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

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From MasterResouce

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.


Why should a thermal plant spend money in a government-rigged market that threatens a reasonable profit? Why should the plant even remain in the market under these conditions?

This is where we find ourselves today: the market is broken, and the risk is that the “insurance” for IVREs, covering the reliability gap (not enough sun or wind for prolonged periods, thus negating any advantage that battery storage might offer them) will fail. After all, the baseload plants are either crippled by deferred maintenance, or else sold on the cheap to buyers that have even less incentive to maintain them. And much needed new capacity is not built at all (phantom plants).



The nature of IVREs will continue to push baseload generators out of business – and IVREs will continue to blame baseload for these problems even as its mandates kill the security that baseload provides. Authors Tom Stacy and George Taylor have written a detailed submission to FERC (the US Federal Energy Regulatory Commission) on this topic: