Das Buch „Shorting the Grid: The Hidden Fragility of Our Electric Grid“ von Meredith Angwin beleuchtet die Entwicklungen im amerikanischen Stromversorgungssystem bzw. speziell die Situation in New England. Zwar gibt es in einigen Bereichen andere Regulierungen, als in Europa, die Grundaussagen und eine Vielzahl der aufgezeigten Probleme sind jedoch auch für das europäische Netz und System gültig.
In today’s grid governance, I see more parallels with the 2007 financial system than I would like to see.
Diese Aussage könnte sich gerade Ende August 2022 in Europa auf drastische Weise bestätigen. Ein außer Kontrolle geratener Strommarkt könnte wie vor 15 Jahren eine folgenschwere Kettenreaktion losgetreten haben.
The financial activities described in The Big Short have many parallels with the current state of much of the power grid in America. In the old days, regulatory bodies wanted to see a grid with reliable power plants and, hopefully, plants that used several different types of fuels. A varied grid meant that, if one fuel had shortages or rose in price, the grid would still be stable, and cost would remain relatively stable. In current grid governance, none of these things matter. In many areas, power plants that make steady, reliable power can’t make a profit. Several large utilities are trying to sell or shut down their nuclear, gas, and coal plants in these areas. These utilities plan to operate plants only in other parts of the country.
Utilities are leaving the Regional Transmission Organization (RTO) areas. These areas have auctions for electricity (and for many other facets of electricity supply).
IN THE RTO AREAS, no group or agency has the responsibility for grid reliability.
No agency is in charge of ensuring that there are enough power plants and power lines to keep the grid operating.
Fragility is the most dangerous problem. In the near future, “rolling blackouts” may become common in many RTO areas.
What about the “free market”, which could conceivably use its invisible hand to bring reliable electricity to the customers? There is no free market. There are false markets, ruled by insider decisions.
How the grid is managed is not transparent, and it is not intuitive. People who work in the utilities do not necessarily understand it. Often, people who work in the regulatory bodies can’t answer my questions and refer me to someone else who can answer them. I am not alone in my confusion.
THE GRID IS ABOUT KEEPING the lights on (I call this the Power Grid) and about payments and policies (I call this the Policy Grid.)
However, most of the problems on the grid arise in the Policy section.
The grid we want
- Reliable electricity
- Relatively inexpensive electricity, so everyone can use electricity for their health and happiness
- Electricity made with low levels of pollution and low levels of ecosystem disruption
Production and consumption are always in balance, in real time. That is the angelic miracle of the grid. Electricity is made in real time.
People have been working on storage since I entered the workforce, more than forty years ago. Some improvements have been made, but the barriers are huge. Storing electricity means losing some energy on the round trip: power into the storage, power out of the storage. This will waste some power. Some power absolutely will be lost to the round trip. Also, if we choose battery storage, we have to realize that manufacturing batteries is resource intensive. For example, it would take vast amounts of specialty mining if we decided that we needed to build lithium batteries at grid scale.
However, people who are sure – in – their – hearts that renewables can do everything usually assume that the storage problem is solved somehow. It isn’t. And such people rarely acknowledge that any storage solution will be subject to the materials – availability issue and the round – trip – power – loss issue. Moreover, to store electricity and use it later, we will have to make more electricity than if we used it immediately.
However, since most renewables are available only part of the time, they must be backed up with other forms of power. Therefore, transmission costs do increase.
Electricity generation is a simple technology with a complex set of rules, while the phone system is a complex technology with a simple set of rules.
With solar, the course of the sun across the sky can form a “duck curve” on the grid. The duck curve happens on a sunny afternoon when demand on the grid is low because so many solar installations are providing power to homes and to the grid. In the afternoon, solar contributes power to the grid. But eventually the sun goes down, and thermal plants have to ramp up quickly to provide the power that solar had provided.This ramping requirement is called the “neck” of the duck curve. The neck of the duck curve is becoming an issue in areas with a lot of solar. Solar input to the grid tends to be highest during summer afternoons. However, when the sun goes down, the solar goes offline rapidly. The BA then orders the dispatchable plants (thermal plants, hydro plants) to ramp up, and they often have to ramp up faster than the solar is ramping down. Faster because people have a tendency to turn on a light as the sun sets, or come inside and begin cooking dinner, and so on. There’s a rule of thumb on the grid that no plant should be so big that it is more than 10 % of the average demand on the grid. One plant going offline should not take 20 % of the grid’s power with it. People look at solar as a distributed system: my rooftop, your rooftop, and a solar array down by the Interstate. No huge power plants here! However, in fact, solar often acts like a single megaplant, which switches off in the early evening. This is another issue that the BA must face.
We must now move to the more depressing area of payment and policy, which is quite capable of wrecking what the BAs and engineers have achieved.
ELECTRICAL ENGINEERS WHO specialize in the grid learn how to handle many complex issues: balancing users with suppliers, keeping the “imaginary” part of the grid (VARs) in balance while keeping the visible part of the grid (voltage and frequency) in balance. The grid is a modern miracle. It takes technical knowledge, computer power, and skill to operate it. In contrast, in many parts of the country, understanding how the power is paid for is a black hole of impossible acronyms and “I can’t believe this” payments.
The utility also got paid a rate – of – return on its expenditures. For example, if the utility had to build a power plant, it was allowed to charge enough money to build it and to make a rate – of – return profit on building the plant and running it. However, in many jurisdictions, a utility’s rate – of – return could be lowered if its customers ’ lights went out too often.
Therefore, before RTOs, it was in the utility’s best interest to spend “whatever it takes” to keep all the power plants and transmission systems in top shape and to have crews ready to fix problems very quickly. In other words, the higher the reliability, the better the chance of a high rate of return on the utility’s investment. The second way for a utility to make more money would be to invest more money, resulting in a bigger “rate base,” as it is called. It was in a utility’s best interest to build more power plants, run a visitor center, replace worn – out poles, and so on. It all went into the “rate base,” and the “rate of return” percentage calculation was based on the rate base. Someone noticed (many people noticed) that this was basically a perverse system. The way for a vertically integrated utility to make more money was … to spend more money. Unlike Joe’s deli down the street, which was always trying to be more efficient with money, in order to have larger profits, a vertically integrated utility wanted to be less efficient with money, so they could have a bigger rate base and larger profits. One of the ways that utilities made more money was to overbuild power plants, that is, build too many power plants. Presenting a somewhat inflated projection of electricity needs in the future could justify a new power plant, which would be approved by the local regulators. The cost of building the plant would go into the utility’s rate base. In this sense, a new power plant generated utility profits, whether or not the electricity was needed. Utilities always need more power plants than their peak power use (they have a reserve margin of plants), but under vertical integration, the reserve margin tended to grow along with the rate base and the utility profits. Now, of course, the utility couldn’t just build things and spend money. A state regulatory agency had to approve the expenditure.
At the state level, utilities tended to get a little cozy with their regulators (“regulatory capture”). Overbuilding and overcharging customers was often the result. On the other hand, the utility had incentives for building a very reliable grid.
LOOKING AT THE PERVERSE incentives for integrated utilities, many people had the idea that a market would fix these high prices — if the utilities could just be forced to compete in a market.
The idea was that, if utilities participated in a market economy, resources would be used efficiently, and customers would be served better.
Distribution utilities are usually “regulated” in the same way as vertically integrated utilities have been “regulated”: with a rate of return. In contrast, generation utilities are supposed to compete in energy markets and auctions.
The auctions between power plants removed each power plant’s incentives for reliability. As a matter of fact, the grid itself can become less reliable. In my area, studies of the future of the grid show the strong possibility of rolling blackouts in winter weather, due to insufficient generation to meet the high demand. In
Since electricity is made and used instantaneously, and natural gas for power plants is delivered just in time for use, sometimes the two “just in times” don’t mesh, and that leads to trouble.
both sets of needs: they cannot deliver enough gas to homes for heating needs and simultaneously deliver enough gas to power plants to make electricity. In this situation, gas – fired power plants may not be able to get fuel.
Oil, coal, and nuclear plants are prepared for demand variations because they store fuel on – site. In contrast, gas plants are supplied by pipelines: They get the fuel when they need it — if the pipeline has it available. Using natural gas for electricity means that real – time electricity meets real – time pipelines. Everything has to happen right now. In some circumstances, it was clear that this would not end well. Homes use natural gas for heat, and homes have priority on the pipeline. In very cold weather, when homes need a lot of gas, power – plant gas supplies are interrupted.
The usual daily price for natural gas in this region is about $ 4 per MMBtu. On January 4, 2018 gas was $ 87 MMBtu. (MMBtu stands for 1 million British thermal units. One Btu is the amount of heat required to increase the temperature of one pound of water 1 degree Fahrenheit.) Electricity prices on the grid also ran very high. The usual grid prices of 2 cents to 8 cents per kilowatt – hour went up to 15 cents to 40 cents and stayed high for days.
In this auction, run by the RTO, plants bid in to sell their power (kWh). They bid in five – minute intervals. But the kWh auction is not the only auction run by an RTO. The RTOs set up many auctions, including new auctions to correct the results of older auctions. If there is a problem on the grid, an RTO will usually try to set up an auction to solve it.
For the winter – reliability projects, ISO – NE set up a new kind of auction. Dual – fuel power plants (power plants that could burn both oil and gas) bid in a special auction for the reliability program. They bid in their proposed costs for storing fuel on – site, planning to use the fuel when they could not obtain natural gas from the pipelines.After the auction, ISO – NE picked the low bidders.
To most of us, the winter – reliability auction looks like a clumsy but effective way to get fuel storage without actually ordering a particular plant to store fuel. Such orders would be expected in a vertically integrated utility but are forbidden in an RTO area.
A demand – response customer promises to go offline when the grid is stressed. Such a customer was allowed to bid into the winter – reliability auctions, just as oil – fired plants were allowed to bid. A demand – response customer would be paid for not using electricity, just as a power plant would be paid for keeping oil or LNG on – site.
Unfortunately for ISO – NE and the grid, there usually isn’t a big response to demand response. In 2013, ISO – NE bought 1.9 million Megawatt – hours (MWh) worth of bids for the Winter Reliability Program. Only 4,000 MWh of demand – response customers bid into the auction. The rest of the bids were for oil on – site. This ratio did not change very much in subsequent auctions. In 2017 – 2018, ISO – NE paid approximately $ 24 million for oil as part of the Winter Reliability Program but paid only $ 34,000 for demand – response bidders. ISO – NE just doesn’t get that many demand – response bidders.
I am just pointing out that you can offer to pay customers to give up electricity on very cold days. However, very few will take your offer.
The idea of Pay for Performance is that plants will be penalized if they don’t go online when the grid is stressed. Hopefully, the fear of a penalty will encourage plants to keep oil on – site, without the RTO actually mentioning “oil.” It’s almost impossible to understand the complex formula of Pay for Performance.
First, it had to define “when the grid is stressed.” Plants go offline for maintenance, and so ISO – NE can’t just slap a penalty on any plant that doesn’t go online when called.
Next, ISO – NE had to define “go online when called.” One of the issues has been that some plants (steam plants) ramp up slowly, and other plants (internal combustion) ramp up rapidly.
WE HAVE SEEN THAT RTOs make a mountain of a small hill: they are unable to take simple steps to ensure winter reliability.
In the pre – RTO system of vertically integrated utilities had some major problems. The system had perverse incentives: it encouraged a utility to spend as much money as possible in order to get the highest profits it could obtain.
What lesson did the airline industry illustrate for the utility industry? There were two lessons: Deregulation leads to lower prices, better service, and more customers Deregulation does not lead to more accidents. The safety – regulation part of the regulatory scheme stayed in place and perhaps was even enhanced.
Airline deregulation showed that deregulation did not have to affect safety.
Deregulating the phone system led to lower costs, more choices for long – distance carriers, cell phones all over the place, and all sorts of good things for the consumer.
In other words, even before cell phones became common, breaking up the telecommunications monopoly improved the choices for the consumer. Phone deregulation showed that there could be significant consumer benefits to deregulation, even with one line into the house.
And yet, and yet … something went wrong with utility deregulation. Careful analysis may show some savings for consumers in the deregulated utility areas, but a first – pass look at the situation shows no savings (see figure 6). You have to look closely and analyze hard to see any savings in the deregulated areas, a situation quite unlike airlines and phones.
The model for the deregulation was similar to the one for phone deregulation.
WHY DID AIRLINE AND PHONE deregulation work for the consumer, but not utility deregulation?
- No consumer choice: In contrast, very few utility ratepayers were given any choice after deregulation. Ratepayers are still ratepayers. Prices didn’t fall after supposed deregulation. Without consumer choice, prices can’t be expected to fall.
- No transparency: The stakeholders (insiders) meet in secret or semi – secret. They all have very good economic reasons to use their full power to influence which power plants are on the grid and how those plants get paid.
- No accountability: Nobody is accountable for the grid. A power – plant owner can run his power plant well or badly: it’s not his plant’s fault if the grid can’t get enough power.
Distribution utilities still have regulated rates of returns and have to keep their lines and substations in good shape. Generators do not have that level of responsibility.
Generation utilities are not really utilities. They are power – plant owners who sell into the wholesale markets, and they run their plants as long as they see the plants as being profitable. They are not guaranteed a rate of return, and they are often called “merchant generators.” The distribution utilities buy power on the wholesale markets, and they sell the power to their customers.
Nobody is responsible
Every individual plant makes money when it runs. If a plant needs maintenance or whatever at an awkward time, it’s not making money at that time. That individual plant is not responsible for keeping the grid going. No individual plant owner is responsible for the grid.
THE SYSTEM WAS SET to be gamed.
California: They closed plants for “maintenance” in order to create scarcity and drive up the wholesale electricity price. Their other plants received the new high prices.
California regulators had told the distribution utilities that they had to pay market costs, but would be limited in what they could charge customers. Their costs could rise, but their revenues could not rise. When some of the distribution utilities began losing money and being late with their payments to generators, some generators ran out of money or patience for extending credit. They simply didn’t buy fuel to run their plants or produce power, since they were not sure they would be paid in a timely fashion.
In New England, grid fragility arose because nobody could order a plant to be ready to run. In California, the fragility was partially due to the system being gamed. In both cases, it was the RTO rules, not natural disasters, that led to the problems.
Market manipulation was successful in California because there was nobody responsible for making the system work.
IN THEORY, IF ELECTRICITY IS really a market, then nobody needs to take responsibility for how it operates.
There’s a famous metaphor about the difference between markets and planning: “Who feeds Paris?” Who does the planning that ensures that Paris will have enough food every day? Is there a central planning agency at the Hôtel de Ville? Of course, there isn’t. The market feeds Paris. There is no central planning authority.
That was the hope of the RTO areas. But the hope was not fulfilled.
The RTO areas are more heavily regulated than the non – RTO areas. They are not markets as we know markets. They are complex systems, with new regulations constantly tweaking and trying to improve existing regulations. They are a bureaucratic thicket, not a market.
LET’S EXAMINE THE INCENTIVES for a power – plant owner in an RTO area. The owner has to decide: Will this power plant run often enough to generate enough revenue for its upkeep? Will it be a hard winter (my power plant will run a great deal, and I will make lots of money) or a mild winter (maybe not so good for me)? How much will my fuel cost? What will be the price on the grid? In other words, with complete uncertainty as to revenues, each power – plant owner had to make a decision about paying for maintenance of the power plant. If an owner has more than one plant, the owner must decide separately on the fate of each plant. Will that plant make money? Should I shut it down?
All these decisions looked dangerous for reliability. Companies could just shut down their power plants. Too many power – plant owners could decide that their power plant wasn’t going to be paid enough, and then there wouldn’t be enough power plants on the grid. Or power – plant owners could game the system by shutting down power plants (as they did in the early days in California).
the plant is not only selling kWh, it is also selling something else the grid needs. It is selling power – plant capacity. It is selling its availability to make power when the grid needs it. In many RTO areas, plants sell “available capacity” whether or not they are making power at the moment. Power plants get capacity payments, and they can use these payments to maintain their plants.
Under vertical integration, it didn’t matter very much which plants a utility dispatched, since it usually owned all the plants anyway. Still, even though the utility was allowed a rate of return on their investment, the PUC tried to ensure the utility would attempt to keep the customer rates as low as reasonable, considering the plants in their fleet.
Least – expensive – first wasn’t (and isn’t) the only constraint. There are physical constraints also. All other things being equal, the dispatcher will choose to dispatch plants that are near the load so there won’t be excessive line loss. The dispatcher must also keep track of how much electricity a line can carry, and not overload any of the lines.
When I am teaching my grid class, I can always get a gasp out of the crowd by explaining the basic auction. “So,” I explain, “I’m the RTO, and I need 500 MW right now, or rather, I need it for the next five minutes. The auction runs every five minutes.” Power plant A steps up: I’ve got 200 MW for you, at 15 cents per kWh. Plant B steps up: I’ve got 100 MW for you, at 20 cents per kWh. Plant C steps up: I’ve got 300 MW for you, at 30 cents per kWh. I’m the RTO, and I answer: “Okay, plant A and plant B, I’ll take all your output. Now I have 300 MW. Plant C, I’ll buy 200 MW of your output, but I don’t need all 300 MW. I’ve got my 500 MW now. “All you plants, you get 30 cents per kWh for your output. Plant C has set the clearing price for this round.” At this point, the people in the class begin to shake their heads: “So plant A bid in at 15 cents and is getting 30 cents?” The answer is: “Yes, indeed.” That is how the auctions go. This “clearing price” system is usually considered the incontrovertible method by which ISOs run. I want to point out that not everyone is happy with this scheme. “Clearing Price” is not written in the heavens or in the laws of physics. It is just how the ISOs do things. It could be changed.
Shocking thing the second: RTO control
If you are paying off a high – priced plant, you can’t add any of that expense into your energy bid. But if you are receiving payments for Renewable Energy Certificates, you can take those payments into account and bid at a lower cost for your kWh. RTOs claim to be fuel – neutral, therefore, all expenses and income streams for all types of plants are equal in the eyes of an RTO. But some are more equal than others.
Shocking thing the third: payment according to their costs
The payment money depends on other people’s bids.
Setting a price for electricity in an RTO area is more complicated than setting a price for zucchini. You are going to have to compete separately on capital costs and production costs, and your bid is sliced, and it is diced. You have a kWh bid and a capacity bid and maybe an extra capacity payment bid (Pay for Performance, and maybe another payment for ancillary services). You don’t get to decide on any of these bids. And the RTO will be looking over your shoulder every five minutes to be sure you do it right.
IN AN RTO ENERGY AUCTION, power plants get paid the clearing price for those five minutes. They get paid the clearing price, no matter what they have bid.
The main explanation for Pay at the Clearing Price is that the clearing price is attached to the marginal cost (for the highest – priced plant), while Pay as Bid would mean that utilities would bid in at the price they hoped and expected to get, which would be more than their marginal costs. So, the bids would have some randomness that the RTO would not have a method to control. The plants would control their own bids. Exactly this sort of thing happens in real markets. Everyone tries to outguess and outcompete everyone else. Naturally, those in charge of the electricity “markets” hate this.
The supposed fear is that “Pay as Bid” would lead to higher prices. In fairness, that could be an issue for power plants, where there are just not that many bidders (unlike the hundreds of farmers that could supply zucchini or butter to Paris).
In real markets, after a while, everyone learns how to bid properly to make a living. Also, real markets tend to be a little cutthroat, which tends to benefit the consumer.
In the long run, RTO markets punish reliable plants and support unreliable plants.
In other words, we aim at having fuel – neutral markets, but once we do things differently and we are out – of – market, then pretty much anything we do is okay.
ISO – NE’s filing begins right after the main transmittal letter, and the first ISO – NE document within that filing is Attachment I – 1a. That document begins by describing how the current forward – capacity market is seriously flawed, to the point of actually being broken. Plants bid into the capacity market, giving the impression that plenty of capacity is available, but then, when those plants are called during a winter emergency, they say something like “Sorry, the cat ate my homework.” Actually, what they say is “Sorry, I can’t get any gas to run my plant.”
Even worse than its effects on the investment decisions for individual resources, however, is the effect of this exemption – laden, flawed availability – based performance metric on the New England fleet as a whole. Because resources that do not contribute to system reliability during scarcity conditions earn the same capacity payments as resources that do, it is profitable for resources with low costs and poor performance during scarcity conditions to remain in the capacity market. These low – cost, but poorly performing resources displace higher – cost but better – performing resources. These higher – cost resources, because they would contribute more to system reliability, are actually more cost – effective than the resources that displace them. In effect, then, the current FCM (forward capacity market) has a structural bias to select less – reliable resources, an outcome completely at odds with the goals of maintaining reliability in a cost – effective manner.
With nobody responsible for the grid, the unexpected consequences never seem to end.
ICF International also predicts that plants will be more uncertain about their capacity payments. Of course, the point of Pay for Performance is to increase this uncertainty: if your plant doesn’t go online, you won’t get paid. On the other hand, much of the uncertainty is totally out of the control of the power plants. How many hours will the grid be in a stressed situation that triggers Pay for Performance? How stressed will the grid be? Will your plant get online and get paid, or not get online and have to pay others? The original point of capacity payments was to provide a backstop for plants that follow load and don’t run all the time. Apparently, this worked too well: plants got the capacity money, but the grid still didn’t have all the resources it needs. Pay for Performance erodes part of the backstop, in the hope that this will lead to more reliability on the grid. Maybe it will (I doubt it), but maybe we will need a couple more rounds of regulation to fix the problems created by Pay for Performance.
In my opinion, something needs to be done about fuel security for the grid. The RTO grids are moving toward fragility and rolling blackouts.
ISO-NE initially ran 23 scenarios for the future of the grid. In 19 of the scenarios, the grid would have rolling blackouts by the winter of 2026. There was only one scenario where the grid had a solid, no – emergency operation. That no – problem scenario had very optimistic assumptions and included increased deliveries of LNG (liquified natural gas).
IN THE FUEL – SECURITY STUDY, ISO – NE modeled the temporary closure of a major gas – fired plant, Mystic Station. This temporary closure would lead to rolling blackouts. The time – frame that ISO – NE modeled was the winter of 2025 – 2026. In March 2018, Exelon, Mystic’s owner, announced it planned to close the plant permanently in 2022.70
When there’s not enough supply of electricity to meet demand, a grid operator cuts power to one section of the grid to keep the rest of the grid from failing. After a while, the operator restores the power to the blacked – out area and moves the blackout to another section. That is a “rolling blackout.”
that is when the grid is most stressed. Rolling blackouts add painful uncertainty — and danger — to everyday life. You aren’t likely to know when a blackout will happen, because most grid operators have a policy that announcing a blackout would attract crime to the area.
In early April, Chicago – based energy provider Exelon Corp. said it would close two large natural – gas units at Mystic Station, Massachusetts. In its report about possibilities for the winter of 2024 – 25, ISO – NE had included the loss of these two plants in one of its scenarios. The ISO – NE report concluded that Mystic’s possible closure would cause 20 to 50 hours of “load shedding” (meaning rolling blackouts) and hundreds of hours of grid operation under emergency protocols. When Exelon made its closure announcement, ISO – NE realized that the danger of rolling blackouts was suddenly more immediate than 2024. It now hopes to provide “out – of – market – cost recovery” — subsidies — to persuade Exelon to keep the Mystic plants operating.
We could plan to import more electricity from Canada, instead of importing more fuel, but ISO – NE notes that such imports are problematic. Canada has extreme winter weather (and curtails electricity exports) at the same time that New England has extreme weather and a stressed grid.
To avoid blackouts, we need to diversify our energy supply beyond renewables and natural gas to have a grid that can reliably deliver power in all sorts of weather. We need to keep existing nuclear, hydro, coal, and oil plants available to meet peak demands, even if it takes subsidies. Coal is a problem fuel, but running a coal plant for a comparatively short time in bad weather is a better choice than rolling blackouts. This can’t happen overnight. It has to be planned for. If we don’t diversify our electricity supply, we will have to get used to enduring rolling blackouts.
ONE OF THE WAYS that the Synapse Report achieves happy outcomes is with misplaced concreteness. There’s a name for taking – targets – as – actual – reality. In logic, it is called the “fallacy of misplaced concreteness” or “reification.” A more common description for this fallacy is sometimes stated as “the map is not the territory.”
In other words, despite the fact that states and even countries (see Germany) routinely fail to meet their renewable – energy targets, Synapse claims that ISO – NE should take those targets as the reality for planning.
“It’s a rare event — so don’t worry so much”
However, the pipeline issue is a nationwide issue. When areas close their nuclear and coal plants, and move to natural gas, they often cannot build pipelines to handle the increased quantities of natural gas that they will need.
No matter how much shale gas we find, it is the size of the pipeline that determines how many power plants can be supported. Inability to supply natural gas is yet another way that the grid becomes fragile.
We can’t run a grid on wishful thinking. In the RTO areas, wishful thinking often prevails. The consequence of wishful thinking is a fragile grid.
To paraphrase: if a generator decides to store oil for days when the grid is stressed, the generator must spend money upfront to buy the oil. However, having the oil (especially if many generators decide to do this) will alleviate price spikes, and the generator will get less money when the price spikes because gas is constrained. Keeping fuel on hand is a lose – lose game for the generator. Upfront expenditures will lower future revenues.
In short, if ISO-NE paid for oil for winter reliability, the power plants were willing to buy and store oil. Without ISO-NE funding, they didn’t buy oil. This is perfectly in line with the perverse incentives on the grid. The power plants do best when the grid is doing worst. When many power plants have uncertain fuel supplies, and the grid is stressed, then electricity prices rise. At that point, many power plants make excellent profits. They don’t even have to manipulate the markets to do this: the incentives are perverse enough on their own.
THE GAS INDUSTRY OFTEN sponsors advertisements that show gas as a good partner for renewables. In the ads and in real life, gas turbines back up the output of wind. When the wind’s not blowing, who you gonna call? The gas turbine, of course. That is true. However, those advertisements tell only part of the story. Gas and wind aren’t just partners in keeping the lights on ; in the RTO areas, they are a mutual – aid society about funding. When the wind energy lowers the real – time energy price, the gas plants make a kind of bonus payment as they shut down for a while.
In terms of assessing the charge for transmission, however, the background idea is: Those who benefit pay in proportion to the benefit they receive.
However, under pressure from the spirit of deregulation, and perhaps more direct pressure from renewable groups, FERC recently changed the rules with Order 1000.95
In my opinion, FERC Order 1000 will break people’s trust in the fairness of transmission – system – cost allocations. FERC 1000 is a huge change, and it has flown under the radar.
If your New England state wants a transmission line to bring power from distant wind turbines to its city center, in the pre – FERC 1000 days, that would be something the ratepayers of that state would pay for. After FERC 1000, one state may decide on a policy, but all states will pay for it.
When all states have to pay transmission costs for one state’s policies, FERC 1000 will set up a “tragedy of the commons” for transmission. The classic “tragedy of the commons” is when a shared resource is overused and therefore depleted because each individual user does not have to pay for the effects of his own overuse of the system.
FERC 1000 sets up a similar problem for transmission costs and a similar level of distrust in the fairness of “socialization.” Why shouldn’t every state decide to buy some new transmission and meet their renewable goals — at the expense of all the other states? Why should state A pay for state B’s goals? And if state A is going to have to pay for state B’s goals, State A will try to arrange that State B pays for state A’s goals, too. This is the tragedy of the commons: every state expands its own share of the socialized payments, since all the other states are expanding their share of the payments.
A typical hot day on the grid was July 3, 2018. The peak was near 25,000 MW, which was pretty high. However, the prices were not high. The LMP (local marginal pricing) wholesale prices for electricity were between about $ 25 and $ 80 per MWh, or about 3 cents to 8 cents per kWh.
But is conservation in summer particularly wonderful? Not really. On a typical hot day, July 3, 2018, we had a fairly clean grid. The fuel mix was mostly natural gas, nuclear, hydro, and renewables (solar, wind, biomass). The grid was running at 60 % gas, 20 % nuclear, 16 % hydro and renewables. Pretty good, in terms of emissions. In contrast, during the cold snap at the beginning of 2018, electricity use never got much higher than 22,000 MW, but LMP prices spent a lot of time between $ 150 and $ 300 per MWh (15 cents to 30 cents per kWh). In the winter, when natural gas was not available, oil and coal were in heavy use. During the cold snap, the mix was 30 % oil, not “less than 1 %” oil, as it is now. Coal use was higher, also, up around 5 %. Though we were using less electricity in the winter, we had a more carbon – heavy mix of fuels.
The utilities are urging conservation in summer because they are playing the Game of Peaks. It’s a utility game about money. If they play the Game of Peaks well, they can shift some costs from themselves over to neighboring utilities. Yeah, it’s a zero-sum game (“I win” can happen only if “you lose”). Let’s look at the rules for that game.
CUTTING BACK ON ELECTRICITY use on the hottest day of the summer is not a moral imperative. It is merely part of The Game of Peaks. This game allows large utilities to shift costs to smaller utilities and co – operatives.
Nobody gets killed in the Game of Peaks, but lots of people get misled about the situation on the grid. And lots of people end up paying more than their fair share of grid costs. There are losers in the Game of Peaks. You may be one of them.
Basically, the percentage of power a utility uses during the peak hour is the percentage of transmission costs that the utility has to pay. If a utility can lower its electricity use for that one peak hour, it will save a lot of money by paying lower transmission costs for the grid. This percentage – of – load calculation is an opportunity for utilities to shift costs elsewhere. Utilities campaign about “shaving the peak.” Announcements state that “we saved hundreds of thousands of dollars by shaving the peak.”
In other words, “beating the peak” provides savings for Green Mountain Power customers, not savings for the grid.
Utilities are masters of greenwashing:
MANY RENEWABLE ADVOCATES like to say that baseload is an outmoded concept and that we don’t need baseload plants anymore.
Baseload is the electricity demand that is in place 24 hours a day, seven days a week.
TRADITIONALLY, BASELOAD POWER has been provided by “baseload plants.” These are plants that are very good at a steady, reliable, inexpensive operation. In general, baseload plants are steam plants: nuclear (my favorite) and coal (there are a lot more coal plants than nuclear in the world). The electricity demand that ramps up during the day and lowers late in the evening is generally provided by “load – following plants.” These are more expensive to run, but more flexible in following the load. They tend to be gas – fired plants and hydro. However, in France, nuclear plants are also used for load following.
When designing a plant, the designer optimizes for flexibility or for steady output. Of course, a steady – output plant can be somewhat flexible, and a flexible plant can be run in steady mode, but they are not optimized for these situations.
What the renewable advocates mean by “We don’t need baseload” is that we no longer have to go through the engineering discipline of designing some plants for baseload use and others for load – following use. It is sort of like saying, “We don’t need big trucks to carry goods down the road. They have very poor acceleration. They are not flexible. All we really need is sports cars, for everything.” The general idea here is that renewables will do it all. They won’t, but people want to believe that they will.
Pro – renewables advocates will imagine complex scenarios with inexpensive grid – level battery storage (which doesn’t exist yet and may never exist) or thermal storage and then making electricity from the hot fluid that you have carefully stored in some insulated cavern, and so on. “It could work.”
For example, ridgeline wind around here is more available at night. However, “more likely” to be available at night does not mean “you can count on wind power at night.” When people discuss how renewables “could” do it all, they generally describe a whole string of things that “could” happen, from advanced batteries to a new, huge set of continent – spanning high – voltage DC lines. “Could.”
Wind doesn’t make baseload power, and it doesn’t make load – following power. It blows when it is blowing, and the rest of the grid has to work around it.
In general, a standard hydro plant cannot be baseload because the turbines cannot run all the time. To operate, the hydropower plant requires a certain water level in the pond behind it. The level of water in the pond behind the dam sinks as water goes through the turbines. When the turbines stop running, the level of water rises as the streams refill the pond. Hydro is generally used for load following, or for filling in when other renewables (such as wind turbines) go offline.
Nuclear plants’ capacity factors average above 93 %, the highest capacity factor of any type of power plant. The average capacity factor for a hydro plant in America is about 40 %, and this capacity factor mostly depends on the availability of water.
This type of run – of – the – river hydro is basically another way to use several dams sequentially to provide baseload.
THERE ARE THREE MAJOR problems with integrating intermittent renewables on the grid. One is their “spikiness,” a second is their reliability, and the third is their effect on the power supply itself.
THERE ARE STUDIES THAT show renewables could provide all our power. Such studies assume grid-level battery storage (that doesn’t exist), or they assume that fifteen times the amount of hydro will be available from existing plants (not possible, even if some studies make this assumption), or they assume a huge buildout of cross – continent, direct – current, high – voltage transmission lines.
1. The need for backup power:
This study showed that the grid needs slightly more fast – reacting fossil available than it has intermittent renewables installed. (1.0 MW fossil installation is needed for every 0.88 renewable installation.)
A grid, large or small, needs as much quick – reacting fossil capacity as it has intermittent – renewable capacity.
Running a gas turbine in an on – and – off backup mode is like running your car in stop – and – go city driving. You don’t get the gas mileage in city driving that you get on the highway. Running an engine steadily is most efficient. So, using a gas turbine for renewable backup requires more gas per kWh than running the turbine steadily.
However, there is no question that some of the renewable advantage of “clean energy” is offset by extra gas burned inefficiently as backup.
Emissions can also increase with the increased use of renewables. Backing up renewables can cause inefficient operation of fossil plants, leading to an increase of emissions on the grid. In other words, as renewables increase, emissions can also increase.
Siehe die aktuelle Entwicklung in Deutschland, wo der CO2 Ausstoß deutlich steigt.
A study of wind (using 2014 – 2015 data and published in 2016) in Ireland shows that, when the fleet of CCGT (combined – cycle gas turbines) in Ireland run steadily at about 55 % fuel efficiency, the fleet produces 335kg CO2 / MWh. However, when backing up wind turbines, with more starts and stops and a lower fuel efficiency, the fleet produces 500 – 600kg CO2 per MWh. 139 However, total CO2 per MWh for the entire Irish grid went down in 2014 – 2015, even though the CO2 per CCGT went up. This is because wind displaces around 20 % of fossil – fuel use.
This stop – and – start driving raises the emissions of the backup gas plants. There is not a simple linear relationship between use of wind on the grid and reduced CO2.
As I described in the chapter on the Balancing Authority, when the sun goes down and there is a lot of solar on the grid, other power plants must ramp up very quickly. This rapid – ramping “neck” of the duck curve is energy inefficient. Think of how much gas your car will burn if you speed away from a stoplight as if you were in a race, compared to how much it will burn if you are cruising down the highway at a steady clip. It’s the same with a gas turbine.
A plant optimized for meeting the constant day-and-night load, a plant that runs steadily, can be optimized for efficiency and reliability, while another plant can be optimized for flexibility. That is how engineering works.
When clearing prices go negative, all suppliers (including very reliable suppliers such as nuclear plants and combined – cycle gas turbines) must pay to put their power on the grid.
However, the speed of the rotation is determined by the wind speed. The current cannot be added directly to lines because the number of cycles per second depends on the wind speed, not on the requirements of the grid. Therefore, wind – turbine AC is customarily converted to direct current (DC), and then the DC is re – converted to AC at the proper number of cycles per second for the grid.
legislators make other laws saying their state grid must be 100 % renewable. The laws of nature are not repealed by these renewable – mandate laws, and yet the laws are passed. Renewable – mandate laws have unrealistic plans for renewables (to put it mildly). They will not succeed in building grids that are 100 % renewable. However, such laws will succeed in making the grid more fragile and more expensive.
Compared to a power plant, batteries are not very scalable to grid level.
Everyone in the industry knows batteries won’t scale to grid – backup level. Nevertheless, the folklore of batteries is very strong.
The Sepulveda paper describes how they modeled more than 900 scenarios. 147 Their conclusion was that using only variable renewables plus energy storage would lead to wasteful overbuilding, with curtailment wasting huge amounts of renewable energy.
paper: “For zero – emissions cases without firm resources, the total required installed generation and storage – power capacity in each system would be five to eight times the peak system demand, compared with 1.3 to 2.6 times peak demand when firm resources are available.” In other words, if only variable renewables and storage were available, generation and storage – installed capacity would have to be five to eight times the peak – systems demand. Such a system would need reserve margins of 400 % to 700 % of peak demand. In contrast, on our current national grid, reserve margins of around 15 % of peak demand are common.
the amount of available wind and solar output that would be wasted due to curtailment in VRE – dominated (variable renewable – dominated) scenarios would be sufficient to supply 60 % – 130 % of total annual electricity demand …” In other words, after overbuilding by five to eight times, we would waste around 100 % of a year’s supply of electricity by curtailment (“Turn off your wind turbine — we can’t use the energy now”).
Malhotra calculates that providing 100 hours of backup for a single massive (1000 MW) coal plant would require 32,000 tons of lithium. In 2018, the global production of lithium was 62,000 tons.
When variable renewables have gone offline, and gas – fired plants must ramp up quickly to supply replacement power, a battery can supply a few minutes of power, and the gas – fired plant can ramp up more slowly. A slow ramp rate uses less fuel.
As usual, the problem is not with renewables or with batteries. The problem is that people aren’t planning for their use or how they might be most useful. Renewables and batteries are overhyped and are beginning to be overbuilt. Both can be helpful to the grid. Even together, they cannot be the grid.
In terms of carbon and renewables and nuclear, emotions run high, and beliefs are firmly entrenched.
As noted in chapter 15, “Selling kWh Is a Losing Game,” in many cases, renewables don’t have to make any money by actually selling their energy to the grid. They make money by selling RECs (Renewable Energy Certificates) and by receiving production tax credits. Renewables can pay the grid to take their power (negative pricing) and still come out ahead financially. Both RECs and production tax credits are paid by the kWh. If the renewables don’t provide kWh to the grid, they don’t get paid those extra compensations. So, their finances depend on selling power to the grid (at a loss) and making their money with the non – grid compensation. This has several effects. Due to the way grid pricing works, if there are
This is widely trumpeted by renewable advocates as “Due to renewables, prices are going down.” But there is a catch. They mean “wholesale prices on the grid kWh auctions are going down.” Prices to the consumer are going up.
Let’s look at a generator that is selling renewable kWh on the kWh auction. Say that this is a wind farm and is bidding into the auction at zero cents per kWh. Due to the auction method, the price for kWh on the grid will be lower, due to the presence of the wind farm. Yes, the clearing price at the auction will probably be lower. However, the wind farm also expects to sell RECs (Renewable Energy Certificates) as well as kWh. Some utility will have to buy those RECs to meet a renewable portfolio standard. The RECs will then be part of that other utility’s overhead, and, therefore, a ratepayer will pay for the RECs. One ratepayer is paying the grid clearing price for the wind kWh, and another ratepayer is paying for a wind REC through his distribution utility.
EVERY NOW AND AGAIN, we will see an announcement that some company is doing its part for the environment by using “100 % renewable” electricity. This is supposed to make us imagine a big industrial facility surrounded by wind turbines and solar panels. Well, no. That’s not the right image. Better to think about an accountant. When a renewable – energy source such as a solar panel or a wind turbine makes a kWh of electricity, it also makes something invisible: a REC (renewable energy certificate) worth one kWh of renewable credit. It sells the electricity to the grid, and it sells the REC somewhere else.
A utility in Connecticut can buy a REC from a wind farm in Maine, and the Connecticut utility can claim to be using renewable electricity. Meanwhile, almost all the electricity on the local grid comes from high – emissions power plants burning gas, and from low – emissions sources such as nuclear and large hydro plants.
RECs don’t even have to be on the same grid as the REC buyer.
The user can claim to be “using renewable energy,” but that is about accounting, not about the energy they are actually using.
The net – metered owner doesn’t contribute to the transmission and distribution costs. As you might expect, these net – metering payments raise the retail price for everyone else. Some areas are now charging “connection fees” to net – metering owners, to cover at least some of the costs of maintaining the grid.
curtailment: In some areas, wind turbines get paid if they cannot get online at the times that they are available.
The NBER study, a worldwide review, determined that a grid needs 1.14 MW of installed fossil capacity for each MW of intermittent renewable capacity.
The renewables are rarely, if ever, cheaper than traditional generation.
1) The intermittent nature of renewables means that backup capacity must be added ; 2) Because renewable sources take up a lot of physical space, are geographically dispersed, and are frequently located away from population centers, they require the addition of substantial transmission capacity ; and 3) In mandating an increase in renewable power, baseload generation is prematurely displaced, imposing costs on ratepayers and owners of capital.
they compared the consumer prices in that state before and after implementation. They found that renewable portfolio standards raise the consumer cost of power.
The authors estimated that consumers in the states with renewable portfolio standards had paid a total of $ 125 billion more for electricity than they would have paid without the policies.
The cost to consumers reflects the system costs of renewables. It is not a pretty sight.
THE SUN MAY SHINE only during daylight hours, but a business may decide to buy solar RECs that add up to 100 % of the power it uses and then advertise that it runs on 100 % solar. Since the electricity and the REC are disconnected, you can use a solar REC at midnight, which is very misleading. “Look, that business runs on 100 % solar. Why doesn’t everyone?”
I would summarize their statements in this way: when the policies get too complicated, the results of such policies become hard to predict, even by the people who wrote the policies.
Looking at the whole complex system, I think the games – with – RECs are going to backfire on the renewable industry. At some point, the shell games will be exposed. The bad news isn’t even that the RECs might backfire. The bad news is that complex policies and games – with – RECs do not lead to a reliable grid. “RECs Are Us” is another road to grid fragility.
As a matter of fact, nuclear plants make the majority of the zero – emission electricity in this country: 55 % is nuclear, 20 % is hydro, and 19 % is wind. 186 Counting all types of electricity generation (coal, gas, oil, nuclear, wind, hydro, etc.), nuclear makes 20 % of the electricity in the United States.
According to the Intergovernmental Panel on Climate Change report of 2014, the life – cycle greenhouse – gas contribution of nuclear is 12g of CO2 / kWh, about the same as offshore wind and lower than utility – scale solar PV at 48g / kWh.
The combined – cycle natural – gas estimate in the same IPCC report is 490 g / kWh, about forty times higher than the nuclear estimate.
When Vermont Yankee shut down, its power was replaced pretty much kWh for kWh by natural gas. 200 In 2014, with Vermont Yankee running, nuclear energy made 36.4 million MWh on the New England grid, and natural gas made 46.2 million MWh. In 2015, after Vermont Yankee shut down, nuclear made about 4.9 million MWh less energy, and natural gas made 5.7 million MWh more energy. (Natural gas also replaced a coal plant, with coal’s contribution going down by 1.2 million MWh.) Meanwhile, solar’s contribution went up by 0.1 million MWh, and wind’s contribution went up by 0.3 million MWh.
Natural gas made 4.9 million MWh more than it had made the year before. This turns into 2,400,000 metric tons of extra carbon dioxide added to the atmosphere in one year, due to the nuclear plant closing.
Not all the gas plants on the grid are combined cycle ; most of them are actually single cycle, which are much less efficient in turning a cubic foot of gas into a kWh of electricity. A typical single – cycle turbine has a thermal efficiency of 35 to 40 %, 202 while a combined – cycle gas turbine has thermal efficiencies between 55 and 59 %.
To produce the same amount of power, the single – cycle turbine would have to burn 1.48 times as much gas as the combined – cycle turbine would require.
Low energy prices hurt some kinds of plants (traditional, baseload – type plants), and low capacity prices hurt other kinds of plants (mostly gas – fired load – following or peaker plants).
The capacity payments also encourage profitability once the plant has been built. However, if the market clearing price for capacity payments is too low, perhaps this new plant won’t be promised enough funding, and it won’t be built. Perhaps no new gas – fired plants will be built.
As shown in figure 15, energy payments in 2008 were $ 12.1 billion while capacity payments were $ 1.5 billion. In contrast, energy payments in 2018 were $ 6.0 billion while capacity payments were $ 3.6 billion. In other words, in 2008, capacity payments were about 12 % as much as energy payments while, in 2018, they were 60 % as much.
In this situation, plants that rely on capacity payments (like gas plants) are the winners, and plants that rely on selling power (baseload plants) are the clear losers.
However, nobody (not the states, not ISO, not the plant owners) is responsible for grid reliability or expense. The buck never stops. When things go wrong, the entities (states, plant owners, ISOs) don’t even have to bother passing the buck and shifting the blame. They never had the responsibility, so they don’t have the blame. The grid may be in trouble, but they aren’t.
I am against the no – planning idea that all types of generation are equivalent: that inexpensive, reliable baseload power is unimportant, because every part of the modern grid will be optimized to be “flexible.”
The largest machine in the world is the North American grid. Not all parts on the grid are interchangeable. Not all types of plants have the same optimizations. With just a “market” for tires, a car won’t be built. With a “market” that treats all sources of electricity as equivalent, despite differences in availability and other parameters, the grid becomes more fragile. The grid will fail in the RTO areas. New types of auction carve – outs will not prevent rolling blackouts. When that happens, in an RTO area, the buck will stop … nowhere.
System costs are hard to explain.
Net metering means the person with the solar panels on his roof will be paid more than market rates for his power — a good deal for him. His neighbors, who do not have solar panels on their roofs, will have to pay the extra costs of their neighbor’s power. Their electricity costs will rise — a bad deal for them.
I can’t believe this meeting! You are not concerned with environmental issues. You are not telling us what we can do to make the electric grid better. You should be running a workshop to show us how we can save electricity, install solar panels, insulate our houses, install heat pumps, and so on. Instead, we have a bunch of people talking about what their agencies or their companies are doing. This isn’t an energy meeting. This is ridiculous!
I am a great believer in taking personal responsibility, but I found her remarks discouraging. Too many people have the idea that their personal actions are paramount and that nothing else matters. It’s a kind of hubris: I will take these actions, and I will make the difference for climate. Well, no. Even if everybody in Germany decided to lower their electricity use, insulate their homes, use LED lights, and so forth, Germany would still miss its climate goals.
The website electricitymap. org shows the grams of carbon dioxide produced per kWh of electricity.
However, Germany has a high-fossil, high – renewables grid that emits about five times the carbon per kWh as France. German households that try to cut back on electricity use will not make German emissions anywhere near as low as the emissions of France. Germans have chosen to cut back on nuclear and increase their use of coal. As you might expect, their carbon emissions are getting higher. Germany has said they will phase out coal by 2038.237 Considering that Germany misses its climate targets on a routine basis, I personally wouldn’t count on this coal phase – out. It’s easy to announce a coal phase – out. Germany will have a hard time actually doing it. It will be virtually impossible for Germany to phase out coal, especially since they expect to close all their nuclear plants before they close their coal plants.
On page 49, they quote a report from the government of India that says that three quarters of electricity in India comes from coal, and that will not change significantly in the coming decades.
In A Question of Power: Electricity and the Wealth of Nations, Robert Bryce used a set of databases to divide countries of the world into three groups: Unplugged Countries, where per – capita electricity use is less than 1000 kWh per year, Low – Watt countries, where electricity use is between 1000 and 4000 kWh per year, and High – Watt countries, where electricity use exceeds 4000 kWh per year. 239 Bryce quotes studies that show that the Human Development Index (HDI) increases with increased electricity use — but does not increase with more use above 4000 kWh per capita.
Looking at the worldwide growth in energy use, it is clear that I can put up some solar panels on my roof, but it would be better for the climate if I could encourage an international aid program that would help build nuclear power plants in India.
David JC MacKay’s book, Sustainable Energy — without the hot air.
MacKay does the calculations: if we captured every drop of water that fell in the English highlands and got it to run through a hydro plant, how much electricity could we make? He concludes that “if every river were dammed and every drop [ of water ] perfectly exploited,” Britain could make only 1.5 kWh of electricity per person per day from hydro power. 242 One sixty – watt light bulb, running the entire day, uses 1.5 kWh of electricity.
He wrote his book to encourage people to do the calculations and get beyond the hype that it merely takes willpower to be completely green.
As MacKay says: “The ‘ if – everyone ’ multiplying machine is a bad thing because it deflects people’s attention toward 25 million minnows instead of 25 million sharks. The mantra ‘ Little changes can make a big difference ’ is bunkum when applied to climate change and power.” We have to make big changes in our power supply. We will have to use more electricity in order to reduce fossil – fuel use in the heating and transportation sectors.
Doing the numbers, as MacKay does, shows that Britain simply can’t make it on renewables alone, and everybody “doing a little” would not be much help. The same is true for many other countries.
“We don’t just hope for miracles, we count on them.”
If new types of carbon capture or new types of batteries can save the day, we can add them to our plans when they are available.
In A Bright Future, Goldstein and Qvist show that countries that have solved climate change are using all their low – carbon resources: hydro, nuclear, renewables.
UTILITIES KNOW THAT IF customer demand did not vary so widely, their work would be easier and more profitable. They would not have to keep so many power plants ready to meet peak demand. They would not have to buy power when fuel and power prices have soared due to high demand. And, perhaps, their customers would not have to pay as much for power, because the utilities would need fewer power plants and would not have to stand ready to fork over “whatever it takes” to buy fuel or power when the prices rise.
Bakersfield customers who had smart meters installed often saw their bills soar unexpectedly. Electricity bills often went up threefold.
According to a recent article on smart meters for New Jersey, 250 PG & E eventually admitted that the meters they had installed in Bakersfield malfunctioned when they got too warm. In other words, PG & E’s claim was incorrect. The large increase in Bakersfield electricity bills was not because the people of Bakersfield did know how to work with their smart meters. The increase was due to PG & E’s malfunctioning smart meters. This type of incident does not make installing smart meters acceptable to the ratepayers.
Demand response may not be popular with businesses, but it is very popular with some environmentalists — the ones who favor less energy use and favor paying for “negawatts.”
For many people, the idea that the power company can manipulate electric devices within their home is extremely distasteful.
The colors on this map have almost nothing to do with choices made by individuals. It is very tempting to believe that, if we stop using electricity whenever we want to use it, and instead we make personal sacrifices, everything will be all right. It won’t be. We merely need to look at the high – emissions German grid to understand that endpoint. An individual German making a decision about using a clothes dryer or air – drying their laundry will not lower the country’s carbon emissions nearly as effectively as if Germany made a different choice about energy choices. At this point, however, Germany is closing nuclear plants, opening coal plants, and promising to close the coal plants sometime in the future. The German grid emits much more carbon dioxide than the French grid, and the decisions of individual German consumers won’t change that. We need to make decisions as a society, not just as individuals.
A SEQUENCE OF EVENTS began to happen among the power plants in RTO areas. It wasn’t visible to most people, but it was happening. As nuclear plants and coal plants threatened closure (or did close) in the RTO areas, it was generally assumed that the problem was that they could not compete with newly inexpensive natural gas and, to some extent, with renewables. Therefore, these closures were taken as showing that “the market is working.” Close observers of the market could note that this story was incomplete, but for most people, this was the story. “Just can’t compete.”
Using 100 % renewables is probably not ever possible, and is certainly not just around the corner. Traditional power plants will have to keep running. Every time Exelon or Entergy or FirstEnergy shuts down a plant, prices on the grid tend to rise (less supply, no change in demand). As prices on the grid rise, the companies that have kept their plants will find that those plants are more profitable. The prices will go up, even if the cost of fuel remains low.
A microgrid can work, if it is backed up by a utility grid or a sufficient number of fossils – fired generators. The end result needs to be reliable power.
HERE ARE MY CRITERIA for an electric grid that meets the needs of humans and is respectful of its effects on the environment: The grid should work very reliably for all customers. Everyone should have access to energy, every hour of every day. The power plants on the grid should be as clean as reasonably possible.
Similarly, safety concerns for nuclear energy have to be balanced with the positive benefits of the technology. Electricity prices should be as low as reasonably possible. In particular, no residential customer should pay an increased bill in order to provide lower prices for another residential customer. Low – carbon, non – fossil sources of electricity should be encouraged, as much as reasonably possible. We should be ready to use more electricity, not less. If we want to reduce pollution from the heating sector and the transportation sector, we will have to use electricity in those sectors. While there is much excitement about microgrids, solar power, and so forth, the grid design should acknowledge that only a small portion of electricity users will be prosumers.
California has provided such extensive supports for intermittent renewables that their grid is often overloaded. In that case, the renewables are often “curtailed.” That is, they are not allowed to put power on the lines because the lines cannot accept so much power at once.
in most months, CAISO has to curtail tens of thousands of MWh of renewable power, because there is too much power for their system in the middle of the day.
In other words, capacity auctions are a gift to peaker plants and a burden to baseload plants.
Let’s look at the cost structures for various types of plants in Ontario.
The major expense for an operating gas turbine is buying the gas. Therefore, the cost of the next unit of production can provide a considerable portion of that plant’s financial requirements. Only 6 % of Ontario’s electricity comes from natural gas. A nuclear plant’s major expense is its capital cost and employees. Ontario has CANDU nuclear plants: their fuel is natural uranium, which is far cheaper than enriched uranium.
For wind turbines and solar PV, the major expense is capital cost. The marginal energy cost (land rent and maintenance) is low. Ontario has regulations that prohibit the use of coal for electricity production. This is a prerogative of state – level decision – making. Within a state, there is usually no requirement to be “fuel – neutral” about generating sources.
TO ENSURE THAT RELIABILITY goals are met, all plants in Ontario get most of their revenue not in the energy market but from Global Adjustment payments, based on their contracted energy price, less any fixed – cost contributions received in the wholesale energy market. In other words, their primary payment is not based on the marginal cost of the next kWh. The system is a hybrid market combining the integrated utility “rate of return” concept and the more usual RTO energy – auctions concept. In this system, nuclear plants and run – of – the – river hydro plants run baseload. Their power is cut back only when there is insufficient demand on the system for even their baseload output. Gas, flexible hydroelectric, wind, and solar are cut back first. Flexible hydroelectric are hydro plants that have provisions for the grid operators to remotely control their output. How does this baseload strategy actually work? “Floor prices” are the key. Ontario’s “floor price” market rules prohibit wind and solar PV from offering energy at negative prices that force nuclear offline. Negative pricing by plants that get subsidies distorts markets: “I’ll pay you to take my power” can be a good strategy for a plant that gets other subsidies, but it is a very bad strategy for a reliable grid. In Ontario, wind and large solar PV facilities are forced to curtail before nuclear curtails. The wind and solar facilities directly connected to the IESO high – voltage grid are affected this way. In general, rooftop solar and small – scale, ground – mounted solar are not affected, because they are connected to the distribution system and not controlled by central dispatching algorithms. Nuclear energy supplies more than 60 % of Ontario’s electricity. 289 Before the floor prices were introduced into market rules, curtailment of nuclear by wind and solar was a frequent occurrence. But, floor prices? Really? A first impression is that setting a price floor would cost money for consumers. It doesn’t. If negative pricing by wind and solar forced nuclear plants offline, those plants would be slow to ramp up again, and a multi – day nuclear outage could result. In the subsequent hours / days, while nuclear was offline, wind and solar would probably be available only part of the time. Natural – gas plants would need to start up. This would result in both higher emissions and higher energy costs for consumers.
ONTARIO HAS A LOW – CARBON, low – cost, and very reliable grid. The nuclear plants are the backbone of the grid, and coal is banned. Floor prices protect the clean baseload and also save money for consumers. The mixed system (Global Adjustments for fixed capacity costs, plus energy auctions) works well for consumers, cleanliness, and reliability.
Clearly, floor prices will improve grid stability if you already have nuclear plants available.
There is no method of running an electric grid that leads to a heavenly outcome, with everybody satisfied. However, if you look at tradeoffs and results, Ontario’s hybrid market – system RTO looks very good. It may not have achieved the optimum grid (whatever that is), but the Ontario grid is clean, reliable, and affordable.
AS A GENERAL RULE, local control of the local grid works best. Yes, we need a regional grid, a balancing authority, and transmission lines.
The problem is that natural gas is just – in – time delivery. This doesn’t matter too much if natural gas makes 25 % of the power on the grid, but it matters a lot when it makes 50 % of the power, as is happening in the Northeast.
However, unless abundant quick – responding hydro is available, the imposition of high renewable portfolio standards means that the grid needs more and more natural gas as backup. In watching the grid, try to be aware of the reality of how unreliable renewables are on the grid. They accelerate the slide to all – gas, all the time. Do not be fooled by the idea that a high renewable percentage is the most virtuous form of grid. It isn’t — not when the renewables have to be backed up with fossil. In my opinion, behind every group pushing for impossibly hard to meet renewable standards for a state or region, there’s another well – funded group eager to sell even more natural gas.
For those who are concerned with climate change, as I am, let me just note that natural gas is a fossil fuel, and nuclear energy has zero emissions. Nuclear energy is also the champion for fuel stored on site, 18 months worth of fuel at most plants. So, you can be in favor of low greenhouse gases and also be in favor of the security advantages of having fuel stored on – site.
It is easy to dismiss New England’s problems as New England’s problems. But they are the direct result of overbuilding renewables, closing nuclear and coal plants, moving to natural gas to back up the renewables, and not building new gas pipelines. This is a scenario for grid fragility. If gas just – in – time doesn’t make it just in time, then the ratepayers will suffer the rolling blackouts.