An explainer about electricity demand [take 1]

Frequent readers will have noticed our enduring interest in electricity demand at WattClarity (including, importantly, the various measures for it).

In some prior years we have given away a BBQ for the “best demand forecaster in the NEM”, but (more seriously) we recognise that the shape and nature of electricity demand is one of the most significant contributors to price outcomes in the wholesale market – which affect all energy users (directly or indirectly).
(a)  In past years the focus might have been primarily on peak demand,
(b)  and to a lesser extent load factor –
(c)  whereas with the snowballing energy transition, we’re entering an environment where other parameters (such as the rate of change in demand) are going to be increasingly important.

Since 2000, when our company started, we have received a large number of questions about electricity demand – how it’s measured, the different metrics, what it all means, and so on…  The rate of these questions has even been increasing in recent times.

In the interests of better answering these questions (including for those who have not yet asked) we’re posting this article in our “Energy Literacy” section of the WattClarity energy sector insight and commentary service.

About “Take 1” of this explainer

This edition of an explainer about electricity demand (posted in April 2018) is the first of what might end up being several iterations, spaced over time, with each successive iteration refined with the help of feedback from readers such as yourself – particularly in relation to:
(a) Any factual errors made in the following; and
(b) Importantly, the extent to which this helps you understand the data provided through our various products, such as in the Live Supply & Demand Widget we are please to provide with the support of RenewEconomy.

We thank those who have provided input already, but make it clear that any errors (and other shortcomings) are entirely our fault.

With that in mind, we hope you will find the following useful:

(A) The difference between a MW and a MWh

[PS in October 2022 we lifted out this initial part from this article and copied it over to a stand-alone article ‘Analytical challenge (or beginner mistake!) – understanding the difference between a MW and a MWh’ here]

Given the number of times we’ve seen people confused about this over the years, we thought we’d start by explaining the difference between the two fundamental metrics:
1) a megawatt-hour (MWh), which is a measure of volume/quantity; and
2) megawatt (MW), which is a rate (or a volume over a time).

To help readers visualise the difference, we’ve included the following animated image showing the analogy of flow into a bucket of water:


Image #1 – A megawatt measures the rate of energy supply (or consumption)

Does this help to clarify the difference?


(B) Different measures of rate, and volume, of energy delivered/consumed

Since 2000 we’ve been striving to make the energy sector more understandable to a diverse range of people.  This has been primarily in Australia’s National Electricity Market – but has also been in a range of other locations.

Across the world there are a couple different units used to describe the same volume of energy, summed up in the following table:

Table 1 – different units of measurement
Measures of volume/quantity Measures of rate
1MWh 1 MWh = 1,000,000Wh

The “watt-hour” (symbolised Wh) is a unit of energy commonly used in the electricity sector.

1MW A megawatt is the rate at which energy would need to be supplied/consumed on average over an hour to deliver/consume a quantity of 1MWh.
3,600MJ 1MWh of energy is the same quantity as 3,600MJ (or 3.6GJ)

= 3,600MJ
= 3,600,000,000J
= 1,000,000Wh
= 1MWh

The “joule” is the SI unit (i.e. International System of Unit) used across many countries for energy more broadly (i.e. not so much in describing electricity).

3,600 MJ/h A rate of 1MW is equivalent to 3,600MJ/h (just expressed in different units).

= 3,600,000,000 J/h
= 1,000,000J/s
= 1,000,000W
= 1MJ/s
= 1MW

In SI units, it is more common to see rates of energy expressed in “joules per second”.

One watt is just an energy delivery/consumption rate of one joule per second.

~3.4MMBtu 1MWh of energy is the same quantity as 3,412,141 Btu

The Btu (British thermal unit) is used in a number of countries for energy more broadly where they do not follow the SI units– most notably including the USA.

An added point of confusion here is that the “M” in this unit represents the Roman Numeral “M” (i.e. 1000) and not the more widely used descriptor of 1 million (i.e. 1,000,000) with SI units.

~3.4MMBtu/h 1MW of energy is the same rate as 3,412,141 Btu per hour

Please do point out any errors I have made in the table above.


(C) Understanding the difference between Dispatch, and Settlement

Using terminology that’s specific for the NEM (but which has underlying parallels in most other locations) it’s important to understand that there are a number of different time frames relevant to measuring how much electricity is produced, or consumed:
#1)  real-time operations (which includes Dispatch) and
#2)  after-the-fact Settlement.

Different data sources are used in real-time operations than in settlement, for a number of reasons (including cost and complexity).

This is illustrated as follows:

Image #2 – Dispatch works differently than Settlement

Currently we (as a company) are focused specifically on real-time operations (i.e. revolving around dispatch, and planning for dispatch), and the different types of visualisation tools we provide (including the numbers they quote/publish) are published with respect to the real-time operations paradigm.


(D) Especially in real time, “demand” is measured at the supply-side end

To an outsider it would seem logical that, to measure electricity demand in certain location, one would take all of the individual electricity meters at each customer connection point and add them up.  However from a macro perspective (i.e. for a whole region/state/province) that’s proved to not be the most effective, or efficient mechanism for doing this (partly because of the delay in accessing settlement data, noted above).

Rather, because electricity must be produced at exactly the same rate it’s being consumed instantaneously, we can start from the supply end and work downwards – knowing that the rate of energy addition at the supply-side end will match, in real time, the rate of energy consumption at the demand-side end.

This is illustrated in the following image:

Image #3 – Measuring Supply, as a proxy for Demand

For those who want to know more here’s two other resources:

(1) In March 2017 one of our guest authors (Jonathan Dyson) put together this 2017 explainer on about the role of the FCAS market in keeping the system frequency close to 50Hz (with several more detailed articles on system frequency, and FCAS in particular, also here).

(2) For a more detailed view of the electricity supply chain we periodically update the detailed “Power Supply Schematic” wall chart, to illustrate the various organisations involved in connecting the supply side and the demand side of the electricity sector.


(E) However there are complexities…

In the 3rd image above, we represent what would be effectively a totally closed system, where 100% of what is supplied at one end is consumed at the other end (which assumes, of course, linear flow path).

As always, reality turns out to be more complicated than simple models. As I have noted before – any model’s just a model, it’s not reality – though they can be useful sometimes (I hope the simplistic model above has helped some users).

There are many complications involved in measuring rate of supply at one end as a proxy for the rate of consumption – though it remains (at least for now) the best method available. We’ll list some of the complexities here, but note that it is not a comprehensive list:

Complexity E1) Dealing with interconnector flow

The model above assumes there is just one “zone” within the grid or market that’s in focus – but this is very seldom the case:

1) Looking at the entirety of demand across the whole NEM would be one such rare instance, but at WattClarity we seem to be one of the few who do this. The vast majority of AEMO metrics relate to supply and demand in particular regions;

2) In the more interconnected electricity grids (across North America, Europe and parts of Asia, for instance) there are always the effects of interconnector flows that need to be taken in consideration – both in terms of raw energy flows, but also in terms of ability to share reserves and so on (though that’s something best reserved to a different article).

Continuing the bathtub analogy, we can see how the rate of energy transfer across interconnectors needs to be taken into account to calculate the rate of electricity consumption in all regions.

Image #4 – Calculating Demand by including flow across Zonal Boundaries

The network topology across the NEM can be described in terms of interconnections between a number of different zones:

1) Our ez2view software describes supply and demand in terms of 27 zones across the NEM, and includes (optional) access to live inter-zonal flows within some regions, and live zonal demand;

2) The rules of the NEM currently provide for 5 regions, which are a special form of zone that supports region-level pricing outcomes;

3) The RenewEconomy-sponsored NEMwatch Supply & Demand widget currently utilises these 5 regions and adds in the “South-West Interconnected System (SWIS)” of Western Australia to show supply and demand for 6 zones in total (5 of which are interconnected).

Our other products also deal with demand at a regional level, and hence the effect of interconnector flows.

Complexity E2) The supply chain is not linear

Our simple model above also assumes that generators are large and centralised – being conceptually located at one end of the “supply chain”, with consumption occurring wholly at the other end.

In reality this is not the case.  It never has been, but the significance of this simplifying assumption is becoming more important with the rise of distributed energy resources.  What follows are three specific examples of how reality is more complex than this simplistic model – but note, again, that even these three examples don’t address all of the complexities involved.

Example E2a) The rise of distributed solar PV

Australia, moreso than any other location we know of across the world, has seen an exceptional uptake of distributed solar PV capacity.  This has been driven by a confluence of environmental advantages, commercial considerations, and government policy.  Whilst the growth has been subject to its own idiosyncrasies, the net result is that distributed PV provides a significant contribution to electricity supplies.

This is not without its own challenges from a measurement and management point of view (as discussed before). In the following image, we explain how this makes it more difficult to understand the rate of total electricity consumption:

Image #5 – The opacity of Embedded Solar PV brings with it a growing challenge of understanding total consumption

It’s important that readers understand that, whether the objective is to understand the rate of total consumption, or the requirements for upstream supply, it does not matter whether energy from rooftop PV is totally consumed at the home, or whether some spills onto the local network to be consumed at neighbouring homes. From the perspective of the upstream high voltage grid, this embedded energy production simply reduces the demand to be met from centralised large supply sources. From the perspective of total consumption, all the production from rooftop PV plus all supply from the wider grid get added together.

From the perspective of the market operator (AEMO, in the case of Australia) these injections of electricity from rooftop PV are effectively “invisible” and their real time (supply-side) measurements of “demand” are correspondingly lower than total consumption.  However this reduced demand is the appropriate level for the market operator to use in scheduling delivery from large scale sources.

In our Supply & Demand Widget, we address this difference between large scale supply and total consumption by showing the estimated injections from small-scale PV in terms of both supply and demand within each region:

On the NEMwatch Supply and Demand Widget, injections of small-scale solar PV also represents demand the AEMO does not see

Image #6 – Ensuring the numbers add up by ensuring estimated supply from small-scale PV is shown on both the supply side and the demand side

This is something we must do, for the numbers to add up.

Readers should be aware that the numbers published by the APVI have a number of imperfections which result in the numbers being different than what is actually happening – with some factors suggesting under-estimation, whilst other factors suggesting over-estimation (as discussed before).  That should not be read as a negative on the APVI and their method – every forecast contains imperfections (as noted before)

Example E2b) Other embedded generation

Embedded solar PV is not the only example of cases where embedded generation (that’s invisible to the market operator in real time) leads to an underestimated level of total electricity consumption.

For decades, a number of commercial and industrial sites have utilised embedded generation facilities in order to supply a portion of their own consumption on site. Most of this has been (and remains) invisible to the market operator in real time:

Image #7 – Embedded Generation at Commercial & Industrial sites has long been invisible to the market operator in real time

While estimates of annual levels of energy produced by some of this embedded generation exist, unfortunately we have not (to this point) identified a way in which we could include some measure of this C&I self-generation to deliver a more accurate picture of real-time Supply & Demand in the Widget.

Across the world, the rate of electricity generation from embedded generation facilities on commercial and industrial sites is also invisible to the market operator (like the AEMO)

Image #8 – The effect of other embedded generation can’t currently be shown in the Widget

Example E2c) Auxiliary Energy Usage

The complications for our simple model don’t end with generation that we can’t see in real time, however.

There’s also a matter that most generation plant self-consume some of the electricity that they generate before it’s exported to the grid:

Image #9 – Self-Consumption of “Auxiliary Energy” at Generation Sites

All generators self-consume a small amount of energy before its exported to the grid:
(a)  In some cases, like solar and wind, the self-consumption is so small as to be negligible
(b)  Generation involving a steam cycle (i.e. boiling pressurised water to spin a turbine) require a non-trivial amount of auxiliary energy in order to power the pumps and motors required for water and air flow, etc…

To explain the difference between the two numbers, the industry commonly uses the following terms:

Table 2 – Different terminology used with respect to supply/demand
“As Generated” The measure that represents the total production of electricity at a particular generator, before accounting for Auxiliary Energy usage

This is sometimes also referred to as “At the Generator Terminals” or “Gross”.

“Auxiliary Energy” A measure of how much energy is consumed on the generator site before it leaves the station “gate”.
“Auxiliary Factor” The percentage of energy rate (or volume) self-consumed as Auxiliary Energy, relative to the As-Generated energy rate (or volume).

It’s important to note that (in the NEM, as in many markets) a generator’s Auxiliary Factor is confidential to that particular participant.

Our NEMreview product utilises an in-built Generator Catalog containing estimates for Auxiliary Factors for the NEM stations for which the AEMO publishes data. We are in the process of expanding and enhancing this Generator Catalog such that:

1) It can be utilised in our other products; and

2) Such that it can be accessed directly, by those who just wish to subscribe to this service.

“Sent-Out Energy” “Sent-Out Energy” is the rate/volume of electrical energy that makes its way onto the grid at the generator’s connection point “at the station gate”.

Hence, if we’re talking rate of production, then

Rate of Generation Sent-Out (in MW) =
Rate of Generation As-Generated (in MW) –
Rate of Auxiliary Energy Usage Internally (in MW)

Hence, if we’re talking volume of production, then

Volume of Generation Sent-Out (in MWh) =
Volume of Generation As-Generated (in MWh) –
Volume of Auxiliary Energy Usage Internally (in MWh)

As with the Auxiliary Factor, the Sent-Out Energy (rate/volume) is confidential to the market participant. This is just the same as an individual energy user’s rate/volume of consumption being confidential to them.

Remembering the distinction between Dispatch and Settlement (section C above) it is important to understand that

· the NEM is dispatched on an As-Generated basis; whereas

· the NEM is settled on a Sent-Out basis.

This means that any figure quoted for rate of electricity consumption (i.e. demand) is highly likely to be on an As-Generated basisthough we note that the AEMO has started to use Sent-Out basis in some instances, like with the consumption and demand forecasts in the 2017 Electricity Forecasting Insights (see footnote 1 on p3) to keep everyone on their toes.


Complexity E3) There is energy “lost” in the supply chain

We wanted to highlight a third area of complexity (noting that there are more than these three) that has to do with energy being “lost” through the transmission and distribution grid, on the way to its final point of consumption.

Now the first point to note is that calling this energy “lost” is not meant to imply that we don’t know where it’s gone. A high proportion of the energy “lost” is converted to heat in the transmission and distribution networks.

Rather, we use the term “energy lost” to imply that it a percentage of the energy generated does not get to do “useful work” at the energy user’s site, because it is used up in the process of delivering it to that end.


Image #10 – Energy “Losses” enroute to final consumption

Losses are typically a function of factors like the size of the conductor, the voltage, and the distance over which it travels.

Reducing losses is one of the main reasons why high voltages are used in delivering electricity over long distances (like using high pressure in pumping fluids over long distances in pipes).

Again, from the point of the Supply & Demand Widget (and remembering that the NEM is dispatched on an “As-Generated basis” we see that the energy “lost” in delivery forms a component of the total demand number.


Complexity E4) Time-points associated with the data

Based on questions we’ve been asked over the years, and clarifications we’ve needed to make in relation to our products (particularly the very widely consumed NEMwatch Widget on RenewEconomy), we know we need to add in some clarification of the different time points that apply in relation to data published by the AEMO (and others, like the TNSPs through ez2view).

One of AEMO’s key tasks is to schedule the dispatch of large scale, controllable supply and demand sources. “Scheduling dispatch” means to send each of these sources, at regular intervals, individual production/consumption target levels that in aggregate meet the demand level that AEMO sees (“scheduled demand”), and are consistent with the market offers made by each source. In the NEM this happens on a 5-minute “look-ahead” (“ex-ante”) basis. AEMO must forecast where demand will be in 5 minutes and schedule the market accordingly. To do this AEMO uses real-time supply-side measurements from operational SCADA metering to calculate current demand, so that the only true forecast required is the change in demand over the next 5 minutes.

This gives rise to a difference between metered and target measures of demand. Metered (or Initial) demand is what’s measured using SCADA metering at the start of every 5-minute dispatch interval, while Target demand is the forecast level at the end of the same interval. In a perfect world, one dispatch interval’s Target demand would be the next interval’s Metered demand, but even over 5 minutes there can be significant deviations away from forecasts (one of the reasons that FCAS services are needed to keep things in balance).

Table 3 – Understanding the time points associated with the data
  Metered Target
Dispatch Through their MMS, the AEMO publishes a number of measures that are metered numbers taken at the start of each dispatch interval.

These measures include Initial Supply (for a region), and Initial MW (for relevant generators).

It is the Initial MW numbers that we use heavily in the NEMwatch Widget for a number of reasons, including:

1)  Initial MW is available in real time, whereas other metrics (such as Dispatch Targets) and deemed confidential in real time and only published on a next day basis.

2)  Data is also supplied for Initial MW for a greater range of generators (including some that are not scheduled, so do not receive dispatch instructions from the AEMO).

Hence using these provides a broader visibility of the fuel type mix supplying the NEM (though there has been some confusion so caused because the AEMO’s data dashboard currently provides data for only a smaller list of generators).

The NEM is dispatched on a 5 minute basis and (until 1st July 2021) settled on a half-hour basis.

Targets are effectively forecasts made, at the start of the (5-min) dispatch interval, for the rate expected at the end of the dispatch interval – such as:
1)  the rate of production of expected from each scheduled DUID (or consumption, for scheduled loads);
2)  the rate of consumption (i.e. demand) which AEMO forecasts on behalf of all non-scheduled loads; and
3)  the expectation of how the interconnectors will be flowing at that time, to keep supply and demand balanced.

The Dispatch Demand Target for each region was one of the few metrics available back when the NEM started.  At that time, there was a singular focus on Scheduled Demand, as well.  It remains one of the key metrics, as it has a direct bearing on what the price outcomes are for the dispatch interval.

For instance, in our “Best demand forecaster in the NEM” competition which we have run for a number of years, we tend to focus on the “Scheduled Demand” Dispatch Target in order to maintain a direct connection with the basis of the prior year results.


(until 1 July 2021, when the NEM moves to 5-minute settlement)

When the AEMO issues reports on new peaks in electricity demand (which tends to be each summer and winter), they tend to do this on the basis of metered data for a half hour. Because dispatch works on a five minute basis, there is no real need for target values to be provided on a half-hour basis.

In some respects (such as generation production) a time-weighted average might still be credible – however in other cases (such as with respect to transmission limits), a half-hourly average of 6 x 5-minute limit numbers does not make a whole lot of sense.



(F) Some other terminology used to describe Demand

As you’ll see from the above, the simplistic model that I started by drawing needs to be layered with different types of complexities in order to arrive at something better reflecting reality.


Table 4 – Three difference definitions of demand used by AEMO, plus one we’ll be using more often
A layperson’s idea of “rate of aggregate consumption supplied from all sources” It may surprise some readers that there is not even terminology defined to describe what a layperson might think of as “rate of aggregate consumption supplied from all sources”.

We know of some industry participants who refer to this as “Native Consumption” to differentiate it from AEMO’s term “Native Demand” (below) – but it is highly likely that there are other terms also in use to describe the same thing.

In particular, note that “Native Demand” (i.e. AEMO’s term) excludes both:
1)  Supplies from generation sources smaller than 1MW (which means all of the rooftop solar that’s producing across the NEM); and
2)  Some non-scheduled (embedded) generation sources larger than 1MW, but for which AEMO and the Jurisdictional Planning Bodies don’t have sufficient data.  We believe that this would mean lack of visibility of:
(2a)  solar PV greater than 1MW but still too small to have metered generation available on a individual facility basis (such as Valdora on the Sunshine Coast, Peterborough in SA, and a rapidly growing list).
(2b)  a number of back-up gensets at commercial and industrial facilities (which might rarely run); along with
(2c)  some of the electricity generation embedded within industrial processes that runs more frequently.

It’s this data “missing” from AEMO’s Native Demand numbers that is the reason why others try to create their own view of “Native Consumption” – it’s also why we try to do the same in our Supply & Demand widget, notwithstanding that we know the picture is incomplete because of missing data about various electricity supply sources, such as:

1) solar production at the growing number of medium-scale facilities above the 100kW SRES cut-off, but below the (at least 5MW) level where the AEMO will take an interest in accessing meter data in real time; and

2) the large number of embedded generation facilities installed in commercial and industrial sites across the NEM.

AEMO term “Native Demand” AEMO defines here the term “Native Demand” as follows:


For a number of reasons (included those alluded to above) it is not practical to calculate, in real time, a 100% accurate picture about the magnitude of Native Demand.

For practical reasons, the AEMO chooses to focus much more on Operational Demand (below).

AEMO term “Operational Demand” Increasingly as this energy transition picks up pace, the AEMO is using “Operational Demand” as the metric they speak about in more public forums.

AEMO defines here the term “Operational Demand” as follows:


I think about “Operational Demand” as “Demand the AEMO can see” – which includes Scheduled Demand (below) but also demand met by larger scale intermittent (but non-scheduled) generators that they can “see” because they have access to SCADA generation data in real time.

The AEMO MMS data field “Demand and Non-Scheduled Generation” most closely matches their definition of “Operational Demand” in real time:

1)  It’s this data that is shown in our “ECA Widget”, for instance;

2)  But we should not that it does not perfectly equate to “Operational Demand” – which is the reason why we have calculated it ourselves from raw unit-level data in the “RenewEconomy widget”.  This also enables us to explicitly show electricity demand used to charge storage – either in the form of:

2a) Electricity stored in batteries – as shown here:


Image #11 – Energy storage to battery

2b) Electricity converted to potential energy in pumped storage hydro facilities – as shown here:


Image #12 – Energy storage to pumped hydro

Separately, the AEMO publishes an Operational Demand metric on a half-hourly basis, and we include this as an additional data series for each region in NEMreview v7.

AEMO term “Scheduled Demand” AEMO defines here the term “Scheduled Demand” as follows:


When the NEM started back at the end of 1998, this was the only measure of demand that existed.

“Scheduled Demand” is still a centrally important metric within the NEM – as it is the demand against which AEMO dispatches controllable sources in order to balance the system and to clear the electricity spot market.  In other words, it produces the prices we all pay.

We just need to keep in mind that Scheduled Demand is

Our term “Demand met by fully dispatchable supply” This is a bit of a long-winded term, but one we will be using increasingly in future – as it represents one of the challenges the NEM (and most other grids) will have to manage increasingly in future.

It subtracts from Scheduled Demand the contribution of sources that are not fully controllable – the so called “Semi-Scheduled” large scale wind and solar PV generators, which can reduce output if requested by AEMO, but whose maximum output fluctuates with wind and sunlight conditions.

When I spoke at All Energy in 2015, presenting some analysis of what the NEM would look like with a 10x increase in intermittent supplies, I used the term “Energy Unserved by Wind and Solar” to describe this metric.


(G) Some other light reading…

For those who are seeking more of the gory details, the AEMO has produced a number of useful reference guides over the

Table 5 – other references you might like to read, about electricity demand
Sometime 2016 The AEMO also published a short explanation of what they mean by “operational” which we found of use.

Here’s a version of this document we saved ourselves sometime during 2016.

Sept 2016 This AEMO document “Demand Terms in EMMS Data Model” from September 2016 can help. It’s a document that has been through a number of revisions over the years.

I find v7 from Sept 2016 much clearer than some prior issues.

Please note that any errors made in translating from these more “industry-speak” documents to something that hopefully is more widely understandable above are entirely mine.

I would be delighted if you could point out any errors I have made, along with anything you think I could clarify even further – either in comments below, or direct with me (please call +61 7 3368 4064 or drop us a line). Just note that I might be slow to respond, given the diverse nature of customer demands on our business.


(H) A different view of Electricity Demand (another Widget)

The Supply & Demand Widget, which we provide with the sponsorship of RenewEconomy, is one of our widgets that we’re pleased to provide freely accessible on the web, with the help of our sponsors.

We have another widget that is consumption-focused, so is worth mentioning here. In mid-2016 we were pleased to be able to introduce this geographical view of Operational Demand in “the ECA Widget” and how it relates to local temperatures at population centres across the country:

Image #13 – The ECA Widget, which you can also find here and here and other locations as well (and are able to embed on your own website too)



(I) Seeking your feedback on this explainer

Thanks for making your way all the way to the bottom of this article – we realise that it’s a fair bit normal than a typical blog post.  But (at least for us) the topic of electricity demand is an important one, and we see that it will become increasingly important into the future as this energy transition gathers pace.

For that reason, we’re keen on your feedback in terms of how helpful you found this (and in particular any errors you have seen in the above):

Option 1 = if you’re happy to have your comments visible to all readers (some of whom might also help answer any questions you have), please just leave a question or comment below the article.

Option 2 = if you’d like to share your feedback privately with us, please use this feedback form here (which will protect your email address, as it will protect ours).

Option 3 = of course, you can always just call us direct on +61 (0)7 3368 4064.

Thanks for your time.

About the Author

Paul McArdle
One of three founders of Global-Roam back in 2000, Paul has been CEO of the company since that time. As an author on WattClarity, Paul's focus has been to help make the electricity market more understandable.

7 Comments on "An explainer about electricity demand [take 1]"

  1. Thanks Paul. This is all excellent but even exceeds my nerd quotient. I do generally find the water analogy helpful. But one nit picky thing is that Image #2 refers to “electrons delivered down the pipe”. It is an interesting fact that in a 50 Hz AC circuit electrons don’t actually travel very far. Energy is transferred at the speed of light despite that fact that individual electrons only jiggle back and forth a short distance along the conductor.
    In G) the first sentence isn’t finished.
    Three paras up there is another unfinished sentence “We just need to keep in mind that Scheduled Demand is”

  2. PS this article says “The truth is way more spectacular: the energy doesn’t travel through the wires at all — it shoots through the space around them, at the speed of light.”
    Not sure I can get my head around that!

  3. Thanks for your time in putting together this insightful article.

    I would love to know more about how the different States are using electricity, for example, why does QLD sometimes use more electricity than NSW, when they have a much lower level of population? Is it due to Aircon usage, or industry?


  4. Thanks Paul, very useful article in explaining some of the more abstract concepts.

    Just picked up on one thing; in section B, the units of the last two lines below should be watt and megawatt?
    = 3,600,000,000 J/h
    = 1,000,000w
    = 1MW

  5. Paul,
    I have just come across this article and noted the remarks about demand in some places being characterised by higher proportions of industrial demand relative to domestic. Many years ago I used to predict daily demand for SA and it was pointed out to me that our demand was relatively lightly affected by industrial load, despite having the car industry and its ancillaries, because gas was such a large contributor to energy usage by industry. Adelaide was the first to take gas from the Moomba gas field and its development was enabled by Torrens Island PS taking 2/3 of the gas from Moomba in the 1960 – 70s; the rest being taken by industry, commercial and domestic.
    When predicting demand the major impact was due to air-conditioning so demand was highly correlated with temperature since there was a small industrial base load for electricity and we became quite adept at ‘adjusting’ for number of days of high temperatures preceding, overnight temperatures etc.
    It was also necessary to take account of school holidays, Christmas and Easter as domestic, school and commercial air-conditioning all had varying effects.
    It was apparently quite a different process with unique considerations compared to the Eastern states.

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  2. Recapping a shaky week for the supply-demand balance in the NSW region last week (Mon 4th June to Fri 8th June 2018)
  3. Beginner’s Guide to how dispatch works in the NEM, and hence how prices are set
  4. Scheduled Demand in South Australia drops to 536MW, an all-time* record minimum in the afternoon of Sunday 21st October 2018 - WattClarity
  5. Hot weather in Queensland to drive Electricity Demand high this week (and warning of LOR2 Low Reserve Condition) – WattClarity
  6. High temperatures (and high demand) forecast for QLD this Friday – WattClarity
  7. Hot weather forecast to drive demand past 31,000MW next Tuesday 15th January – WattClarity
  8. My first look at the highs, and lows, in Victoria and South Australia on Thursday 24th January 2019 – WattClarity
  9. Looks set for a peak demand in QLD on Wednesday up near the all-time maximum – WattClarity
  10. Some thoughts about Demand Response, in parallel with AEMC deliberations – WattClarity
  11. A (Much) Deeper Dive into Friday March 1 2019 – WattClarity
  12. ‘Duck Curve’ delivers declining Minimum Demand levels in South Australia – WattClarity
  13. AEMO forecasts new “lowest ever” demand today in South Australia – but misses by 200MW – WattClarity
  14. South Australia experiences lowest (non System Black) Scheduled Demand in 21 years – WattClarity
  15. Sweating on the return of Loy Yang A Unit 2 – WattClarity
  16. Return-to-service of Loy Yang A2 hits a snag – WattClarity
  17. Queensland Scheduled Demand exceeds 9650MW today – within 400MW of the all-time record! – WattClarity
  18. NEM-wide demand might exceed 34,000MW on Friday evening – WattClarity
  19. Buckle in folks, Friday afternoon/evening might be a bit bumpy – WattClarity
  20. 13 headline questions and observations following the long-term islanding, starting Friday 31st January 2020 – WattClarity
  21. Reviewing the ‘accelerated accidental experiment’ thrust on SA during the islanding (31st Jan to 17th Feb) – a 1st review – WattClarity
  22. Surviving on the island – again – WattClarity
  23. Electricity demand as a Performance Metric, in the age of coronavirus – WattClarity
  24. Careful with the ‘doomsday claims’ that COVID responses have (or will) massively reduced aggregate underlying electricity consumption in the NEM…. – WattClarity
  25. Observing Easter Saturday, a little belatedly – WattClarity
  26. Saturday 4th July 2020 sees QLD spot prices crunched over long periods of the day, with solar booming – WattClarity
  27. Difficult to determine (i.e. minor) reduction in daily NEM-wide aggregate ‘Underlying Consumption’ in 2020, the (first?) COVID year – WattClarity
  28. The NEM consumes 10GW of supply from renewable plant on Sunday 19th July 2020 – WattClarity
  29. What effect has Stage 4 Lockdown in Victoria had on electricity consumption in the NEM? – WattClarity
  30. Solar eats a large hole in QLD daytime Scheduled Demand … lowest level in 16 years on Sunday 23rd August! – WattClarity
  31. Victorian Scheduled Demand plunges in the middle of the day, Saturday 29th August 2020 (a new daytime record low in NEM times?) – WattClarity
  32. Exploring deeper, about minimum demand on Saturday 29th August 2020 – WattClarity
  33. Diving deeper (part 2), about low demands on Saturday 29th August 2020 – WattClarity
  34. New minimum point for Scheduled Demand in South Australia on Sunday 13th September 2020 – WattClarity
  35. South Australia solar power reaches 94 pct of state demand on Sunday | RenewEconomy
  36. Rooftop PV drives daytime Scheduled Demand even lower than the low point a month ago … lowest level in 16 years on Sunday 27th September 2020 – WattClarity
  37. The decline to zero continues… SA demand and whole-of-NEM both drop even lower on Sunday 11th October 2020 – WattClarity
  38. Queensland price spikes to $15,000/MWh at 09:45 on Tuesday 13th October 2020 … coincident with many Large Solar Farms tripping – WattClarity
  39. With increasing diversity, the low point of instantaneous aggregate Wind Generation across the NEM is nudging away from 0MW – WattClarity
  40. Low point for demand in Victoria drops still lower on Sunday 1st November 2020 – WattClarity
  41. An evolving perspective – forecast impacts of the South Australia short, sharp ‘Circuit Breaker’ COVID response – WattClarity
  42. Low demand experienced in SA on Sunday 14th February 2021 – WattClarity
  43. High temperatures drive QLD Scheduled Demand to 9,476MW (highest this summer, so far) – WattClarity
  44. Will the traditional ‘Peak’ contract be another casualty of this Energy Transition? – WattClarity
  45. Price spikes to $15,000/MWh in South Australia on Friday 12th March 2021 … part 1 – WattClarity
  46. The $15,000/MWh in South Australia on Friday 12th March 2021 … part 2 (what seems to have happened) – WattClarity
  47. Repair work on Heywood continues to affect South Australian region – WattClarity
  48. Several QLD price spikes on Saturday 10th April 2021 – WattClarity
  49. Spot market volatility report – Thursday 3rd June 2021 (as at 17:54) – WattClarity
  50. Tight supply/demand forecast for NSW on Thursday 10th June 2021 – WattClarity
  51. Evening volatility continues into Thursday 10th June 2021 – WattClarity
  52. Three potential tripwires looming in October 2021, for those who are not wary – WattClarity
  53. Is the predictability of day-ahead demand improving? – WattClarity
  54. NEM-wide scheduled demand exceeds 31,000MW and IRPM drops to 11.93% on Monday 5th July 2021 – WattClarity
  55. Mainland region price spikes on Tuesday 6th July 2021 – WattClarity
  56. Friday evening price spike in QLD and NSW – with 300MW demand response in QLD – WattClarity
  57. Exploring the price spike in NSW on Wednesday morning 14th July – WattClarity
  58. New all-time record for NEM-wide wind production on Saturday 24th July 2021 (above 6,000MW for the first time) – WattClarity
  59. A quick look at the generator bids across Sunday 23rd August 2021 (when Solar temporarily eclipsed Coal) – WattClarity
  60. A list of (some of) the factors contributing to the volatile price outcomes seen in Q2 2021 – particularly QLD and NSW – WattClarity
  61. ‘Grid Demand’ in the NSW region plunges on Saturday 11th September 2021 – WattClarity
  62. Demand records in NSW tumble for the second weekend in a row – WattClarity
  63. Minimum Demand in South Australia drops lower on Sunday 26th September 2021 – WattClarity
  64. NEM-wide minimum demand (in winter) drops lower on Sunday 15th August 2021 … and Renewables Share in VIC higher – WattClarity
  65. A first view of bids under Five Minute Settlement – WattClarity
  66. New low point for minimum demand (not artificially suppressed) in QLD on Sunday 3rd October 2021 – WattClarity
  67. … also a new lowest point for NEM-wide demand on Sunday 3rd October 2021 – WattClarity
  68. Low points for NSW demand in December 1999 and January 2000 – WattClarity
  69. The slide continues – demand in NSW lower still on Monday 4th October 2021 – WattClarity
  70. Re-starting compilation of GenInsights21, for release December 2021 – WattClarity
  71. AEMO forecasts new record minimum Operational Demand (NEM-wide) on Sunday 17th October – WattClarity
  72. A monster leak in the Grid drives ‘Minimum Demand’ on a NEM-wide basis down on Sunday 17th October 2021 – WattClarity
  73. Price volatility in South Australia on Wednesday 27th October 2021 – WattClarity
  74. Evening LOR2 in the QLD region – and early ‘summer’ evening – WattClarity
  75. Minimum Demand records drop lower – for the SA region, and NEM-wide – WattClarity
  76. [CORRECTION – CLOSE TO] New Record Scheduled Demand point also set for NSW on Sunday 31st October 2021 (Part 2) – WattClarity
  77. Updated tabulated record of minimum demand points – for each region, and NEM-wide – following 31st Oct 2021 – WattClarity
  78. New Minimum Demand point also set for Victoria on Sunday 31st October 2021 – WattClarity
  79. Scheduled Demand drops very close to 0MW in South Australia on Sunday 21st November 2021 – WattClarity
  80. Spot price and demand up in QLD on a hot and humid Monday 20th December 2021 – WattClarity
  81. ‘Market Demand’ in Victoria moves a shade lower on Tuesday 28th December 2021 … but not quite, for Operational Demand – WattClarity
  82. Price volatility in South Australia Thursday evening 30th December 2021 – WattClarity
  83. Forecast tight supply/demand balance in Queensland on Monday 31st January, Tuesday 1st and Wednesday 2nd February 2022 – WattClarity
  84. South Australian price spike on Sunday 30th January 2021 with declining wind, and following (apparent) trips of Bungala 1 and 2 Solar Farms – WattClarity
  85. Price volatility (and low IRPM) on Monday 31st January 2022 – in QLD, VIC, SA (a first initial review) – WattClarity
  86. After a hiatus, Queensland demand starts rocketing back upwards late afternoon Tuesday 1st February 2022 – WattClarity
  87. Only 5 percent IRPM (485MW spare) in the QLD Economic Island! – WattClarity
  88. QLD ‘Market Demand’ at 9,869MW at 14:50 … are we going to reach an all-time record? – WattClarity
  89. A quick look at the 14:30 price spike today (Wed 2nd Feb 2022) – WattClarity
  90. Demand forecast ‘warming’ for QLD for Tuesday afternoon 2nd February 2022 – WattClarity
  91. We dodged a bullet today in QLD (Tue 1st Feb 2022) … but there’s new challenges to confront tomorrow (Wed 2nd Feb 2022) – WattClarity
  92. Price volatility in the QLD region on Sunday evening, 30th January 2022 – WattClarity
  93. Queensland Market Demand hits 10,000MW (and is rising fast) late Tuesday afternoon, 8th March 2022 – WattClarity
  94. New all-time record demand for QLD region on Tuesday 8th March 2022 – WattClarity
  95. First big price spike in QLD at 18:35 on Wednesday 9th March 2022 - WattClarity
  96. Prices spike in South Australia on Saturday evening, 19th March 2022 (State Election Day) - WattClarity
  97. Reviewing the ‘accelerated accidental experiment’ thrust on SA during the islanding (31st Jan to 17th Feb) – a 1st review - WattClarity
  98. What Demand-Side Responses can we see in QLD’s heatwave of Tue 1st February and Wed 2nd February 2022? - WattClarity
  99. Evening volatility in QLD (and NSW), and a mysterious/significant drop in Available Generation, on Monday 2nd May 2022 - WattClarity
  100. Price volatility in QLD and NSW on Tuesday 3rd May 2022 - WattClarity
  101. Drop in forecast wind conditions for Thursday 12th May 2022 briefly triggers forecasts of Load Shedding (LOR3) in South Australia - WattClarity
  102. Market Volatility (and low IRPM) on Monday evening 16th May 2022 in QLD region - WattClarity
  103. Morning price volatility in South Australia on Tuesday 17th May 2022 - WattClarity
  104. A (temporary?) reprieve from the incessant high prices on Sunday 29th May 2022 - WattClarity
  105. Tight supply-demand balance on Monday evening 30th May 2022 drives prices high and IRPM low - WattClarity
  106. Tight supply-demand, so price volatility, in NSW and QLD on Tuesday 31st May 2022 - WattClarity
  107. NEM-wide IRPM drops below 15% on Wednesday 1st June 2022 - WattClarity
  108. Morning price volatility on Thursday 2nd June 2022 - WattClarity
  109. Very tight supply-demand (NEM wide!) on Thursday 2nd June 2022 - WattClarity
  110. Volatile prices on Friday evening 3rd June 2022 - WattClarity
  111. Tasmania sees its own spell of volatility on Saturday evening 4th June 2022 - WattClarity
  112. New record production from wind on Tuesday 31st May 2022 (larger still in the afternoon!) - WattClarity
  113. Evening price volatility on Tuesday 7th June 2022 - WattClarity
  114. Queensland spot prices on Wed 8th June 2022 … a (discordant?!) Symphony in 3 Movements - WattClarity
  115. Brisbane's week is ‘Coldest in 118 years’ … what is the outlook for electricity demand? - WattClarity
  116. Friday evening volatility in the QLD Region (escalated to actual LOR2) - WattClarity
  117. Under Administered Pricing, QLD sees ‘Actual LOR2’ and Market Direction - WattClarity
  118. IRPM drops to only 8% NEM-wide - WattClarity
  119. Is South Australia or Victoria next to the CPT … with Administered Pricing also in NSW? - WattClarity
  120. Australian grid teeters on edge of blackouts tonight - Climate-
  121. IRPM on a NEM-wide basis drops down to 9% again, at 20:05 - WattClarity
  122. TAS spot price at $15,100/MWh with near-record Market Demand … and NEM-wide IRPM hits a low of 4.33% Tuesday morning - WattClarity
  123. Cloud cover and cold temperatures spark price spike in QLD on Monday 4th July 2022 - WattClarity
  124. Queensland scrapes through on Tuesday 8th March 2022 … with only 210MW spare capacity at the lowest point! - WattClarity
  125. Actual LOR1 and $15,500/MWh in the QLD region on a cold/dreary Monday evening 4th July 2022 - WattClarity
  126. Price volatility on Monday evening 11th July with ‘Market Demand’ near 31,000MW - WattClarity
  127. New all-time record for wind output, NEM-wide on Saturday 16th July 2022 - WattClarity
  128. Spot price volatility in South Australia Thursday morning 28th July – second morning in a row - WattClarity
  129. New lowest point for QLD ‘Total Demand’ on Sunday 7th August … excluding outages - WattClarity
  130. QLD minimum demand drops lower still on Sunday 14th August 2022 - WattClarity
  131. Substantially different than a year ago, the 2022 ESOO points to challenges ahead in the supply/demand balance - WattClarity
  132. A deeper (but still incomplete) look into the Overnight volatility in South Australia (i.e. part 2) - WattClarity
  133. ‘Minimum Demand’ records pushed lower in QLD on Sunday 11th September 2022 - WattClarity
  134. Two charts from ‘Smart Energy Queensland’ presentation, illustrating the electricity supply mix in Queensland - WattClarity
  135. Minimum Demand drops lower, on Sunday 25th September 2022 – for the NSW region, and also NEMwide - WattClarity
  136. *Was* solar production disappointingly low through (parts of) Q2 2022 … and, if so, why? - WattClarity
  137. ‘Market Demand’ in Victoria drops to a new low point on Sunday 2nd October 2022 - WattClarity
  138. Analytical challenge (or beginner mistake!) - understanding the difference between a MW and a MWh - WattClarity
  139. Sequence of events in Tasmania on Friday 14th October 2022 (initial look) - WattClarity
  140. Uncharted territory for rooftop PV in South Australia - WattClarity
  141. A new lowest point for NSW demand on Saturday 29th October 2022 - WattClarity
  142. Long-range trend of Instantaneous Reserve Plant Margin (IRPM) and focus on Q3 2022 – from GenInsights Quarterly - WattClarity
  143. A quick (interim) review of the ~7 days living on the SA island + some broader questions to explore later - WattClarity
  144. Victorian minimum demand drops lower on Sunday 18th December 2022 - WattClarity
  145. A subdued start to summer 2022-23 - WattClarity
  146. Might see more price volatility this week … at least in QLD? - WattClarity
  147. Tuesday afternoon look at the (escalating) forecast for Friday 3rd February 2022 … will Reserve Trader be triggered? - WattClarity
  148. A burst of heat and volatility in QLD on Tuesday 31st January 2023 - WattClarity
  149. Forecasts pointing to record demand and other risks in QLD for Friday afternoon.. but caveats aplenty - WattClarity
  150. Quick Friday morning look-ahead to Friday evening in QLD - WattClarity
  151. Spot price volatility has begun (in QLD on Friday 3rd February 2023) - WattClarity
  152. Twelve hours of Mainland NEM System Frequency on Friday 3rd February 2023 - WattClarity
  153. The worm has turned? Actual demand levels dropping lower than forecast (QLD 3rd Feb 2023) … maybe no record? - WattClarity
  154. QLD Market Demand for 17:30 lands at ‘only’ 9750MW (Fri 3rd Feb 2023) - WattClarity
  155. To weather! The cause of.. and solution to.. all the electricity market's problems? - WattClarity
  156. QLD Market Demand reaches 9,512MW on a hot Sunday afternoon–12th February 2023 - WattClarity
  157. Price volatility in VIC and SA on a warm summer evening, Thursday 16th February 2023 - WattClarity
  158. Recapping Thursday 23rd Feb 2023 (when hot weather drove demand in South Australia highest in 9 years) - WattClarity
  159. Forecasts for a hot Monday 6th March in NSW, and potential LOR2 in the evening (now also Tuesday evening) - WattClarity
  160. Late ‘summer’ hot blast drives demand higher in NSW and QLD - WattClarity
  161. AEMO forecasts point towards a possible record total demand in QLD this afternoon on 17th March 2023 - WattClarity
  162. New all-time record for Operational Demand in QLD on Friday 17th March 2023 … but not for Market Demand - WattClarity
  163. Spot price volatility in QLD and NSW on Sunday 19th March 2023 - WattClarity
  164. Reviewing what happened in NSW and QLD on Thursday 16th March 2023 (with Actual LOR2, Volatility and Reserve Trader almost triggered, etc) … part 1 - WattClarity
  165. New low-point for demand in NSW on Easter Sunday, 9th April 2023 - WattClarity
  166. Case Study of Friday 3rd February 2023 (Part 1) ... two consecutive large instances of collective under-performance for Semi-Scheduled units - WattClarity
  167. Spot price volatility in NSW and SA on Monday 1st May 2023 - WattClarity
  168. Currently forecast LOR2 for South Australia for Wednesday 10th May 2023 - WattClarity
  169. We’re not building enough replacement dispatchable capacity - WattClarity
  170. IRPM drops below 15% on Tuesday 23rd May 2023 - WattClarity
  171. (Early!) winter evening volatility returns to QLD and NSW on Wednesday 24th May 2023 - WattClarity
  172. AEMO’s MMS 5.2, ez2view v9.7, Semi-Scheduled MaxAvail in the Bid, and a self-forecasting example - WattClarity
  173. Record for NEM-wide wind production nudged slightly higher on Thu 8th June 2023 - WattClarity
  174. Whiplash on VIC1-NSW1 - WattClarity
  175. A cold evening drives NEM-wide demand high, and IRPM low, on Tuesday 20th June 2023 - WattClarity
  176. Evening volatility in QLD and NSW on Wed 21st June 2023 - WattClarity
  177. Increasing curtailment of Wind and Solar across the NEM - WattClarity
  178. Evening volatility in the SA region on Friday 11th August 2023 - WattClarity
  179. Evening volatility in SA, VIC, NSW and QLD on Tuesday 15th August 2023 - WattClarity
  180. New low point for ‘Market Demand’ in QLD on Sunday 20th August 2023 - WattClarity
  181. New ‘lowest ever*’ points for Market Demand–in Victoria and NEM-wide on Saturday 16th September 2023 (and record high IRPM) - WattClarity
  182. QLD’s turn at new lowest point for minimum demand (in ordinary times) - WattClarity
  183. About the low Operational Demand on Sat 16th Sept and Sun 17th Sept 2023 - WattClarity
  184. It’s hot in Sydney (and elsewhere) … and demand is (moderate but) tracking ahead of forecasts - WattClarity
  185. It’s hot in Sydney (and elsewhere) … and demand is (moderate but) tracking ahead of forecasts - Breakthrough News Today
  186. Negative ‘Market Demand’ in South Australia on Saturday 23rd September 2023 - WattClarity
  187. Buckle in folks, Friday afternoon/evening might be a bit bumpy - WattClarity
  188. NEM-wide demand might exceed 34,000MW on Friday evening - WattClarity
  189. 13 headline questions and observations following the long-term islanding, starting Friday 31st January 2020 - WattClarity
  190. QLD minimum ‘Market Demand’ (in ordinary times) drops lower still, on Sunday 1st October 2023 - WattClarity
  191. ‘Minimum Demand’ in South Australia drops further below 0MW on Sun 1st October 2023 – measured by Market Demand - WattClarity
  192. New lowest point for NEM-wide demand also set on Sunday 1st October 2023 - WattClarity
  193. NSW region hit new ‘lowest ever’ point for Market Demand on Sunday 9th October 2023 - WattClarity
  194. Minimum Market Demand in NSW drops lower still, on Sunday 29th October 2023 - WattClarity
  195. Victoria’s ‘Market Demand’ low point drops further–on Sunday 12th November 2023 - WattClarity
  196. NEM-wide ‘Market Demand’ above 31,000MW on Monday 12th February 2024 - WattClarity
  197. 4 Loy Yang A units simultaneously trip, on Tuesday 13th February 2024 - WattClarity
  198. Some *initial* headline questions following the transmission damage, unit trips & loss of load, initiated on Tuesday 13th February 2024 - WattClarity
  199. Evening volatility in South Australia on Wednesday 21st February 2024 - WattClarity
  200. Afternoon spot price volatility on a hot day in VIC and TAS … and bushfire limitations - WattClarity
  201. Victorian ‘Market Demand’ above 9,000MW on Thursday 22nd February 2024 … for the first time since 31st January 2020 - WattClarity
  202. NEM-wide ‘Market Demand’ soars to (just below) 33,000MW on Thursday 22nd February 2024 - WattClarity
  203. Demand climbing in NSW and QLD on Friday afternoon 23rd February 2024 - WattClarity
  204. ‘Market Demand’ in QLD over 10,000MW … but cooler in NSW - WattClarity
  205. Stubborn forecasts for LOR2 (low reserve condition) for NSW for Thursday evening 29th February 2024 - WattClarity
  206. Evening volatility in South Australia on Tue 27th Feb 2024 + bushfire risk - WattClarity
  207. ‘Market Demand’ in NSW above 13,000MW in mid afternoon Thu 29th Feb 2024 - WattClarity
  208. NSW hit with first wave of price spikes as demand continues to climb towards 14,000 MW on Thu 22nd Feb 2024 - WattClarity
  209. A first look at the NSW price spike at 15:10 (NEM time) on Thu 29th Feb 2024 - WattClarity
  210. NSW ‘Underlying Demand’ peaks at 15,100MW at 15:00 (NEM time) on Thu 29th Feb 2024 - WattClarity
  211. So how much did Eraring Power Station supply, of the NSW electricity consumption, at peak demand time on Thursday 29th February 2024? - WattClarity
  212. Derivation of Underlying Demand on 30th and 31st January and 1st February 2020 - WattClarity
  213. Derivation of Underlying Demand in NSW on 8th, 9th and 10th February 2017 - WattClarity
  214. Derivation of Underlying Demand in NSW on 30th and 31st Jan and 1st Feb 2011 - WattClarity
  215. Antony Stace’s question about the step change (down) in QLD demand forecasts in AEMO MT PASA runs during February 2024 - WattClarity
  216. Cloud impacts on demand, a review of NSW on 29 February 2024 - WattClarity
  217. Elevated prices (and demand) in VIC and SA on Sunday evening 10th March 2024 - WattClarity
  218. SA price spike on Tue 12th March 2024 with rapid ramp in demand - WattClarity
  219. Digging further into ‘Aggregate Scheduled Target’, to understand what Dispatchable Capacity is actually required - WattClarity
  220. A focused look at operations at Victoria Big Battery (VBB) on Tuesday 13th February 2024 - WattClarity
  221. AEMO’s forecasts for higher ‘Market Demand’ in NSW on Thursday evening 25th January 2024 don’t materialise - WattClarity
  222. Evening volatility in QLD and NSW on Monday 29th January 2024 - WattClarity
  223. NEM-wide wind lull stretches extends to a full week (Tue 16th April 2024), and has another week to go! - WattClarity
  224. Brief Case Study of Sunday 4th February 2024, with low IRPM following high Market Demand - WattClarity
  225. Aggregate Dispatch Error across all Semi-Scheduled units (NEM-wide) throughout Thursday 22nd February 2024 - WattClarity
  226. Elevated demand in SA and VIC on Saturday 9th March 2024 - WattClarity
  227. Low aggregate wind yield after sunset continues – Sunday 26th May 2024 - WattClarity
  228. There might be a sustained burst of wind generation to finish off the month of May 2024 - WattClarity
  229. Snapshot of Monday evening 3rd June 2024 - WattClarity
  230. Afternoon volatility in TAS on Friday 14th June 2024 - WattClarity
  231. Low IRPM eventuates (as low as 10.89%), as expected, on Tuesday evening 18th June 2024 .. reaching 120 minutes - WattClarity
  232. NEM-wide ‘Market Demand’ above 30,000MW on Wednesday *morning* 19th June 2024 - WattClarity
  233. Correlation between low wind Capacity Factor and low IRPM (NEM-wide) in recent evenings + Thursday evening looks likely to be low, as well. - WattClarity
  234. Forecast evening IRPM next week healthy … despite ‘ferocious Tasman Low’ - WattClarity

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