Reliable vs. Intermittent Generation: A Primer (Part II)

From MasterResource

By Bill Schneider — March 2, 2023

“IVREs are inherently unreliable. One cannot demand that the wind blow or the sun shine. Industrial wind power and on-grid solar is not cheap but expensive, duplicative, and parasitic.”

Intermittent variable renewable energy (see Part I) generation sources are primarily wind turbines and solar photovoltaic panels (solar PV). But they can include underwater-based turbines (“tidal”) and solar collectors (“mirrors”); large-scale lithium-ion battery storage facilities (“batteries”); and electric facility-stored fuel (water/hydro, oil, coal, natural gas, or nuclear energy), to be turned into electrons when needed, since these fuels can be stored at less cost than electrons.

Storing fuel and converting it into moving electrons (electricity), with the exception of planned maintenance (relatively rare occurrences) and unplanned outages (even rarer), most generators were designed – and, more importantly, costed – to operate at a fairly steady state. This steady state is commonly called, baseload energy. When a baseload generation facility is pumping out all the electricity it can produce, it operates in a steady-state, which is good for its design life as well as maximizing revenues against costs for maintaining high performance and attracting more of the same to meet demand growth.

To handle “peaks” in electricity demand (due to unseasonably hot or cold days, or to handle capacity should a generator or powerline network experience an unplanned outage), variable-output, “peaking” generators are called on by grid managers to handle sudden surges in load. Typically, peaking generators are relatively cheap to build (since they don’t operate very often) but expensive to operate (as they must recoup capital, operating, and maintenance costs across a relatively small window of power generation time). As demand steadily increases, the financial business case to add new baseload generation also increases.

Obviously there is a lot more detail here, but this is the general way that electricity supply and demand was managed – that is, until governments began mandating and incentivizing IVREs.


Presently, IVREs enjoy the following incentives and mandates from legislators and regulators:

  • Direct subsidies. This subsidy could be a direct cash grant from a government department or agency
  • Tax incentives. These are special tax breaks (credits) or deductions targeted at specific types of electrical generation facilities
  • Loan guarantees. A loan guarantee removes risk from the lender, when a government department or agency guarantees fulfilment of loan terms, making it easier for lenders to fund projects that are targeted by such legislation or regulation
  • “First-use” mandates. Typically, regulators will require grid managers to accept electricity sold by beneficiaries of these mandates before any other generation facility. First-use mandates ensure that an IVRE can sell its power whenever it can produce it.
  • “Floor-price”/minimum price mandates. Sometimes called “mandated feed-in tariffs,” these mandates can either be written directly into law (legislative) or required by regulatory bodies. Either way, such mandates require that beneficiaries are paid a minimum price for the electricity they produce, regardless of whether the price is aligned with market demand or not.

The combination of these subsidies and mandates ensures that IVREs attract financing and monetize their capacity “in front of the line” – despite their inherent inability to store their “fuel” (as sunlight, wind, and tidal energy cannot be stored, and parking electrons inside large batteries is very costly, resource-intensive, and time-constrained).

Without these subsidies and mandates, the cost of IVRE-supplied electricity would be high – and more importantly, the likelihood of being called on to generate power into the grid by either a large industrial consumer, or by a grid manager, would be very low (since IVREs cannot guarantee, or “dispatch,” their capacity prior to the time of generation (since they cannot control what the sun, wind, or tidal forces decide to do).

But with these subsides and mandates, IVREs are able to not only jump the line, they are also able to operate knowing that if they cannot produce, someone else will. This means that baseload loses demand (sales) without being paid to stand by, ready to generate at a moment’s notice, when IVREs cannot generate due to drops in “fuel” that are at the behest of Mother Nature. This issue is explained in more detail below.

ELECTRON MARKET, Historical Model

Imagine, if you will, a market for electrons. There are producers and consumers. Because electrons must be consumed immediately upon creation (as they cannot be stored in bulk for more than a few hours), there is a market regulator – let’s call this person the Electron Market Manager (EMM).

The market includes large electron consumers (we’ll call them ECL), medium electron consumers (ECM) and little electron consumers (households and small businesses, we’ll call them ECH), as well as various kinds of Electron Producers (EPs)

Demand is measured in five-minute increments, throughout the day, making the market have 288 “slots” per day where demand for electrons must be scheduled against production capacity.

When the EMM deals with the ECL, it’s a quick conversation: ECL needs XX electrons in Slot YY.

Being so large, ECLs will have contracts directly with EPs. These contracts are known by the EMM and are scheduled into time slots based on known requirements.

Smaller ECMs and all the ECHs aren’t large enough to contract directly with an EP, so they buy from Electron Retailers (ERs, a middleman that buys electrons in bulk based on anticipated demand and sells them to ECMs and ECHs).

EPs build capacity based on contracts with either ECLs or ERs. Note that ERs have to build some flexibility into their contracts with EPs because their sales demand to ECMs and ECHs can vary.

On the whole, the market looks like this:

EP(x) to ECLs and ERs = 100% EPx capacity

EMM ensures that EPx has enough electrons to satisfy both large, contracted ECLs and the rest of the market (ECMs and ECHs, managed through ERs)

As the market grows, new large ECLs may have their own EP built for the new demand (say, a large manufacturing plant). When ECMs and ECHs grow, the ERs must be able to anticipate and absorb the growth into their contracts with EPs – and the growth eventually creates enough demand to justify investments in new EPs.

ECMs and ECHs, not being large enough to contract with an EP directly, pay a premium to have their requirements managed through an ER. In return, the ER may offer significant flexibility to its customers, but at a price that manages risk. If the ER cannot sell the electron, it must pay for that electron anyway, so the value of the unused electron is lost.

Finally, both ECLs and ERs can opt to buy from the EMM directly, rather than through a contract. This is called the “spot market”, and generally, price is a function of the balance between demand and supply.

The EMM must balance the market constantly, to ensure that enough electrons are produced to meet demand. Surges in demand usually come when ER customers’ aggregate requirements suddenly increase (e.g., needing more electrons because of a very hot or very cold day).

So the EMM provides for “peaking electron production” by allowing standby EPs (remember, “peakers”) to nominate how much they will charge for their electrons if they have to enter the electron demand market – because if they run their Electron Plant only a few hours each season, they have to earn enough money to justify building and maintaining the EP.

In a normal market, “peaking electron production” would be quite expensive – and ERs would have to account for this increased surge demand in their contracts. But because they buy so many electrons, they do their best to forecast the electron demand over the course of the year, and their pricing models will include the costs of “peaking electron production” volumes and prices anticipated in that timeframe.


Now let’s differentiate the “base electron production” as EP-B, and the “peaking electron production” as EP-P. In a peak demand time slot, the market will look like this:

EP-B + EP-P = ECL + ER(Δ), where ER(Δ) is a temporary increase in demand.

A EP-B is usually built to maximize revenues for a given quantity of electrons produced. Its “unit cost per electron” will significantly increase if demand drops. Conversely, an EP-P is often cheap to build, but expensive to run, since it isn’t needed very often.

All good so far. But suppose Government decides to throw money and mandates at a different type of EP, one whose “fuel” for its electrons is “free” but cannot be stored or controlled. Let’s call this an EP-IVR, or an Intermittently Variable Renewable Electron Producer.

An EP-IVR may be able to manufacture 100 electrons in an hour, but only if the “fuel” is available. If the “fuel” isn’t available (because the sun isn’t shining or the wind isn’t blowing) then a EP-IVR cannot manufacture any electrons.

This limitation would normally mean that the EMM wouldn’t bother to schedule any EP-IVRs, except to the figure that they could forecast a few time slots in advance, and this scheduling would be done at the very last – just like with an EP-P.

It would make EP-IVR electrons have to be priced very expensive, to cover what they can produce, and demand from the EMM for EP-IVR electrons would not be realized often, since EP-Bs operate cheaper and so the EMM would use all EP-B electrons first.

Conversely, if the “fuel” is available in quantity (due to plenty of sun and/or wind in a particular time slot), the EP-IVR may find that there simply aren’t enough buyers for their electrons.

Therefore it’s quite likely that few, if any, EP-IVRs would be built at all, because the cost to build them is high and their ability to deliver is often constrained by the inability to store or control their “fuel”.

ELECTRON MARKET, IVRE subsidies and mandates

Enter Government. It decided that more EPs should be EP-IVRs, so it did a number of things to push the entry of EP-IVRs into the electron market:

  • Subsidies: often a combination of cash, favorable loans, and tax breaks
  • Guaranteed Demand: mandates require EMMs to buy electrons from EP-IVRs in front of all other EPs, ensuring that EP-IVRs sell every electron they can produce
  • Guaranteed minimum pricing: EP-IVRs are guaranteed a minimum price for every electron they can sell, affecting how much ECLs or ERs must pay to EP-IVRs over other EPs

The net effect of these market interventions is: now EP-IVRs get to unload their electrons in front of all other sellers – and even ECLs are either pushed (indirectly by governments, shareholders, lenders, and/or regulators) or actively seek out EP-IVRs over EP-Bs.

Therefore the market is reordered in this way:

EP-IVR + EP-B + EP-P (if required) = ECL + ER(Δ)

If capacity provided by EP-IVRs was constant, or even predictable, this wouldn’t be as much of a logistics issue as one merely of price intervention only.


EP-IVR sales capacity cannot be forecasted beyond six time slots from the current slot. This variability makes the EMM’s job difficult.

EP-Bs must be operated behind the scenes, kept in a “ready” state, but not actually generating any revenue from selling electrons. This condition is called “spinning reserve”, and it means that EP-Bs are burning fuel and paying operating costs to run their plants, on the off chance that EP-IVRs might not be able to deliver their predicted capacity – or that anticipated demand outstrips EP-IVR predicted capacity in a time slot (e.g., because the wind isn’t blowing and the demand for electrons is high on a hot day).

Conversely, due to “first-use mandates,” if capacity at EP-IVRs is actually higher than predicted (due to there being more wind or sun than forecasted), the EMM must require ECLs and ERs to buy from the EP-IVR first, when buying directly from the EMM.

This forces EP-Bs to operate in a non-revenue, “spinning reserve” state.

Conversely, should the EP-IVRs not deliver their predicted quantity of electrons, the EP-Bs must be prepared to pick up the slack.

Even with guaranteed minimum pricing via regulatory mandate, the short-run marginal cost of producing an electron from “free” fuel is pretty cheap, so the EP-IVR lobbyists trumpet how cheap they are to everyone.

Meanwhile, EP-Bs bear the risk of EP-IVR non-delivery, and EP-IVRs are able to get financing and make money because risk has been transferred to EP-Bs.

This unfunded risk transfer makes it less likely that investors will fund more EP-Bs (since, thanks to government subsidies and mandates, the “sure bet” investment is now EP-IVRs), and more likely that current EP-B operators will curtail or cease operations altogether. This will in turn cause EP-Ps, expensive to operate, to spring up like weeds, increasing prices to consumers.


Remember that with very limited (and very expensive) exceptions, electrons cannot be stored. Once they are produced, they must be consumed.

Government has chosen to “invest” in schemes to attempt to store produced electrons (via battery storage) and convert “free” fuel into stored fuel (via pumped hydro storage).

Both schemes are very expensive, and as such, attract subsidies and first-use mandates. They further disincentivize EP-Bs from either being built, or continuing operations. Plus, the insurance that both storage methods provide typically lasts between seven and twelve hours. Beyond that, most must be recharged, taking capacity away from the market rather than contributing to it.


Electricity markets are quite complicated once one gets into the details. The purpose of this article was not to get down to that level; rather, the purpose of this article was to provide an overview on the topic for a lay person who does not normally read, discuss, or consider how electricity markets work.

IVRE advocates have, and will continue to, rebut the conclusion that their power technology is deficient and survives only because of the web of government subsidies and mandates. Just remember that without those mandates (which include funding popular storage schemes such as installing/operating banks of extremely expensive batteries whose capacity lasts approximately 7-8 hours at full load, or building pumped hydro facilities that rely upon existing large holes in the ground from excavated mine sites, or “voids,” whereby water is moved from one void to the other for peaking power and then moved back via IVRE generation), IVREs are inherently unreliable.

One cannot demand that the wind blow or the sun shine. Industrial wind power and on-grid solar is not cheap but expensive, duplicative, and parasitic.

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Tom Halla
March 4, 2023 2:12 pm

By Mises analysis of socialism, lacking real prices, knowing real costs is impossible. Renewables are a favorite hobbyhorse of socialists, who are already tied into an unreal economic model.
But trust them, this time they will get central planning to work.

Dennis Gerald Sandberg
March 4, 2023 2:34 pm

RE (Ruinous Energy): Grid penetration at five (5) percent, harmless, 10% nuisance, 15% expensive and wasteful, 20% grid destabilizing and economy threatening, 25% insanity.

Reply to  Dennis Gerald Sandberg
March 4, 2023 2:52 pm

Even at 5% it still causes the cost of all electricity to go up.

Dennis Gerald Sandberg
Reply to  MarkW
March 4, 2023 3:18 pm

Agree, but zero is politically impossible. Biden’s new inflation inflaming act assures us we’ll be doubling our current wind and solar 12% to 24% to more closely match Germany, UK, South Australia, California and Texas.

Speaking, of Germany, who’s wind model all the progressives have loved for the past 20 years:

Germany doesn’t need to admit their “Energiewende” (transition to renewables) has failed. Results speak louder than words:

“…the rollout of onshore wind slowed down significantly in January (2023) with net new additions of only 54 MW as 21 turbines with a combined capacity of 31.9 MW were decommissioned”. 

Note: Germany’s wind addition rate peaked in 2018 (they added about the same capacity that year as in 2019-2022 combined.

Reply to  Dennis Gerald Sandberg
March 4, 2023 6:28 pm

How old were the 21 decommissioned turbines?

Dennis Gerald Sandberg
Reply to  BobM
March 4, 2023 8:57 pm

Not reported in the article but a 2018 article explained that by 2020 there would begin to be more each year that would lose the early lucrative tariff and not be economical to operate. By the retired capacity we see they were old 1.5MW turbines.

Dave Andrews
Reply to  Dennis Gerald Sandberg
March 5, 2023 8:21 am

Wind Europe say 38GW of Europe’s first generation onshore wind will be reaching the end of it’s normal operational life by 2025.

Reply to  Dennis Gerald Sandberg
March 5, 2023 5:07 am

Your levels are wrong. Texas already has ~30% of its electricity from wind and solar PV – it hasn’t been destabilizing/economy threatening.
Don’t get me wrong – there are definitely problems, and it isn’t clear how much higher Texas can go from 30%, but the end of the grid in Texas has not yet happened.
California, on the other hand, has had enormous curtailment even at the ~5% solar PV level.
So while I would fully agree that Net Zero is destabilizing, economy threatening and insanity – it is not clear precisely at what % solar PV + wind at which this occurs.
Nor do I particularly want to find out the hard way – why is the precautionary principle not applicable in this field?

Dennis Gerald Sandberg
Reply to  c1ue
March 5, 2023 7:56 pm

Texas has already had a massive “grid destabilizing cold weather event” and a couple near-miss hot weather events, directly attributable to an over-reliance on wind. Those natural gas turbines on cold standby, that they couldn’t get started after the storm hit, would have been up and running if ERCOT hadn’t been trying to rely on wind.
A series of postings about a month ago here on WUWT addressed the maximum economic amount of RE on a given grid service area. Texas makes an ideal study because of a lack of interconnection. The “Pollack Limit” suggests that the RE can’t exceed the capacity factor of the specific grid because any additional capacity is wasteful because of curtailment payments. The postings include the supporting mathematics. It gets confusing when both wind and solar are applied, but my understanding is it would be averaged not added. A typical grid would have 50/50 wind at 35% CF & solar at 25% CF (30% combined, not 60%). Texas currently has much more wind than solar, but I get the impression that’s changing. I have a lot of Texas grid and “Pollack Limit” on my hard drive-available on request.

Reply to  Dennis Gerald Sandberg
March 6, 2023 6:44 am

You said: “Texas has already had a massive “grid destabilizing cold weather event” and a couple near-miss hot weather events, directly attributable to an over-reliance on wind.”

Winter Storm Uri’s failures were first order due to natural gas plants not performing in both peaker and base load contractual basis. I would agree that the weatherization is very possibly due to over-emphasis on wind and solar PV, but wind and solar PV were neither expected to contribute a large percentage of generation capacity during that period of time unlike the natural gas plants.

So your statement above is factually wrong.

Nor is your “near miss” statement correct either. The Texas grid – both intermittent and dispatchable – successfully delivered more power to the grid to meet record demand – demand greater than California and New York combined on those days – including both solar PV and wind.

I would lastly note that the 30% overall generation from intermittent has been the story for a number of years now. It is working because Texas has massive natural gas base load and peaker capability – if you look at 60 day curtailments as compiled here (, natural gas is also curtailed along with wind and solar PV. Arguably, Texas may have some level of solar PV and wind overbuild…

So again: the problems posited by this article are very likely but not at the 30% levels presently in ERCOT/the Texas grid. If a grid doesn’t have the massive natural gas backbone like Texas has, it is possible that the supportable level of intermittent is lower but the reality is that we don’t know yet.

And that statement alone is NOT what legislators, consumers and grid operators should find acceptable.

Trying to fight disinformation via ignorance and/or misinformation in return just muddies the water for everyone.

It doesnot add up
Reply to  c1ue
March 6, 2023 11:19 am

The first order problem was having insufficient dispatchable capacity to meet demand. Result: no reserve margin, frequency erosion and a cascading trip that knocked out all sorts of key points when automated load shedding kicked in. Bad grid management by ERCOT.

Reply to  c1ue
March 6, 2023 10:08 am

Don’t be so timid. We can say there is enough supporting evidence, the capacity factor of a renewable energy schema approximates the maximum penetration before the system is destabilized. i.e, if the capacity factor for solar in a grid area is 20%, then a 20% solar capacity is the max before the grid costs start to skyrocket with no benefit, and burgeoning instability causes reliability issues.

Reply to  Dennis Gerald Sandberg
March 6, 2023 8:58 pm

Dennis, we need a graph of this functionality.

Ronald Stein
March 4, 2023 2:34 pm

Climate Child labor- Who cares?

Wealthy countries mandating green electricity encourage humanity atrocities in developing countries! Subsidies to buy EV’s and build wind turbines and solar panels are financial incentives to continue exploiting people of color in developing countries.

Reply to  Ronald Stein
March 5, 2023 8:56 am

IMHO we would be more humane to have a giant squirl cage and have the children walk in the cage in four hour shifts.

Forrest Gardener
March 4, 2023 2:51 pm

Very good and careful explanation but I find I can only hold a few acronyms in my head at any given time. So by the time I got to the last part where “IVREs are inherently unreliable” I had to ask myself what that acronym stood for.

It may be that the inherent complexity is what makes decision makers make such stupid decisions. Or perhaps it is what enables them to make stupid decisions confident they will never be held accountable.

Last edited 22 days ago by Forrest Gardener
Steve Case
Reply to  Forrest Gardener
March 4, 2023 3:07 pm

There are people in this world, way too many of them, that seem to think that peppering their prose and speech with undefined acronyms makes them look smart.

Reply to  Forrest Gardener
March 4, 2023 4:40 pm

I find myself asking WTF more often.

Reply to  Scissor
March 4, 2023 8:00 pm

Nothing beats a good TLA.

Reply to  Forrest Gardener
March 5, 2023 12:40 am

If you noticed, I gave the definition of each acronym term at first use in the article. This practice is commonly used in contractual correspondence.

I used so many acronyms because writing out the descriptors instead would have made a long article way longer.

Forrest Gardener
Reply to  BLS1965
March 5, 2023 4:08 am

I intend no criticism of your writing and you are right about the need for acronyms. It’s just the topic is quite complex.

Reply to  Forrest Gardener
March 5, 2023 8:01 am

The author gave the definition at the beginning of part one of this series.

March 4, 2023 3:36 pm

Guaranteed Demand: mandates require EMMs to buy electrons from EP-IVRs in front of all other EPs, ensuring that EP-IVRs sell every electron they can produce

Guaranteed minimum pricing: EP-IVRs are guaranteed a minimum price for every electron they can sell, affecting how much ECLs or ERs must pay to EP-IVRs over other EPs

Neither of these points are true in the Australian electricity market. Economic curtailment of grid W&S is a regular feature in the Australian market. They cannot tolerate a negative price greater than their subsidy because they have no way of guaranteed recovery so they stop generating for economic reasons.

The network operators have also developed distribution control protocols that take rooftop PVs out of the market if the grid stability is at risk.

Sunday 0930 on the Australian east coast and all grid scale W&S generators are into economic curtailment because the price in every region is negative – per attached.

As more grid W&S connect, the capacity factors of existing generators are coming down due primarily to economic curtailment.

There is enough small scale rooftop PV to saturate the grid in two States at lunchtime and all mainland states are heading the same way.

Screen Shot 2023-03-05 at 10.28.48 am.png
Nick Stokes
Reply to  RickWill
March 4, 2023 4:04 pm

Negative prices can’t last. Someone will get a big resistor and happily pay the negative price.

But better uses will be found. Aluminium smelters will be smiling. In fact, I see that Alcoa is restarting the potline tht has been idle since 2009.

Reply to  Nick Stokes
March 4, 2023 4:53 pm

Imagine the aluminum smelter reliant on RE … it’ll be shutdown again for another 3 years whilst they repair the damage.

Nick Stokes
Reply to  Streetcred
March 4, 2023 5:03 pm

No, they aren’t reliant on RE. And Victorian power is on all the time. But Al smelters are great for soaking up electricity when it is cheap. That is why it was built in Portland in the first place. The SECV offered a good deal on electricity at night, when they wanted to keep the coal generators going, but there was little other demand.

Reply to  Nick Stokes
March 4, 2023 6:05 pm

As usual Nick tells half the story and tries to pretend that he’s given you all the relevant information.
Yes, Al smelters do try to cite themselves where ever electricity is cheap. So do all companies, for that matter.
However another factor that is 100% vital for Al smelters is that the electricity must be reliable. If the power goes off and the what is in furnace solidifies, it will take dynamite to fix the problem.

The dams along the Columbia river are all short. Because of this they can’t store much water behind them. The water is either used to create electricity or it has to be released to flow around the dam.

It doesnot add up
Reply to  Nick Stokes
March 4, 2023 7:06 pm

Aluminium smelters must have reliable supply. They can tolerate short periods of reduced supply, but frequent loss of power for economic or shortage reasons is not a sustainable way to run a smelter, especially if the outage risks lengthening to several hours or more. Just having cheap intermittent power is not good enough.

Nick Stokes
Reply to  It doesnot add up
March 4, 2023 8:46 pm

As I say, Alcoa has been working for 40 years without dynamite; Victorian power is reliable. But it varies in price. Getting cheap electricity is very important to their economics, and there is enough thermal inertia in the pots that they can take a rest during daily peak prices, and do very well when they are low. They have been doing that for 40 years too.

Reply to  Nick Stokes
March 5, 2023 8:02 am

ALcoa uses hydro energy, not renewable energy. Big difference that you once again gloss over.

Nick Stokes
Reply to  MarkW
March 5, 2023 12:02 pm

As I said, in Victoria Alcoa used mostly coal energy. They even had a coal mine. But whatever the source, the key thing is that the smelters can soak up electricity when it is cheap. That’s the way they work.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 2:10 pm

As I said, aluminium smelters require reliable power. If they don’t get it, they close, however cheap intermittent power might be. I have reviewed the power contracts for several smelters, so I think I know more than you do about the basis on which they are negotiated.

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 2:19 pm

And as I said, Alcoa has operated in Victoria for forty years and the power has never failed. What matters to them is the cost of the electricity. They love negative prices.

That is why, after many years, Alcoa Portland is expanding.

Reply to  Nick Stokes
March 5, 2023 4:33 pm

The power has never failed because prior to now, there was no, to very limited renewable power in the mix.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 5:28 pm

Alcoa secured a series of guarantees on electricity supply and pricing in a new contract, and a not insubstantial contribution of AUD38.4m a year from Federal and State government towards their costs of participating in RERT. They seem to have learned from the renewables industry that you should apply to the government for subsidy. A reliable and cheap supply is essential to them.

Tomago Aluminium chief executive Matt Howell is no renewables sceptic: the man running the country’s biggest power user has rooftop solar at home and says anyone who can afford it would be crazy not to.
But for the smelter covering a vast tract of land north of Newcastle and employing 1100 people, switching to renewable energy remains a very distant prospect.
“There’s no question you can have a smelter run by batteries and renewables: wind and solar,” Howell says from the boardroom of Australia’s largest aluminium smelter, just metres from the three, kilometre-long potlines that churn out 1 per cent of the world’s supply of the lightweight metal.
“But you’d be bankrupt, you can’t make money from it.”
Howell has fielded approaches from wind and solar developers on the hunt for an industrial customer that could underpin their projects. But the typical offer approaching $45 a megawatt-hour only applies when the plant is generating, so is no use for a plant needing 950 megawatts of power around the clock.
At the going rate of $70/MWh for “firmed” renewables – typically wind or solar backed up by gas power – Tomago “doesn’t have a future,” he says.
Howell says the plant’s three potlines have a three-hour window when they can do without power, but any longer than that and the cells – where the electrolysis that is central to the smelting process takes place – solidify.
“When they freeze in an uncontrolled manner … that’s it, they’re gone, finished,” says Howell, who puts the smelter’s replacement cost at $5 billion.
“And you don’t restart an aluminium smelter.”
Reliable electricity supply, then, is a “mission critical issue” that comes at an annual cost of “hundreds of millions” of dollars. While the plant’s power contract with AGL Energy lasts until 2028, Howell is worried about what comes next, especially with dwindling baseload capacity when AGL’s Liddell coal plant shuts in April 2023.

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 6:56 pm

“But you’d be bankrupt, you can’t make money from it.”

Looks like things have changed. From Tomago itself:

Tomago Aluminium’s primary energy contracting objective is to fully decarbonise the smelter through sourcing electricity supply from renewable sources and energy storage technologies, ideally by 2030.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 7:01 pm

As you well know that is simply greenwash, and only enabled by distorting markets and pretending that renewables supply you when they don’t. Tomago will close the first time Victoria has a blackout that kills its potlines.

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 9:13 pm

that is simply greenwash”
It is a clear statement of policy, made in a pitch to investors. If they really believe it will send them bankrupt, that should land them in a court, somewhere.

Tomago is in NSW.

It doesnot add up
Reply to  Nick Stokes
March 6, 2023 6:50 am

Selective quotation.

Matt Howel, CEO of Tomago, told the Australian Financial Review: “Our goal would be, by 2029, that the largest load in Australia is, for all intents and purposes, 100% renewable. There’s further improvements on the cost of the equation to go before firmed renewables is a viable option for us, but we are perpetually optimistic; I think we will get there.”

In other words they have yet to nail down the subsidies. Also, it’s “firmed renewablex” I.e. with gas backup.

Reply to  Nick Stokes
March 5, 2023 4:32 pm

Nick really is an expert at changing the subject whenever he finds himself losing an argument.

Reply to  Nick Stokes
March 4, 2023 5:05 pm

Funny Nick.
While others here post details of what is ACTUALLY happening in the real world today, you’re usually posting conjectures about what’s MAYBE GONNA HAPPEN HOPEFULLY one day.

It’s a bit like socialism / communism –
next time it’s definitely gonna work without causing the deaths of millions of citizens.

Reply to  Nick Stokes
March 4, 2023 5:56 pm

You are correct that negative prices can’t last.
However in the here and now negative prices are a blindingly clear indicator that there is a problem in the system. It usually means that renewable energy plants are producing power that nobody wants or needs.

Reply to  Nick Stokes
March 4, 2023 6:01 pm

Negative prices can’t last. 

Negative prices will last as long as there are subsidy payments. LGCs are currently running at AUD64/MWh. Subtract some cost of FCAS that W&S are paying and they are making money at minus AUD40/MWh. They are adjusting their generation to level to just make money after payment for LGCs produced.

There will need to be some form of subsidy beyond the expiry date of the current RET, which ends in 2030. So I expect negative prices will remain a common feature as it is a means of forcing grid W&S curtailment.

Lunchtime Sunday, and all mainland States are curtailing grid W&S. East coast price all around minus AUS20/MWh and WA at minus AUD40/MWh. Tasmania at positive AUD11/MWh.

Some retailers are offering zero cost lunchtime energy, 10am to 2pm, on the east coast. But all those dormitory suburbs pump out electricity when there is no one home to consume it. So even free energy is not going to encourage much more use.

Nick Stokes
Reply to  RickWill
March 4, 2023 8:18 pm

Negative prices will last as long as there are subsidy payments.”

No, you missed my point about competition from buyers. Being paid to use electricity is just too good a deal. They will bid up the price. S&W may increase output, but that then tangles with the target, and will bring down the price of LGCs.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 2:11 pm

The reason prices go negative is because it is too expensive to make use of highly intermittent, very variable surpluses. Learn some economics.

Last edited 21 days ago by It doesnot add up
Reply to  Nick Stokes
March 5, 2023 12:54 am

Lol Nick, any aluminium smelter operator that would trust a government claim on IVRE power availability is not long for his position in his or her company’s food chain 😉

PS: I’ve worked in aluminium smelting. How about you?

Nick Stokes
Reply to  BLS1965
March 5, 2023 1:31 am

In Victoria, at least, power is always available, at a price. If the wind fails, then the penalty for Alcoa is not that their pots will freeze. It is that they will have to either pay more for a while, or cut back their current use. Fortunately, they can do a lot to cut back their current use (and still keep the pots liquid).

Tis isn’t theoretical. When Alcoa came to Victoria, the Gov’t gave considerable help. Their first priority was that Alcoa would use electricity mainly at times of low demand in the daily cycle. That made our coal generators much more economical. The second, not widely publicised, was that Alcoa would agree to cut back during acute power shortages. In early days that was often industrial action. Later it was mainly generator breakdowns or hot days (A/C). This has all worked well.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 3:02 pm

You know nothing about the Alcoa contracts. I can guarantee they will not have been negotiated on the basis of hourly variations in market prices for power. What Alcoa have done is to participate in RERT, with Federal and State governments coughing up AUD38.4m a year to do so. The full terms are not disclosed, but given the way RERT operates they may include giving ample notice of a major shortfall that would see the potlines shut down, potentially with plant closure if reliable power cannot be obtained (e.g. following the closure of a major coal generator), as well as offering periods of typically 2 hours, but on occasion up to four hours of sharply reduced offtake to help with demand peaks. There will be limitations on the frequency of such events.

Participation in RERT precludes participation in wholesale markets under AEMO/AEMC rules, which is one reason I can guarantee that Alcoa do not have a wholesale price responsive operation.

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 3:42 pm

Participation in RERT precludes participation in wholesale markets”

Just not true. Here is a submission to the ACCC from the smelter at Tomago, which is in RERT

“Tomago is a wholesale customer in the National Electricity Market (NEM) and has power supply and transmission contracts in place until at least 2028. Approximately 5% of Tomago’s electricity requirements are currently exposed to the NEM spot price. “

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 5:14 pm

The letter you cite is from 2017, and does not necessarily reflect the current rules, which were last modified in 2019. I did not make the claim without being quite sure of it.

The current rules are quite explicit. Here is the chapter and verse from AEMC:

When AEMO seeks reserve providers it must comply with the out-of-market provisions set out in clauses 3.20.3(g)-(l) of the NER. These provisions serve to minimise the distortionary effect of the RERT on the market. Under these provisions:

• Scheduled reserves cannot participate in RERT if they have been in the wholesale market in the 12 months preceding the date of execution of the reserve contract. Scheduled reserves also cannot participate in the wholesale market for the duration of the contract.

• Unscheduled reserves cannot participate in the wholesale market and in RERT for the trading intervals to which their contract relates.

It doesnot add up
Reply to  RickWill
March 4, 2023 7:08 pm

Australia is well on the road to the point where renewables cannabalise their own revenues, as well as everyone else’s including the grid, and the whole system collapses economically.

Nick Stokes
Reply to  RickWill
March 4, 2023 8:51 pm

Here is a fun version of your prices, at 3.40pm. They need better interconnectors:

comment image

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 5:35 pm

NSW needs more dispatchable capacity.

Reply to  Nick Stokes
March 6, 2023 2:12 am

Nick, I think the question you need to answer is more general. People can argue about various details of how the Australian energy system works and is paid for.

In the end though the question is, what do you believe the role of wind, solar, coal, nuclear, gas ought to be?

You obviously think that wind is an important and viable part of the mix. Not sure what you think of solar. So what percentage of generation do you think the evidence suggests can be done by wind? And what will the other components be?

A second question would be, do you think in a fully deregulated market wind operators would erect wind farms, and do you think their supply would find customers at a price which will give them a return?

The latest wailings and demands for subsidies from the UK wind bidders suggest otherwise, and I have never seen a study showing financial viability in a deregulated world. But if you think it, say so, and say why.

I’m looking as a for instance at yesterday in the UK. Wind varied between 1.3 and 3.1GW. This is in a demand environment of around 40GW, and on a wind installed base of 28GW. This was for a bit over a day. Weeks of generation of less than 5GW are quite common. Not fit for purpose.

The onus is on anyone who believes this is a viable technology to explain why.

Nick Stokes
Reply to  michel
March 6, 2023 4:15 pm

“In the end though the question is, what do you believe the role of wind, solar, coal, nuclear, gas ought to be?”
I think the broad outlines are clear. Wind and solar have now fairly small capital costs and no fuel cost (and no CO2 emissions). That is too good to pass up, and will be used somehow. In the bidding they displace other generators. But of course, they are not dispatchable.

Coal is still relatively cheap, but is also not very dispatchable either. It is troublesome to turn on and off. So with fuel cost, that makes it a pretty bad option, and the decider is that no-one wants to put up the substantial funds to build a new plant.

Nuclear is declining; the basic reason is that no-one has figured out a way of dealing with waste that people will accept. It’s also very hard to get a new one built, and few want to try.

Gas, for now at least, is what will work on a windless night. It is the source that is nearest to fully dispatchable. But fuel is expensive. It will certainly have a continuing role.

I’m surprised that people here have so little faith in markets. They are very good at sorting out the balance of these things. When wind is available, wind competes with wind, and electricity is cheap. When not, then gas competes with gas. A price will be set that keeps gas in business, for the usual economic equilibrium reasons.

Eventually, gas will recede. There will be better interconnectors, bringing wind or solar from far away. There will be pumped hydro, to mop up the wind surpluses. Not in Denmark, it’s true, but that is where the good interconnectors come in. And maybe further down, hydrogen by electrolysis.

old cocky
Reply to  Nick Stokes
March 7, 2023 1:35 pm

I’m a bit late to the party, so everybody has probably gone home by now…

Coal is still relatively cheap, but is also not very dispatchable either. It is troublesome to turn on and off. So with fuel cost, that makes it a pretty bad option, and the decider is that no-one wants to put up the substantial funds to build a new plant.

It’s not so much the fuel source as the response times. Coal is typically used to heat water for steam turbines, with quite slow response times – the assumption is they will be working near capacity for extended periods, so they are optimised for this.
Gas or diesel are typically used for quicker response systems, such as OCGT, CCGT or reciprocating engines. Could pulverised coal be used for turbines? There wouldprobably be too much blade erosion, but it may be possible.

There will be pumped hydro, to mop up the wind surpluses.

That’s probably what will eventually compensate for wind power being so erratic, but it requires suitable geography, has long build times and faces serious regulatory hurdles

Nick Stokes
Reply to  old cocky
March 7, 2023 2:18 pm

On Hydro, the Snowy 2.0 will go quite a long way. But virtually any existing hydro can be adapted; ours are limited by river flow, but doesn’t matter for pumped. Even the ancient Rubicon Hydro would be useful. It has an adequate top dam, a clearway for pipes, a generating station. All it needs is a bottom pondage, bigger and more pipes and more generators. And pumps, of course.

old cocky
Reply to  Nick Stokes
March 7, 2023 2:40 pm

Tho bottom pondage may well be the limiting factor in most cases. The reservoirs tend to be built at the spot where the most water can be readily held back, and there’s really sod-all available downstream.

old cocky
Reply to  old cocky
March 7, 2023 2:53 pm

On further thought, there may well be scope for hydro-electric generation with the inland stock/irrigation water supply dams
a) used for pumped storage with relatively small bottom pondage
b) just plain hydro during releases for downstream agricultural water supply and also environmental flow releases.

The city water supply dams such as Avon, Cordeaux, Cataract, Nepean and Warragamba probably have hydro potential as well (if not much pumped) because they have rather regular release rates. Prospect Reservoir might be a decent bottom pondage for them as well.

Allan MacRae
March 4, 2023 3:49 pm

There never was any scientific or technical support for the CAGW and Green Energy scams – it’s always been false propaganda – wolves stampeding the sheep for political and financial gain. The cost to society of this Climate scam is measured in tens of trillions of squandered global resources and hundreds of billions of wasted lives. Nuremberg 2.0!

My co-authors and I wrote the following correct observations in 2002;
1.   “Climate science does not support the theory of catastrophic human-made global warming – the alleged warming crisis does not exist.”
2.   “The ultimate agenda of pro-Kyoto advocates is to eliminate fossil fuels, but this would result in a catastrophic shortfall in global energy supply – the wasteful, inefficient energy solutions proposed by Kyoto advocates simply cannot replace fossil fuels.”
– by Sallie Baliunas (Astrophysicist, Harvard-Smithsonian), Tim Patterson (Paleoclimatologist, Carleton U), Allan MacRae (Professional Engineer, retired (Queen’s U, U of Alberta)
Allan MacRae, B.A.Sc.(Eng.), M.Eng., Calgary

Allan MacRae
Reply to  Allan MacRae
March 4, 2023 5:15 pm

typo: delete “hundreds of”

Nick Stokes
March 4, 2023 3:51 pm

Conversely, due to “first-use mandates,” if capacity at EP-IVRs is actually higher than predicted (due to there being more wind or sun than forecasted), the EMM must require ECLs and ERs to buy from the EP-IVR first, when buying directly from the EMM.”

There he goes again, spelling out his supposed first use mandate. I asked in Part 1 if anyone knew of a system where this actually happens. No-one could name one.

  • Subsidies: often a combination of cash, favorable loans, and tax breaks
  • Guaranteed Demand: mandates require EMMs to buy electrons from EP-IVRs in front of all other EPs, ensuring that EP-IVRs sell every electron they can produce
  • Guaranteed minimum pricing: EP-IVRs are guaranteed a minimum price for every electron they can sell, affecting how much ECLs or ERs must pay to EP-IVRs over other EPs

Again, no indication of what jurisdiction these might apply in. Subsidies are vague. Guaranteed Demand more or less corresponds to the renewable obligation, which the UK discontinued in 2017 but still happens in Australia. But Guaranteed minimum pricing? Really? It’s true that the UK replaced ROs with CfD, which do guarantee a set price. But that is a commercial arrangement, where the counter-party also collects the upside, which makes it attractive. In fact the UK counte-rparty LCCC is currently doing very well on the deal, to the extent that they are now looking at negative levies.

Reply to  Nick Stokes
March 4, 2023 5:26 pm

Nick, if you had spent all of your working career in private sector business (as I and many others here have done), you would appreciate that there is only one outcome that makes any venture worthwhile or sustainable –


Which in the case of ‘renewable energy’ enterprises, that would be reliably, consistently supplying customers with affordable electricity at stable cost, non-reliant on any special public funding contributions.

On this score, ‘renewable energy’ enterprises all around the world are failing miserably.

Nick Stokes
Reply to  Mr.
March 4, 2023 9:04 pm

On this score, ‘renewable energy’ enterprises all around the world are failing miserably.”

The bottom line is that they are going from strength to strength, They are everywhere. People seem to have a different bottom line.

Reply to  Nick Stokes
March 5, 2023 1:21 am

Siemens’ Gamesa Wind Turbine Unit Struggles to Generate Profits
20 February 2023

After a disastrous first quarter highlighted by failures at its Gamesa wind turbine location, Siemens indicated it anticipates little change to its 2023 bottom line. This announcement caused shares in their Energy division to decline on Tuesday.

There were initial questions around the quality of Siemens wind turbines, putting pressure on the company to spend more than €500 million in Q1 last year on their Siemens Gamesa Renewable Energy unit and foot increased future costs for maintenance.

Following this, their overall revenue loss shot up to almost twice its 2022 figure, from €246 to €598 million.
It hasn’t been an easy ride for the Gamesa renewable energy spin off since 2020.

They were dominated by the company’s other divisions in Q1, which produce steam turbines for traditional power plants and equipment for energy transmission networks.

Revenue increased by 22% and profit increased by more than 50% for the Gas Service part of the business, 

Nick Stokes
Reply to  SteveG
March 5, 2023 2:12 am

Yes, EU wind turbine makers are getting competitive pressure from China. But plenty of wind turbines are being made.

comment image

Dave Andrews
Reply to  Nick Stokes
March 5, 2023 8:32 am

In Europe 38GW of wind will reach the end of it’s normal operating life by 2025. Same applies to other installations elsewhere 20 — 25 years old.
A coal plant can easily operate for 50years.

Last edited 21 days ago by Dave Andrews
Dave Andrews
Reply to  Dave Andrews
March 5, 2023 8:48 am

That’s 38GW of onshore wind

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 3:29 pm

We are now in 2023. The kink in the curve reveals that less capacity was added in 2021 than in 2020 – in fact, 17.4GW less. The EU installed just 16GW in 2022. Globally the industry has been running into headwinds, with rising costs, not least for financing. The Inflation Creation Act will of course provide some boost to US investment, but that will take time to take effect. Meanwhile in the UK the AR4 wind farms scheduled to be built in the next few years are now in doubt because they would be unprofitable, with the industry begging for extra subsidies. The problem will also affect the AR5 auction scheduled for later this year, where the administrative strike price cap has already been set at too low a level, and with tightened terms on the contracts they are not fungible into FID decisions.

Reply to  Nick Stokes
March 4, 2023 6:06 pm

Nick asked in part 1, and was answered in part 1.
Once again no matter how many times his whines are responded to, Nick Sophist will pretend that people are ignoring his questions.

It doesnot add up
Reply to  MarkW
March 4, 2023 7:39 pm

He ignores all the answers. Does he need a trip to Specsavers? He appears to be incapable of reading, let alone marking and inwardly digesting. An automaton without intelligence.

Nick Stokes
Reply to  MarkW
March 4, 2023 9:48 pm

You keep evading the question. Bill Schneider has made a specific, central claim. Here is the new, more detailed wording
“Conversely, due to “first-use mandates,” if capacity at EP-IVRs is actually higher than predicted (due to there being more wind or sun than forecasted), the EMM must require ECLs and ERs to buy from the EP-IVR first, when buying directly from the EMM.”
If these first use mandates exist, it must be possible to point to a grid somewhere that uses them in the way described. Where is it? No-one can say.

Reply to  Nick Stokes
March 5, 2023 8:05 am

Directly answering the question is evading it?

Nick Stokes
Reply to  MarkW
March 5, 2023 11:57 am

The question was, “Where is it?”. What is the “direct answer”?

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 3:35 pm

It applies in every grid subject to EU regulation, as I have already pointed out to you several times. There is a requirement to maximise renewables. That must mean they get priority dispatch, however it is achieved (and the detail on that does vary depending on the details of local regulation to implement the EU Directives).

Reply to  Nick Stokes
March 4, 2023 6:39 pm


Most, or all, Independent System Operators (ISOs, who manage power grids) in the U.S. dispatch energy based on price. This means wind and solar get dispatched first because they have no cost of fuel (and lot of subsidies) so they can produce the cheapest electrons. So, yes, they do get preferentially dispatched. That is to say, there is a first-use mandate.

Subsidies are not vague, they are numerous. When a friend of mine put SunRun solar panels on his roof some years ago, I counted some six different state (California) and federal subsidies that SunRun was taking advantage of to put the “free” panels on his roof. I also calculated that if we used similar subsidies to reduce the U.S. carbon use to zero, it would cost around $50 trillion dollars, assuming the technology existed to make the transition possible: it doesn’t.

Nick Stokes
Reply to  Thomas
March 4, 2023 8:24 pm

So, yes, they do get preferentially dispatched. That is to say, there is a first-use mandate.”

No, a mandate is a mandate. You are describing a competitive success. As you said, they produce the cheapest electrons. What alternative dispatch priority do you think ISOs should use?

Dennis Gerald Sandberg
Reply to  Nick Stokes
March 4, 2023 10:05 pm

Competitive success? South Australia claims 70% “renewable” Why not take it from the grid and get the price down. Call it what you want but it’s a mandate.
Australian Electricity Prices per kWh by State
Electricity usage rates vary from state to state, and even within different parts of the same state. There are a number of reasons for this, but for the purposes of this article it’s enough to know that the average price of electricity per kWh in Victoria won’t be the same as in NSW. Below, we’ve listed the typical electricity usage rates across QLD, VIC, SA and NSW. This was done by calculating the average usage rates of flagship market offer contracts from five leading electricity retailers – AGLOrigin EnergyEnergyAustraliaRed EnergyAlinta Energy. Prices are shown in cents per kWh.


Average Electricity Usage Rates (per kWh)









Prices based on single rate electricity tariffs for selected postcodes in each state, January 2023. 

Iain Reid
Reply to  Nick Stokes
March 5, 2023 12:03 am


the cheapest electrons refers to the company’s cost; due to the other costs that are incurred in using this ‘cheap’ electricity’ the consumer pays very dearly. That is the important cost, the overall system cost not a generator’s cost.

Wind and solar require an equivalent amount of reliable and instantaneously available alternatve generation, which some time has to run very uneconomically but must be paid for as it is essential generation. It provides balancing and inertia and could run the grid alone. the cost of building and running wind and solar is on top of that cost. It’s finacially and technically crazy.

Nick Stokes
Reply to  Iain Reid
March 5, 2023 1:06 am

The rules for operating a grid are usually to take the lowest bids. You don’t want a market operator to be evaluating the “overall system cost” in deciding bids. What markets do well is to match the diverse needs of a heterogeneous group of buyers and sellers, and it works through price alone. Not all buyers do want an evenly priced supply 24/7. Many can adapt to use cheaper electricity when it is available, and the market can accommodate them. That does make some extra costs for “reliables”, and they will recover that through higher prices when “unreliables” are doing their thing. There is a question (never answered properly here) as to whether those costs added up outweigh the fuel savings of W&S. But there is another equity aspect. The market makes users who demand electricity at those times pay the costs, and there is considerable fairness about that.

I’m sure someone will wail about Granny freezing when the wind isn’t blowing, but Granny isn’t buying in the spot market. Retailers smooth this out, as they should. The big boys can handle a proper allocation of costs.

Last edited 22 days ago by Nick Stokes
Reply to  Nick Stokes
March 5, 2023 6:45 am

Nick, A rule that puts wind and solar first in line is the same as a mandate. They are only cheaper when the subsidies, tax breaks, and the cost of backing them up with reliable power are ignored.

California just past a law that limits the amount of money paid for power generated by roof top solar because, “Customers with rooftop solar depend on the … grid to use electricity when their rooftop solar systems are not generating electricity. The compensation that (solar) customers receive is greater than the value of the energy.”

Even the very liberal California Congress realized that solar has been getting a free ride and that hurts the average consumer, particularly poor folks who can’t afford rooftop solar but have been forced to subsidize, through higher rates, the solar panels of the rich.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 3:49 pm

Originally OFGEM was charged with regulating in the interests of consumers. In 2010 that was formally changed in law, under Ed Miliband’s 2010 Energy Act, to give primacy to green interests, which are always deemed to be in consumer interests. i.e. the consumer interest in cheap and reliable power was legally sidelined.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 3:41 pm

The mandate is either to formally put renewables first in the merit order regardless of true merit, or to rig markets to achieve that result, in order to maximise the use of renewables which is the formally mandated objective. That is what is achieved by a feed in tariff, per MWh subsidies and CFDs (which allow the lucky holders to undercut other generators to set “market” prices and still get compensated at the CFD strike price).

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 5:12 pm

No-one has shown the existence of such a formal rule. \and I do not believe that any EU law imposes an obligation to rig markets.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 7:09 pm

I have quote it to you at least half a dozen times, complete with origin.. The EU imposes lots of obligations to rig markets. It does it all the time, with quotas, requirements for taxes and subsidies, technical rules. It’s the raison d’etre of most of the Berlaymont. The rule is quite clear. Tell me how you maximise use of renewables without giving them priority via one mechanism or another, and I’ll tell you you don’t understand “maximise” as a mathematical term.

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 9:09 pm

You keep quoting EU waffle, when I keep asking for an actual rule, by a grid, anywhere, which says that bids from renewables get priority.

It doesnot add up
Reply to  Nick Stokes
March 6, 2023 8:34 am

It is the LAW.

Back in 2016 there was concern because the EU bureaucracy actually gave consideration to removing grid priority for renewables in favour of a more properly competitive system. Lobbying duly ensured that the provisions to maximise renewables remained.

More regulatory detail

Accept you are WRONG.

It doesnot add up
Reply to  Nick Stokes
March 4, 2023 7:34 pm

Nonsense. You were quoted chapter and verse, and here you are pretending it never happened, and trying to pretend that directives calling for renewables to be maximised didn’t mean they had priority on dispatch subject only to grid constraints.

Moreover, you have ignored being told that the Renewables Obligation is still very much in operation. It is only closed to new capacity. The market operates to guarantee CFD producers a sale in almost all circumstances. The only case where that is not working is for the portion of Drax plus Lynmouth because of the crazy way in which the baseload reference price is set. However, the other units at Drax operating with ROCs are busy collecting subsidies. There is nothing particularly attractive about UK CFD prices, and indeed we are back in the territory where CFDs are collecting subsidies after the the price spike evaporated. Offshore wind has continued to rake in subsidy over the past two quarters.

Incidentally, you appear not to understand the OFGEM decision and how the system of CFD payments works for retailers. OFGEM’s decision relates to how they calculate their now largely redundant retail cap (since it is government subsidy that sets the real cap on prices paid by consumers, quite outwith the OFGEM calculation). Retailers are expected to fund CFD payments to generators in advance, and are reimbursed for overpayment in a post quarter end reconciliation. When generators are due to pay retailers, the advance payments are set to zero, and the retailers do not get their money until after quarter end. The OFGEM decision is that they will reudce the retial cap to reflect what retailers get paid after the quarter end in the event of high market prices. That dealt with the specific circumstances of the price spike last summer, but has not applied since.

Nick Stokes
Reply to  It doesnot add up
March 4, 2023 9:01 pm

trying to pretend that directives calling for renewables to be maximised didn’t mean they had priority on dispatch subject only to grid constraints”

I’m not trying to pretend. They just aren’t the same. You claim that because they have been tasked to maximise renewables, therefore they would take a certain action (grid operators would mandate first use). But the test of that is whether it actually happened. And no-one has an example of a grid that does that. In fact, thinking you were reproving me, you pointed out that grid operators are not purchasers, as claimed by Schneider.

It is only closed to new capacity.”
Wind power capacity went from 19387 MW in 2017 to 28537 MW in Q3, 2022. So already about a third are not on RO, and of course increasing.

“Incidentally, you appear not to understand the OFGEM decision”

From the decision
“3.15. We consider that if we do not remove the £0/MWh floor there will be material and systematic impacts, as customers would not see lower bills when suppliers are forecast to experience negative CfD costs.”

“3.18. In addition, the current CfD cap allowance is bound at £0/MWh and there is a negative payments profile forecast for cap period eight overall. We expect that there is currently a one-off benefit that suppliers could be receiving that is not accounted for in the allowance and which could net off cost increase concerns for cap period eight.”

They expect the flow of funds to go to retailers, and want to see that that is not delayed.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 4:29 pm

As I previously explained, retailers only get recompensed for any net payment by CFD generators in arrears after the end of the quarter. There is no adjustment to the rules for payments from the Low Carbon Contracts Company as the CFD counterparty to retailers. The Interim Levy Rate (payments on account) has a floor of £0.00/MWh, and the LCCC also retain a cash reserve funded by retailers known as the Total Reserve Amount, which is effectively a collateral payment that varies with the risk that market volatility could result in increased needs to compensate generators, and has never been eliminated even during the price spike when the risk was minimal. The OFGEM decision is to impose an added cashflow penalty on retailers via their calculation of the cap, by estimating what recompense they might get after the end of the quarter before the sums are actually known. It is a politically inspired attempt to massage the retail price cap down in the short term. Of course, longer term it will have no effect, because there will be no corresponding reduction after the quarter end to be accounted for in the next cap calculation. It also has no effect when the ILR is set at a positive value – as it now is – because CFD generators are going to be paid by consumers.

The Renewables Obligation closed to new applications in 2017. However, capacity subject to ROs continued to be added throughout 2018, and in one case where construction was delayed, as late as 2021. So your figures are not correct, and your original post implied that ROs no longer exist at all. They are still very important consumers of index linked subsidies, which will only decrease when the subsidies or the wind farms themselves expire. They are also very important in the price setting process at times of surplus, as their subsidies determine the extent of negative pricing.

I refer you to my answer up thread, explaining why all grids subject to EU law run an effective renewables priority system in order to meet the mandate to maximise renewables, You need to explain how it fails to do so to have any kind of counter argument.

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 5:09 pm

I refer you to my answer up thread, explaining why all grids subject to EU law run an effective renewables priority system in order to meet the mandate to maximise renewables,”

No, you explained why you thought an EU exhortation might induce them to impose such a rule. What no one has ever done is show an actual system which has imposed such a rule.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 7:12 pm

It is an EU REGULATION – a LAW that REQUIRES renewables be maximised.

I have shown you that all the EU grids and local markets faithfully follow that law by running systems that do indeed maximise renewables. You have failed to show that they do not – and you cannot, because the law is followed and implemented.

Iain Reid
Reply to  Nick Stokes
March 4, 2023 11:56 pm


The Contracts for Difference contracts are badly written and some wind companies are not taking up their contracts but selling at market price, which is higher than their contracts. There have been some very silly Contracts for Difference bids which are significantly lower than their capital and operating costs.

Nick Stokes
Reply to  Iain Reid
March 5, 2023 12:35 am

some wind companies are not taking up their contracts but selling at market price”

Yes. CfDs are a gamble by both sides, and lately the LCCC has been winning. Staying away from them is very sensible.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 4:32 pm

The LCCC is neither a winner nor a loser. It is simply an intermediary, taking money in and paying it out again, and calculating amounts due in accordance with a set of rules. The losers have been and continue to be consumers.

The other main responsibility of the LCCC is as the CFD counterparty to ensure that generators are held to their contracts – which do not include commencing the CFD when the operation is commissioned.

Last edited 21 days ago by It doesnot add up
Nick Stokes
Reply to  It doesnot add up
March 5, 2023 5:05 pm

It is simply an intermediary, taking money in and paying it out again”

Sounds like there is plenty of scope for winning or losing there. In fact they pay money out when the market price is below the strike price, and take it in when it is above. And in high price times, they are mainly taking it in. Which is why wind generators now have cold feet about CfDs under their terms.

It doesnot add up
Reply to  Nick Stokes
March 5, 2023 5:54 pm

No,. The LCCC sits in between generators and retailers. Any money it collects from one side is paid to the other with their costs being for retailer account, but those are small in the light of the multi billion flows). The rules under which it operates guarantee it has a cash float to make any payments due to generators, obtained from retailers who are required to amke various forms of up fron t payment, and are only paid any money they may be due in arrears.

Wind generators are only having cold feet where they bid aggressively low prices in the expectation that the market would be reformed and the contracts set aside by being bought out to enable the next set of renewables scams necessary to cope with the effects of rising renewables penetration. They are still hoping for that – see REMA. CFD Generators who have been making out on fat cat high price contracts have no such concerns, particularly since they have been exempted from windfall tax. They are of course once again collecting money off consumers anyway.

Nick Stokes
Reply to  It doesnot add up
March 5, 2023 5:21 pm

Here is S&P setting it out

“Payments to producers are contingent on the difference between a strike price and the market price, with the former being agreed via the Low Carbon Contract Company (LCCC), a UK government set-up. To ensure an efficient strike price, the LCCC holds allocation rounds every two years, with costs minimized through competition between projects.

Once the renewable installation is online, if market prices are below the strike price then generators receive the difference as a payment from the LCCC, which is ultimately passed on to consumers through their power bills.

However, if market prices climb above the strike price then generators pay back the difference to the LCCC and bills are reconciled. Renewable producers agree to this deal as it underwrites risk on renewable returns, thus promoting greater institutional investor interest.”

Last edited 21 days ago by Nick Stokes
It doesnot add up
Reply to  Nick Stokes
March 5, 2023 6:56 pm

Sounds like that was written by a trainee. The LCCC has no role in the auctions. The parameters are set by the government, and the auction is run by the EMR Delivery Body, which is currently part of National Grid, and which advises the government. The maximum bid prices are part of the auction parameters. The LCCC simply sends out contracts in accordance with the predetermined terms for winners to sign, and then administers the subsequent process, including calculating indexed strike prices, and the daily amounts of CFD payments. It also handles payments due to or from retailers, thus ensuring that they charge their customers on the basis of strike prices rather than market prices. Retailers are obligated to pay accordingly.

CFD payments are only activated by a notice from the generator to the LCCC, which can only be given if it has met all the conditions precedent in commissioning the project and certified that it has done so, but it has no immediate obligation to submit a commencement notice. It can earn revenue during installation and commissioning and up to the commencement notice that is not subject to the CFD terms.

Philip Mulholland
March 4, 2023 4:27 pm

Industrial wind power and on-grid solar is not cheap but expensive, duplicative, and parasitic.

Getting people to understand that Green Energy is a Parasitic Industry is the key to destroying this cancer.

Reply to  Philip Mulholland
March 4, 2023 5:45 pm

I have great confidence Astralian governments of the dominant parties will allow the cancer to destroy its host before there is any real change. Anyone who is banking on them actually exorcising the parasite are smoking the same stuff as the politicians.

The Australian grid is now inseparable from the parasite. The rot started from the time intermittent generators were permitted to connect under completely different conditions of supply to the dispatchable generators.

March 4, 2023 6:46 pm

Bill Schneider. Thanks for the informative article. I’ve often wondered, do street light exist in part to have somewhere to put unneeded electrons when most people are asleep and not using power? Base load plants can’t easily ramp down to very low loads in the middle of the night. Efficiency goes way down at low loads and ramping causes thermal stresses that have associated maintenance costs.

Reply to  Thomas
March 5, 2023 12:52 am

Thomas, it depends on the grid. When I worked in Western Australia (note I am in the US these days), a “hot day” could see peak loads pushing 4500 MW, whereas a good fall evening could see a nighttime drop down below 900 MW. That state is very heavily industrialized compared to the relatively small residential population that is served by the SouthWest Interconnected System (SWIS) grid.

So a quick story for you. When the Collgar wind farm began operating around 2012 (~230 MW) they of course had a first-use mandate to shove their available power onto the SWIS when they were generating. Wind in that region is diurnal – high in the middle of the day, low in the morning and evening, and high again in the middle of the night.

Remember how I said that overnight use on a fall (or spring) day could drop to 900 MW? Imagine Collgar crapping out its full capacity right then, butting out the rest of the “stack” because IMO were mandated to buy IVRE power. I had someone from Verve ask me if the cogen on my site could ramp down in order to balance load due to Collgar – and my site needed the steam (HRSG) regardless. So I told this person to give me a formal request via letter correspondence…and I never received it…

Finally, you’re right, baseload plants cannot easily ramp down. They go into “spinning reserve” where they are fired but not actually generating energy. This is a zero-revenue state, but cheaper than trying to alter furnace output. The result is that operating costs are higher and must be recovered over fewer generating hours.

The problem with IVREs “cutting the line” is that this pushes baseload generators into non-revenue status at times/period quantities that were not budgeted in the original investment case. To use a popular movie phrase, Government has “altered the deal”, and not for the better.

Eventually, Atlas will shrug.

March 4, 2023 8:18 pm

Very nice, this needs wide distribution. One more example of how government screws things up. Our government needs to be whittled down to size. It has become a freakish nightmare.

March 5, 2023 1:19 am

Typically, peaking generators are relatively cheap to build (since they don’t operate very often) but expensive to operate (as they must recoup capital, operating, and maintenance costs across a relatively small window of power generation time)

I don’t understand this. How often they operate should not affect how much they cost to build. Their capital cost is what they cost regardless of how much they are used.

Nor does their need to recoup capital on a small or large window of generating time have any bearing on their operating cost. It is what it is.

I can understand the situation might be that the peaking generators are fairly cheap to build but rather expensive to operate. Or that their cost per MW generated is high because of high fuel consumption and perhaps high capital costs per MW generated. But as its put the statement makes no sense and its not clear what he is saying or how it fits into the argument.

Reply to  michel
March 5, 2023 7:04 am

I think he means peaking generators are cheaper to build because they are typically just a small gas turbine connected to a generator with no provision to make additional power from the hot exhaust gases. These are called simple-cycle plants. A combined cycle gas turbine (CCGT) plant has a heat recovery steam generator (HRSG) that makes steam using the hot exhaust gases from the turbine. The steam drives a steam turbine that powers another generator. CCGT plants can approach 60% thermal efficiency compared to around 35% efficiency for a simple cycle plant. Simple cycle plants (peakers) are more expensive to operate because they burn more fuel per kWh or electricity. Also, since a peaker doesn’t run very often, the owner has to charge more per hour in order to get a decent return on investment.

Reply to  michel
March 5, 2023 12:50 pm

michel, I assume you aren’t thinking along the lines of return on investment for peaking facilities, when you say,

“I don’t understand this. How often they operate should not affect how much they cost to build. Their capital cost is what they cost regardless of how much they are used.

“Nor does their need to recoup capital on a small or large window of generating time have any bearing on their operating cost. It is what it is.”

It’s all a continuum that add up to the potential to recover investment.

Peakers are designed to only be needed rarely. The opportunities they have to sell into the market are few. So their capital outlay must be low, which in turn means that their operating costs are going to be high – because not enough money was invested into the plant to make it operate efficiently.

Thus, peakers are built cheaply and pricey to operate, because they are effectively acting like insurance policies. Most of the time they are not used. So owners don’t want a lot of capital tied up in them.

Does this clarify things for you?

Reply to  BLS1965
March 5, 2023 4:39 pm

Peakers don’t need to be profitable in order to save utilities money.
The existence of peakers means that the total amount of base load power that has to be built can be less, and that the base load that does exist can be run at a more or less constant rate, which is where they make the most money.

March 5, 2023 6:22 am

I’m the target audience and I found this article very clear and very helpful. Big thank you.
Sorry I can’t add to the discussion as I’m an ignoramus (there’s a lot of us out there!), I just wanted the author to know that he succeeded in what he wanted to do.

Reply to  MCChandler
March 5, 2023 12:32 pm

Thank you 🙂

Reply to  BLS1965
March 5, 2023 7:54 pm

Whilst most would agree with your opinion on Renewables, your ideas on electrons are not correct. Electrons do not get stored, produced, sent or consumed. Electrical energy is produced and sent as voltage, being the combined electrical and magnetic field that is transmitted along outside the wire. Electrons simply jiggle back and forth inside the atoms of the metal which the conductor is made from. Electron drift is around about one metre in 17 minutes so the number of electrons in a length of conductor stays the same. Electromagnetic energy moves at just under the speed of light and consists of photons.
They are continually being absorbed and emitted by electrons in huge numbers and whilst electrons create a magnetic field when they rotate and are a vital part of electrical energy it is voltage that is transmitted and measured and it is voltage that forms the basis for Faraday’s laws of induction. If we really wanted to get technical it is virtual photons forming the electric field and positrons being the anti particle of the electron are also involved but that gets into quantum physics.

March 5, 2023 10:51 am

If we thought ENRON was bad, imagine the distribution Ponzi scams that will proliferate under all these random energy mandates.

Forrest Gardener
March 5, 2023 7:21 pm

And in news that will surprise noone Nick Stokes has replaced himself with a bot.

March 6, 2023 9:48 am

Good article. I keep trying to think of ways to explain this to people, but I often want people to understand the electric grid is not just 24/7/365. It is also 60 minutes every hour, 60 seconds every minute and 1000ms every second, so it’s 24/7/365/60/60/1000. If you have a power grid that wants 100 Kilowatts, and you have 100 Kilowatts of green power on at that moment, great, and I bet your parents are proud. But then the green power is gone, say the wind stopped blowing, the sun set over the horizon, the hydropower dam is in a drought, and the batteries are too expensive so were never purchased; not to insert too may real problems that actually exist today, but you get the point. The grid now needs 100KW from a traditional power station, and even if those exact circumstances only occurs for a few days every year, you still need one whole power station. 50 KW means only 50% of people get what they want or everyone gets 50% of what they want. Zero KW of traditional fossil fuel (or nuclear) power means there will be times you get zero power. That is how third world countries live. That is living in poverty. You get one whole power station or you get to live a poor man’s life.
Now, I hope I have convinced you even if you don’t want to use that power station, you still need to have it on standby. If I haven’t convinced you, please go live in Africa for a few months. It won’t be long before you have changed your mind, but now assuming you want a power station on standby, let see how much this power grid costs. You have purchased one green power system and it does its job when the wind blows and the sun shines. Also, over there in the corner is a traditional power station. Ideally, it seldom runs, but you can’t buy one for half price, regardless.
Glancing over your electric bill, you may notice you paid full price for two power systems that do the same job, although maybe only one was working. The green one and the traditional one are both represented on the bill even if the traditional power plant didn’t run this month, but you still paid for it. This is because even if you don’t use it, the traditional power plant still costs money. Sure you didn’t spend any money on fuel, but the guys working at the plant still collect a paycheck, the insurance company still gets a check, the administrative costs still exist, the bank still wants the loans paid, the tax collector still got his share (maybe, local results may vary), repairs still had to be done, and just making sure all the parts work was a critical job that month. You see, even if the power plant only operates 5% of a year, nearly 100% of the costs remain. What plant worker will accept 5% of a paycheck because that’s how much time was spent running? You will pay him 100% of what his union demands or you get no workers. Same for everyone else with interests at that power plant.
And that my friends is why your electric bill is so high. (that and the Biden Administration’s opposition to developing energy resources to reduce costs, but that is another story for another day).

John Brown
March 6, 2023 1:09 pm

It is possible to run a grid using solely renewables if excess energy is used to generate hydrogen through electrolysis. But so inefficient is the process that my calculations (which I have posted before on this site) show it is necessary in the UK to install 8 GW of wind power capacity for each 1 GW of reliable/dispatchable power. For the case of solar in the UK the figure is 30 GW of installed capacity for each 1 GW of reliable/dispatchable power.

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