Vibrant Clean Energy released a study showing that inclusion of large amounts of distributed energy resources (DERs) can lower the costs of achieving 100% renewable energy. Commentors here have criticized the study for several reasons, some with reference to the supposed economies of scale of the grid.
While economies of scale might hold for individual customers in the short run, the data I’ve been evaluating for the PG&E and SCE general rate cases aren’t necessarily consistent with that notion. I’ve already discussed here the analysis I conducted in both the CAISO and PJM systems that show marginal transmission costs that are twice the current transmission rates. The rapid rise in those rates over the last decade are consistent with this finding. If economies of scale did hold for the transmission network, those rates should be stable or falling.
On the distribution side, the added investment reported in those two utilities’ FERC Form 1 are not consistent with the marginal costs used in the GRC filings. For example the added investment reported in Form 1 for final service lines (transmission, services, meters or TSM) appears to be almost 10 times larger than what is implied by the marginal costs and new customers in the GRC filings. And again the average cost of distribution is rising while energy and peak loads have been flat across the CAISO area since 2006. The utilities have repeatedly asked for $2 billion each GRC for “growth” in distribution, but given the fact that load has been flat (and even declining in 2019 and 2020), that means there’s likely a significant amount of stranded distribution infrastructure. If that incremental investment is for replacement (which is not consistent with either their depreciation schedules or their assertions about the true life of their facilties and the replacement costs within their marginal cost estimates), then they are grossly underestimating the future replacement cost for facilities which means they are underestimating the true marginal costs.
I can see a future replacement liability right outside my window. The electric poles were installed by PG&E 60+ years ago and the poles are likely reaching the end of their lives. I can see the next step moving to undergrounding the lines at a cost of $15,000 to $25,000 per house based on the ongoing mobilehome conversion program and the typical Rule 20 undergrounding project. Deferring that cost is a valid DER value. We will have to replace many services over the next several decades. And that doesn’t address the higher voltage parts of the system.
We have a counterexample of a supposed monopoly in the cable/internet system. I have at least two competing options where I live. The cell phone network also turned out not to be a natural monopoly. In an area where the PG&E and Merced ID service territories overlap, there are parallel distribution systems. The claim of a “natural monopoly” more likely is a legal fiction that protects the incumbent utility and is simpler for local officials to manage when awarding franchises.
If the claim of natural monopolies in electricity were true, then the distribution rate components for SCE and PG&E should be much lower than for smaller munis such as Palo Alto or Alameda. But that’s not the case. The cost advantages for SMUD and Roseville are larger than can be simply explained by differences in cost of capital. The Division/Office of Ratepayer Advocates commissioned a study by Christensen Associates for PG&E’s 1999 GRC that showed that the optimal utility size was about 500,000 customers. (PG&E’s witness who was a professor at UC Berkeley inadvertently confirmed the results and Commissioner Richard Bilas, a Ph.D. economist, noted this in his proposed decision which was never adopted because it was short circuited by restructuring.) Given that finding, that means that the true marginal cost of a customer and associated infrastructure is higher than the average cost. The likely counterbalancing cause is an organizational diseconomy of scale that overwhelms the technological benefits of size.
Finally, generation no longer shows the economies of scale that dominated the industry. The modularity of combined cycle plants and the efficiency improvement of CTs started the industry down the rode toward the efficiency of “smallness.” Solar plants are similarly modular. The reason why additional solar generation appears so low cost is because much of that is from adding another set of panels to an existing plant while avoiding additional transmission interconnection costs (which is the lion’s share of the costs that create what economies of scale do exist.)
The VCE analysis looks a holistic long term analysis. It relies on long run marginal costs, not the short run MCs that will never converge on the LRMC due to the attributes of the electricity system as it is regulated. The study should be evaluated in that context.
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“I believe these resources are going to become stranded assets because the flexible load isn’t nearly as price sensitive as controllable load.”
I meant to say controllable load isn’t as price sensitive as stationary storage. Stationary storage needs to buy low and sell high. This is going to be difficult when you have a ton of controllable load eating peaks and filling valleys. The basic idea is that load will cut in line ahead of storage.
Load is only so flexible. As fossil-fueled generation disappears, price signals should change to use more storage. If that fails to appear, then we might need to tie storage more directly to the source of generation so that we more effectively use solar and wind.
I appreciate the conversation today. You explained a few key things that have puzzled me. I’d like to talk more about market design. It’s a great curiosity for me how we’re going to build a market full of zero marginal cost generation. I don’t mind having the conversation on your blog but email could also work.
You can email me at firstname.lastname@example.org.
Ahh… BC Hydro doesn’t manage Libby… That’s probably BPA but I’m not sure. I think you’re thinking of Mica which does indeed hold many months if not years of water. This dam is the keystone dam at the top of the Columbia. I visited this site during construction of Unit 5. During part of the tour we went in the tailrace of this unit (the exhaust pipe if you will). Just huge!
Ah yes, Libby is in Montana. I’m thinking of the Kootenay reservoirs that are governed by the Columbia River Treaty.
“We need to think about the electricity resource market like the housing market–we don’t have daily hotel rates driving housing investment.”
I agree. What are your thoughts on how this market should be shaped? Is there an existing market that you can point to as a good model?
I think we should have open auctions for PPAs which are either turnkey operations or tolling agreements. I don’t think we gain anything of note by having merchant plant operators who run independently. California almost got that system in 1988 when the CPUC approved the such a system, but SCE appealed it to FERC and had the decision overturned. I think we have a different setting now and it is much more likely to stand up. An important element is that the auctions need to be sufficiently transparent so that both sides can see the clearing prices–that’s rarely the case with how PPAs are procured now. The plants would then be dispatched on merit order but there would be no pretending that the energy prices are somehow representative of full market prices. There also would not be strong incentives to withhold to jack up prices as is the case now. (We saw some of that in the CAISO market in August 2020.)
Most major industrial equipment like airplanes and locomotives are bought as full elements and operated by the company selling the service. When there is leasing, the terms on an annual basis, not hourly even though they have incremental hourly costs.
“…that’s rarely the case with how PPAs are procured now.”
Agreed… PPAs are a black box. I agree with the competitive auction idea and the transparency element. What do you think of this same sort of competitive auctions with a Contract for Difference setup rather than PPAs? Would this be more flexible? I’m attracted to the CfD setup. I suppose it could introduce some gaming but I also think you could end up with under bidding and then making things whole via competition.
“There also would not be strong incentives to withhold to jack up prices as is the case now. (We saw some of that in the CAISO market in August 2020.)”
Really? I haven’t heard this. Thermal generators I’m assuming? I was on shift the night before this event and CAISO called us up in the wee hours of the morning knowing they were going to be thin. They’re lucky the tail end of that episode occurred on the weekend. I have a good friend at CAISO who has indicated that many thermal facilities aren’t as reliable as we’d like them to be owing to the fact that they’re being forced to retire and are deferring maintenance and such.
Can we speak at some point. I don’t quite understand your description of how the clearing would work? The PV/Wind projects would all bid zero right? How does this play with the PPA? I have long wanted to understand the market dynamics in CAISO and/or anywhere. As I mentioned part of my job faces the market but this only has to do with energy tagging.
“Most major industrial equipment like airplanes and locomotives are bought as full elements and operated by the company selling the service. When there is leasing, the terms on an annual basis, not hourly even though they have incremental hourly costs.”
Are you suggesting some sort of capacity payment setup?
I haven’t thought in depth about yet about how the market might work for this type of procurement. It would likely look like a capacity payment, but it could be a lump sum. Leasing could be an option. The tolling agreements seem to have both delivered market valuation benefits and avoided market gaming. I hadn’t considered CfDs, but I think we want to avoid tying these transactions to hourly market prices because of the many problems in latter prices, both technical and economic. It all works in theory but then it get messy.
Withholding in CAISO looked a lot like the Enron games with power being exported when it was needed in CAISO. Here’s two links to a presentation that discusses more about what was happening. It certainly looks like this was a problem with market design and mechanisms, not a physical shortage. That peak was 3,000 MW less than the record peak in 2017, so we’re not outgrowing our fleet.
Click to access What-CAISO-didnt-tell-you-about-the-August-blackouts-02_rf-28-Jan-2021.pdf
As a side note, I originally wrote a draft of this as a comment posted in response a comment on the Energy Institute blog post. The moderator never approved the comment, although a number of my other comments were approved.
Three additional developments that undermine the myth of grid “scale”:
– PG&E in its 2023 GRC is proposing to increase distribution rates 78% by 2026. This would seem to indicate that maintaining the current grid configuration is becoming increasingly expensive.
– Doubling down, PG&E also proposed to underground 10,000 miles of rural lines at the cost of $15 to $20 billion. That would translate into an additional 45% increase in distribution costs. In contrast, installing targeted microgrids likely would be half or less of that cost.
– TURN submitted testimony showing SCE’s marginal distribution costs for its B-bank system and circuits to be three times higher than SCE’s estimate. That closes the gap on what’s reported in SCE’s FERC Form 1.
As I mentioned on the Haas blog I think we could (I’m leaning towards will) see economies of scale bypass transmission constraints by building captive plants. Captive isn’t a great word so they’ll be called the opposite – Free Plants…
I’m seeing more and more of these projects and they’re getting larger. As a general description these facilities would be self-supplied with 80 to 90% of their power and only rely on the grid for a small remainder. In general I see these facilities as industrial plants with large thermal energy demands. That said I can also imagine regional grid zones (the Permian Basin region for example) where a variety of industrial facilities (not just those with high thermal demands) would be co-located.
Quick question regarding the CEPP and/or alternatives to the CEPP. I’m not a fan of this asymmetrical carrots and sticks approach. It’s not obvious to me how this policy will pinch towards a solution. When in comes to RE incentive policy I favor back loaded incentives which encourage durability. That said the PTC, while back loaded, has some perverse outcomes such as negative prices which destabilize wholesale markets. In general my favorite policy is feed in tariffs because this incentive policy adapts over time and you eventually end up with ab incentive to manage energy consumption locally – ultimately this is what we all need to do.
My question is… What do you think about making RE projects tax free? There are two basic options that come to mind. 1. Front loaded tax holidays for construction and licensing. 2. No taxes on production profits.
Do you know if this tax free policy has been used in energy or elsewhere? Did it work? Does this approach have an obvious Achille’s Heel?
Also… It seems to me this policy could be adapted such that the tax rate isn’t necessarily zero but it could be some fraction of the normal tax rate and it could ratchet up to normal over time. This creates a ramp to take you from special treatment into competition.
That renewables create negative hourly market prices is inevitable, and whether the PTC creates these is just a second order effect. This is why we can’t rely on hourly markets to be the sole means of sending market value signals, which so many economists advocate. We need to think about the electricity resource market like the housing market–we don’t have daily hotel rates driving housing investment. FITs are good alternative so long as they reflect the true full value of the resources, not just a translation of forecasted hourly market prices which is too often the case.
The ITC is tax based, and the tax credit investment swaps create incentives for durability because the developers don’t start getting paid off until 6 years into the deal. While this isn’t “tax free” it comes pretty close.
RE creating negative hourly markets is absolutely not inevitable. I strongly disagree with this statement – especially considering the low penetrations we’re currently at. These negative markets we’re seeing are largely a function of paper policies. Negative prices won’t exist at all in a high penetration RE grid because it’s very easy to electronically “flare” excess production.
The physical mechanics of negative pricing generally have to do with thermal power plants judging the costs of thermal stress against the costs of negative prices. This if far different from the negative prices created by the PTC which are all on paper. There’s no reality to the paper. Utilities such as BPA have rightfully refused to allow negative prices on their markets.
I agree hourly markets are insufficient mechanisms and we should be working towards regional day ahead markets. We’re moving in this direction which is very good.
I don’t share your view of the ITC. The ITC is prone to tax fraud. Ask yourself why are solar projects in the US being build with storage? It’s because of the ITC. Why aren’t wind projects in the US being built with storage? Why aren’t solar projects in Europe being mostly built with storage? The basic answer is that the ITC creates a front-loaded way to inflate the value of solar + storage projects such that they pencil. This isn’t good policy for many reasons.
Can you answer my questions about tax holidays? Have you seen this incentive policy used in other areas? Does this policy have an obvious Achille’s Heel?
At least one California IOU has publicly stated that it uses a negative price adder for its renewable PPA bids to reflect the lost opportunity value of RECs if renewables are curtailed. That leads to negative prices in the CAISO market. Given that this arises from scheduling of generation by an LSE vs. the bids from a wind generator, I don’t think these effects are additive.
You’re right that an additional pressure is the need to avoid fossil fuel plant commitment costs if the plants are taken off line during off peak periods. I calculated a few years ago that the CAISO side payments for these commitments were suppressing CAISO MCPs by about $7/MWH.
On the ITC, I was just pointing out that it is a form of the tax holiday that you were proposing. The ITC may be more open to fraud than a simple zero tax. I’m not sure why building storage + storage is a bad thing. It leads to a reduction in transmission investment because the capacity can be reduced to the output from the storage units rather than to the uncontrolled solar output.
California has had a law that at least a large portion of a solar project was 100% exempt from property taxes (and the other portion was 75% exempt.) I’m not aware of any other 100% exemptions. Almost all tax policies are either deductions (e.g., accelerated depreciation) or credits (e.g., ITC). The biggest problem is that an entity will attribute as much income as possible to the renewables project, even if it’s only tangentially related. It’s probably as ripe to abuse as the ITC.
“At least one California IOU has publicly stated that it uses a negative price adder for its renewable PPA bids to reflect the lost opportunity value of RECs if renewables are curtailed.”
I’m guessing this is due to the combination of the PTC and the carbon tax. The carbon tax is much like the production tax credit in that it allows RE project owners to make a profit even though they’re selling at a negative price.
Building storage along side solar is a bad thing in so much as it’s not optimal. If you see storage in a power system it’s often a sign of a poorly run system and/or a constrained power system (see Japan, South Korea and other island grids). Most of our storage in the US was built between 1965 and 1985. These storage projects were often associated with inflexible coal and nuclear plants. The idea was to move excess power from the middle of the night to the middle of the day. This plan worked relatively well until the mid-1990s when FERC started to pass all the open access rules. These rules make it so it’s generally far more economic to move power inter-regionally than it is to store power. Transmission losses are generally around 7% compared to 20% for storage.
There are plenty of large hydroelectric reservoirs with 4+ hours of storage. These plants are spread out between California, Oregon, Washington, Idaho and British Columbia so there are a lot of options so far as moving power around goes. It would have been much cheaper (likely only a few hundred million) to use a portion of the money we’ve wasted on battery mandates to establish a Day Ahead market (DAM) which would help us optimize how our existing assets could all work together. The success of the Energy Imbalance Market is undeniable so I have high hopes for a DAM.
As you know you can also move power via demand side policy. I believe sophisticated price signals are a must when it comes to the electrification of heating and vehicles. Hot water tanks and EVs are forms of storage as it is. These storage assets are smoothly distributed and once activated they will kick centralized storage into permanent obsolescence.
I believe nearly all of the short term storage we need will be provided by demand side management, hydro and a strategy called Over Build and Spill (OBAS). The OBAS strategy results in what’s called “implicit storage”. Implicit storage is essentially the deferral of physical storage – i.e. it’s cheaper to build too much wind and solar and waste it compared to building just enough and using storage assets to move the energy around. Look up Dr. Marc Perez if you want to learn more about OBAS.
“The biggest problem is that an entity will attribute as much income as possible to the renewables project, even if it’s only tangentially related. It’s probably as ripe to abuse as the ITC.”
Hmmm… Thanks… Hmmm… I see what you mean.
The negative price for renewables is entirely for renewable energy credits (RECs) that are used to meet RPS compliance. They have nothing to do with PTC or carbon taxes. RECs are commonly used across the Western Interconnect, and registered with the WREGIS.
As for storage losses, they are converging between transmission and storage. Batteries are now about 92% efficient and closer examination of T&D losses show that they increase exponentially with load, so they are much higher than the standard 8% during high load periods.
There many hydro reservoirs with MONTHS of storage. BPA has enough storage for 40% of Columbia River flow and Libby Reservoir run by BC Hydro holds more than a year at that point of the Columbia. The Colorado River reservoirs hold several years worth of streamflow. Shasta and Oroville together hold a bit less than a year’s worth of Sacramento River flow. There are many PG&E reservoirs with weeks and months of storage. (I have the data from the divestiture proceeding in 2000 that I worked on for the CPUC.)
That said, the Western Interconnect operators already have substantial incentives to store water for later release in a relatively optimal manner. The operational constraints on those hydro plants are pretty strong as is (most are also used for water supply and environmental constraints are flattening generation) they already optimize operations to the extent that they can. Most importantly they can’t generate any more during peak periods than they already do, so they can’t store any more energy from renewables. (In 2000 we modeled the flexibility of PG&E’s hydro system and there wasn’t a lot more that they could do–a few percent one way or the other due to constraints.)
I agree that OBAS will be a strategy up to a point, but storage gives a different kind of flexibility to generate in hours when renewables are down in production. OBAS won’t solve that.
I think the path towards storage will be different–it will be distributed to reduce consumer demand charges and much of it will be portable on vehicles. As I’ve written before, a 100% EV fleet in California will have enough storage to meet the CAISO peak load by more than 30-fold.
“The negative price for renewables is entirely for renewable energy credits (RECs) that are used to meet RPS compliance.”
Why wouldn’t the carbon tax contribute to the negative bidding? Wouldn’t the carbon prices stack on the RECs? Can you explain? Part of my job is market facing but only a small part.
“There many hydro reservoirs with MONTHS of storage. ”
I can only think of three large reservoirs off the top of my head (Hoover, Mica and Shrum) in WECC but there are probably a few more as you’ve mentioned. BPA’s working storage capacity with Coulee is less than a day’s worth if I’m not mistaken. Shasta definitely has enough storage to act as a peaker – it’s the poster child for a peaking hydro plant. Not sure about Oroville or Libby. Libby impounds the Kootenai btw. Mica and Shrum dwarf all the other reservoirs in WECC by a long ways. I believe these two stations can be managed more aggressively. If you manage Mica more aggressively you’re unlocking potential at all the downstream plants especially with the multi-hour storage at Coulee. Same goes for Shrum which has one downstream plant and another under construction.
It’s easy to see how hydroelectric operations have changed in PG&E, BPA and elsewhere since 2010. Peak hydroelectric power used to occur between 1600 and 1800 but this has shifted over to 1900 to 2100. I believe there’s considerable amount of additional flexibility in WECC – particularly on the Columbia. Note that the residual load in the 1900 to 2100 time slot is lower than what the peak load used to be in the 1600 to 1800 time slots. This suggests there’s less peak load on the transmission lines. These things are obviously highly locational but a broad strokes argument is still mostly true.
“OBAS won’t solve that.”
I think you’d agree that OBAS doesn’t need to solve the entire balancing problem. OBAS need only solve a percentage of the problem to make it so that most stationary batteries fall out of the money. The basic idea is that you use OBAS to shrink the amount of residual load and modify the shape of the residual load. If there isn’t enough residual load the batteries won’t be used enough. Stationary batteries are currently only being used about 4% of the time. This is less than half the utilization rate of our pumped hydro facilities in the US. This already low utilization rate will necessarily shrink once we establish a Day Ahead market. It will also shrink as we add more controllable load. The forecasted size of our controllable loads are an order of magnitude larger than the forecasted size of our 4 to 8 hour stationary storage resources. I believe these resources are going to become stranded assets because the flexible load isn’t nearly as price sensitive as controllable load. I’d also note that our controllable loads can be leveraged to make OBAS more effective – this isn’t terribly hard to model.
Now if you think most of the storage will be in EVs then we’re both seeing mostly the same thing. My opinion is that the OBAS, EV batteries and controllable thermal loads will eat up all the market that stationary batteries hope to compete in.
It’s not unlike the frequency control market. I’m sure you’ve heard this market described as a “shallow market”. While the 4 to 8 hour market is larger it’s definitely exhaustible and I believe the EV and thermal load we’re going to add are going to eliminate this market a lot faster than people seem to think.
The GHG allowance cost is treated as an adder to the gas fuel price in the CAISO so it doesn’t create a negative price–renewables have a zero carbon cost rather than negative. The REC is a separate value attached to the renewables and it’s foregone if the generation isn’t used. That leads to a negative price for the renewables. (The California utilities aren’t doing this entirely correctly which is accentuating this effect in the price stack, but that’s a different topic.)
Between Lakes Powell and Mead on the Colorado (Glen Canyon is the other dam), there’s about 40 million acre feet of storage with an average flow in the Colorado Compact of about 22 million acre-feet (which is an overestimate due to the period used for the calculation.)
Yes, I generally agree with the rest of your observations. However, I don’t think that there’s enough flexibility in the WECC hydro system to accommodate a large enough portion of renewables to shift the output to the peak hours. Yes, the peak has shifted, but that’s just a couple of hours. And I’ve told others that I think distributed storage in many forms will make utility scale storage obsolete. The question is how long before that happens.
Thank you for the clear description of why carbon doesn’t create negative prices in California. I appreciate that. Learning has occurred.
“However, I don’t think that there’s enough flexibility in the WECC hydro system to accommodate a large enough portion of renewables to shift the output to the peak hours.”
Trust me… I’m not saying hydro is a panacea. I just think there are several GW of additional flexibility that can be squeezed in WECC. Let’s say around 5 GW. Is that a lot? Yes and no. How much does 5 GW of stationary batteries cost? My general argument is that we should max the flexibility of our existing resources and modify markets before we add expensive assets like batteries.
5 GW of hydro is a lot given that California has only about 6 GW of hydro total and the Colorado another 4 GW. The other problem is the transmission constraint from the PNW, where that flexibility largely resides, to CA and elsewhere. It would take modeling that I haven’t seen to demonstrate that the hydro system has sufficient slack capacity to deliver that amount of additional storage basis.
Well, it’s not 5 GW all of the time… It’s 5 GW periodically. It’s mostly a rough guess but I work in the space so it’s an educated guess. It would mostly come from BPA and BC Hydro but there are are non-negligible oppourtinies to optimize the hydro controlled by small BAs like IID, Chelan etc.
This isn’t a hill I’m willing to die on. I’ve modeled all of the hydro in WECC from a couple of different angles but my 5 GW guess has more to do with my work experience than anything else.
That availability runs into the Pacific Intertie capacity limit because most of that load and solar generation is on the other side of the divide. Depending on a single corridor 600 miles long doesn’t do much for reliability or resilience.
I think we’re looking at the problem from different angles. The Pacific Ties are a lot more reliable than they used to be but they’re definitely still a weak link. That said, they aren’t a weak link when it comes to renewable integration. Hopefully we can talk about this. I’ll send you an email
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