’s webinar.
I am joined today with Ergon Energy’s Manager of Regulatory Determination and Pricing, Brendon Crown. And of course you’ll hear from Brendon shortly.
But before we get started I just have some of the housekeeping and the how tos of the webinar process.
When you joined the webinar session, a Control Panel will have appeared so you can manage your session.
If your Control Panel is blocking your view of the presentation, you can just use the small orange arrow to close it. And then just re-click it to make it re-appear.
From the Control Panel, you can control how you listen to this webinar. If you are having issues with your audio, you can dial in via telephone at any time by selecting the telephone option and calling the number provided.
Alternatively, as some of you would be already, you can use your computer speakers or a headphone.
Another screen will have also appeared showing you the first slides of our presentation.
I will just test that now to make sure that moves on. That’s the control panel I was talking about before that you should be able to see.
We have activated our webcam functionality, so you should be able to see me and you’ll see Brendon later on in the session.
For this webinar, we have put all the microphones on mute, so you will not be able to speak… and nobody else will be able to hear you.
You can still ask questions of us during the presentations though by typing them into the Questions Pane at the bottom of your Control Panel. So there is an option there.
These questions will be monitored throughout the session. As well as Brendon, I have a couple of members of his team standby to assist here.
We’ll also take a few minutes at various points in the session to address questions, and then use the time set aside at the end as dedicated question time.
If we are unable to answer your question or if you have additional questions after the session, you of course can send them through to us. And we will endeavour to address your questions via email and we will give you that at the end of the session.
I’d also like to let you know we will be recording today’s session so that anybody who has been unable to participate will be able to access it.
It will be made available online and we’ll email it out to you.
Today’s session will go for approximately one hour. We’ve allowed about 40 minutes for the formal presentation and then 15 to 20 minutes for questions.
During the session, we plan to ask you to complete a couple of quick polls.
These polls, just two of them, will pop up on your screen at the right time.
These multiple choice questions will help us gauge your perceptions and let us know where we need to focus the conversation basically.
Hopefully that covers off the key things you need to know.
In terms of today’s agenda, we firstly be talking, doing a bit of a recap of Ergon Energy’s tariff reform journey and how it fits in the bigger picture… and the processes and consultation that’s currently underway.
We’ll then take five minutes to address any preliminary questions.
Then we’ll use the majority of our time working through some of the matters the Australian Energy Regulator has raised in its issues paper regarding our Tariff Structure Statement, which covers our network tariffs out to 2020.
So I think you will have some question during the break for discussion and then close the session with some more time to take your questions.
To get this started, I will do a quick poll now. I will just launch that.
You should see on the screen now, and quick question just to give a guide as to who we have online.
Could I just get you to answer that.
The question is: Have you been involved to date in our conversation about our network tariff reforms?
The four options are:
- No exposure, until today
- Looked briefly at material online
- Attended a previous webinar
- Reviewed material online in detail
- Engaged with us face-to-face or one-on-one
I can see the responses coming through there now. Thank you everybody.
We have a big chunk of people who have attended previous webinars, about 42% and another third who have looked briefly online.
But a small handful who have had limited exposure. So Brendon that will help you as you go through.
I would now like to introduce you to Brendon Crown, Ergon Energy’s Manager of Regulatory Determination and Pricing. I will just get you to take over to you.
Thank you Sara – and welcome to a further update on Ergon Energy’s network tariffs.
This is about the fourth or fifth time we have done a webinar and we have some fairly positive response from it.
We do not that we have had some problems with sound dropping out. If you do have a problem, please flick through a comment or question and we’ll fix that at our end.
As Sara said I do want to first briefly introduce network tariffs for those of you that are new to the topic. As we have a lot to go through, I will not dwell for too long on some of the material that we have outlined in previous webinars. I would recommend some of the webinar and supporting material on our website for those of you wanting more context around some of the issues we will be discussing today.
We’ll out that website up at the end of the session.
In short, network tariffs are the charges we apply for the use of the electricity network; as you can see they are just one part of the bill. They don’t cover electricity generation, green schemes or the other retail costs.
This is important to get our head around as it impacts what we are going to talk about today.
Now our focus on network tariffs can be confusing for stakeholders because Ergon Energy, as you are well aware, also operates as an energy retailer.
Many of you will be aware of two recent consultation processes regarding tariffs….
The first being the AER engagement on our Tariff Structure Statement for tariffs out to 2020.
Because my focus is on the network part of the bill and the charges and components that form part of the network bill, most of today’s discussion will be around the issues raised in the AER’s paper on our Tariff Structure Statement.
However, it would be remiss of me not to spend a brief amount of time discussing the Queensland Competition Authority draft report on regulated retail tariffs for 2016-17, primarily to explain the link between our tariff reform agenda and the QCA consultation.
It is important that you appreciate that we have different network tariffs for very different types of customers.
Our customers are grouped into tariff classes based on electricity they use.
Of the 730,000 customer connections Ergon Energy provides electricity to… around 725,000 of these use less than 100MWh (megawatt hours) of electricity a year…
86% of these are residential customers and 14% are small to medium businesses.
And over the last few years, many of you have been on the journey with us to make substantial changes to the tariffs we offer customers.
We have made changes to the majority of our tariffs and now offer significantly more choice with additional tariffs being offered.
To support the introduction of the Tariff Structure Statement, we have established this next year, this 2016-17 year as our foundation year, as we expect all of our major reforms to be finalised in time for 1 July 2016 with the AER’s approval.
From there, we plan to keep our tariff structures relatively stable out to 2020… and in doing so build a greater understanding of the new tariff options whilst also promoting their benefits and hopefully uptake.
Our objective is and was to ensure we could continue to meet everyone's needs into the future for the best possible price and to deliver fairer, more equitable pricing signals for everyone.
Along the way we have refined our views on the appropriate path forward, and the tariff structures detailed in our Tariff Structure Statement, are based on your feedback.
The extensive consultation and reform process over the last few years means that our Tariff Structure Statement… covering our tariffs from 2017 out to 2020… comprise tariff structures that we have already consulted on and have already been approved by the AER.
We presented our Statement to the AER in November last year, and this was the main topic in our last webinar.
You will be aware that the AER has commenced its own consultation on our TSS…as well as the TSS of Energex’s. The release last month of an issues paper does allow you as stakeholders to consider some of the material presented from the AER’s perspective, while also considering our own Tariff Structure Statement.
You can see that we are going to be friends for a while, this process will continue as you can see… but the next major milestone is the AER’s public forum on the 13 April.
In case you thought this wasn’t enough, this timeline doesn’t really show the process we will need to start going through for developing our 2020-25 Tariff Structure Statement. We expect that this will need to commence in the next 12 months to ensure we can meet our regulatory timetable.
So the process that runs parallel with this is the annual determination of regulated retail prices.
Many of you will be aware that last week the Queensland Competition Authority – the QCA – has been delegated the task of setting the Notified Prices for 2016-17.
We, importantly, feed into this process by providing them the detail of our indicative network rates for each tariff, but like you we have only just seen their draft determination.
The slide you see on the screen, we have shared this slide here before. It shows how the price stack works for regional Queensland. And in the last webinar we detailed our indicative rates.
What we are talking today about what we charge for the use of our network… highlighted by the dark blue network part of the graph.
You will see that the prices represented by the aqua bar are lower than the cost price “stack” next to it…which includes our network cost.
And the aqua bar represents the QCA notified price for regional Queensland.
The difference is because electricity prices in regional Queensland are subsidised by the Queensland Government… this means the QCA can set prices for residential and small business customers on the cost of supplying electricity in south East Queensland… while notified prices for large customers based on the lowest cost of supply in regional Queensland.
I do note that the Queensland draft determination is draft only and they are consulting with a public roadshow prior to finalising their determination in May 2016.
More information on the workshops and how to make a submission is available on the QCA website, which we will give you at the end. They will make a final determination by 31 May.
So setting network charges at Energex cost levels means that customers in regional Queensland will, generally, pay the same for network services as customers in south east Queensland.
In the draft schedule for the regulated retail tariffs the flat rate Residential and Business Standard Asset Customer Small or SCA Small reflect the structure and rates of Energex’s network charges, consistent with the Government’s Uniform Tariff Policy.
The important change that happened only recently is that for the Time-of-Use tariffs the QCA is using Energex’s costs, but our pricing structures. So you are seeing here the outcome of the reforms we have been progressing… and consulting with the QCA on… these structures are at a subsidised rate.
Now the demand-based, seasonal time-of-use tariffs are the key reforms that the AER has been reviewing and asking for comment on.
The QCA has… in our view… correctly summarised that Ergon Energy customers do need to be provided the pricing signals consistent with the times most likely to impact future network costs.
In other words the QCA applies Ergon Energy’s cost reflective tariff structures – not Energex’s. It does however discount the rates so that the prices themselves are consistent with what would be charged in south east Queensland.
That’s for the small customers, for the last two customer segments, the notified prices as I said are based on the lowest cost of supply in regional Queensland. By that I mean what it costs to supply customer along the coast, or what we call our East zone.
The QCA’s draft determination includes a lot of information on the transitional tariffs and I expect that will be a hot topic of discussion in the public forums they are running.
I don’t really intend to cover the issue of transitional regulated retail tariffs today, as from a network perspective we have very limited influence over QCA’s decisions in this regard.
There is also a lot more information in the draft determination on street lighting tariffs and unmetered supply which, in the interests of time will not cover today.
However, I do want to close off on an issue we raised at our last webinar as it relates to issues some of you have raised on our cost reflective tariffs …
Many of you will remember from our last webinar that we saw opportunities for retailers to develop, using our new network tariffs as the foundation, a monthly retail energy cap plans for residential customers, in which customers pay the same price for a pre-set level of demand and energy each month.
We saw this, as well as delivering savings to the customer compared to their existing tariff… we saw that customers could benefit from the certainty of monthly payments that this type of tariffs brings, and without customers needing to understand the detail of the underlying components of the network tariff.
Now on a read of the QCA’s draft determination, we understand that such a tariff has not been included for regional customers in Queensland… but we will continue to engage the QCA and other stakeholder on this initiative.
We note that recently Origin Energy has launched a similar concept to what we have been proposing although I believe the concept can be improved with additional savings to customers when partnered with a cost reflective tariff.
I am hoping to do more in this space… and we’ll keep stakeholders informed of our progress on this.
So now that we have covered a bit about the processes and consultation underway.
What I would like to do is spend the rest of today’s session on is the AER’s issues paper on our tariff structure statement.
The AER is holding a public forum next week and I understand that some of you on the webinar will be participating or presenting at this forum.
The AER has asked stakeholders to respond to some important and complex questions on pricing arrangements.
So we thought it would be worthwhile providing our initial thoughts on these important but complex questions on pricing arrangements. We hope will assist you in focusing your thoughts on the issues that concern you.
So the issues that we thought would be worth covering today before the public forum are the following topics:
The Definition of cost reflective tariffs
- How we set the peak period
- How to apply the residual costs
- How we best transitioning to cost reflective tariffs
- How we best address the locational issues
- And how we have progressed reforms for our larger customers.
But I think we’ll take a break now so I can have a quick glass of water and answer any questions that you have so far… or possibly take any suggestions on topics we may have missed in the issues paper.
Okay, well Brendon, at this stage we don't have any questions so just in the interest of time we might skip this and continue on and if anyone has any questions as we go through don't hesitate to drop them in there and if we need to cover different topic we were more than happy to. So I will hand it back to you.
Excellent, thank you. So it is worthwhile now, Sara, recapping on where we have landed with our reforms on the next slide, and this was outlined in our previous webinar.
Our current suite of tariffs include this new concept of a seasonal, time-of-use demand tariff. For want of a better acronym we refer to this as the STOUD or STOUD tariff.
And it is now an option for all published tariff classes… not just for our small, but also our SAC Large and our CAC customers.
I have identified the components of two of these tariffs here – related to our SAC-small on the left and SAC-large on the right. You will note they are different and we will go into detail as to why they are different later in the presentation.
You can go online to see a guide for each class, which goes through the detail of the tariffs on the screen… or of course you can review the previous webinar.
As I mentioned earlier we been undertaking reforms now for a number of years.
Later this month - we will be submitting our 2016-17 pricing proposal to the AER and this includes some minor changes to our structures based on comments we have received from you. And these were included in our Tariff Structure Statement.
We see the prices in 2016-17 as laying the final foundation for the tariffs we have to put out from 2017 to 2020.
Many of the issues raised by the AER refer to these tariffs. So we’ll move on to discuss them…
First let’s talk about how we have approached cost reflective tariffs during our tariff reform prices over the last three years.
We see the concept of cost reflectivity as one that provides the right price signals to customers.
Cost reflective tariffs ensure the choices each customer makes in using the network is reflected in the price they pay (and importantly not in the price other customers pay).
A cost reflective tariff therefore has to signal to customers the relative cost of their energy demand to the network depending on time of day and time of year.
And this is probably the main distinguishing feature of cost reflective tariffs compared to existing legacy tariffs.
See legacy pricing structures are not cost reflective because they provide no signal to customers about the cost of their energy demand to the network. This means that customers pay more than what they should for the majority of the time and less than what they should at times most likely to impact future network investment.
These inefficient price signals increase unnecessary bypass of the centralised energy system at times which don’t help the network with little or no response when it is needed.
This impacts the network via higher voltage management costs and falling utilisation.
The cost to serve customers through the network thereby increases, incentivising more bypass – again, with no corresponding reduction in network prices. Legacy pricing structures can only respond by increasing energy rates across the board.
There are implications for both the network and retail businesses, but also for the economy as a whole, as the total cost of delivering energy in Ergon Energy’s network area becomes less efficient.
Now it is welcoming that the AER’s issues paper shares a similar view on the problems with legacy pricing structures.
So if cost reflectivity provides the right signals to customers, then cost reflective tariffs should be able to demonstrate how these signals are established.
And these concepts of cost reflective pricing are relatively simple to explain. However, the mechanics of how they are applied to go into technical detail which we outline in our Tariff Structure Statement.
Now I am going to acknowledge that this is really more complex than you probably wish to understand… but I do want you to go away hopefully with some appreciation that our tariffs for each tariff class have been developed more from science than from art.
A cost reflective tariff has both a peak charge component and a residual component.
A peak charge component which is set at long run marginal cost (LRMC), or the cost meeting future growth in peak demand. This signals to the customer the cost of using the energy during peak times. Obviously customers who value energy usage at peak times greater than the LRMC will continue to use the network at these times.
However, there’s choice. Customers may choose to avoid the cost at these times through reducing or substituting energy use.
The beauty of this is that if they do so, we believe this will reduce costs over the long term.
In the Small customer example you see on the screen the box in dark blue representing the summer peak demand charge and this is the peak charge or LRMC component which we are applying.
Now setting tariffs to reflect marginal cost – even LRMC – will typically not, by themselves, allow a distribution network to recover all of its historical capital costs. A cost reflective network tariff also has an efficient residual charge component. Economists suggest residual cost recovery tariffs should be structured so as to have the smallest possible unintended impact on customers’ consumption decisions. In the examples, the boxes in lighter blue represent the residual charges.
I just want to emphasise this point as I think it may have been confused in the AER’s issues paper. Our Tariff Structure Statement identifies the “peak” demand charge as the LRMC peak charge mechanism. The non-summer off-peak demand charge does not recover the LRMC – it recovers residual costs. It is an important difference between our proposed cost reflective tariffs and those in other network areas.
And the next slide will hopefully explain why.
The AER’s issues paper correctly identifies the challenges in linking the LRMC signal to the period most likely to influence future network investment.
And these challenges are exemplified in the network area we are talking about. Ergon Energy supplies electricity across a vast, diverse service area of more than one million square kilometres – across 97% of the state of Queensland.
Our network is divided into three zones. However, two of these pricing zones on their own would still be larger than most of the network areas in the National Electricity Market.
At a network level Ergon Energy will exhibit different demand profiles to other network areas.
And we agree with the AER and QCA that different approaches in setting demand charging windows, of tariff parameters, are appropriate when dealing with a network of our size and magnitude.
Providing a more efficient signal to customers in 97% of Queensland geographic area in our view outweigh any issues of consistency with customers in the remaining 3% of Queensland’s geographic area.
Now I’m not going to lie to you… the issue of calculating, and applying the peak charging mechanism is a complex one that does require a number of considerations. Our appendix includes around 25 pages of information to support our approach.
For those of you who have been on the journey you will be aware our approach to calculating and applying the peak charging mechanism has been developed over a number of years with a number of iterations and with the assistance of well-regarded independent economists and consultants.
The AER’s issues paper suggested we did not provide enough analysis in support of our approach which we were surprised at given the development we have undertaken over the last few years.
So in the next few slides I do want to give you confidence that we have applied what we consider a comprehensive approach to establishing LRMC and peak charges – I may lose a few people along the way – but it is important to reinforce that our considerations around peak mechanisms particularly were based on comprehensive analysis rather than preference or punt… we would like stakeholders and the AER to understand this context when attempting to address some of the issues the AER has raised.
Now Ergon Energy, like other network service providers is often guilty of simplifying the daily consumption decisions of every individual customer into one chart.
But the reality is that the system load profile is not a very good representation of any individual customer’s daily consumption. Nor is it necessarily a good representation of feeder or zone substation profiles.
Our starting point therefore was to try and understand the relationship between individual consumption decisions and the network load profile to which it relates.
To do this we needed to first break that system load profile down to a more granular level and use the profile of that granular level to establish the window that will most likely influence future network investment.
Now it is important to get the window right. Including hours that are unlikely to drive peak demand reduces the price per kWh and thereby the economic signal to loads operating in the period of peak demand. Similarly not making the window big enough may bring forward future investment because of the wrong signal.
So in order to come up with the peak window, Ergon Energy analysed the 30 minute load profiles of each of its zone substations.
It became clear that these zone substations could be segmented into mainly residential and mainly business segment datasets.
We then separated these profiles into weekday/weekend and summer/non-summer.
Residential Zone Substation load segmentation highlights the significantly higher afternoon periods, compared to alternative seasons and day types. By separating out the summer period from the other periods, it enables to provide a much more cost reflective seasonal time-of-use (TOU) structure to be define.
Interestingly enough the Business Zone Substation load segmentation on the left shows a different overall profile of consumption, with a flatter peak period and a greater demand reduction due to day type. The summer weekend profile is significantly lower than the weekday profile.
Of course zone substation load profiles were not uniform – in fact there were considerable differences and variances in substations across our network area.
So we had to stress tested the off-peak period we defined… against the actual distribution of peak periods… for all our residential zone substations.
We looked at the risk that off-peak prices could result in undesirable increases in peak demand growth in some areas. We assessed this risk against alternative the risk of broadening the peak demand times for all customers and making to window too large to cope for individual variances.
Where the drivers of the peak window in individual substations represented a lower percentage of the total population, changes to the structure were less likely to be appropriate.
A good example of this was the observation that some residential zone substations experienced high demand windows in both winter, as well as summer. The problem of this was that adding a winter peak to account for this small number of substations would have diluted or water down the peak signal for 80% of substations that don’t exhibit a winter peak.
And so given other considerations relating to the risks of summer vs winter peak loads we were confident to proceed with the original peak periods provided.
Of course the setting of the demand window does not fully answer the question of how we will apply the peak charge.
The AER’s issues paper asks a very interesting question: What are the advantages and disadvantages of calculating a demand tariff based on a single 30 minute maximum demand period within the charging window (Energex) as opposed to the average of the four highest days of demand recorded within the charging window (Ergon Energy)?
It is important to note that this question is not entirely representative of Ergon Energy’s position.
Ergon Energy’s seasonal time-of-use demand tariff for large business and industrial customers uses what the AER describes as the Energex approach. In other words, for SAC-Large and CAC customers we apply a single 30 minute maximum demand period within the charging window.
We do of course adopt a different approach for our residential and small business customers. For these customers we look at the highest four days of average demand in the demand window.
Now why is this? In our view, there is no global superior method, and so the question is not why one is better than the other. Rather it should be how do you choose which is the appropriate approach to apply the peak charging mechanism and in what circumstances.
In other words this becomes a horse for courses question.
If you look at the attached diagram, to your left, you can see the net system load profile for a particular zone substation represented by the grey shaded area… as well as a subset of the individual profiles represented by the different coloured lines. You can see that there is quite a lot of variance between each individual customer loads and, you can also see quite a lot of difference between the individual load profile and the network load profile.
And this is the observation we saw across residential zone substations.
Because individual customer maximum demands are not heavily correlated to the timing of network utilisation peaks, applying an LRMC charge to one period in the month could penalise customers inefficiently for their individual maximum demand and provide no further incentive to reduce demand outside of this individual peak.
For residential customers, the use of the average of the highest four days of average demands in the window makes more sense than a single half hour maximum demand.
Applying the LRMC to an average of demands over a smaller window provides the right signal to customers outside of their individual maximum demand, and this aligns customer’s behaviour in the “peak window” to the network utilisation peak.
There is an additional benefit for customers here in that they have more control over how they use their energy without being substantially impacted by an ‘outlier’ event such as what occurs for this customer at about 6pm.
There is more uniformity of load profiles in the SAC-Large group represented on our right chart. On this basis we applied a maximum demand approach to SAC Large customers and an average demand approach to SAC Small customers.
We explain some of the economic theory which supports this approach in Appendix C of our Tariff Structure Statement.
In summary, we believe our approach is very much supported by the theory which underpins recent changes to the National Electricity Rules and is based on robust analysis to ensure our tariffs at different classes are as cost reflective as possible.
So hopefully I have not lost all of you.
I just want to spend one more slide talking about the other aspect of our cost reflective tariffs.
Obviously we’re explained our approach to the peak charging mechanism, it is necessary to work through our approach on residual charges.
And as we noted above, residual cost recovery tariffs should be structured so as to have the smallest possible unintended impact on customers’ consumption decisions.
From a purely theoretical perspective fixed charges are often advocated as the best means of recovering residual costs. But theoretical perspective can often result in having fruit thrown at you.
Recovery of residual costs via fixed charges alone has two main shortfalls. Firstly, fixed charges can disadvantage small, and potentially vulnerable consumers and this is something Ergon Energy wants to avoid.
Secondly, as the AER has pointed out, fixed charges may inadvertently drive incentives and behaviour resulting in disconnection from the network and place an additional burden on the broader community.
But it is not only high fixed charges that can do this.
Setting volume rates too high can also inadvertently influence behaviour resulting in lower energy use and this can also place additional burden on the community – including the potentially vulnerable customers in our community.
So the allocation of the residual costs becomes a balancing act of recovering the non-LRMC component in the least distortionary way.
And that why our approach over the last two years is to analyse various residual structures against various peak charging mechanisms and to actually model the impact of behaviours of customers based on the structures and rates assigned. Rather than just considering the implications of excessive fixed charges – which was pointed out in the AER’s issues paper – we looked at all residual recovery options to design a balanced approach to residual recovery.
We also took into account the impact of monthly volatility associated with a seasonal demand, as customer feedback regarding their preference for lower fixed charges.
Because the peak charge applies to three months of the year, collection of the residual component in the same month as the peak charge mechanism does creates an unnecessary bill increase for that month and may influence the behaviour of customers when deciding to take up the tariffs. Alternatively, by removing a daily fixed charge in preference for an off-peak demand charge, we minimise the impact of the monthly bill in the summer months – and smooth out the impact for customers across the year while still sending the LRMC signal.
The AER has questioned this approach in its Issues Paper. But it is important to distinguish the circumstances in this case. Energex is seeking to recover LRMC through the demand window across the year, where Ergon has been able to demonstrate it would be inappropriate for a peak charging mechanism to apply to non-summer months and therefore we have a very strong signal over a much smaller number of periods. This consideration of different residual approaches are appropriate in this circumstance.
Okay … we will move to some questions. I have saved you a couple there. So if you open your question screen you can see them there. And there is a little note from Graham in the Chat as well.
It certainly was some pretty complex concepts around how peak pricing is established and of course how it provides the actual signals that are core to creating a cost reflective tariff.
So if you have anything more to add please send them through, but I have got three questions now that Brendon can share.
Sure the first question comes from Bruce Cooke, his question is: Doesn't these 3 kilowatt off peak minimum charge discourage the uptake of batteries.
So I think in our modelling that we did with Energeia, Bruce, that wasn't the case. Of course the benefit of the seasonal time-of-use demand tariff is that it sends a very strong and appropriate signal for the use of energy at peak times, which for many residential customers goes between 3 and, I always get the times wrong, I think its three and 9.30 or 3.30 and nine, one of the two… it’s on the previous slide sorry.
And obviously that go into the night, so I would see this season time-use demand structure being very advantageous for customers that can have both solar and batteries.
What I think tariff does, and I will get into this later, is it provides those with batteries and even greater opportunity to provide opportunities for networks and give them some benefits particularly in constrained areas, but will get on to that in a latter slide.
Luke has raised a question: you show some typical load profiles for businesses and residential users, do they remove demand supplied by solar PV generation?
So the load profiles that we had there I believe are the culmination of various substation load profiles, so my understanding is that they do have solar PV included in those, but Luke don't quote me on that I will get someone from my team to chase that up.
Finally, have I got time for one more Sara?
Very quickly, if you can answer that one quickly.
I might leave that one for later. David, I've got your question but I might leave that for later otherwise I might see if Gordon can answer that off line.
Okay, handing back to you then.
These slides will go a lot quicker, so hopefully we do not have too long to go and hopefully we will have time for questions at the end.
I do want to go through some of the other issues raised in the AER’s Issues Paper.
For the reasons outlined above, and in our TSS we believe the long term interests of customers is achieved by moving customers toward cost reflective pricing as soon as possible.
And we note and appreciate the fact that the AER shares this view. Achieving the National Electricity Objective would suggest a bias towards moving more quickly and more aggressively to cost reflective pricing and a more efficient national electricity sector.
And I think the AER correctly observes that we have not removed our existing legacy tariffs and that, currently, seasonal demand based tariffs are opt-in. And that this means to adopt a cost reflective tariff, any new and existing customer must specifically request to do so through a retailer.
The AER I think has also appropriately raised the challenges in moving residential and small business customers to these preferred cost reflective tariffs. Our concern is that without further incentives, the likely churn to these tariffs is likely to be low even though they are probably in the long term interests of customers.
Our TSS notes our preference to make the SAC Large seasonal, time-of-use demand tariff the default tariff for new premises and customers moving into existing premises from 1 July 2017.
We would still offer customers the ability to opt-in to our existing legacy tariffs through their retailer. But the availability of the legacy tariff would still be there giving customers choice.
Similarly for SAC Small, subject to myriad of metering outcomes possible, we said in our TSS that we may seek to apply the seasonal, time-of-use demand to all new premise connections (with installed metering capable of applying the tariff) from 1 July 2018 (that is in page 27 of our TSS). Customers would still be able to opt out of the Seasonal Time of Use demand tariff through their retailer, because we still remain committed to giving our customer choice and control.
We note and accept the AER’s proposed alternative approach to make demand tariffs the default tariff for all customers, which could probably be accommodated for larger tariff classes where meter functionality is available. In our conversation with customers, however, we’ve experienced some reluctance toward this approach, so we will be interested in the stakeholder response to the AER’s proposal.
Moving to a question that Bruce raised before.
We see that our approach to setting network tariffs will increasingly utilise LRMC as the foundation building block to set the rate of the peak charge component.
This will mean network tariffs will essentially reflect the average long run marginal cost within a pricing zone level over the long run.
However, in practice, differences between the average system long run marginal cost incorporated in network tariffs and localised higher LRMC associated with points of actual network capacity constraint at a particular times will arise.
The AER has raised the issue appropriately of how we should consider the impact of localised LRMC when setting tariffs now, or in future Tariff Structure Statements.
And we note that the introduction of new cost reflective tariffs across three separate pricing zones has increased the number of tariffs we already publish to 175. Our concern is that increasing the number of localised pricing points through a published exponentially increases the number of tariffs that are required to be published. And this does create some burdens for our customers and for retailers.
Ergon Energy considers responding to localised capacity constraints is most efficiently addressed through dynamic demand management initiatives that can be accurately targeted, calibrated at the known opportunity value, and specifically harmonised in terms of both time and location.
So complementing cost-reflective, broad-based tariffs with demand management initiatives allows Ergon Energy to both signal LRMC across the pricing zone while also overlaying a tightly targeted additional value signal in constrained areas to facilitate Ergon Energy optimising our asset investment and timing.
The benefit of this optimisation is that it enables the savings from deferred or avoided capital investment flows through to all customers, not just those in the constrained area.
Accordingly, the proposed relationship between network tariffs and demand management opportunities can be enhanced when overlaying more broad-based, cost-reflective network tariff signals with specific demand management initiatives that are independent of, but built on the network tariff price signals… what we are referring to the dynamic layer.
These benefits of a dynamic layer represent a second wave of tariff reform opportunities and realistically can only be properly realised when there has been a substantial transition to cost reflective tariffs. In other words we have to crawl before we can walk. There is no use talking about locational LRMC pricing as a dynamic layer while less than 1 percent of customers are on a cost reflective price.
Nevertheless, Ergon Energy is looking now at opportunities to encourage tariff transition in future constrained areas so as to pilot ways of leveraging cost reflective tariffs with dynamic layer opportunities.
Now, for those customer who represent our larger customers, our larger business and industrial customers… the AER’s issues paper appropriately suggests that there is probably going to only be minimal changes to tariff arrangements for you from 1 July 2017.
While this is technically true, however, it does hide the reality that substantial changes to customers consuming more than 4GWh per annum have occurred over the last few years. And we want to acknowledge the cooperation from various customers in helping us with that.
We have standardisation of rates for CAC customers
We’ve introduced an optional seasonal time of use demand tariff for CAC customers
And now we’ve introduced a KVA charge and an excess kVAR charge for both our CAC and ICC customers
And already seen really positive response from some of these changes which provide incentives to customers who improve power factor. We think this has benefits for these customers and for all customers going forward.
While further changes are not being considered for the TSS period, we have flagged possible future changes to tariff arrangements for the 2020-25 period.
Well that has brought me to the end of what I wanted to cover for you today.
I trust this has helped build your understanding of our world and the reforms we are progressing.
Where to from here?
As I mentioned the QCA is holding public workshops for regulated retail tariffs in Toowoomba, Bundaberg, Townsville, Cairns and Brisbane in the coming week. I think we will have representation at some of these sessions. They are seeking submissions on the draft determination by 20 April…so that they can make final determinations before the end of May.
And you can find out more about that in their web page.
The AER is then holding its public forum on our proposed Tariff Structure Statement on 13 April. They are seeking submissions on our proposed Tariff Structure Statement, which as I said earlier covers our network tariffs out to 2020, by the 28 April….so that they can make a draft decision July. This will then lead to a final decision by end of January 2017, which will apply to tariffs from July 2017.
Again you can find out more from their web site or by contacting them directly.
Or of course we would be happy to go over anything we have covered today with you individually. Please just leave an email or leave a Question.
In the meantime I will see if we can answer any questions in the remaining time….
Thank you Brendon. Actually I should thank you on behalf of everyone that is on the line because we have 50 attendees so that is excellent.
We will now be take the time to look at the questions. We have not had many but I have just passed on there now from Paul Lemming to respond to. So Brendon can respond to that.
Yeah Paul, it's an interesting question I think I'll have to get back to you on this I am probably not the expert on solar feed in tariff cost recovery. Ah the question is that the solar bonus scheme cost moving forward increase from 2016. How is this possible when you're losing customers from the $0.44 not gaining? So I will attempt to address that, but we will get one of our guys, Dean to have a look at that. We do look at this in a fair amount of detail, I think Paul there may be a under recovering of some feed in tariff revenues from the previous year that may increase 16-17, so I will chase it up with you separately.
David I will get back to your question.
The customer's four highest demand days may not coincide with Ergon's four highest demand days. Would cost reflectivity be achieved by charging based on the four days when usage is highest on the network as it is usage on those days that will influence future investment?
Look it is a good question. The challenge with these questions, with these issues, is that network tariff pricing need to provide a kind of up front or ex-ante signal and you don't actually know the four highest network days until the end of the month.
So whenever you are dealing with ex-ante rather than ex-post type signals you do have to kind of take a punt. And we can only take a punt by analysing the individual customer use and the network use and try and work out the correlation between the individual peak and the network peak.
The alternative is to actually go to ex-post charging but that would mean that there's no incentive for customers to reduce demand because they won't know the particular time that is network peaking until after it has peaked. That is possibly a fairly poor answer to that question. If you still want to know more David I am more than happy to follow that up.
I have just launched the final poll, while you have another minute to answer the final question. We have got one from Rose McGrath.
The poll is just to give us a bit of an indication on how well this webinar has supported you in understanding the matters raised by the Aer. So if you could do that that would be very much appreciated.
Yeah Rose always raises the complicated questions so thank you Rose. I'm as much interested in this as much as anything else.
It would be very useful to understand I was meeting policy going forward in respect of advanced metering.
Rose says unless people have an advance meter they will not be able to access to the demand tariffs. Will we have incentives to take up advanced meters?
Rose, it's a really complicated question because it does take into account number of issues including the QCA arrangements for regulated retail pricing. Yes this is a big issue. My expectation, Rose, it that we are still probably in the area of encouraging customers to take up, early take up of season time-of-use demand tariffs for residential and we expect that we will have to probably provide incentives for those customers.
What we are hoping to be able to do is include in the incentive the ability for customers to have advanced meter or interval meter supplied to allow that. And obviously customers aren’t going to do that if they have to pay more money. So these are some of the things that we’re doing with our pilot trials that when developing.
Sara Collins is actually on our sort of trailblazer internal employee pilot trial. And I will be looking to work with EEQ, our retailer, to see if we you can really bolster that moving forward. Certainly the idea is to try and get the tariff structure there, in place and working, And then really for our Tarff Structure Statement period the idea is to see how we can kinda get many customers on to this tariff as soon as possible.
Fantastic, well I think we will wrap it up there.
Thank you so much for the feedback. We had at well over half of you saying that the webinar gave you a good appreciation of the issues. So we are really pleased with that.
I have put the email addresses up on the screen, so if you have anything further that you would like to discuss then we be more than happy to get an email and to talk to you with you independently.
Again thank you off participated, reminding you that we are recording of the webinar, and it will be emailed around and will put it online, if you have anybody else that you are working with that would benefit from the content of today.
Thank you very much and enjoy the rest of the day
November 2015 -Tariff Structure Statement
This is when we released our initial Tariff Structure Statement. Since this time we have released a revised statement and supporting document.
The Overview document continues to be useful to gain background on the reforms. The remaining documents are for reference only and are superseded by the revised documents.
|An Overview of our Tariff Structure Statement (PDF File, 975.0 KB)||27 Nov 2015|
|Tariff Structure Statement 2017-18 to 2019-20 (PDF File, 897.5 KB)||27 Nov 2015|
|Appendices Tariff Structure Statement 2017-18 to 2019-20 (PDF File, 1.5 MB)||27 Nov 2015|
A webinar was held in November 2015 to provide a preview of our Tariff Structure Statement, including the refinements planned for 2016-17. Watch the following video for the overview of our tariff reform journey or alternatively review A Preview: Ergon Energy’s Network Tariff Structure Statement presentation (PDF 1.9 mb)
Good afternoon everyone. Thank you for joining us today for this webinar on Ergon Energy’s Network Tariff Structure Statement. It’s wonderful to have so many of you here and thank you for joining us.
My name is Janet Houen; and I’ll be facilitating today’s webinar. I am joined today by Ergon Energy’s Manager of Regulatory Determination and Pricing, Brendon Crown. You’ll hear from Brendon shortly.
Before we get started though, I’d like to go through a few instructions to ensure this webinar progresses smoothly.
When you joined the webinar session, a Control Panel will have appeared on the right side of your screen. You can use your Control Panel to manage your session.
If your Control Panel is blocking your view of the presentation, you can use the small orange arrow to minimise it. You then just need to re-click the arrow to make it re-appear.
From the Control Panel, you can control how you listen to this webinar. If you are having issues with your audio, you can dial in via telephone at any time by selecting the telephone option and calling the number provided. Alternatively, you can use your computer speakers.
Another screen will have also appeared showing you the first slide of our presentation.
We have also activated our webcam functionality, so you should be able to see our speakers throughout their sessions. For this webinar, your participant microphones have been muted, meaning nobody else can hear you.
You can still ask questions of the speakers during their presentations though by typing them into the Questions Panel at the bottom of your Control Panel. These questions will be monitored throughout the session.
We’ll take a few minutes at various points in the session to address preliminary questions, and then 10 minutes has been set aside at the end as dedicated question time. If we can’t answer your question or if you have additional questions after the session, please send these through to Ergon via email. The email address for questions will be displayed at the end of the session.
The other good aspect of today is that we will be recording today’s session so it is accessible and available to people who were unable to join us now. And it will be made available online on Ergon’s website.
Just to cover off the agenda, today’s session will run for approximately one hour. We’ve allowed 40 minutes for the formal presentation and then 15 to 20 minutes for questions.
During the session, we plan to ask you to complete a number of quick polls.
These polls will pop up on your screen at the right time.
These multiple choice questions will help us gauge your perceptions and let us know where we need to focus our efforts.
Right, hopefully that covers off the key things you need to know.
In terms of today’s agenda, we will start today with a bit if a recap on Ergon Energy’s tariff reform journey and what is meant by cost reflective tariffs.
We’ll then take five minutes to address your early questions.
The second part of the formal presentation will be about the detail around the network tariff structures for 2016 and out to 2020. First for customers using LESS than 100MWh, then after questions, for customers using MORE than 100MWh.
To close the session, we then have some more time to take your questions.
We are just going to have the first of our quick polls. The question we would like to ask you is have you been involved to date in our conversation about our network tariff reforms or read any of the material online?
Could I please ask you to take a moment to respond to the poll on your screen? The question is: Have you been involved to date in our conversation about our network tariff reforms?
Please select either:
No exposure, until today
Looked briefly at material online
Attended a previous webinar
Reviewed material online in detail
Engaged with us face-to-face or one-on-one
I will just give you a few moments now to complete that.
Ok, it is a relatively even split. But it certainly looks like quite a few of you have attended a previous webinar, which is great. And then pretty much evenly exposed between have not started the conversation yet, had a bit of a look at the material online or have been talking to Ergon Energy face to face. So that is great.
All right. Sorry, I won’t be one moment.
I would now like to introduce you to Brendon Crown, Ergon Energy’s Manager of Regulatory Determination and Pricing. Over to you Brendon.
Thank you – it sounds as though we have a reasonably diverse audience with us today. Thank you for your time.
At Ergon Energy we like to pride ourselves on being a little different to the rest and how we go about things… embraces the differences that Ergon Energy has to other businesses in the National Electricity Market. And I want to spend some time looking at those areas of difference because it is key to understanding our approach to pricing and how our pricing arrangements relate to the final bill you may receive.
Our first major point of difference is that, unlike most other network businesses, Ergon Energy is a net-tailer. While there are mainly gen-tailer’s out there, net-tailers – businesses that are both a network and a retailer are a less common breed.
So while we are aware that we have a relationship with most customers as both a network and a retail business, I do want to concentrate today on the network part of the customer bill and the structures, charges and components that form part of the network bill.
Another big difference is our size. Ergon Energy is responsible for only 7% of customers in the National Electricity Market but we cover over 44% of its geographic area. Over two-thirds of our customers are located outside urban centre with large distances between communities.
The size of the area we serve – the fact that our customers are spread out across wide areas and the radial nature of our network makes us an outlier to most other network businesses in Australia and the world.
The size of our network area requires us to develop not one list of prices but three, representing three different zones in the East West and Mount Isa. This makes our pricing processes final price lists and pricing outcomes, more comprehensive and complicated than businesses with only one pricing zone.
We also serve a great number of larger customers compared to other networks and our tariff arrangements necessarily have to accommodate different customer usage types.
Ergon Energy’s different characteristics make the cost to serve customers in our area higher than say the cost to serve customers in networks with smaller denser populations. And this gives rise to three additional important differences.
Firstly, the Queensland Government recognises the costs of supplying customers in regional Queensland will be higher and therefore provides subsidies so that many regional customers in Queensland have access to the same regulated retail prices as customers in south east Queensland.
In other words, a residential customer in Quilpie has access to the same regulated price for electricity as the customer in Indooroopilly even thought the costs to serve these customers is quite different. The government in effect pays the difference between what the customer in Quilpie should pay and what the customer does pay in its regulated price. This is an important difference as it affects the extent to which our network prices are actually seen by the majority of our customers. We will explain this further later.
Secondly, the location of many of our customers the sunny climate they enjoy and the relative size of homes, gives our customers greater opportunities to harness and access a large amount of alternative sources of energy… all year round, such as solar and battery storage.
Finally, even with subsidies and alternative sources of energy, the cost to serve customers has until recently increased significantly between years, making affordability of electricity a key concern for all customers in our network area.
And all of these issues became part of the mix when we embarked upon our network tariff reform journey three years ago.
At that time we knew that the way customers were using the network was changing and that we had been working hard to ensure our network was keeping up with that change.
In hindsight, we may not have been applying the same amount of effort to ensure that – how what we charged for the network – was also keeping up with the way customers were using it.
In addition to becoming more efficient and effective, we saw tariff reform as essential to address the ongoing affordability of our electricity distribution services.
Our objective was to ensure we could continue to meet everyone's needs into the future for the best possible price and to deliver fairer, more equitable pricing signals.
And over the last few years, many of you have been on the journey with us to make substantial changes to the tariffs we offer customers. We have made changes to the majority of our tariffs and now offer significantly more choice to the majority of our tariff classes and the additional tariffs being offered.
With the introduction of the Tariff Structure Statement, we have established the 2016-17 year as our foundation year, with all of our major reforms to be in place from 1 July 2016.
From there, we plan to keep our tariff structures relatively stable out to 2020 to build a greater understanding of the new tariff options and promoting their benefits.
Customer insights have been instrumental in forming our views on the appropriate path forward, and the tariff structures detailed in our Tariff Structure Statement.
I would like to sincerely thank all who have participated actively in our reform program – especially those that have been part of the conversation from the beginning, a number of you are on the line.
It’s been worthwhile hearing direct from you and your thoughts on where we are trying to go. We have had very active engagement in our one-on-one discussions and very strong exchanges of sometimes differing views.
Every contribution has been vital to developing the best tariff structures possible to take regional Queensland’s electricity supply arrangements into the future.
Stakeholders have raised both broad and specific issues with us and we have attempted to respond to them in changes we have made, or in developing justified reasons as to why changes were not made.
Over the next five years our expenditure overall is forecast to be more than a billion dollars less than the last five years. I will show you shortly that this is reducing what customers pay for the use of our network.
I know from submissions that many of those on the webinar don’t think our cuts were severe enough and there is a strong difference of opinion by some about how much cost we can actually take out of Ergon Energy to provide safe and reliable supply.
What I can say is that unless we make some change to the way we charge for electricity the benefits of lower costs at our end will be disproportionately shared by customers in the future.
I think submissions are acknowledging this growing tension between the need to remove cross subsidies in tariffs that exist as early as possible and the need for more time to ensure customers are able to respond to the changes.
For us this has led to customer choice being a fundamental part of the transition to new tariff options.
Our biggest challenge is to improve understanding around these new choices. We need to be able to educate customers appropriately and, ultimately, for them to be confident in choosing to adopt the new tariffs. Part of this will be ensuring there are adequate protections for customers.
While there is some concern around the ability of some customers to respond to the price signals, there is a growing understanding of how the path we have been progressing along can support the best longer term price outcome for all.
The pace we have set for our journey has been all about balancing the short-term year on year impact on individual customers and the longer term community cost if the reforms are not implemented.
This has been difficult in recent years where there have been constant increases in prices each year.
Given the reform already undertaken we can now implement our new tariff options in the current regulatory control period in an environment where our charges overall have been brought down.
Of course it is important to re-emphasise that a network proportion of a customers’ bill is around 50%.
The blocks above the dotted line over the next five years are our guestimate of forecast transmission, retail and solar costs. Now these cost are not for our services, and are largely outside of our control as a network business.
And again we need to emphasise that Ergon Energy is different in terms of what we charge for the use of our network and what some customers actually see in their bill. The picture shown looks at the historic build-up of a typical residential customer bill using ergon energy’s network charges.
This is a high level estimate of what the customer may see if no subsidy was applied to the retail tariff. Customers on a market contract – who do not have Ergon Energy as their retailer – would more likely see this price.
The light blue bar in each year represents the QCA determined residential retail price which includes a subsidy for customers in regional Queensland.
To be consistent with the Queensland Government’s uniform tariff policy, the retail prices set by the QCA for residential and small business customers are based on the costs of supply in south east Queensland.
This obviously means the underlying network cost component of each tariff cannot reflect Ergon Energy’s network rates as – for reasons I outlined in the beginning of this webinar – Ergon Energy’s network prices are necessarily higher than those of Energex.
Our tariff rates and structures are therefore not used for Tariff 11 and Tariff 20, the primary retail tariff for small customers.
The QCA is likely to use Energex’s network tariffs and prices to work out the retail prices for Tariff 11 and 20 – even for Ergon customers.
And I do harbour on this point, because it is an important point to emphasise as it does tend to be a source of confusion and frustration for customers when they are looking at our tariffs and trying to reconcile them to what they receive in the final bill.
There has been a recent change though for our new optional tariffs. For those tariffs the QCA has been using our network tariff structures – that is, our peak and off-peak times and conditions – and equalises the price levels of those structures to match what Energex would charge if it had similar structures and peak times to ours.
For those of you who have been involved in other webinars, you will know we have invested significant effort to understand the short-term and long-term impacts of moving to the different tariff structures available. To minimise customer impacts in the short term, where necessary we have adjusted rates so to manage the level of potential impact on individual customers. For the longer term, our analysis of the different tariff structures has allowed us to target options that best minimise the overall community cost of energy delivered.
Based on this analysis we can look at tariffs that have a greater element of cost-reflectivity in them.
‘Cost reflective’ tariffs are simply charges that are better aligned with the underlying cost of supplying electricity. Cost reflective tariff structures charge higher rates when the level of demand across the network is likely to drive future capital investment and lower rates where there is little or no likelihood of investment.
Many legacy tariffs or those tariffs that existed prior to our reforms were not cost reflective. They charge the same 24/7 rate all year round. This means the rate is too low when the level of demand across the network is likely to drive future capital investment and the rate is too high at other times
What this means is that compared to a cost reflective tariff, legacy pricing structures create the wrong customer response, and this distorted response means that some customers pay more than what they should and other customers are paying less.
More importantly though is that legacy tariffs send the wrong signals about how customers should use the network. We want to transition tariffs so customers who want to reduce their electricity bill, do it in a way that is likely to benefit all customers through lower network costs.
Modelling commissioned as part of our tariff development work showed that if we don't act and instead continue to send the wrong signals, legacy tariff rates will continue to rise, even if we keep our costs low. This is a direct result of the cross subsidies that are being created by the lack of cost reflective price signals in our legacy tariffs.
We have a window of opportunity now to avoid this, for the good of all of our network users.
If you haven’t worked it out yet, Ergon Energy is different. And another further difference is the window in which demand will drive future investment.
Many other networks, particularly those in southern states have windows of high system peak demand on cold winter days, which can be as high as demands on hot summer days.
Other networks can project up to half a dozen extreme weather days over summer which are surrounded by much milder temperatures.
Ergon Energy largely differs from these networks in this respect.
There is a reason why customers in other network areas holiday in our network area in winter.
Similarly in summer, temperatures are less volatile between days.
As one of my staff in Mackay told me “I turn my air con on 9am one morning in November and turn it off one evening in March.”
Ergon Energy builds new infrastructure largely in response to demand during particular windows in the summer months.
So this is seeing us align the demand-related components of our charges to the incremental costs or the additional future network costs - what is commonly called our Long Run Marginal Costs (LRMC) – associated with demand in the summer peak window.
And another difference for Ergon Energy is that we have more segregation of substation and feeder profiles between residential and non-residential loads.
The network supplying predominantly business customers shows that peak demand consistently occurs during summer weekdays, from 10.00am to 8.00pm. And, for the parts of our network supplying predominantly households, peak demand is later in the day, from 3.00pm to 9.30pm each summer day.
It is important to note, results obviously differ across our network area but our analysis reveals common trends. For residential areas of the network there is minimal difference between the days of the week.
The load profile or shape for our residential areas has changed significantly over recent years, in some areas dramatically, with the increased use of air conditioning and the take up of solar energy systems.
It is important to note that those nice pretty smooth graphs that you are seeing before you now, aren’t necessarily like that for every feeder and substation.
In fact a typical day will have a lot of volatility and those smooth lines will be very jaggered between days and between time of day.
I will hand it back to Janet to see if any questions have come through.
We will now take a moment to answer a few of your questions relating to Ergon Energy’s network tariff reform journey so far.
Thanks Brendon that information has been great. We are just going to see if any questions have come through. Give us a moment. We do not have any at this point.
There is a question from David, “At high level, how do the maximum demand growth forecasts in the Energeia modelling tally with AEMO's forecasts? If they are different, I am interested why that might be.” David, that is a good question. The Energeia analysis that was supporting the demand growth was based on some demand forecasts done about 12 months ago. I don’t know how much they are consistent with AEMO’s current forecasts. They certainly were consistent with our demand forecast at the time of our regulatory proposal. We haven’t updated that analysis. I think that will be part of our future work going forward. I imagine there may be some changes based on the changes in both Ergon Energy’s demand forecasts which mirror AEMO’s.
Okay, if there are no more questions at this point we will move on. Conscious of the time. I will now hand back to Brendon and he will walk through the detail and the refinements for 2016-17 and out to 2020 for small to medium business and residential customers out to 2020.
Thank you Janet.
Ergon Energy provides electricity to around 1.5 million people – through over 730,000 customer connections.
Around 725,000 of these use less than 100MWh (megawatt hours) of electricity a year – 86% of these are residential customers and 14% are small to medium businesses.
We will talk about the Standard Asset Customer – Small class first … then we will talk about our really large customers after that.
Moving forward, to be more cost-reflective the tariffs for our customers who use less than 100MWh of electricity a year need to have a bigger focus on the amount of electricity used at specific times of the day.
The first step in this direction was made in July 2014 with the introduction of an optional energy-based, seasonal time-of-use network tariff structures. To help move further along this journey, we then, in July 2015, gave customers the opportunity to access new optional tariffs that reward customers for using demand outside of peak times.
Both of these tariffs were and continue for the moment to be optional tariffs, giving customers more choice from their existing tariff.
These demand-based tariffs are our preferred options for the future. Since being introduced we have been listening to stakeholders, and working hard to refine these tariffs. This has seen us simplify the way the demand charges in the tariffs are calculated for 2016-17.
The charges in the tariffs will now be calculated in the same way both for the summer and non-summer months.
Let’s look further at the components of the tariffs and how the charges are calculated. Each month a charge is incurred for the demand the customer places on the network during the busiest or peak times for the network. This daily demand window is different across business and residential areas of the network as we demonstrated earlier.
The rates for the demand charge are significantly lower once we move out of the three summer months to the non-summer months.
The lower rates set in this tariff for the off-peak demand charge and also the any time energy charge means real savings for customers exist for 90% of the time, when the network is not being used to its full capacity. There is also the benefit of no fixed charge throughout the summer months.
The demand charges will now be calculated throughout the year on a consistent basis.
Using a measure that average demands in a window is a more moderated application of the demand charging mechanism (compared to using the maximum demand which is the calculation approach applied by other networks).
In summer months minimises the bill impact of any abnormally high peak demand days and also improves the likelihood of the period measured coinciding with the network wide peak (peak demand drives our costs, so any opportunity to reduce this demand will benefit all customers).
Ergon Energy’s demand charge looks at the daily demand window.
In the residential customer example on the screen, this is represented by the green bars. However, instead of looking at the highest demand in the window we look at the average of the demands in the window.
You can see how averaging minimises the impact of an abnormal half-hour period by the difference between the highest green bar and the dotted black line.
The customer’s demand day is therefore determined by the average demand recorded in these windows. We apply the monthly demand charge to the average of the highest or top four demand days.
So if we assume this customer had exactly the same energy profile each day, we would apply peak and off peak demand rates to an average demand of 1.4kW.
In the non-summer months the rate applied to the demand charge is much lower. The only other difference is that a 3kW floor also applies – meaning the customer pays for 3kW of demand or the average of their top four average demand days in the month, whichever is the greater. Importantly however, you will note that there is no fixed charge for the distribution component of the customer’s bill.
We’ve now had a seasonal time of use demand tariff in all of our published user group categories.
The response from the larger customers who have been used to demand based tariffs has been quick to take up the seasonal time of use demand option.
For stakeholders representing smaller customers have had a more mixed response. There has been concerns expressed that many customers don’t understand the complicated arrangements affecting the bill they receive today let alone adding to the complication with additional charging components.
And this is a key challenge for us, and for every network business and retailer as the industry as a whole moves from legacy tariffs to cost reflective tariffs.
Importantly, we received some really good ideas on how to improve and simplify the structure of the tariff, and many of you will see changes we’ve made to the tariff structure as a result, so thank you for those suggested improvements.
We also haven’t forgotten about the need for pilots and trials to improve education of customers. Unfortunately at Ergon Energy’s end our need for systems and processes to initiate trials is occurring at a time where we are overhauling billing systems and there is a preference from the IT guys that trials of new tariffs happen when new systems are cutover, to avoid significant costs. So we wait patiently for the green light to commence these trials.
Probably the initiative I am most excited about is developing a monthly retail energy cap plan for residential customers, in which customers pay the same price for a pre-set level of demand and energy each month.
So rather what customers see in a high quarterly bill that covers three months of demand and consumptions, a customer pays the same amount each month and only pays excess charges if they go over a pre-set level of demand or energy in the month.
As well as delivering savings to the customer compared to their existing tariff, we are confident that customers will benefit from the certainty of monthly payments and a reduced need to understand the detail of the underlying components of the network tariff.
You could see that this type of tariff would be easily integrated with a variety of new technologies, including solar and storage or home energy management to deliver even greater benefits.
From the network perspective, the benefit of this tariff is that it is underpinned by the existing cost reflective network tariff. The customer benefits from the bundling of the network charges and smoothing these charges with retail and other technologies to deliver savings and a constant monthly bill.
We are still in prototype mode for this type of tariff and will be consulting with various stakeholders soon on the viability of adding this to the list of retail tariffs Ergon Energy residential customers can choose.
Now, I am aware that we have representatives from retail businesses who do have market customers not subject to the same regulated retail rate that most residential and small business customers are on. And for the purposes of those stakeholders I have included the relevant network tariff rates we are proposing in 2015-16 and beyond.
It’s worth re-emphasising that there is not a direct link between the rates on the screen and the rates that customers on regulated retail tariffs will receive.
In the interests of time I have included only the rates that apply to the East Zone. The rates that apply to the West and Mt Isa zones will be available in the appendices attached to our main tariff structure statement.
Over to you Janet.
Great. Thank you Brendon. We will now take a moment to see if anyone has any additional questions relating to this section of the webinar. So if you do have anything you would like to ask Brendon or Ergon please send those through:
Right we do have a question from Jonathan.
“Is there an expectation that total household consumption will decrease?”
That is a good question.
What we’ve found it that generally the average household consumption has been decreasing over time. We have assumed in our energy forecast for our indicative prices a fairly flat energy growth forecast. However, we have assumed there will be some increase in the number of customers. While we have seen a decrease in energy per house we have seen a fairly constant increase in the numbers of customer being connected to the network per annum.
There is another question here. This is from Renato.
“For customers to understand their load profiles they need 1/2 hourly data. At present depending on what the customer's sites tariff is will determine what information is available - particularly demand on sites still using non demand tariffs. What is Ergon doing to improve customer data information with regards to metering upgrades?”
Good question Renato. I think there is actually a final regulatory determination from the AEMC on meters. We are waiting with baited breath as to what the outcomes of that will be. That will have big implications about who is responsible for meters, whether it is the network or the retail business. Obviously for these tariffs to work they need to have a meter capable of half hourly interval data and we are suggesting they need to be a remotely read meter. So it will require a retailer to install that meter based on current regulatory arrangements. So we need to work with retailers on how can give customer that choice, with meters that have that type of functionality to allow that type of choice.
Okay. Thank you for those questions. They were good. And don’t forget you will have the opportunity to ask any others by email after the session if you so wish.
Brendon now going to explain a bit more about what he means by cost reflective charges.
Right this is important for those who are part the group, And I know they are on the list, the customers using more than 100MWh and how we are using cost reflective charges for those customers.
So our commercial, industrial and rural industry customers who use between 100MWh and 4GWh of electricity a year – about 8,500 customers who are located throughout the distribution network. You will be aware that we introduced a new demand tariff, for this group in July 2015, and this has actually been quite well received and taken up by customers. This option has come about from our work to better understand our cost drivers and make our tariffs more cost reflective. Unlike the other demand tariffs available for this group, this tariff recognises the peak demand window that occurs in the summer months.
It is important to note that this is still an alternative or optional tariff that customers must speak to the retailer about if they want to take it up. We still have the existing default tariffs available to these customers.
Now, you might remember, for this group we also reviewed the introduction of kVA tariffs.
We considered that there may be potential benefits in extending the changes to so that demand calculations for SAC-Large customers are based on KVA rather than KW.
As this change was already made for our largest customers over the last two years.
However – we propose not be progress this for SAC Large customers before 2020. We need more time for detailed network analysis at the low voltage level to ensure effective and efficient network performance can be maintained if we move to kVA for these customers. We will engage on this again, at a later stage, before we develop our position on tariffs beyond 2020.
The opportunity or impact on an individual business from the reforms will depend on whether the business is on the regulated retail prices determined by the QCA or on a contract with a competitive retailer.
For businesses on the regulated retail prices, the rate rebalancing in these reforms is being passed on through the QCA in their price determinations. For those on a market contract, the retailer or the contract the customer is on will determine if, how and when the changes will be passed through.
Our next largest group are the 200-odd customers using over 4GWh of electricity a year – requiring an ‘extra-large’ level of network capacity and in many cases a dedicated connection.
In July 2015 we introduced a seasonal time of use demand tariff for this group. To progress with this tariff, after further analysis, modifications are being made in a number of areas to apply from 1 July 2016. This optional seasonal time of use tariff structure includes a peak demand charge, a capacity charge (measuring off-peak demand) and an off-peak energy charge.
In 2016-17 the peak demand charge is based on the customer’s monthly maximum kVA demand during the peak period in each summer month.
The capacity charge will be based on the greater of the customer’s authorised demand and the actual monthly half hour maximum demand. The capacity charge applies for all 12 months of the year. Over the summer months, it excludes demand occurring during the peak demand window of 10.00 am to 8.00 pm on summer weekdays. The off-peak energy charge is applied to all energy consumed in non-summer months.
These changes will make it more attractive for customers and provide a greater incentive for them to respond to the pricing signal in the summer peak demand window.
A connection unit charge also applies for customers who connected the network prior to July 2010.
In addition to these changes, for the Connection Asset Customers from 2016-17, will have a new excess reactive power charge will apply.
Many of these customers will know that this has already happened for our largest customers and, following successful introduction, we are looking to implement this into our CAC customers as we indicated in our consultation.
This charge reinforces the price signal introduced by the kVA tariff in 2015-16, which encourages customers to improve their power factor and reduce their usage of network capacity.
So based on a customer’s authorised demand and applying a NER compliant power factor under the electricity Rule, a permissible kVAr quantity is determined. The reactive power recorded at the time of each customer’s individual monthly kVA peak is compared to the permissible quantity and excess charges are applied where the permissible quantity is exceeded. And only where the permissible quantity is exceeded.
The following slide shows the various rates that are available for CAC customers.
The impact on an individual business on the move to excess reactive power charges will depend on whether the business’ premises is on the regulated retail prices determined by the Queensland Competition Authority (QCA) or on a market contract.
Really quickly for the ICC customers. This is the state’s major coal mining customers, as well as customers involved in other types of mining, transport (rail) and pumping who use more than 40GWh of electricity each yea.
In this area we have already made the major reforms that we wanted to. The rates for these customers are calculated on an individual basis to reflect the specific site’s load requirement.
We have brought these tariffs in line with the principles of cost reflective pricing, and we have not identified further reforms for 2016-17.
In summary, this has been a very high level overview of Ergon Energy’s Tariff Structure Statement, which we will be submitting to the AER tomorrow.
The full statement explains in detail Ergon Energy’s methodology for determining tariff structures and allocating network costs over the period to 2020.
Our network tariff reform strategy has been informed by an extensive engagement program. We trust we have shown we are listening, and provided you with a better understanding of how are network tariffs are structured and charged.
We will be providing it to our regulator, the Australian Energy Regulator to determine that our proposals meet the requirements obligations under the National Electricity Rules.
This is the start rather than the end of for the Tariff Structure Statement.
The AER will be holding a public forum in the coming months and inviting submissions on our reform path. After considering our documentation, along with stakeholder submissions, the AER will publish a draft decision on our tariff proposals (scheduled for July 2016) for stakeholder comment. They will then make a final decision before the end of January 2017, which will apply to tariffs from July 2017.
So you’re going to be with us for some time yet.
It is important you know you can provide feedback on our reforms directly or you can submit your feedback to the AER.
For further information go to the web site details on the screen.
We hoping to have both our Tariff Structure Statement and informative tariff guides available to you once we submit or early into the next week.
Thank you for listening.
Great, thank you Brendon for your presentation.
We now got probably about 10 minutes for you to ask any further questions of Brendon while he is here and available so please submit those via your online screen there.
And also remember if you have question after the seminar when you have absorbed the material you can email Ergon and they will endeavour to come back to you.
So I will hand over to Brendon now to respond to the questions that are coming in.
Great. Look the first question I have on the screen comes from Angelique. It says ‘’will you have any incentives for power factor improvement like Energex provided.”
Angelique, I do not know the detail of the power factor improvement that you are suggesting. I do know that we have a dedicated team that goes out and talks to people about how they can improve their power factor over time. Obviously by moving tariff kW to kVA and creating the right incentive for customer to be able invest in their own power factor to reduce their network charge means it will benefit of the network overall. So we think our pricing structures are reflecting some of those types of incentives.
I have another question here from Rose, “What will Ergon do to help customers who want to go on the monthly retail plan understand what their "peak demand" will be please?”
This is an important question Rose, particularly for those customers that do not have the interval metering to be able to understand. What we are hoping that we can do is provide the type of tariff that will really try and focus towards customers that are unlikely to go above a certain amount of demand and still achieve savings. The idea will be to give them sufficient demand so that will always stay under the demand and still give them savings compared to the Tariff 11 rate. How that works through in terms of a regulated retail price as I said we’re are still in protocol mode Rose, and you will be one of the people we come to speak to as we work out how this could apply to a various range of customers.
I do have a question from Paul. I might ask Emily if she can put Grahame on the line for this. Paul’s asked, “when will CAC customers be advised of their Compliant PF”.
Grahame are you able to answer that question. I think that come up in a recent session.
Grahame, are you online?
Sorry I have had my phone on mute. Can you hear me?
I can Grahame. Did you hear the question?
Yes. The answer to the question is that we will be writing to the CAC customer before Christmas to give an indication of the indicative rates and the compliance power factor really is set by the voltage by which that connect to the network. And that information can be provided.
Thank you Grahame. I have got a question from Robert, “With the AER implementing an upfront customer fee for meter re-programming in July what options are in play from Ergon Distributions perspective to incentivize customers to change Tariff when (due to fee) they may not see a benefit in the short/mid term?”
Robert the metering problem, remains a problem I think no matter whether you are on Tariff 11, 12 or 14. I think the issue of the upfront fee that Ergon Energy must charge as part of an Alternative Control Service is going to be a fairly large obstacle for time-of-use energy charge. I will note that in order to have a time-of-use demand tariff Ergon Energy cannot as a network business install a remotely read meter under the existing meter rules so what we will be trying to do is incentivise both customers and importantly retailers as to how they can best offer the demand tariff to customers. I am hoping they will have more flexibility as to how they apply the metering charge to those customers, at least in the early days.
I have got a question from Lynette,” Is there a notified demand STOUD for CAC customers? If so where is it detailed in Gazette?” It is a good question, Lynette. At the moment the time-of-use demand tariff is a network charge, I can’t remember whether the time-of-use demand tariff is actually offered as a gazetted retail tariff option for CAC customers as a regulated retail tariff. Certainly customers in the market can access the seasonal time-of-use demand for CAC customers. Importantly, to note Lynette, the tariff that I have just talked about does involve some important changes to the current tariff that exists. So you may want to look at what changes we have made to the tariff that currently exists to work out if it right for you or not.
We have a question from Brad, “I can see the average customer being very confused by the new tariff rollouts. It there plans to train up consultants or others to help spread the message.”
So Brad, what we need to do over the little while is work out how we are going to encourage these customers to take up these tariffs. As I suggested before we are looking at trials and pilots to be able to do that. There have been some delays doing that at this stage, purely due to infrastructure and IT issues. I have a feeling that if you speak to most people or most network businesses around Australia, they believe that retail tariffs will take a bit of the confusion away by bundling up the more sophisticated network charge with a more easier to understand set network or retail monthly plan similar to what you might get for internet usage or a mobile phone plan. I think every retailer is trying to work out how to do that and help customers along the way. We are trying to do the same thing and we’ll be working on that over the coming months.
We have a query from Gunnar, “How will the proposed changes impact irrigators? Gunnar I actually think the type of changes that we are proposing are very, or could be very valuable for irrigators. Particularly those irrigators that use a lot of their energy outside of weekdays between 10am and 8pm.For those types of customers I think there is a real opportunity to make some savings compared to the tariff that they may be on. That obviously depends of course on what type of tariff they are on existing, whether they are on existing QCA tariff or a competitive tariff in the market. But certainly some of the reasons why we’ve made these changes were very much born by customers like irrigators that may possibly be paying more than they need to on a flat energy charge. They could probably get a lower charge for when they are using their energy outside of the peak periods.
We have another question from Lynette, “Will the excess kVAr tariff to be introduced in 2016 for CAC customers be for notified (non-market) customers or only market customers?”
Grahame are you able to answer that one for the CAC class?
What was the question please?
Sorry Grahame, Will the excess kVAr tariff to be introduced in 2016 for CAC customers be for notified (non-market) customers or only market customers?
At the moment the notified major tariff are based on SAC Large HV demand. Ergon is proposing to have discussions with the QCA to see if they can pick up the CAC anytime demand tariff and the STOUD tariff structure as well. In that way the structures will be passed through. That is a discussion to be had with the QCA, Brendon.
Sure. Lynette I think that will be work in progress as we work through the regulated retail tariffs.
Michael has asked the question, “Where is the incentive for solar customers to go to time of use.”
Michael I think there are some important opportunities for solar customers to be able to go to a seasonal time-of-use demand tariff. I think it gives them plenty option to use their existing solar functionality probably with the combination of batteries and home energy management systems to be able to reduce their demand at peak times. So I think there are some real benefits. Obviously if you look at the demand profiles the benefits for commercial businesses going onto solar has also increased because we are applying a higher charge for the time of the day, between 10am and 8pm, when solar is going to be at its best.
Another question, and important question from Cheryl. I will try and paraphrase it as much as I can. Cheryl is concerned about the fact that the new tariffs will cause a huge customer backlash, because people will not understand them I am assuming. Is Ergon considering offering a default option to customers to these cost reflective tariffs?
Cheryl it is important to note that we are interested in getting as many customers over to the cost reflective tariffs as possible the theme for Ergon Energy for the remainder of this Tariff Structure Statement period will be choice and control. So customers that want to stay on the tariff they are currently on will be able to stay in the tariff they are currently on, customers that want to move to a more cost reflective tariff should have the right to move to a cost reflective tariff. So we want to promote cost reflectivity in our tariffs and choice and control, which is a major theme for Ergon Energy.
Right thank you, back to you Janet.
Great. Okay. Thank you so much for joining us everyone. Just before you log off if you would not mind we are just going to do our last poll. It is really important for us to do a bit of measurement and to find out if you feel these sessions are valuable. So if you could just take a moment, Did you find the webinar experience valuable?
So that is fantastic. Thank you very much for responding. So that’s a positive response there. We are having good results with Yes, it was very valuable, so that is very handy feedback for us.
So just to wrap up, I’d like to thank Brendon Crown on your behalf for his time today. A lot of preparation goes into these sessions.
I’d also like to thank you, our attendees, for taking the time to participate and hear the information.
Once again, just a quick a reminder that the webinar will be placed on the Ergon Energy website. So that you can share that with any colleagues who weren’t able to be with us today.
Questions. Using that email@example.com and someone from Ergon, you are invited to put them through and someone from Ergon will undertake to get back to you as soon as they can.
And that’s really wrap. I’d like to thank you again and hope you can join us next time around.
August/September 2015 - Your feedback received
The following feedback submissions were received on our longer-term network tariff strategy following the consultation paper released in June 2015.
This feedback has helped to shape our Tariff Structure Statement.
June 2015 - Consultation paper
Below is the Consultation Paper Our Network Tariff Reform Report released in June 2015.
This paper provides details on:
- The network tariff strategy development undertaken
- Our response to the stakeholder submissions received
- The areas remaining under consideration where we are seeking stakeholder feedback.
We have also published a stakeholder session on the topic. The meetings notes and presentations can be seen below.