Kevin Kilty
Until about a year ago, I thought about public utility regulation as too boring, too far outside my education, and unrelated to my interests and experience to bother with. I was wrong.
Figure 1. The relationships among interest on bonds and dividends to preferred shares (collectively called debt) and return on capital to return to ordinary shareholders (equity)
What prompted my change of view was recognizing that a frontline in the war, if you will, to remake the electric grid will take place not in arguments about the reality of climate change, but when utilities decide to change the way they generate electrical energy and pay for these changes. The permission to make these changes, and how the ratepayer gets hit afterward, are decided in the public service commissions which by law have to make their deliberations substantially transparent to the public. In particular permission for changes are gained in hearings of public necessity and convenience; how the ratepayer gets hit is decided in rate cases. I plan to examine only rate setting in this brief essay.
My principal goal is this. Many of us are pretty certain that pouring more renewable energy into a network makes delivered energy more expensive and less reliable. We often point to a graph that shows costs rising with percent renewable contributions to generating capacity. Yet, our antagonists claim that adding energy from renewables should, and in fact does, reduce utility costs. They have data, too. We strengthen our case by demonstrating specific reasons, or lack thereof, for rising utility bills. The rate setting process ought to make those reasons visible.
I also suspect most people know little about rate setting and are unaware about its complexity. It’s important to understand this bit of the order of battle.
Where I live we are in the middle of a general rate case affecting one-half the state. It calls for substantial rate increases (21.6% or over $140 million) and has become exceptionally contentious. It resembles rate cases that have been decided or are in progress across the U.S.[1] The application for this general rate case includes thousands of pages of exhibits and appendices.
The Essence of Rate Setting
Long ago people recognized that the delivery of utility services was probably best handled by allowing a private firm to have a monopoly over this service. At the same time people also recognized that the inherently bad effects of monopoly power had to be addressed. The response was to create public utility commissions whose decisions regarding utility expenditures and methods of financing those expenditures would have the force of law.
The basis of utility rates are best explained as follows in two equations.
- Needed revenue = operating expenses+depreciation+taxes+(rate of return x rate base)
- Then; rates = needed revenue / assumed volume of service.
The usefulness of this organization is apparent. Operating expenses, and taxes are aligned pretty well with the immediate delivery of services. Depreciation is how capital expenses are eventually recovered as assets wear out. Rate of return is necessary to provide access to capital markets where the resources are garnered for construction of assets to provide service.
There is some overlap. For example, some maintenance could be a capital expenditure and depreciated. Nonetheless, this is a pretty clear summary of revenues required to operate.
Equation 2) appears far more simple than the actual situation. What we call rates is actually a large set of tariffs each of which involves many components and which apply to various customers. The tariffs are structured to prevent one group of customers, such as residential consumers, from subsidizing another, say industrial consumers; while at the same time supplying the needed revenue of Equation 1). The “assumed volume of service” category is actually a guess at the volume of sales. It occasionally happens that the utility over-estimates its sales volume and cannot reach its proposed revenue requirements – a case of volumetric risk.
The goal is to arrive at revenues allowed by the Commission and a structure of tariffs that are “just and reasonable”. The standard of “just and reasonable” became a governing standard through a couple of Supreme Court cases in the 1920s to 1940s.[2] It means, in effect, that customers are truly paying for the value of the service they receive while the utility can earn enough money to stay in business and maintain access to capital markets; all the while the service that results being affordable and reliable. The most contentious aspect of any rate case is justifying and ordering the rate of return on equity.
There is another standard which serves as a worthy goal but which is rarely mentioned in my experience of reading documents and attending meetings. This is “used and useful” which is where the value of a net-zero grid becomes doubtful. It is allowed through Wyoming Statute (Wyo. 37-2-119) but which might be missing in the enabling statutes of other states. The idea is that prudent planning and expenditures should be useful to the delivery of service and actually used in the delivery of service. Stuff falling outside this domain, such as excessive compensation or excess labor or poorly justified projects are the very definition of unnecessary and unjust, unreasonable expense. Dispatchable versus non-dispatchable generation without dedicated backup cannot be viewed as equally “used and useful”. The standard of “just and reasonable” has trouble weighing the differences.
Two other things are important. First, there is dreadful asymmetry with regard to knowledge between the utility and practically all other parties to the rate case. The president of the utility verified this when he said that there are no parties who know more about the topic or the rate case than the utility company itself. This standpoint is entirely reasonable, but it unwittingly also makes the point that since parties are biased toward their self-interest, the greater knowledge of the utility must come with skepticism about their claims.
Second, proof of the reasonableness of the proposed costs, revenues and tariff adjustments is made by applying them to a test year to show how they would work in practice. Traditionally the test year was a historical year for which almost all the data involved, except the new tariff structure, were known quantities. About 15 years ago the utilities began making a case that a future test year (FTY) was more appropriate because it would reduce the regulatory lag between identifying shortfalls in revenue and new tariff structure. Wall Street endorsed this view also. However, having utilities and Wall Street, who both stand to gain by shifting their risks, endorse this new model should raise a flag of caution.
The FTY contains unknown quantities; inflation, capital markets, economic activity, volume of service, demographics changes, and so forth have to be guessed at. Combined with the asymmetry of knowledge, the uncertainties in using a FTY serve not only to make expenses obscure,[3] but potentially reduce market discipline. Regulatory lag aided market discipline by making the utility responsible for costs during their “naked” interval. Lack of market discipline leads to overcapitalization and bloated O&M.
A Current Rate Case
How the simple picture painted above of utility regulation departs from practice is well explained by our rate case. The rate case in question was born on March 1, 2023 when the utility sent its application and all supporting appendices, which amounted to thousands of pages, to the Public Service Commission. A historical year running from mid-2021 to mid-2022 provided a data gathering period to project into the FTY which is 2024. The order resulting from this hearing must be rendered by January 1, 2024 when the new tariffs become effective.
The utility makes its case for rate increases in the application thusly:
(1) continued capital investments including, the Gateway South, Gateway West Segment D.1 transmission lines and the Rock Creek I wind project, along with the Foote Creek II-IV and Rock River I wind repowering projects, which are required in order for the Company to meet its obligation to serve its customers and includes an associated rate of return of 7.60 percent on all capital investments; and (2) NPC.
So, there are three categories of costs; (1) capital expenditures which are recaptured through depreciation, (2) cost of capital which involves the debt involved (bonds and preferred stock), and return to common stock (see Figure 1), and, (3) net power cost (NPC) which catches the rest of Equation 1).
The first two categories are, in my view, relatively clear in their cost of power implications. New capital expenditures will enter a depreciation schedule and the rate structure will directly reflect those depreciation charges. What has to be determined is, on a per kW capacity basis, do renewable energy assets cause larger depreciation charges than the thermal assets they replace? I think the answer is yes for two reasons. First because the average capacity factor for renewables is far lower than thermal assets, the capital cost to replace thermal assets is going to lead to a larger book value to depreciate. I’d say at least 50% larger first cost for equivalent capacity.
Second, renewable assets have shorter depreciation schedules (20 years is widely quoted) than thermal assets (40-50 years is widely quoted). Treated as a perpetuity of sorts, renewables are decommissioned and replaced twice as often. A complication in this instance is that while coal assets are being abandoned (early in some instances), there are some new gas-fired assets that are needed largely as backup for non-dispatchable assets. These will have useful lives much shorter than typical thermal assets (15 years if the schedules in the typical integrated resource plans (IRP) are followed). Even if these plants have utility left in them by the time they are decommissioned, the remaining value will enter some sort of account that will be amortized on an accelerated schedule.
The impact on cost of capital follows similar thinking. There is a differential cost on an equal capacity basis which the rate structure will deliver a return on capital, dependent on the utility’s capital structure and interest rates on debt, but which is typically 7-8%. Let’s just take a wind plant as an example. For wind with an annual capacity factor of one-third to deliver energy like a coal-fired plant with annual capacity factor of 0.85 would require building 2.55 times as much wind plant (0.85/0.33). A quick estimate of the differential first cost would be $825 per kW of nameplate. The impact across rates would be around $100 per kW per annum of additional depreciation and return on capital. In fact, the overbuilding might be much larger. Xcel Energy advertises net dependable power of non-dispatchable sources as needing an overbuild relative to dispatchable coal being three to six.[4]
One could analyze many other new assets the same way. For example, some new transmission lines would not be built if not for the need to gather widely dispersed wind or solar energy. There may be some offsetting savings in debt because of an ESG preference for valued assets versus thermal derived energy, but considering the planned investments in renewables and the enabling transmission lines there cannot be but growth of rates from depreciation and return on capital.
Keep in mind that people might confuse depreciation with return on capital, but they are very separate and additive – one provides for recovery of capital expenditures the other affords access to capital markets.
The complications of NPC
Now we come to that place where the story becomes hazy – net power cost (NPC). The term NPC isn’t clearly related to any single item in Equation (1). The legal definition I have placed in the notes.[5] Its definition seems to open the door to all sorts of things.
Moreover, NPC is not directly determined from accounting entries which is what Equation (1) implies. Instead, in our rate case, it results from modeling. In our case, a sophisticated modeling and optimization program, “Aurora”, has input to it all the assumptions and projections (and uncertainties) of the FTY plus the known characteristics of generating, transmission and distribution assets. In working to find a least-cost solution to the problem of delivering specified power to all customers, it also produces a detailed projection of the components of NPC for the test year. I won’t remind readers of WUWT about the pitfalls of modeling future outcomes vis-a-vis desires.
In our rate case one witness produced a detailed picture of NPC factors affecting policy and operations. Examples are:
- Taxes; including a direct $1/MWhr wind tax in Wyoming to an indirect $24.75/MWhr carbon tax (the CCA) in Washington State levied against a natural gas plant that probably does a lot of balancing wind and solar.
- Abandonment of hydroelectric plants on the Klamath River.
- Market purchases of 1) Day Ahead/Real Time (DA/RT) purchases, 2) summer shortages of thermal plant capacity, 3) Coal to gas conversion requiring temporary market purchases. The utility claims these costs of market purchases of power have risen 200%. What causes this market price inflation?
- Environmental concerns such as the Ozone Transport Rule (OTR) and NOx emissions.
Thus, many factors that could fall under a category like “environmentalism” have substantial impacts on NPC.[6] Even a small factor like net power purchases or feed-in tariffs from residential wind and solar have the effect, one witness said, of increasing rates across all classes of customers. Perhaps the rising NPC and adoption of wind generations are simply both correlated with the endless stream of environmental demands.
Our utility claimed in multiple instances that wind energy saved customers $85 million because it has no fuel cost. A person would really like to see the cost accounting that substantiates such a claim. However, in absence of such data we could ponder Feynman’s dictum that “if you start a [classical] argument in a certain place and don’t carry it far enough, you can get any answer you want.”[7] Carrying far enough in this case means saving customers even more money by adopting 100% wind energy right now which is what the Sierra Club and a majority of voters apparently want.[8] Figure 2 shows this to be patently impossible.
Figure 2. Generation data from EIA in the PacifiCorp East balancing authority area this past week.
What Figure 2 shows first, is that wind disappears routinely. In fact, October 2023 has delivered four separate wind droughts in the EIA Northwest region; one of which was a full week long. More important, though, is to note the anticorrelation between wind or solar and coal thermal energy in Figure 2. Coal is 70% anticorrelated with solar and 50% anticorrelated with wind. Coal is balancing both with some limited help from natural gas. The amplitude of the total adjustments in coal output are as large as 3,000MW; sometimes more than once a day. It would not be remotely possible to run PacifiCorp East (PACE) on wind energy without coal or its equivalent. Moreover, the indicated capacity factor of coal plants is 51% and wind is 27% in Figure 2.
No one in their right mind designs a coal thermal plant, especially a base-load plant, for 50% capacity factor. Instead coal design should figure 100% at maximum demand and some reserve and running capacity at about 80% or even higher.[9] What has happened to the capacity factor?
Figure 3. Trend of U.S. thermal plant capacity factor. Data from EIA. Figure for 2023 is based on January through August with estimates for the balance of the year.
Figure 3 perhaps supplies an answer by illustrating a trend. The capacity factor of coal plants in the U.S. has been on a long decline commensurate with adoption of more renewables. This same tendency of declining capacity factor is true of all networks worldwide and especially among coal thermal plants but is true of renewables as well.[10] In other words, a universal consequence of adding renewable energy to networks is more costs devoted to delivering less energy per unit of investment.
People try to explain this observation in ways convenient for their worldview but I see a simple explanation.[11]
Renewable generation took the best locations early and as more is added these less capable locations reduce overall capacity factor. The variations in renewables, clearly visible in Figure 2, grow larger with more renewables. Thus, the balancing dispatchable source of energy, typically thermal, has to supply larger power levels for the worst cases of renewable shortfall, but has to be curtailed to accommodate the occasional large contribution from renewables. Thermal plants can only be curtailed so far but any curtailment leads to a reduced capacity factor.[10,12] The limited ability to curtail thermal plants inevitably leads to more curtailment of renewables which lowers their capacity factor further. The two very different generating sources walk one another to lower and lower capacity factors. Eventually capacity factor declines to whatever source dominates the grid.
The utilities and environmentalists might contemplate how forcing thermal plants to accommodate and balance non-dispatchable energy, with its poor capacity factor and wild swings of output, leads to: 1) reduced efficiency of thermal plants, 2) increased maintenance costs, and 3) shortened asset life.[12] Perhaps someone could quantify these factors and apply them to the cost of delivering “free” wind energy just to humor us skeptics. Yet, the answer doesn’t matter. No matter how the costs are accounted for, the consequences demand higher rates.
Conclusions
Engaging in happy talk about wind energy saving customers money and garnering the approval of the ESG obsessed will never substitute for reliable operation. Whining about thermal assets being inflexible and preventing full adoption of wind and solar is simply PR. Someone must admit the realities that Figures 2 and 3 show.
References and notes:
1- Minnesota PUC cut Xcel Energy’s request of 22% to 9.9% in June 2023. The New York State PSC cut rate requests by NYSEG and RG&E by about 50% in October 2023.
2-These are referred to as Bluefield Waterworks (1923) and Hope Natural Gas Co. (1944). However many other early decisions could serve just as well. See for example, Herman Trachsel, Public Utility Regulation, Irwin Publ., 1947. I’m not sure why these two cases seem to have exerted the most influence.
3- One consistent feature of testimony of the utility and the intervenors, both written and oral, is to seemingly forget that the NPC is for a test year which is in the future. There is a tendency for the utility witnesses, when asked to justify some driver of NPC, to immediately begin discussing some event of the recent past or the present rather than their effects in the FTY and especially not into the uncertainties of their projection.
4-American Experiment, June 20, 2023, Minnesota’s energy transition threatened after Xcel’s reduced rate increase. Online at “Minnesota’s energy transition threatened after Xcel’s reduced rate increase.pdf” If a person considers storage to replace dispatchable thermal assets, then the amount of overbuild expands greatly.
5-From Lawinsider.com the definition of NPC:
Net Power Cost means, for any period, the cost during such period of purchases by Power Marketing of Deficit Station Power, increased by (i) the amount of any transmission or other costs incurred by Power Marketing during such period in delivering Deficit Station Power to the point of sale, (ii) the amount of any state or federal Taxes paid or required to be paid by Power Marketing with respect to the purchase of Deficit Station Power or otherwise with respect to the performance of its obligations hereunder, and (iii) the amount of any other costs paid by Power Marketing during such period in connection with the purchase of Deficit Station Power, including an arms-length, commercially reasonable allocation of overhead and administrative expense.
6-As of this morning I received notice of a hearing on continuation of a 0.3% per month surcharge on all billing statements to establish a Carbon Capture Use and Storage (CCUS) portfolio standard – currently deferred but which the deferred balance accumulates interest at the allowed cost of capital.
7-Feynman’s Lectures on Physics, Vol II, Chapter 34 Section 6.
8-The Sierra Club actually believes PacifiCorp could abandon thermal assets immediately and claim that depending on thermal assets was always a “risky” proposition. A survey indicates that voters in Utah want more solar and wind generation by a majority of 8:1.
9-The factor includes some down-time for turnaround maintenance and additional curtailment because of variations in day/night demand.
10-Natanael Bolson, et al, 2022, Capacity factors for electrical power generation from renewable and nonrenewable sources, PNAS, 119, 52, doi:10.1073/pnas.2205429119
11-Such excuses include the idea that thermal plants were overbuilt through poor projections of energy demand. Some decline might be related to aging of plants with underinvestment in maintenance.
12-The lower limit of curtailment depends on many factors but could be 30-70% of maximum. Generally, the lower the limit on curtailment the worse the efficiency of fuel use and aging of plant.
13-IRENA, 2019, Innovation landscape brief: Flexibility in conventional power plants. International Renewable Energy Agency, Abu Dhabi. Available online at www.irena.org/publications
Discover more from Watts Up With That?
Subscribe to get the latest posts sent to your email.
“Long ago people recognized that the delivery of utility services was probably best handled by allowing a private firm to have a monopoly over this service.”
Efficiency, yes. Best handled? I don’t think so.
The problem is that the private firm is most dedicated to increasing share holder profit and not to delivering for the consumer.
And, as the article correctly states, “there is dreadful asymmetry with regard to knowledge between the utility and practically all other parties.”
So the current system always ends up hitting the consumer’s long-term needs for short-term cash extraction.
Enron was not atypical.
I have a problem with the shareholder / investor terminology. Only the original purchaser of a share when issued is an investor, the subsequent owners of that share are speculators. Even the original owner may have gambled on a quick profit.
To invest condfidently there has to a liquid market for the shares. Some will “play” the system in the hope of quick profits, but the aftermarket buyers are necessary. They are not exclusively speculators.
Depends on your definition of speculation, buying in order to generate an income or buying to increase your wealth by reselling at a profit are different forms of this definition
Many speculators pay little attention to the fundamental value of a security and instead focus purely on price movements.
Firms buy back stock, they have treasury stock, just for the purpose of raising capital when required.
Shareholders, whether they bought their shares from the firm or from a previous shareholder, are the owners of the firm and are ‘invested’ in its gains and losses as long as they continue to own their shares.
Would you be willing to say that only the person(s) who first arranged to build a house are ‘homeowners’ and all subsequent owners are ‘speculators’?
‘The problem is that the private firm is most dedicated to increasing share holder profit and not to delivering for the consumer.‘
You might want to re-think this. The most profitable firms are those that best serve consumers’ needs. Enron was a typical rent-seeking parasite that took advantage of the regulatory power of the State to coerce energy producers into offering inferior products to consumers.
= Crony Capitalists! And very good at it, and their government elected cronies walked away unscathed with the money still in their pockets.
You might want to re-think how a monopoly needs to respond to consumers’ needs.
And you might want to consider that monopolies, or more generally cartels, can only arise / prevail where coercion, read government, can be used to prevent competitive suppliers from entering a market. This is the whole ‘genesis’ of the regulatory state – spend a few bucks to lobby for and capture your regulator in order to enjoy above market profits. See big pharma, big labor, etc.
And then there is the biggest monopoly of all, government.
A not insignificant consideration is that, although it may be difficult, a private firm is subject to action through the courts if they are not operating within their contract. This is not always the case with government entities .
Enron was a case of outwitting regulators and some of the slower market participants who did not understand the market manipulation that they were subjected to, and didn’t know how to protect themselves. It was never a TSO, but took care to understand and exploit the rules that TSOs apply to grids. Much the same applies to renwables suppliers today, who hide from regulators and the public the real costs of integration into a grid system.
However, it is wrong to assume that a nationalised monopoly will act in consumer interest. Much will depend on their access to funds. In a poorer country like Venezuela where funds in any case get misappropriated the result is inadequate investment in maintenance and facilities, which leads to blackouts. Search “Venezuela apagon” for copious examples if you read some Spanish.
At the other end of the spectrum the degree to which the CEGB had gold plated the system at consumer expense was exposed in the aftermath of privatisation, leading to significant falls in costs until government started to decide it was going to dictate what was going to be invested in.
Only the distribution lines need to be monopolies, and not always then.
Power generation itself does not need to be a monopoly.
It is perfectly workable to have a joint venture with participation of interested parties. They can lobby for investment that benefits them, while the other participants keep a watchful eye for their own interests and preventing undue waste. This works for consumers when they are represented by retailers as system offtakers.
As capacity factors decrease it becomes impossible for renewable energy to produce enough energy to build replacements over their lifetime.
As such, renewable energy is a dead end, unable to provide enough energy to build and maintain the millions of solar panels, windmills, transmission lines and transformers required.
https://en.wikipedia.org/wiki/Energy_return_on_investment
How much energy does it take to produce a solar panel? How much energy does a solar panel produce in its lifetime.
Unless the solar panel produces more energy than it takes to build a solar panel, you can set the price to consumers to infinity and the power utility still cannot make enough money to pay for itself.
A point not well understood by many, and by almost none among environmentalists.
You can gain market share by selling Dollar bills for 99 cents, but you can’t make a profit on that basis.
Back in the 1980’s even the BBC seemed to understand that oil and other fossil fuels are such profitable products because our entire civilisation is founded upon the high energy gained for the energy expended by acquiring them.
Power companies with large hydro facilities love to see neighboring utilities install renewables. The hydro facilities function like huge batteries, buying surplus renewable power for next to nothing, and reselling it back for a fortune when renewables are not available.
Ergo Norway.
They also love nukes for this reason.
This statement sums it up. It is money looking for an investment return that is better than government bonds.
In essence, it is those with investment funds working out how they can bleed those who do not have the funds to invest.
In Australia, households are encouraged to invest in solar so they can bleed the poor who cannot afford a roof. The ESG mob just do it on a larger scale. Spending heaps of money on useless resources that offer a guaranteed return through monopoly power.
No regulating body will say to a power provider that they cannot commit to some “renewable” project because it will increase costs to consumers – we cannot just keep burning coal and let the planet burn.
What they have not realised is no amount of weather dependent generators will actually save coal. It just gets burnt in China, or India or Indonesia or any other unwoke jurisdiction.
“Our utility claimed in multiple instances that wind energy saved customers $85 million because it has no fuel cost.”
This is a foolish argument and I am sure your utility knows that. Oil, coal and natural gas also have no fuel cost – I have yet to see a meter installed by nature or God on an oil field. But it takes certain machinery and workers to exploit fossil fuel, burn it to make electricity and deliver the product to our 24/7 grid. It also takes certain machinery and workers to exploit solar or wind energy and deliver the product to the grid. The cost of wind and solar electricity very high largely because of its unpredictable intermittency. When all the costs are considered, adding wind and solar electricity to the grid increases overall costs and rates go up.
If they know it’s a foolish argument, then they are lying in public, and have no qualms about it.
If they don’t know it, then they are incompetent and shouldn’t be running an utility.
They know it, they are depending on you not knowing it.
And capital cost, compared to capacity factor, are much higher for unreliables. Average capacity factor over season durations can be as high as 6X nameplate, requiring a large overbuild of inefficient generators and/or large expenditures on inefficient long distance transmission and backup generation.
There’s a lovely example, to my mind, of ‘money grubbing’ (just for the sake of it) going on near me right now.
Walpole Substation is the heart of the action – seemingly a fairly new creation meant to connect the Race Bank windfarm into the UK grid.
1/ They are quite seriously extending Walpole right now and I thought it was to do with the solar farms popping up all around here.
One of those solar farms is an extension of an existing solar farm on some land where a CCGT power station exists = 3 miles away (as crows fly at Sutton Bridge) from the substation and connected via overhead pylons. There is another CCGT, 14 miles away at Spalding.
What ‘got me’ was why the country lanes/roads needed to be dug up so as to lay a 33kV 3-phase underground cable from the solar extension to the substation.
Why? Why not connect the solar farm via the existing overhead line?
How was/is the existing solar farm connected?
Oh well no matter: Following The Rule concerning these things and how ‘Jobs expand to fill the money available‘ what was promised to be a week of diversions/road-closures and inconvenience turned into 2 months. Nice work eh.
Who paid for it – for 8 weeks of extra work beyond what was promised.
Folks were getting very annoyed, the diversions meant 5,7 and 10+ miles of extra driving for a lot of people.
Response from the workmen: “Oh, we’ve got to take our time and be careful else the road will blow up”
2/ I had a leisurely drive past the substation recently, with my best rubber-neck and eyes-on-stalks and it seems they are constructing a synchronous capacitor there.
A UK (new) company called ‘Conrad’ are in cahoots with Siemens to build twin machines.
They tell us that they are ‘DC Excited alternators’
Fair enough and my actually living 3 miles from the thing, can understand why it’s needed, sometimes the LED bulbs in my house flicker like candles-in-the-wind.
The Reason Being, the huuuuuge number of ‘cold stores’ that farmers around here are required to build, operate and maintain.
Those things were never needed when I was a kid so why now?
Taking the need for these stores as an Actual Need, those stores are each and every a very powerful refrigerator. Each is the size of typical UK house, some farms have 4 or 5 of them, and when the thermostat in there ‘demands cold’ – big electric motors promptly attach a short-circuit to the mains electricity supply.
That’s what all electric motors do when you switch them on, no surprise, the lights flicker for miles around.
OK, we’ve established the need for a synchronous capacitor = something to hold up the grid voltage and supply the Amps those motors need to get themselves up and running and, the solid-state electronic inverters of the solar farms simply can not supply that. They ‘take things too literally’ and when they sense a short circuit on their outputs, simply shut themselves down as a self-protection feature.
Which is THE very last thing the grid needs when an electric motor is trying to start.
Then it dawned, when the solar farms are generating, the CCGT power station won’t.
i.e. When a synchronous capacitor is needed to hold up the solid-state inverters, the huge big turbine/alternator in the power station will be sitting idle.
So, why not use the power station(s), when they are idle, why not use them as the synchronous capacitor? For Walpole station, there’s one only 3 miles away and another barely 14 miles away and both are already connected into the grid.
Good grief, that is exactly what the alternator is an any power station – a DC excited ‘thing’ precisely as the capacitor is described
But no, The Powers That Be have decided to build 2 new synchronous rotating machines (at what cost) when at the very times they’ll be needed, there are 2 synchronous rotating machines sitting idle. 3 miles away at Sutton Bridge and another 14 miles away at Spalding
And when the CCGTs are up and running (at night and during wind-droughts) the new capacitors won’t be needed. Apart from sucking power out of the grid to keep themselves ‘ready’
That, in microcosm on my own doorstep is why power costs are skyrocketing.
Electricity prices are part of what is skyrocketing. The other part that is going up sharply is what one must spent on most other purchases because of the insanity.
Thanks, Kevin. Looks like fig. 2 says: either stick with coal or convert to nuclear. If not nuclear then natural gas is the only viable substitute for coal. Enter dysfunctional politics; the China Syndrome was a documentary and fossil fuels are killing the planet, so we must destroy the economy.
I am a big fan of nuclear especially if we can figure out how to get back to power plants that can supply base-load without having to ramp up and down balancing wind and solar. I have no idea if the SMRs have some exotic fuel cycles to aid in load following, but particularly late in the fuel cycle it’s hard to get a nuclear plant to giddy’up to follow a load — they are barn-sour critters at that point.
The TerraPower design uses a double shuffle of heat with storage in molten salt to try a work around of this problem. I have my doubts about this scheme. I know there are many smart folks working for TerraPower, but I also know that many of my academic colleagues eventually revealed their misunderstanding that near 100% adiabatic heat exchange doesn’t mean 100% availability exchange — quite the contrary. The more heat exchangers involved in tandem, the worse for efficiency and ramp rate.
The schedule for plant operation at Kemmerer is too optimistic, I think, but everyone apparently remains convinced that a nuclear plant will be running in 2028.
‘…but particularly late in the fuel cycle it’s hard to get a nuclear plant to giddy’up to follow a load — they are barn-sour critters at that point.‘
The Soviets figured out the best way to do that was by pulling out all the control rods and shutting down the cooling water pumps.
And how does the US Navy do it on all their nuclear powered warships?
One has the impression that they do it very well.
Those reactors run at a typical power level of 60% or less and can ramp qickly to 100% and back down. I have no idea of the technical details but surely they use very special fuel elements in a special array pattern. Why no one in the world of commercial reactors do it similarly maybe BetaBlocker knows.
Only recently with the increasing penetration of wind and solar has there been a perceived need to place more design emphasis on a commercial reactor’s load following capability.
In a market environment without government mandates to eliminate fossil-fueled power generation, we would not be seeing greater load following efficiency as a primary design requirement for a commercial power reactor.
The operational duty cycles of the comparatively large 800 MW to 1200 MW power reactors currently operating in the commercial power marketplace were intended from their inception to be very different from a naval reactor’s operational duty cycle aboard a warship.
Most if not all of today’s commercial reactors can load follow to some extent. But doing so on a regular basis with current reactor designs comes with operational and maintenance complications which add penalties in the form of added costs and possibly less total operational life.
In theory, the TerraPower SMR design will do a better job of load following than will the NuScale SMR design, which in turn will do a better job of load following than the legacy reactor fleet.
Does this facet of the TerraPower design give it a strong competitive advantage over the NuScale design in the commercial power marketplace?
My personal opinion that is no, it does not. My opinion is that the TerraPower SMR design is more technogically and programmatically risky because of its greater emphasis on load-following capability in comparison with the NuScale design, which in any case will be good enough.
Naval Reactors operate anywhere between about 5% and 100% power. They are PWRs, like most of the commercial operating reactors, but the fuel design is different, because they try to avoid having to refuel the reactor, which is a major PITA. I think the aircraft carriers are now operating with one planned refueling during the ship’s lifetime, while the submarines have enough fuel for the life of the ship.
Their fundamental operation is the same as commercial reactors. The limiting factor for “load following” is the number of thermal cycles it imposes on the fuel, which causes the fuel to age faster than it would if it operated at a constant power level. Aging of the fuel has to be taken into account in accident analyses, because fuel that has more cycles has more microscopic cracks that could allow fission products to escape from the fuel, and potentially into the reactor coolant system, during a serious transient or accident. Naval fuel is designed to accommodate that aging phenomenon due by power cycling. Commercial fuel could also be allowed to load follow, but the accident analyses would limit the lifetime of the fuel, requiring more frequent refueling.
The French already operate a number of their reactors in load follow mode, because they have such a large fraction of nuclear plants in their generation mix. It is not dangerous or difficult, it just costs a little bit of extra money.
Chernobyl style…
Having been involved in cost and schedule estimating for nuclear projects in the fifteen to twenty billion dollar range, I view the currently published schedule for the TerraPower SMR as being a complete fantasy. 2035 is a more realistic date assuming everything goes perfectly.
The fact is that most current reactors can load follow — if they have to. But most reactor operators in the US prefer not to do that. Rather, it is more economical and technically efficient to use gas-fired plants for that job.
TerraPower is gambling that over the long term, the use of gas-fired generation for purposes of load following for the renewables will be systematically eliminated. Their SMR design is intended to be better economically and technically at load following than is the current generation of reactors.
But here is another issue which isn’t often discussed publicly in nuclear power circles.
The systematic elimination of coal-fired and gas-fired power generation capacity from the grid without adequate replacement will eventually result in serious shortages of electricity. Every legacy power plant which still remains connected to the grid will be under gradually increasing pressure to either produce power at 100% capacity, or else to be offline altogether when the renewables are dumping excess power.
This is just my opinion, one that is not universally shared by any means. A TerraPower SMR which begins its operational life as a load-following plant is likely to become a full time baseload plant as the grid’s power reserves gradually decline over time. At which point we might as well have built a less technically sophisticated SMR which does not place nearly as much design emphasis on load-following efficiency.
When you said “current” plants it caused me to think about what the “spectrum” of nuclear plants in this country actually is. Are there any first generation plants in service? Are most plants now second generation or higher?
It seems to me that nuclear plants are in some of the same situation as coal. Because of environmentalism we haven’t commissioned a coal plant in 12 years and so a lot of the coal fleet are older and inefficient. If politics hadn’t gotten in the way we might have pursued supercritcal replacements which would have aided in efficiency and thus reduced CO2 emissions. Instead we are headed to putting all fuel eggs in the natural gas basket, then abandoning that before its paid for itself completely, and into all renewables plus a little storage which is destined to fail quickly.
A lesson learned in the 1970s, and now apparently forgotten, is to not discriminate against one fuel or another. Make incremental changes.
Kevin, going with wind, solar, and nuclear is strictly a public policy decision. In the absence of government’s low carbon and zero carbon mandates, the power markets would shift decisively towards gas-fired generation.
We buy nuclear because it gives us a measure of energy reliability and security, but at a cost premium over what gas-fired generation costs.
In the case of nuclear’s energy reliability and security, we generally get what we pay for, as opposed to what we actually get with wind and solar for the huge sums of money we now spend on renewable energy.
Here in the US, all of the 1st Gen prototype power reactors have been decommissioned. For myself in looking at the history of nuclear reactor development over the past sixty years, I see the labels Gen II and Gen III as being an over-simplification of reactor evolutionary history.
In regard to the oncoming reactor designs now on the horizon, we see the labels “Gen IV” and “advanced reactor” being used to identify the newer designs as opposed to the legacy designs.
Yes, the oncoming reactor designs encompass many differences in their driving operational requirements in comparison with past designs. And so our current design implementations are different from past design implementations to one extent or another.
What I see as important for purposes of limiting technical and programmatic risk in fielding these new reactor designs is the extent to which one set of operational requirements becomes dominant in the technical design implementation scheme versus some other set of operational requirements.
See my comment on that score here. I remain convinced that the NuScale SMR design will be the first to enter commercial service in the US, simply for the fact that NuScale’s design philosophy is to deliver the most SMR advantage for the least technical and programmatic risk.
One key word missing in this piece is “storage”, the magical solution to inflexible thermal generation. One approach to dealing with this issue would be to require that all renewable generation plants be dispatchable, with the same annual availability as coal generators. Some such approach would be unavoidable as thermal generators are retired by age, economics or government fiat.
I am pretty well convinced that storage will never be affordable in any away other than to handle minor intra-day shortfall — i.e. things like the duck curve. I know most people don’t have the time or patience to read the obligatory Integrated Resource Plans (IRPs), but they are remarkable documents for their combination of relatively good near time analysis with magical thinking beyond — the changes from one IRP to the next one two years later is also instructive. Ours change quite a lot in the direction of increasing short term reality.
Yes. Traditional fossil fuels and nuclear already perform the storage function. It is called having unburnt fuel stocks immediately to hand.
While there were other factors, before confronting the miners strike in 1984 Margaret Thatcher made sure they ramped up coal stocks so that the problems of the previous strike in 1972 could be at least partially circumvented.
Dimwit communist Arthur Scargill then started the miners strike at the end of winter, not the beginning.
Power station oil tanks were also filled. Some had 5 months supply at full output.
Storage is one of those ultimate ironies for renewable energy and environmentalists. When the first nuclear plants were built, there was a proposal to build pumped storage facilities up the Hudson River from Indian Point, so that IP could operate continuously at full power. In those days, there was a LOT of load following going on in NY.
But the environmental movement got part of its start in opposing pumped storage for IP. They said that it was environmentally unacceptable because it would innundate precious wildlife areas and create dead zones when the water rose and fell. There were also questions about the effect of the pumping on fish stocks. Standard environmental objections.
Now, ironically, their preferred method of generating power really needs storage for the times when it doesn’t work. I think they are still opposed to pumped storage, for the same reasons, and when they find out what sort of storage will be needed for wind and solar, they will probably oppose that, too.
They really want to turn the lights out, everywhere, forever.
Excellent writeup, Kevin Kilty. Keep up the good work.
“No matter how the costs are accounted for, the consequences demand higher rates.”
For years now, intermittent wind and solar sources have been allowed AND INCENTIVIZED to inject power into the system when produced, with no responsibility to deliver any power at all when it is calm or dark. This is operationally and therefore financially parasitic to the reliable dispatchable sources.
It cannot be otherwise.
Buckle up for the slow motion wreck. And vote out the ideology-locked representatives and executives, especially state governors, that support “climate” action.
Thanks, David. I find it amazing that no matter the problem which appears and then grows with more renewables, certain people find a way of blaming on fossil fuels. They easily ignore that the capable and reliable grid we have at present grew on the back of a diversity of mainly fossil fuels — must have been luck.
Someone must admit the realities that Figures 2 and 3 show.
Nope it’s not gunna happen until the increasing penetration and dumping by renewables crashes the grid. Only then will it become obvious out loud to the hastily convened Commission of Enquiry as to what went wrong.
Classic fallacy of composition as political idiots believe they can disprove a fundamental axiom of engineering- Namely you can’t build a reliable system from unreliable componentry. You’re in engineering and need to pay the bills you realise you’re getting paid via the political idiots to shut your gob and shrug and get on building the unreliable componentry.
No discussion of the consequences of storm damage to power generating facilities. Can you harden wind and solar against hurricanes, tornadoes, ice storms etc? What happens when those renewable generating facilities get destroyed? How long will it take to rebuild the ability to generate power let alone dispatch it?
Thanks for this detail on rate setting. While I have had the general outlines in my head from my years in that industry, this crystallizes the process.
Some years ago, in the post-TMI soul-searching amid the Carter recession years, many states, including New Jersey, where I worked, decided to require utilities to get a “Certificate of Necessity” prior to constructing new facilities. This came as utilities were cancelling nuclear power plants that were pretty far along in construction, both because the costs grew astronomically (due to high interest rates at the time and the extensive modifications required by post-TMI regulations) and because electric demand forecasts declined due to the recession. Many companies were asking to increase rates to cover the costs of these now cancelled assets.
I don’t know if a certificate of necessity is still required up front, but if so, that is where the justification for a facility is decided and any subsequent increase in costs becomes a moot point. The state has already agreed the facility is necessary.
Good comment. There are routine applications and hearings on public necessity and convenience around here. You are correct that because permission is granted before rates are established that this just amplifies the asymmetry between the public/psc on one hand and the utilities on the other.
The recent rate case I allude to in Minnesota is a example in contrast, however. Xcel was asking for $170 million to build 750 or so charging stations across the state without having established need first. Went down in flames.
‘More important, though, is to note the anticorrelation between wind or solar and coal thermal energy…’
I think it’s more important to look at the correlations of wind and solar to load.
For PJM, at least, the former is indeed anti-correlated with load, meaning that if one were considering wind power to reduce the hourly variance of serving load, a rational hedger would actually ‘go short’ wind.
For solar, there is a very slight amount of variance reduction taking place at the currently low level of solar penetration, but even this benefit disappears and reversed as the amount of solar increases.
Having said that, the article is another fine contribution from Dr Kilty.
You are correct that how well wind and solar serve demand independenly of any other sources is also important. However, wind and solar can vary from positively correlated to negatively correlated with one another, and both anticorrelated with demand. Wind is a special mess in all this. It simply goes away on its own accord. That people like to brag about being able to accurately forecast wind means little without a positive method of handling shortfall.
Demand response is one of the common answers provided, but I am willing to bet that because folks constantly are too optimistic about things, there isn’t really as much demand response available as they have estimated. I recall reading that IPCO, i think it was, had learned this through some audits. Besides how does a person account for the economic hit of shutting down enterprises when power has to be prioritized to residences?
‘Wind is a special mess’ is absolutely correct.
Absent subsidies or special treatment, I have no problem with people installing solar panels to shave off a few kW from their load, particularly since utilities and grid operators can account for this in their day ahead and real time planning. But wind is just God awful.
I did not intend this to be a forum to bash the power companies. I have gotten good service at affordable rates from mine, Rocky Mountain Power, for a decade. They are between a political rock and a environmentalists hard place — some of finding themselves there was their own doing. But I do note that much testimony often is contra their PR. I became an opponent of this rate increase just over the propaganda I read.
The Sierra Club are simply awful. They show up at a hearing to oppose rate increases, but are demanding abandonment of coal and natural gas right now, and promote that it is possible to do so. They worry about the climate a hundred years from now, but not a peep from them the impacts of wind turbines on wildlife right now. Their present campaign against coal, which calculates a statistical number of deaths and then multiplies each by $10,000,000 to figure costs is one of their low points — one among many.
Good point. It’s like the old saying that there’s no such thing as a bad dog, just bad dog owners. At least out West, there’s some degree of rationality on the part of the regulatory commissions – here in the East, it’s hopeless.
Btw, what’s going on with WY’s governor?
Maybe I should write an essay about the puzzle that is Mark Gordon, but he is a “fence sitter” and his present difficulties arise from getting splinters in his pants rather than finding a better thought-through place to sit. Did it to himself. He really has no idea what to do about the coming utter destruction of Wyoming’s economy so he has settled on a strategy of saying “we are in favor of all of the above — solar, wind, coal, gas, nuclear, hydrogen, etc.”
But saying all of the above is not a strategy. It’s a way of letting all comers colonize the state. I have had meetings with some of his advisors, and come way thinking that performance will soon improve but then being always disappointed.
‘It’s a way of letting all comers colonize the state.’
Sounds like ‘Yellowstone’. Oddly enough, his bio paints him as a real life John Dutton.
In the UK the ‘private’ monopolist was the State which owned the grid, generation and retail. In the Thatcher era of denationalisation of State owned industries and their sale into private hands, grid, generation, retail were privatised to create a competitive free market: a wholesale market and retail market.
Of course the plan was only a partial success when Government just couldn’t resist regulation, and then lost its ‘free’ and ‘competitive’ element when along came climate hysteria, subsidy, preference given to wind, forced closure of coal, no new nuclear to replace elderly reactors because nuclear is not ‘green’.
Thus inevitable, along with carbon tax, saw energy bills rise, but the Government managed to lay the blame on ‘greedy’ energy company making ‘excess’ profits, so introduced price caps. As always happens, this led to reduced investment, reduced supply, more subsidies, higher cost to tax payers. So-called renewables may appear less expensive if only the market price is considered, but when all the subsidising is taken into account and the fact fossil fuel is still required as back-up, the price is much higher than if we just had coal & gas with some nuke.
Telecoms privatisation by contrast worked well. The former State entity was obliged to allow competitors to use the local loop – for a fee – but had to build their own trunk infrastructure, and could give competitive rates and service plans. Fortunately cellular telephony came after the Socialist nationalisation spree, so apart from selling frequencies, the State didn’t get its nose stuck into it.
Outstanding Kevin.
Indeed, a very good and clear exposition of the issues.
Thank you. Good article. Some commenters in the weeds and conflating issues with socialistic statements ..essentially “ trust the government” BS.
Comments section littered with evidence that WUWT readers remember up- and down- stock market events going back at least 30 years.
(implication is a prepondence of people who have paid attention for a long time)