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California’s Strategic Electricity Reserve: (How) Should We Use It?

Should we really build clean generation just to let it sit idle?

There was a lot going on in Sacramento in June, as the legislature rushed to pass its new budget amid furious negotiations focused largely on what to do with California’s record-breaking budget surplus. One “modest” part of the surplus – what’s a few Billion here or there? – has been directed to a newly formed strategic electricity reserve. What is a strategic electricity reserve, you may ask?  I appeared at a budget committee hearing on this topic in early June, and my sense was that there were a lot more questions than answers on this topic.  

The general framework will be that California’s Department of Water Resources (DWR) will be empowered to contract for, or even purchase, electricity supply resources. It also appears that some of these resources will come from a set of aging natural gas plants that have been slated to retire due to the impacts of their “once-through cooling” (OTC) systems on coastal ecosystems. Most of the opposition to these proposals has come from the environmental community, which has objected to what they see as an overreliance on fossil-fueled resources.  

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The fate of the OTC plants has been in limbo for some time, however, and their looming retirements have generated ulcers over the implications for reliability within the California ISO system for almost a decade. The blackouts on August 14-15, 2020, triggered by supply shortfalls, brought these abstract concerns into sharp focus, and the plants were granted environmental waivers to continue operating through 2023. It now appears that at least some of these plants may stick around beyond then as part of the strategic reserve, although that would still require further regulatory approval. The legislature has also signaled that the law would require DWR to prioritize zero-emission resources over fossil fuel resources.

There are many other aspects of the state-owned strategic reserve that have not received as much attention, however, and many questions remain about the implications of such a reserve for the future of California’s reliability planning, and for what’s left of its deregulated power market. At the hearing I framed these uncertainties around three broad questions:

Why Do We Need a Strategic Reserve if We Already Have Resource Adequacy Requirements?

The June 1 hearing featured awkward testimony from the institutions responsible for ensuring California’s electricity resource adequacy (RA) explaining how the system would be inadequate without this substantial new injection of public funds. The California Public Utilities Commission (CPUC) already has fairly broad powers to order the electricity providers it oversees to procure the level and types of resources which forecasts from the California Energy Commission (CEC) say are necessary for reliable service. The formation of a significant new, publicly-owned, strategic reserve is either a tacit admission that this existing system has failed, or a move to subsidize some of the costs of reliability with the budget surplus.  

Certainly, moving some of the costs contained in electricity rates to the tax base is not a bad idea. My colleagues at EI have made a strong case that many activities funded by electricity bills, such as wildfire hardening and low-income energy purchase subsidies, should be paid out of the general fund. But given that about 2/3 of the revenues collected in a typical electric bill pays for infrastructure and other social costs provided by uncompetitive monopoly providers, it is notable that the big application of public funds here will go toward paying a share of the minority of electric utility services that have largely been procured through (somewhat) competitive markets.

When expansive new powers are called for to meet what are characterized as urgent needs, it is natural to ask “how did we get to this point”? Screen Shot 2022-07-17 at 12.40.10 PMThe messaging around this seems to be that the RA process was intended to meet “normal” needs while the reserve is needed to meet the extraordinary challenges introduced by climate change. Left unanswered, at least at the hearing, was the question of why, if a consensus over a need for more reliable supply has now emerged, the existing RA machinery could not have been adjusted and deployed to force additional procurement. One possible answer to that question is that the resources put in the reserve will be used differently than other resources. This leads to the next question.

How will the resources in the strategic reserve be procured and operated in the wholesale power market?

The California market has long struggled to find the right balance between regulatory supervision, market incentives, and customer choice. With the exception of the post-crisis period in 2001 (an episode that does not evoke fond memories), regulators have not had to think about how to integrate large-scale participation of a state agency directly into the market. When taxpayer money is directed to make investments in a market, the natural question is about what impact public investments like this one will have on power market prices, and consequently on private investment in generation and storage.  

The answer to this question needs to be handled very carefully, as there is already precedent for State supported electricity contracts being vacated by the Federal Energy Regulatory Commission (FERC) because they were deemed to interfere with interstate commerce. At a high level, taxpayer money isn’t supposed to be used to subsidize “local” businesses in ways that could give them unfair advantages in interstate markets. If the strategic reserve is seen to be somehow suppressing prices of either capacity or energy in California’s wholesale electricity market, it may run into problems with FERC.

There may be a way to navigate this issue by positioning the resources as truly additional capacity to be deployed only when prices are at their maximum limits.  The Governor and Legislature are highlighting that this is the intent, emphasizing that the reserve will be used “only as a last resort.” They also state that the “Reserve will operate on top of and after procurement by load-serving entities,” and are clearly trying to signal that the DWR’s activities will not impact market demand, or prices.

 What is the “last resort” in electricity markets? That’s a question that lies at the heart of many debates about resource adequacy over the years.  It might mean a shoppingprice trigger. In the energy market, for example, resources in the reserve could be required to bid the maximum allowable (bid capped) price, effectively ensuring they operate only when prices reach their maximum (price capped) levels. This “break-glass-only-in-case-of emergency” usage might also mollify environmental critics worried about the emissions from gas plants in the reserve. Still, the temptation to draw upon a strategic reserve when prices are high, but not yet into reserve deficiencies will be powerful, and may be difficult to credibly resist.  

However, it is worth pointing out that such a limited deployment also greatly restricts the value of the resources being procured, particularly if they are clean energy or storage resources with low marginal costs. Even under the more gloomy projections, there just aren’t that many hours of true supply shortfall, and debates continue about the actual economic costs of well-managed, transitory, load-shedding. By contrast, the costs to customers of the Public Safety Power Shutoffs, motivated by wildfire prevention, are much higher, given the number of customers losing power for days at a time. The money going to the strategic reserve will do nothing to prevent those. It is also worth considering that much cheaper options for enhancing reliability through widespread adoption of truly dynamic retail pricing continue to be ignored.  

How will the existence of a strategic reserve affect reliability planning going forward?

Now that we have a new reserve, what role will it play in planning and investment going forward? This question is tied in with the “how did we get here” question. Will the RA process continue to address only “regular” needs and the reserve be responsible for dealing with the unexpected impacts of climate change? Or will the RA process be further adapted to accommodate the growing uncertainty brought by droughts, heat waves, and a rapidly diversifying generation fleet?

Another aspect of this question that I have not heard raised is that many electricity customers in California are served by entities operating outside of the CPUC/CEC/CAISO reliability planning process. These entities choose their own reserve margins and make their own plans to meet them. Representatives of the Los Angeles Department of Water and Power (LADWP) and the Sacramento Municipal Utility District (SMUD), the state’s two largest publicly-owned utilities, were conspicuously absent from the hearing I attended, so we did not get to hear whether they felt like they needed a strategic reserve, or whether they felt their current resource plans were more than adequate. Either way, their citizens will be contributing to the cost of the strategic reserve. They will also continue to have large discretion over their own reliability planning going forward.  

There is a classic risk here for what economists call “moral hazard.” For example, if we give everyone free flood insurance, we get more houses in flood plains. If we give California electricity providers a “free” strategic reserve, and everyone pushes the reliability envelope too far, we could find ourselves in a situation where we perpetually need to rely upon the “emergency” reserve, and it becomes an institutionalized part of the State’s grid.

The difficult reality is that reliability planning is a very uncertain enterprise, and there are lots of ways in which reasonable people could disagree. Historically, reliability-focused institutions like the CAISO have taken more “hawkish” stances on reliability while cost-focused institutions like the CPUC, and the electricity providers themselves have pushed back on some requirements on the basis of costs. The large municipal utilities, like LADWP, contain both camps in-house. It is hard to see how the existence of a large state-owned reserve could not influence this process of give-and-take, and resolve some of these arguments on the side of pushing the reliability envelope (e.g. running with smaller reserve margins or making generous assumptions about resource capabilities) just a little bit more.  

To Reserve or Not Reserve

There seems to be growing recognition that supply shortfalls in California are a real, and increasing risk, at least in the short term. Keeping some old generation capacity around, with the expectation of almost never using it,  seems reasonable if it can be done in a cost-effective manner that doesn’t derail the primary process of planning and investment. Investing significant capital into new storage and renewable capacity that we plan to almost never use seems more problematic. The point of clean energy projects is to use them as a first resort, not a last resort.

Keep up with Energy Institute blog posts, research, and events on Twitter @energyathaas.

Suggested citation: Bushnell, James. “California’s Strategic Electricity Reserve: (How) Should We Use It?” Energy Institute Blog, UC Berkeley, July 18, 2022, https://energyathaas.wordpress.com/2022/07/18/californias-strategic-electricity-reserve-how-should-we-use-it/



29 thoughts on “California’s Strategic Electricity Reserve: (How) Should We Use It? Leave a comment

  1. “The formation of a significant new, publicly-owned, strategic reserve is either a tacit admission that this existing system has failed, or a move to subsidize some of the costs of reliability with the budget surplus. ”

    James, the existing system has indeed failed. Here, in one image, is the reason why:

    The Failure of California Electricity Policy, In One Image
    https://californiaglobe.com/articles/the-failure-of-california-electricity-policy-in-one-image/

    “There seems to be growing recognition that supply shortfalls in California are a real, and increasing risk, at least in the short term.”

    Short- or long-term, the shortfall is (and will be) the same: a lack of reliable, baseload electricity. But don’t take my word for it, take the word of former CAISO President Steve Berberich. On a phone call with reporters after the 8//14/20 debacle, he revealed

    “We will be forced today to ask utilities to cut off power to millions today, and tomorrow, and beyond. Demand will greatly exceed supply…

    “People wonder how we made it through the heat wave of 2006. The answer is that there was a lot more generating capacity in 2006 than in 2020. We had San Onofre [nuclear plant] of 2,200 MW, and a number of other plants, totalling thousands of MW not there today.

    “The situation could have been avoided. For many years we have pointed out that there was inadequate supply after electricity from solar has left the peak. We have indicated in filing after filing after filing that procurement needed to be fixed. We have told regulators over and over that more should be contracted for. That was rebuffed. And here we are.”

    I’m beyond caring whether I sound like a broken record with my pro-nuclear schtick. Nuclear is the only source of clean, reliable, baseload electricity. Baseload electricity is essential for powering a reliable electricity grid. Ergo, nuclear is essential for powering a clean, reliable electricity grid. It wasn’t complicated 30 years ago, and it isn’t complicated now.

    • Here’s an alternative explanation of what happened in August 2020 that shows that CAISO failed to keep several thousand MWs “in house”. It doesn’t appear that there was a physical shortage as much as a failure in market operations, which would be in CAISO’s wheelhouse. https://clean-coalition.org/wp-content/uploads/2021/01/What-CAISO-didnt-tell-you-about-the-August-blackouts-02_rf-28-Jan-2021.pdf

      One additional point: the August 2020 conditions were 1 in 35 weather conditions, well beyond the standard planning parameters of any system. Rolling blackouts are standard operating procedures when we get to this level. Further, the level of wildfire smoke was unprecedented which both suppressed solar and wind output and increased AC use. We probably need to reassess what constitute extreme conditions and the probability thereof, but that does not mean that those conditions could have been anticipated. That’s the nature of black swan events.

      PG&E is installing island microgrids where they expect fossil backup to run to meet 11% of the load. There’s plenty of biofuels to meet that demand. The 10,000 miles that PG&E plans to harden serves about 1,200 MW of peak load.

      • We MUST get used to load shedding, the same way as we are used to highway stops. There is no economic justification to GUARANTEE 100% up-time for electricity. Yes, there are critical needs that must be assured supply; life-sustaining equipment, some hospital situations, traffic lights, etc. i would be quite willing to have my supply throttled in extreme days – in exchange for a share of the savings. [I do not have deep understanding of the ISO ops or other regulatory redrictions]

        • “There is no economic justification to GUARANTEE 100% up-time for electricity.”

          Like perfect health, attendance, efficiency, or sex, 100% uptime for electricity is not only impossible – it’s a distraction. But ask any small business owner: (s)he will tell you that it’s impossible to run a business without reliable electricity. To put it another way: there is no economic justification for electricity that is unavailable, to everyone in society, on average, for more than 53 minutes/year. That’s “four nines” (99.99%) reliability, and it’s very possible.

          “i would be quite willing to have my supply throttled in extreme days – in exchange for a share of the savings.”

          Savings?! Do you think your utility is saving money when the grid is down?

          • The utility supposedly has to ‘fire up’ expensive resources to maintain supply. The savings are in avoiding that expensive, and likely dirtier, resource.

            Those who ‘want-need’ 100% uptime may pay for it. On a dynamic cost basis.

            LOWER demand is the only reliable way to save on cost AND environmental damage.

          • I’ve already experienced 4 outages this year in my neighborhood lasting from 1 to 6 hours. We’ve had an extended outage almost every year that I’ve lived in this town for 25 years, lasting from a couple hours to a couple days–all distribution system related. Generation reliability isn’t our problem–it’s distribution driven. The generation/transmission outages are almost black swan events (at least up to now) happening once every couple decades. Distribution outages are a regular occurrence. Our generation reliability will have a miniscule effect on that aspect.

          • Richard, you write

            “I’ve already experienced 4 outages this year in my neighborhood lasting from 1 to 6 hours…all distribution system [network] related.”

            When PG&E customers install rooftop solar with net metering, they become part of the generation/transmission system. And when hundreds of homes have rooftop solar within a distribution network, they’re very capable of wreaking the same havoc on distribution lines that commercial wind and solar farms are wreaking on 350kv AC transmission lines:

            “With more and more DERs connected to the grid, we have seen a surge in congestion creating unpredictable strain on the network. Congestion can be defined as violations of network constraints (voltage and frequency) due to too much electricity demand or due to too much electricity generation. In some territories, traditional grid reinforcement techniques cannot keep pace with this strain, which can lead to damage of circuit segment cables, fuses and transformers, as well as voltage variability and outages across the distribution network.”

            https://www.tdworld.com/distributed-energy-resources/article/20971510/is-all-thats-green-good-tackling-grid-congestion

      • “Here’s an alternative explanation of what happened in August 2020…”

        You’re citing CleanCoalition.org, a solar-wind industry group with the stated mission of “accelerat[ing] the transition to renewable energy”? I have no idea why anyone would assign credence to developers of the very sources responsible for CAISO’s reliability problems, but their explanation amounts to damage control – nothing more, nothing less.

        “August 2020 conditions were 1 in 35 weather conditions, well beyond the standard planning parameters of any system.”

        A nearly-identical excuse was offered by ERCOT for the Feb. 2021 near-collapse of Texas’s grid: “It wasn’t our fault, it was extreme weather.” No, 2020 was no “black swan” event, and it wasn’t even extreme weather. Unlike 2006, when blackouts were caused by failing transformers, it was a lack of reliable, baseload supply. With all of its solar farms, wind farms, and batteries, CAISO couldn’t come up with 3,000 fewer megawatts when it was desperately needed.

        Though renewables supporters continue to offer excuses, California businesses and residents have had enough. Fortunately, Gov. Newsom will support relicensing Diablo Canyon – he recognizes grid instability in coming years could jeopardize his political career.

        • Rather than attack the messenger, directly address the substantiated findings in the report. Or is that only organizations that agree with your preferred stance have a legitimate voice in the debate?

          Yes, extreme climatic/environmental events happened in both cases. They weren’t anticipated because the standard analytic methods up to that point had anticipated climatic changes, but there wasn’t good empirical evidence to include these particular extremes. However in the case of Texas, they had seen a similar set of conditions in 2011 and knew exactly what they need to require of the natural gas delivery system. They failed to implement those measures. In California, the smoky conditions along with the monsoon heat was completely unknown and unanticipated. No smoke, no reliability problems.

          • “Rather than attack the messenger, directly address the substantiated findings in the report.”

            Criticizing a report from by a source with an undeniable conflict of interest is not only legitimate, it’s necessary. Moreover, nothing in Climate Coalition’s report is substantiated. Full of incomplete links and reeking of confirmation bias, it’s the expected M.O. of renewables consultants and hucksters.

            “In California, the smoky conditions along with the monsoon heat was completely unknown and unanticipated.”

            CAISO doesn’t mention anything about “smoky conditions” in its Final Root Cause Analysis: Mid-August 2020 Extreme Heat Wave. It does describe how, on August 15, unanticipated storm clouds, an unanticipated decline in wind generation, and an unanticipated sunset wrought havoc on California’s fragile, renewables-dependent grid, leaving frantic scheduling coordinators dispatching erroneous dispatches and shedding load:

            “At 12:26 p.m. the CAISO issued a Warning effective 12:00 p.m. through 11:59 p.m.confirming the Alert issued the day before because conditions had not improved…
            between 2 p.m. and 3 p.m., solar declined by more than 1,900 MW caused by stormclouds…
            between 5:12 p.m. and 6:12 p.m. wind generation declined by 1,200 MW…
            At 6:28 p.m., the CAISO declared a Stage 3 Emergency because solar was rapidly declining while demand remained high…
            If the CAISO continued to operate with the deficiency in spinning reserves it risked causing uncontrolled load shed and destabilizing the rest of the western grid if during this time it lost significant generation or transmission.”

            Click to access Final-Root-Cause-Analysis-Mid-August-2020-Extreme-Heat-Wave.pdf

        • The implicit peak load* in ERCOT in 2020 was an all-time peak. This is in a summer peaking system. A few months ago ERCOT had an all-time peak in the waning days of spring. Has anyone ever heard of a power system reaching an all-time peak in spring? I have not… ERCOT promptly beat that system peak in the first few days of summer. ERCOT is having bonkers weather.

          We’re seeing many power systems doing things that don’t make sense. Up here in the Pacific North West, we’re seeing winter peaking systems flip over to summer peaking systems…. Portland did this last year… Puget and BPA may be next (if not already) and then it’s BC Hydro. This is weird stuff. When it comes to forecasting load we use neural networks that are fed historical weather data matched up to load data. Guess what weird weather does to these programs? Winter load projections have been particularly problematic.

          A good friend of mine is a system operator at CAISO. We served in the Navy together. Without going into details I can tell you he’s scared. California has shut down way too much gas way too fast – to make matters worse the expectation of retirement has led to plants deferring maintenance and this makes them unreliable. I’ve been a power plant operator for 25 years – plants don’t like extreme weather. Cooling systems built for X temperature don’t work at X + 10. If I see a high-temperature alarm I don’t need to refer to an operating order to determine what my action should be – I know I need to reduce load period. We’re hitting X + 10 situations all over the place – and this is a synchronized event across multiple balancing areas which have traditionally been un-synchronized.

          Fun fact… Heroic actions are occurring in control rooms. This isn’t getting reported in the news because it’s politically inconvenient. We haven’t seen a weather-driven energy emergency in BC, unless you count fires taking out transmission lines, but it’s definitely something that’s on the radar. I like this blog but I think we need to de-wonk things for the next few GWs. Economic concerns are secondary to reliability. Quick fix now… Slick fix later…

          Random thought… Lately, I’ve been thinking the California Coastal Commission is California’s equivalent of Joe Manchin. All sorts of things need to happen (gas plants and desal) and this one agency keeps blocking action. I love the coastline but why in the world are we prioritizing micro-biota?

          *Implicit peak is a made-up term. The point I’m trying to make is that had ERCOT been able to serve load they would have reached an all-time peak.

  2. “there is already precedent for State supported electricity contracts being vacated by the Federal Energy Regulatory Commission (FERC) because they were deemed to interfere with interstate commerce…. [the strategic reserve] may run into problems with FERC.” The obvious way to deal with that is to just stop building interstate transmission and start derating it instead. Then you’ll get to the point where the strategic reserve is not impacting interstate commerce, because interstate commerce will never be on the margin! I wonder why they didn’t think of this in Maryland, Massachusetts and New Jersey. 😉

    • It’s a big deal when we purposely drop load. This is a tool of last resort and should never be thought of as “something to get used to.” Our transmission customers (large industrial loads with their own transformers) are often on interruptible tariffs that are triggered in stages by frequency – If the frequency drops to 59 Hz for X number of cycles you drop one tranche of load… 58.5 Hz another and so on. This is a lot different from shedding a feeder to an unprepared community. No, no, no… Load shedding is not something to get used to.

      I tend to think EV charging and electrified hot water are excellent loads to apply voltage/frequency triggers to. Blackouts are deadly whereas losing hot water is an inconvenience. You could potentially design these loads to act like governors in that they’d have what’s called a droop setting. These settings would be hard-wired so you wouldn’t be exposed to hacking. Ten years back I gave a presentation to some investors about this type of load control strategy. At the end of the short presentation, they said… All of this makes sense but how do we make money off of this? Back then and still today I don’t have an answer to this question. The difficulty around monetization is probably part of the reason we haven’t seen this technology take off.

      Back then we didn’t have EV load on the horizon. Uncontrolled EV load is a clear and present danger to the system because it’s a highly synchronized peak load. Centralized control of EV load via some sort of pricing system makes sense but what happens when the communication system fails or gets hacked? It seems to me you have to have an embedded backstop that prevents these loads from crashing the system.

      Here’s a real-world example. Ever heard of cold-load pickup? The basic idea is that you have a community lose power during a cold winter day. When the power gets restored all of the thermostats are triggered simultaneously, you have a big rush of demand and the circuit trips. In a system with lots of EV and thermal load this type of problem could exist all year round.

  3. I’ll start with these are all very good questions. If the OTC plants are thrown into the reserve and bid at the $2,000/MWH cap, the environmental damages could be quite limited. Many of those units require a 72 hour commitment so there might be some residual commitment payments when the MCP fails to reach the $2,000 threshold and the units aren’t called. Not sure why there’s a need to acquire non-fossil resources because…

    The resource adequacy (RA) standard of 17% above the forecasted 1 in 10 peak is intended to accommodate almost all scenarios and should have covered the August 2020 event. The problem likely was that either the CAISO or the IOUs hadn’t thought of the ways that generators could go around the must offer rules to sell outside of the CAISO markets–it wasn’t a hardware shortage. (Please don’t try to respond with the CYA report from CAISO/CPUC/CEC.) The LSEs should have enough incentive to buy what they need. Oh, but wait the CPUC has blunted the incentives for the CCAs through the PCIA, the RA rules and formation of the Central Procurement Entity.

    While dynamic prices might sound like a good idea, direct marginal generation costs are less than a quarter of current electricity rates and likely to fall to as little as 15% by 2026 in PG&E’s area. That’s not going to be enough variation to create a meaningful demand response (other than an overall reduction in metered electricity use). Instead, we need (1) targeted demand response that bases prices on recovering pecuniary externalities of reduced prices from other customers and (2) build microgrids that displace undergrounding at less cost AND add peaking capacity. Essentially, the state could add 1,200 MW at no additional cost through this wildfire management strategy and at much less cost than $2,000/MWH.

    A couple other responses:

    The old steam turbines at the OTC plants run on fuel oil No.2, not jet fuel, and it much heavier than even diesel fuel. I don’t know what the biofuel supplies that are available of that fuel type. And I don’t know if they still have the storage tanks on site–SCAQMD regulations may have required that those be dismantled.

    PG&E has probably been deferring the cap adds needed to run Diablo beyond 2025. That could be a very costly investment.

    • This is a relatively rare case of where a microgrid is the way to go. Undergrounding those transmission lines is madness.

      • Again, yes I know that the fossil OTC plants burn almost exclusively natural gas. I worked on the 3 divestiture environmental analyses for the CPUC. But most of those plants had fuel oil back up: https://ia.cpuc.ca.gov/environment/info/esa/divest-edison/newsce/chap2.htm

        And I also mentioned that the SCAQMD may have put in regulations that forced those plants to retire the fuel tanks, but I can’t quickly find the answer to that question. Those tanks is what would hold the liquid biofuel that the original commenter mentioned.

      • Yes, I know which I didn’t make clear. I was talking about their back up fuel (which is what the original poster was referring to as well.) That should have been clear when I referenced the potential removal of the fuel oil tanks due to local air quality regs.

  4. There is only one problem with the California electric supply and that is PRICE. As you say, solar and wind are the cheapest source of electricity available now. Why don’t you study why the cheapest source of supply results in the highest cost of electricity in the nation in California? Quantify how much money is extracted (and by who) from ratepayers by the operation of California’s “wholesale Power Market”. I can not even think of how much more ratepayers will pay if subjected to “truly dynamic retail pricing”. Review your history to discover again why Enron proved there was no “Market” for electricity. This is not a supply, demand problem because we need infinite supply to get people to transition to electricity to defeat climate change and then we can clean up the supply. This reserve is a good idea. It should kick in whenever the retail cost of power is over 10 cents a kilowatt hour and the PUC should lower rates until all that supply is sucked up. If the supply is not all used it should be dumped into hydrogen electrolysis to supply those old gas plants after they are upgraded to hydrogen.

  5. WATER!
    We need Water in California and water from DE-salinization plants can be used to help keep the coastal regions from needing so much of the water that the Central Valley needs for crops. Water can be turned into green Hydrogen through electrolysis and get profitable Oxygen along with it. The utilities say the excess electricity produced by rooftop solar is only worth 3 cents so use that 3-cent energy to produce water at de-salinization plants or hydrogen at green hydrogen plants. The hydrogen could be burned instead of fossil fuels in existing electrical steam turbines or Peaker plants throughout California. Fast to start and quick to shut down, Peaker plants, using green hydrogen could power us through shortages.

  6. Since many of these old gas plants can also run on jet fuel, it may be possible to keep the plants for emergency backup and run them CO2 emission free with bio fuel. Granted there is nowhere near enough biofuel to run them continuously, but for occasional peaking this may be a valid strategy. Also useful if the gas supply fails as it did in Texas.

    • There’s technically enough biofuel to do 10 GW of microgrids across the US. Rough estimate is 500 million gallons and we produce 14 billion. This is napkin math but it seems doable.

      • “It is also worth considering that much cheaper options for enhancing reliability through widespread adoption of truly dynamic retail pricing continue to be ignored.”

        I asked my boss (a former energy trader in PJM) about this yesterday. He seems to think dynamic pricing schemes are political hot potatoes. I suppose that’s a fair answer, but you’d think blackout are hotter potatoes than dynamic prices. Things are bad now but there’s a tidal wave of new EV load that’s going to hit the West Coast sometime between 2025 to 2030. My utility, BC Hydro, is forecasting 1 GW of extra peak load in 2030 and if I recall correctly, CAISO is projecting around 5 GW of new load. EV adoption rates have found a new gear in the last 12 months (especially in BC) so these forecasts already seem far too conservative.

        This article has some charts showing the growth trajectory. In Q1, 17% of new cars were EVs.

        https://dailyhive.com/vancouver/bc-electric-vehicle-statistics-sales-uptake

        Until recently, EV growth forecasts tended to be too bullish. I remember PG&E’s CEO talking about V2G as early as 2005. For years we’ve had shock jocks like Tony Seba throwing around fairy dust like its Mardi Gras. The flood of bad projections and hype results in optimism overload which leads to turning the channel. But then one day you look around and 25% of the cars in the parking lot are EVs. Is this the parking lot of a tech startup company? No, it’s a parking lot previously dominated by F-150s. Can you say uh-oh?

        How do you get EV load to avoid charging during the evening peak without using dynamic price signals? Additionally, how do you make EV charging affordable if you don’t pull out fixed costs? What about electrified hot water which is also a load that peaks in the mornings and evenings (the shoulders) pretty much precisely when wholesale prices are peaking? What is so hard about making hedged dynamic pricing a voluntary option? France has shown relatively high adoption rates of 30% in their Tempo rates. As you all know, dynamic pricing provides non-linear benefits so 30% adoption would get you something like 70% of the idealized benefits.

        I could well be wrong, but I think there’s a good chance the EV load problem is going to indirectly solve this reliability reserve problem. I think it’s also rather interesting that the dynamic EV and thermal loads are also the solutions to the much hyped Duck Curve.

        California’s water infrastructure is the biggest consumer of electricity in the state. Interestingly, these loads are dynamic and CDWR actually coordinates with CAISO so far as day ahead operating schedules go. If you go back 10 years all of the pumps were running in the middle of the night… When do you think they’re running now?

        As you all know the southwest has been in a mega-drought since 2000 – AKA: Empire killing weather. One can imagine forecasting the growth of this dough keeping pace with EV growth – every year another 3 to 5% worse. Has anybody seen Lake Powel lately? Going once, going twice, sold to the golf course in Utah. For decades now we’ve seen a movement away from flash-type desal over to reverse osmosis. The falling prices of solar and industrial heat pumps could bring flash-type desal back in the money. This could eventually lead to GW of desal load that would be highly dynamic because it would necessarily be coupled with a large amount of thermal storage.

  7. This is just one more hare-brained idea being entertained by California politicians. How much will this wasteful investment add to the already outrageous retail electric rates?

    The first remedy they should be considering is extending the life of Diablo Canyon.

  8. Having a reserve that is so rarely invoked is like having a lifelong subscription to [anything eg magazine or streaming or carwash] that one might rarely use. I would rather direct the expense as a savings, ie negative charge on their monthly bills, to USERS to commit to reducing usage with remote triggers. So, when there is a need my smart meter throttles the capacity so I can only use, say, one of my AC units. Or it turns off the 220v option so I cannot use my oven etc. Keeping old obsolete polluting systems on life support make no sense.

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