Europeans with any sense have woken up to the fact that the much-touted wind and solar ‘transition’ is a cruel hoax driven by cynical crony capitalists and their political enablers.
Driven by starry-eyed ideology, rather than sound engineering and economics, the great ‘green’ reset fell apart because households, businesses and industries aren’t prepared to limit their power use to occasions when the sun is up in a cloudless sky and the wind is blowing, just right.
No, modern civilisation is built upon having electricity as and when we need it, rather than according to the fickle whims of nature.
And therein lies the fundamental flaw in claims that we’ll all soon be powered by nothing more than sunshine and breezes. For a while that myth was sustained by an equally specious claim about giant lithium-ion batteries filling the gaps in wind and solar output, when sunset and/or calm weather sets in. The laws of physics put paid to that story. The battery storage of electricity is, and will remain, at the margins. There is no grid-scale storage of electricity using batteries, anywhere in the world.
In this two-part primer, Bill Schneider debunks both fallacies in grand style.
Reliable vs. Intermittent Generation: A Primer (Part I)
1 March 2023
This two-part post is a follow-up to Robert Bradley’s recent article, “Wind, Solar, and the Great Texas Blackout: Guilty as Charged.” His article discussed how regulatory shifts and subsidies favoring Intermittently Variable Renewable Energy(IVRE) producers resulted in prematurely lost capacity, a lack of new capacity, and upgrade issues with remaining (surviving) traditional capacity. These three factors–“the why behind the why”–explain the perfect storm that began with (or was revealed by) Storm Uri.
Part I below describes how the market was originally meant to work–but has not worked given the governmentally redesigned power market, beginning with generation. The change was caused by:
- Investment monies lured away from developing baseload capacity by government subsidies and special tax incentives, and
- Operating opportunities lured away by “first-use” mandates. First-use mandates are especially pernicious as grid operators must purchase from IVREs whenever they are producing, leaving the reliable generators idle.
Imagine a billion dollars on the table for building a nuclear, coal-fired, or natural gas-fired generation facility. Your financials require a return on investment (ROI) to obtain the required capital from investors and/or shareholders.
You built the facility in good faith, based on robust grid modeling that suggested a significant opportunity to profitably sell your energy over the operating life of the plant. You did due diligence on this opportunity versus the cost, and the ROI was good enough to get signoff on a Final Investment Decision (FID), so the plant received financing and was built. Great.
Assume under the business case that X units of electricity were to be sold into the grid. Based on satisfactory plant performance, the project is statistically certain to sell, say, at least 50 percent of X (obviously making up numbers here but you get the point) and to break even. At a high level, the variables to manage are: 1) Fuel price, 2) Labor costs, 3) Maintenance costs.
This is a normal market–the way it used to be. The utility had an “obligation to serve” and had the ratebase incentive to key capacity above peak-demand scenarios.
Enter government intervention….
IVRE “first-use” mandates. Not only do these mandates require grid operators to buy power from IVREs “first” if they are generating, but these mandates also often require grid operators to pay a premium for IVRE power over any other source.
Your business case has now been kneecapped with a double-whammy: not only are you losing business because IVREs must sell “first,” but there is absolutely nothing you can do to make your power more commercially attractive, since IVREs not only have very low short-run marginal costs—in that the next electron that they can generate is extremely cheap, since wind and solar (and falling water for hydro) are “free.”
In this scenario, due to other political externalities, the price of your fuel (if you are using natural gas or coal) is rising.
Doesn’t look too good for you now, does it? Suddenly the volume of power that you are competing for (that is, market demand) has shrunk because IVREs can “cut in line” in front of you at any time.
Not to mention that with few exceptions, your ability to shut down when demand has dropped—and thus limit your operations and maintenance costs (O&M)—is very limited, especially if you are expected to have power ready to sell if demand suddenly ramps up.
Thus comes the double-edged sword of IVREs: their ability to produce can drop just as quickly as it rises. When that happens, grid operators expect baseload to be ready to sell, often with only a short notice. This means that baseload operators cannot shut down when they aren’t selling; rather, they have to keep their plants warm and turbines spinning in case they are called upon to sell when IVREs cannot.
This condition that baseload operators are forced to wait in is called “spinning reserve” – meaning the plant is operating but not generating any saleable electricity. But it is piling up fuel, labor and maintenance costs (see the list above).
Therefore, if fuel costs are rising, and I am running my generation facility on a skeleton crew, what’s left for me to cut?
Rather than spend money on scheduled maintenance, the generator will try to shore up the red ink by deferring maintenance. The more I am forced to do this (with the alternative being bankruptcy or exiting the market), the more I am playing a game of “Russian Roulette” with my ability to operate.
Planned maintenance is scheduled on the basis of statistical modeling, so I can operate my plant safely and produce saleable energy. I can stretch these statistics by implementing condition monitoring (“con-mon” for short), but eventually I have to maintain the plant if I do not want to risk a failure.
But if I cannot afford to perform the maintenance, I’ll defer items that I think I can get away with, like equipment used to operate the plant in extremely low temperatures, since weather rarely gets “that cold” here in Texas. And I’ve heard what is said about climate change moderating winter lows….
Statistically my risk is pretty low, right?
Until the proverbial holes in the layers of “swiss cheese” line up (some may recall the safety model using this graphic) and suddenly it’s very cold, and IVREs are not generating enough to make up the gap.
And, having deferred maintenance, my plant tries to generate saleable power, but it breaks.
Yes, in this example, my baseload plant broke. This is the first “why” that the IVRE advocates point out–but they dare not go further. The layers below the initial “why” all involve government having fundamentally “altered the deal” for baseload generators after the fact: IVREs attract investment dollars and are allowed to cut the line for market demand whenever they are generating.
For IVREs, it’s a no-risk deal, with markets guaranteed and taxpayers country-wide adding profits. But what about the need for reliable power?
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: https://elibrary.ferc.gov/eLibrary/docinfo?accession_num=20230113-5070
Reliable vs. Intermittent Generation: A Primer (Part II)
2 March 2023
Intermittent variable renewable energy 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.
IVRE Incentivized Model
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.
2 thoughts on “Why Naturally Intermittent Wind & Solar Can Never Replace Coal, Gas & Nuclear”
This just another parasite takeover! They can fly their planes, cause wars and launch rockets! CLIMATE CHANGE? I don’t think so!
Twelve hours isn’t near enough storage. 850 in USA average, 1,200 in California. Cost would be NINE TIMES TOTAL GDP EVERY YEAR!
The Greta Green Energy Transition Is Physically Impossible.