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What Drove Solar PV Price Reductions?

A new book explores the precipitous decline.

One of the most remarkable trends in energy economics over the last 50 years is the tremendous reduction in solar photovoltaic (PV) prices. The figure below charts prices on a log scale. In words, it shows that prices in 1970 were about 1,000 times higher than they are currently.

Source: Nemet (2019)

I’ve been on a quest to understand this phenomenon – I’d heard conjectures about scale economies driven by generous subsidies for rooftop installations under the German Energiewende or massive subsidies from the Chinese government, but hadn’t dug into it myself.

It turns out that Greg Nemet, a professor at the University of Wisconsin, recently published a book called, How Solar Energy Became Cheap, which provides a number of insights. And, because there are so many promising energy books to review this year (more on that to come!), I’m going to break my book reviews into pieces and devote this post to Nemet’s book.

Can We Replicate the Solar PV Price Reductions?

Understanding the decline in solar PV prices is a hugely important exercise. If we can replicate the solar experience for energy storage, carbon capture and sequestration, small nuclear reactors or other clean technologies, we’d make a lot of progress addressing climate change. Plus, I’ve had a nagging fear that the current ultra-low PV prices were unsustainable, perhaps reflecting huge subsidies that could disappear with the stroke of a pen.

So, how much of the solar experience actually can be applied to other industries? Was it pure serendipity? For example, did solar PV benefit from advances in the computer industry, which similarly use silicon’s semiconductor properties for microprocessors, that were driven by forces completely outside the energy industry? Or, are there key policies or business practices that can be replicated for other clean energy technologies?

Nemet’s book is based on 70 interviews across 18 countries and also draws on quantitative work that he and others have done for academic publications. It’s a pretty good read, especially given the format – there are footnotes, references, tables and figures, so it’s not exactly a light beach read.

The Case for Replication

At a high level, Nemet comes down on the side of replicability. In fact, the subtitle of his book is, “A Model for Low-Carbon Innovation.” I must admit that I started the book with some skepticism – I was worried that he would be so intent on drawing lessons for other industries that he would ignore the serendipitous explanations. I came away more convinced.

Nemet traces solar PV from the first Bell Lab application in 1954 through to about 2016. He argues that there were essentially four epochs when worldwide PV output was dominated by US, Japanese, then German and finally Chinese production. He devotes a chapter to each country and explores the local demand-pull policies (e.g, Japan’s first-of-a-kind net metering policy in 1998) and technology-push policies (e.g., research and development subsidies, such as the creation of the Solar Energy Research Institute, which later became the National Renewable Energy Lab (NREL)).

Nemet also points out that solar PV benefited from the fact that it was hugely scalable and could be applied across a number of niche markets. The Japan chapter explains how companies like Sharp invested in very small-scale solar cells for calculators and bigger niche applications such as lighting offshore oil platforms.

Solar PV prices really plummeted in the last 15 years, so I found the two chapters on the German and Chinese epochs most interesting. In the chapter on China, Nemet tells the fascinating story of Suntech, the first large-scale Chinese solar module manufacturer. The company was founded by Zhengrong Shi, who spent 15 years as a researcher at an electrical engineering lab at the University of New South Wales in Australia before he returned to China in 2001 with a business plan to build a plant to produce 3 MW of solar modules per year. By 2008, Suntech was producing 1,000 MW per year and had over $1 billion in sales. Suntech went bankrupt in 2013 due in part to its decision to acquire an Italian solar developer later accused of massive fraud, but current powerhouse companies such as Trina Solar, JinkoSolar and JA Solar developed closely on Suntech’s heels.

Shi’s story highlights the importance of academic R&D, as Shi was able to convince German customers that Suntech’s modules were high quality based on his relationship to the university research lab. And, Nemet emphasizes how, “Shi’s experience in the lab [gave] him a broad expertise in PV technologies that allowed him to switch technologies quickly when an opportunity for cost-reductions emerged.”

The story of Suntech and its competitors also emphasizes the doggedness of a number of Chinese entrepreneurs including Shi, who shopped his business plan around China for months before he finally found $5 million in financing. Though Nemet mentions Chinese government policies to invest in renewables to spur demand and says obliquely that, “many of these [solar] firms received substantial funding from the local governments,” I was left with the impression that Chinese solar manufacturing was really launched and developed by scrappy, capitalistic entrepreneurs.

A Series of Incremental Improvements

The scale economies in solar PV are pretty mundane – a bunch of incremental improvements in manufacturing processes, panel efficiency, supply chain optimization, and automation rather than one or two breakthroughs in someone’s R&D lab. For example, Nemet describes how early module manufacturers used second-hand manufacturing equipment repurposed from computer microprocessor plants, but as the industry expanded, suppliers for solar-specific machinery emerged.

He also describes how Shi led the switch from using poly-crystalline silicon to cheaper and more efficient mono-crystalline silicon, which is perhaps as close as we come to an ah-ha insight that drove costs down. It’s splitting hairs a bit, but this last example could be learning-by-doing rather than scale economies as the insight didn’t necessarily require huge volumes of production.

In the end, some of Nemet’s messages are encouraging: the forces of capitalism, nudged by government programs, encouraged entrepreneurs who saw a growing market for solar to invest capital and a fair amount of blood, sweat and tears into fine-tuning manufacturing processes that led to significant cost-reductions. I’m going out on a limb a bit as I’m pretty averse to making forecasts without a lot of evidence to back them up, but I don’t see an obvious reason why the price reductions have been exhausted.

As Nemet points out, though, the decline in solar prices took a long time, so even if other industries can replicate this path, they’ll have to figure out a way to do it much more quickly.

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

Suggested citation: Wolfram, Catherine. “What Drove Solar PV Price Reductions?”, Energy Institute Blog, UC Berkeley, September 9, 2019,


Catherine Wolfram View All

Catherine Wolfram is Associate Dean for Academic Affairs and the Cora Jane Flood Professor of Business Administration at the Haas School of Business, University of California, Berkeley. ​She is the Program Director of the National Bureau of Economic Research's Environment and Energy Economics Program, Faculty Director of The E2e Project, a research organization focused on energy efficiency and a research affiliate at the Energy Institute at Haas. She is also an affiliated faculty member of in the Agriculture and Resource Economics department and the Energy and Resources Group at Berkeley.

Wolfram has published extensively on the economics of energy markets. Her work has analyzed rural electrification programs in the developing world, energy efficiency programs in the US, the effects of environmental regulation on energy markets and the impact of privatization and restructuring in the US and UK. She is currently implementing several randomized controlled trials to evaluate energy programs in the U.S., Ghana, and Kenya.

She received a PhD in Economics from MIT in 1996 and an AB from Harvard in 1989. Before joining the faculty at UC Berkeley, she was an Assistant Professor of Economics at Harvard.

134 thoughts on “What Drove Solar PV Price Reductions? Leave a comment

  1. I would like to see some commentary on the financing mechanisms that drove the price of solar down. I’ve seen instances in power purchase agreements where the upfront $/MWh is extremely low, however, the buyout provisions can be very high.

    It appears that developers/investors are accepting a low starting PPA price in the hopes of obtaining higher gains in the future. Ventyx curves speculate extremely high unit energy costs after the life of the contract.

    I have suspicions that the true levelized cost of solar has not yet reached $20/MWh because of these types of investment strategies. The costs of manufacturing solar modules and the cost of construction have truly gone down, I’m just wary of accepting the $20 mark without further investigation.

  2. Carl
    You appear not to understand how the CAISO market works and that generators are not paid “as bid” prices. As the expert witness for the Joint CCAs I see PG&E’s revenues from its power plants. Diablo and other zero-bid (self scheduled) resources are paid the market clearing price (MCP) in each hour. For a baseload resource like Diablo, the annual average MCP is a close approximation of average hourly revenues.

    You wrote: “With the current residential retail price of PG&E electricity at $.22/kWh, the plant is thus worth $1.24 billion in annual revenue to the utility.” I can only interpret that you assumed that Diablo is being paid the retail price for its generation and I pointed out that there were many more expenses that go into that rate that you ignored. As to the other spurious costs for renewables that you mention, they are much less than you assume. I suggest that you provide a quantitative analysis backing up your erroneous assertion.

    You wrote: “PG&E is not paying off stranded asset costs for Diablo Canyon.” If that’s the case, then why are those costs included in hte PCIA exit fee? My clients would be more than happy to remove those costs. Diablo Canyon has been depreciated on a standard schedule equivalent to all other generation assets. PG&E 2016 application showed that the costs required to relicense the plant would more than double its cost per MWH which made it uneconomic. You are ignoring those added costs (which would have excluded the past investment costs, which if they were extended as you suggest would make relicensing even more uneconomic.) You should research how ratemaking is done at the CPUC, and look into PG&E’s current 2020 GRC application for the calculations of cost recovery for Diablo. Your description is fictional with no basis in facts.

  3. Please substitute “Adding firm capacity adds only $20 to $30/MWH at the most” for “Adding firm capacity adds only $20 to $30/MWH at the mos” in the above quote from Richard McCann, Ph.D.

  4. I just read this blog and the comments.

    Commercial nuclear reactors are capable of following load and they routinely do in France, Canada and other countries. These plants typically can vary output from 100 percent down to about 30 percent, though not very quickly. US nuclear plants have also followed load. ComEd in Chicago used to cycled their BWRs between 50 percent and 100 percent output in order to follow the diurnal load changes. PWRs can also follow load but are less flexible than BWRs. And, of course, all nuclear powered ships can vary output over an even wider range because they are specifically designed to do this and utilize fuel that is much more highly enriched than that used in commercial reactors.

    While commercial nuclear plants can follow load it is seldom economic to do so. Almost all of the costs of a nuclear plant are fixed, not variable, so little is saved by reducing output. This is particularly true when the plant operates in a competitive wholesale market, rather than being included in a utility’s rate base.

    So is Diablo Canyon partially to blame for the Duck Curve? Yes, but not to the same extent that solar and wind facilities are. Why? Because (1) solar and wind can more easily curtail their output and (2) because if their intermittent nature, they cannot be relied upon to reliably serve load. Meanwhile, Diablo Canyon reliably keeps churning out MWhs, 24/7.

  5. I take exception to solar power advocate Richard McCann’s false statement that zero-emission nuclear power is not dispatchable. Furthermore, baseload nuclear power serves to provide important stability services to the California power grid being subject to the destabilizing effects of large amounts of intermittent solar and intermittent wind. Both German and south Australian power grids have recently been harmed by events connected with a higher penetration of intermittent solar and intermittent wind. Those expensive harms include blackouts and damaged equipment. Grid-intervention events associated with the stops and starts inherent with both solar and wind are increasing for both of these grids.

    CGNP established during the sworn oral cross-examination phase of PG&E witness Frazier-Hampton in CPUC A.16-08-006 that all power systems require baseload power. Specifically, when asked, “Are you aware of any large electric grid, anywhere in the world that operates without a substantial continual supply of electricity from base-load sources?” PG&E witness Frazier-Hampton, who performed their needs analysis, was unable to identify such a grid anywhere. A.16-08-006 Oral Evidentiary Hearing Transcript, April 26, 2017, PG&E, Frazier-Hampton, pp. 946, line 6. Additional details are found in the Appendix, “CGNP’s Summary Responses to other Parties” Dec. 7, 2018.

    Furthermore, the widely-promoted “duck curve” serves to advocate for the inefficient and intermittent dispatch of natural gas fired generation required to compensate for both the intermittencies and poor alignment of the solar power production peak with the late afternoon and early evening load peak. In a previous post, I referenced “Turns out wind and solar have a secret friend: Natural gas,” by Chris Mooney, August 11, 2016, The Washington Post, serves as an introduction to: “Bridging the gap: Do fast-reacting fossil technologies facilitate renewable energy diffusion?” by Elena Verdolinia, Francesco Vonab, and David Popp, Energy Policy 116 (2018) 242–256, The environmental harms identified in those sources remain un-rebutted by McCann

    in this energy policy debate, it is “creative salesmanship” to claim that the increased emissions associated with inefficient and intermittent dispatch of natural gas fired generation yields benefits (except perhaps to natural gas wholesalers.) Furthermore, in its written testimony in CPUC proceeding R.16-02-007, CGNP establishes using CAISO data that “heat rates” for California generators are rising as more and more intermittent solar and intermittent wind are added to the California power grid. For those that are unfamiliar with the term ” heat rate,” it is a measure of efficiency in power production. Rising heat rates mean decreased efficiency.

    • There’s nothing here that says the power grid problems were related to solar power, and the Tesla battery in fact averted outages in Australia:

      That a witness says that they are not aware of something happening elsewhere in the world does NOT mean that that they are saying that it can’t happen or isn’t now happening. You’ve made a conclusion not supported by the evidence.

      No one is claiming that natural gas power used for load following is beneficial. And of course incremental heat rates are rising. That happens as power plants are run less and less. That’s consistent with the dramatic drop in emissions from the California grid over the last decade, which is a citation I’ve already present to you and Carl Wurtz. Marnay’s article shows how there are some offsetting emissions from natural gas with increased solar. That does NOT mean that the total reductions from solar are MORE than offset by the gas generation. You’re reaching for straws. Present real evidence that emissions have INCREASED over the last decade (not for a single dry year that follows once of the wettest years on record.)

      There is not a single U.S. nuclear unit today that follows daily ramp, much less meet variable load changes.

      I’m not a solar advocate; I’m not paid by the solar industry in any way. I’m an opponent of wasteful spending on technologies that have shown over and over again that they are not advancing. Nuclear by any measure today is much more expensive than the combination of viable alternatives. Give us some real numbers of new U.S. nuclear plants that can compete. (There aren’t any, BTW.)

      • Richard,

        You’re right about the cost of building new nuclear plants in the US, at least using the current AP1000 technology. But it would be highly irresponsible for the US to not pursue development of the Gen 4 nuclear technology. These designs are smaller, safer and promise to be cheaper. And at least one of the technologies (the “traveling wave reactor) can burn as fuel the waste currently being stored in pools of water at current plant sites.

        It is hard to believe that we are going to achieve zero-emissions using just renewables and storage. Certainly not at a reasonable cost – assuming it is even physically feasible. Is the public really going to stand for massive amounts of land covered by solar arrays and wind farms? There are already protests against these facilities being sited on the East Coast. And what about all the new transmission lines that would be needed? When was the last time a new line was built without public opposition?

        We cannot afford to write off nuclear power.

        • If the Gen 4 technology delivers on all this promise, then it would be useful. But we have heard so MANY promises that have failed to materialize. We all should be highly skeptical of any claims until the industry delivers, and don’t make any plans based on promises too frequently empty.

          • Richard,

            I agree, that we should not be making plans today that irreversibly commit us to any technology that is unproven. What I said is that we should not summarily dismiss nuclear at this time. That would be irresponsible. The federal government should fund the R&D needed to develop one or two Gen IV small modular reactors whose designs look promising. It will likely be at least 15 years before such a design is commercially available and 20 years before it can play a significant role in decarbonization. Nonetheless, when that time comes it will be when integrating renewables into the grid will be increasingly expensive.

            Numerous studies show that the cost of going from a 90-95 percent clean grid to 100 percent adds a prohibitive increment of cost because of the need to fully back up the entire renewables fleet with other capacity that can be relied upon to be there when all of the wind and solar resources simultaneously stop producing energy. Adding nuclear capacity could greatly mitigate this problem by reducing the amount of renewables (and storage) needed.

            Think the need for back up capacity is far fetched? Take a look at wind and solar generation in California in 2017 (Figure 2-15 on page 51 of EFI’s California decarbonization study):

            Click to access EFI_CA_Decarbonization_Full.pdf

            The study goes on to say:
            “The figure shows days in January, February, November, and December on which wind and
            solar combined could not meet peak demand, and several periods of seven to ten days
            with little or no wind generation (most likely from an inadequate wind resource on those
            days, although wind system constraints, e.g., transmission congestion, are an alternative,
            if less likely, explanation for these gaps in wind generation). The length of the gaps in wind
            availability to the system raises a range of issues, including the adequacy of even the
            longest-duration storage; the placement of energy storage on the electric grid; the need
            for redundant, fuel-supported generation; overall system management; and the potential
            role for, and benefits of, a regional grid.”

            Or wind generation in Texas. In the past two months ERCOT has experience numerous operating reserve deficits causing wholesale prices to spike up to the $9,000 cap because 95 to 99 percent of the wind generation did not show up during the peak hours of the day.

            This strongly suggests that we cannot rely on just renewables and storage to achieve a 100 percent clean grid at an acceptable cost without nuclear power. And maybe not even at any cost.

          • And I agree that it should be held on the bookshelf for the potential need 20 years down the road, but apparently Gen 4 technology has already been on the bookshelf for a dozen years with no results yet.

            As to whether we will have solutions to getting to 100% renewables in 20 years, I’ll note that cars were a high priced oddity in 1900 and cell phones were but a notion in 1985, yet 20 years later they, and the associated infrastructure, were ubiquitous.

          • “Nuclear should be held on a bookshelf for the potential need 20 years down the road,” should it Richard? That’s rich. Feel free to hold nuclear on your bookshelf, if you like. The existential threat it poses to renewable sources, and fossil fuel gas, must be as frightening as the death rays you imagine radiating from nuclear fuel.

            The rest of the world is tired of listening to excuses for the intermittency of solar and wind, their exorbitant land use, and their harm to wildlife. Work proceeds apace at Vogtle with the delivery of the final expansion module days ago; within two years the plant will be generating more carbon-free electricity than all solar and wind east of the Mississippi combined. UAMPS has ordered a 12-pack of Gen-4 NuScale small modular reactors that will occupy 1/40th as much land as a solar farm, and generate clean electricity 24/7/365 – an accomplishment of which solar will never be capable.

            Forget the bookshelf; solar panels and wind turbines should be taken to the toxic waste dump with all due haste.

          • Vogtle is the poster child for the economic failure of nuclear power. As I described earlier, I calculated the average cost for Vogtle power is higher than $100/MWH, which is multiples of the cost of renewables. Why would we pursue such a costly technology? The cost difference is easily made up with other technologies such as storage.

            And we’ll see if the Gen4 modules work and are cost effective. I’m not holding my breath given the lackluster performance of this industry.

          • Richard,

            “As I described earlier, I calculated the average cost for Vogtle power is higher than $100/MWH, which is multiples of the cost of renewables. Why would we pursue such a costly technology? The cost difference is easily made up with other technologies such as storage.”

            While I’m not about to even try defending the cost of the Vogtle project, you need to be more honest in comparing it to the cost of renewables.

            Firstly, even at a cost of $100/Mwh, Vogtle energy will be cheaper than offshore wind.

            Secondly, to get a true measure of what renewables cost you have to include the cost of the capacity needed to back up the renewable when it doesn’t produce energy. Neither wind nor solar produce firm, reliable energy like a nuclear plant does.

            Given the fact that both wind and solar have at least a 2-to-1 seasonal variations in the US latitudes the cost of the storage needed to smooth their energy output would be prohibitively expensive, assuming it is even physically feasible at high penetration levels. As Marc Perez has shown, it is cheaper to overbuilt the renewable resources so they meet the winter peak loads, then curtail the excess energy when they overproduce in the summer. But that more than doubles the cost of the renewable energy – before adding in the cost of the storage needed to back up their short-term intermittency. You may be aware of the fact that wind energy production in California can drop to near-zero for a week or more – across then entire state! And, of course solar doesn’t produce energy at night. So add in the backup costs of the resources needed to fill those energy voids.

            Other than pumped hydro and water stored behind dams, storage is expensive. And most of the hydro sites have already been developed in the US.

            The bottom line is that relying on renewable energy and storage to get to zero-emissions will be very expensive and will consume huge amounts of land. A cheap, safe form of nuclear power would be a godsend. Let’s hope that the Gen 4 plant designs deliver as promised.

          • Adding firm capacity adds only $20 to $30/MWH at the most. To even get in the ball park, renewables would have to cost $70 – $80/MWH, yet we are seeing most costing less than $60/MWH. Storage plus solar deals are costing less $50/MWH in many cases, and doubling the storage would get to only $70/MWH. And still cheaper to double the installed solar capacity than to build nuclear. Just saying that we need power around the clock doesn’t mean that we should pay whatever it costs for that power. There are many cheaper alternatives than nuclear.

            As for offshore wind, its a tiny percentage of US renewables capacity, and its much cheaper in Europe where they have worked through their local issues. Wind costs are going one direction while nuclear are going the other.

          • “Adding firm capacity adds only $20 to $30/MWH at the most.”

            Really Richard? Tell us how you arrived at those numbers. And show your work. LOL!

          • Based on the CAISO Market Performance Report a new CT should cost $160/KW-year. The CAISO CPM payment is $75/kW-yr. The California average RA prices is $40/KW-year. Those costs translate into capacity costs of $18.25/MWH, $8.50/MWH and $4.50/MWH to retail customers.

          • “Based on the CAISO Market Performance Report a new CT should cost $160/KW-year. The CAISO CPM payment is $75/kW-yr. The California average RA prices is $40/KW-year. Those costs translate into capacity costs of $18.25/MWH, $8.50/MWH and $4.50/MWH to retail customers.”

            To convert an annual capacity cost into MWh requires an estimate of how much energy the resource produces annually. What estimates did you use and where did you get those data?

          • Robert, excellent points all. However, I will point out nuclear electricity from Diablo Canyon is already safe and cheap:

            • In 33 years of operation, not one fatality can be attributed to operation of Diablo Canyon, which has generated 594 trillion watthours of carbon-free, 24/7 energy for California residents and businesses.

            • As a “price taker”, Diablo Canyon essentially bids $0 in California’s electricity wholesale market and is awarded the highest bid price, an average of ~$15/MWh. With the current residential retail price of PG&E electricity at $.22/kWh, the plant is thus worth $1.24 billion in annual revenue to the utility.

            Viewing an opportunity to burn (and sell) gas, however, PG&E is anxious to close the plant down, claiming “departing load” going to CA Community Choice Aggregators (CCAs). Because PG&E itself will likely be supplying >90% of electricity to CCAs, however, any departing load is illusory. Worse, a premature Diablo Canyon shutdown in 2024-25 would essentially waste $10.4 billion in capital cost recovery for which its customers will have already footed the bill.

            “Not so fast,” says CA Assemblyman Jordan Cunningham, “PG&E has some unpaid bills.” In January he will introduce a bill to force the utility to sell Diablo Canyon as a condition of exiting bankruptcy, with $1 billion or more from the sale to be allocated for wildfire victim relief. Because several national and international energy companies have expressed interest, the only losers will be solar, wind, and fossil fuel gas interests. California might even follow Ohio’s lead and cancel California’s ineffective RPS scheme entirely – if so, it won’t be a moment too soon.

          • What a strange, erroneous comment. The average CAISO price in 2018 was about $50/MWH, not $15/MWH, which is representative of Diablo revenues. However, it cost ratepayers about $45/MWH in going forward costs (based on FERC Form 1, and close to my estimate presented in PG&E’s 2019 ERRA case), and the total cost recovery is in excess of $65/MWH, excluding decommissioning costs. In other words, Diablo Canyon would not be “in the money” if it was built today, even with its current configuration that violated environmental regulations. And asserting that 100% of retail revenues go to Diablo Canyon costs is either naive or ignorant. PG&E has substantial costs in distribution and transmission assets as well as public purpose program costs. In addition, PG&E is paying off $2.5 billion in stranded asset costs annually, of which Diablo Canyon is a significant portion.

            And you’ve fallen into the sunk cost fallacy. It doesn’t matter if ratepayers have paid $10 billion (of which at least $3 billion is double payment to PG&E as I pointed out in 1996)–it’s the cost going forward that matters. An advisory board of attorneys to SMUD made the same error in 1988 and SMUD wasted another $250M before closing Ranch Seco and saving the utility in 1989.

          • And California’s RPS isn’t disappearing soon. Despite the onerous PCIA exit fee of over $25/MWH to pay in part for Diablo Canyon’s stranded costs, the CCAs are still able to beat PG&E rates relying on mostly renewables. The state isn’t turning away from its 100% renewable goal.

          • What a strange, erroneous assumption that PG&E paid the average CAISO price for electricity from Diablo Canyon in 2018. Diablo’s reliable 24/7 generation allowed them to bid $0/MWh and still get paid the highest price for electricity when demand is lowest, which came to about a third of CAISO’s average price. That’s something you’ll understand when you have more experience with California’s wholesale market and meeting baseload demand, which understandably can be confusing for renewables activists.

            We’ve already discussed PG&E’s inflated “going forward” costs in ERRA 2019, and how its departing load was deliberately exaggerated by ignoring electricity PG&E will provide to CCAs itself. Any suggestion I’m asserting 100% of retail revenues go to Diablo Canyon is both naive and ignorant. I’m asserting the ~$15/MWh going to Diablo Canyon is far more cost-effective than solar/wind together with gas to address variability. Add in negative pricing overcharges and decremental bids paid to solar and wind farms for curtailment, and solar/wind might be worse than coal in terms of combined economic/environmental cost.

            Your attempt to dismiss the sunk costs of Diablo Canyon as fallacy has more basis in Greenpeace talking points than economics. PG&E is not paying off stranded asset costs for Diablo Canyon. They are being billed to ratepayers in an accelerated depreciation schedule, the end of which miraculously coincides with Diablo’s 2024-25 shutdown date. Ratepayers would be on the hook for the entire sunk cost of Diablo Canyon, then the 4,000 MW of gas generation FERC has ordered to replace it, if Rep. Cunningham’s bill doesn’t force a sale. That one of three U.S. energy companies are interested in buying the plant promises the best possible outcome for everyone except California antinuclear activists, who I fear are in lost in a daze as the Nuclear Renaissance unfolds.

          • A true cost of solar includes the substantial social cost of carbon (SCC) associated with the natural gas generation required to firm intermittent solar power. The U.S. EPA estimated in August, 2016 the 2020 SCC (CO2) at a 3% discount rate at $42/metric ton. Furthermore, with a 3% fugitive methane statistic, the 2020 SCC (CH4) is $1,200/metric ton. Given the empirical requirement that 1 MW (nameplate) of natural-gas-fired generation is required to firm each 0.88 MW of intermittent solar or wind, the true cost of firming solar is considerably more than the “lowball” estimates provided by Richard McCann on October 21, 2019 below. ……… “Adding firm capacity adds only $20 to $30/MWH at the mos” …….. Since these substantial imposed costs are hidden in the total cost of California fossil-fired generation which provides about 60% of California’s in-state generation on a megawatt hour basis,, these costs are easy to overlook. However, they are one of the reasons why California residential power rates on a per kilowatt hour basis are about double the national average. Further, please note from Richard McCann Ph.D.’s summary biography at that his clients include the California Energy Commission and the California Public Utilities Commission. (CPUC) Both of those bodies have a cozy relationship with California’s large investor-owned utilities (IOUs) per the Wikipedia article regarding the CPUC and Intervenor CGNP’s and intervenor TURN’s criticisms

          • Again, I point out that you have confused installed gas capacity is generation from that capacity. As evidenced by the substantial decline in gas generation with increased renewables generation, the relationship between added renewables and gas is actually NEGATIVE. Note also that the study was done in 2016 at a national level where other states have not adapted to the increased renewables. California has added only 300 MW of new gas capacity since 2013 (the other 2,500 MW replaced a larger amount of retired gas generation). So on net California’s renewables have SAVED on GHG social costs. Please provide a numeric calculation demonstrating that California’s GHG emissions have increased in the manner that you describe.

            If you really bothered to look at my qualifications, you would see that I work extensively for the California CCAs and several intervenor groups at the CPUC that hardly have a “cozy” relationship with the IOUs. Read my blog at and you will see my critiques of the IOUs. And the CPUC and CEC staff hardly have a “cozy” relationship with the IOUs (and I haven’t worked on a CPUC funded project since 2005 or under contract to the CEC since 2014.) Almost everything in your post is fictional.

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