Do small modular reactors (SMR) hold real promise?

The economic analyses of the projected costs for small modular reactors (SMRs) appear to rely on two important assumptions: 1) that the plants will run at capacity factors of current nuclear plants (i.e., 70%-90%+) and 2) that enough will be built quickly enough to gain from “learning by doing” on scale as has occurred with solar, wind and battery technologies. The problem with these assumptions is that they require that SMRs crowd out other renewables with little impact on gas-fired generation.

To achieve low costs in nuclear power requires high capacity factors, that is the total electricity output relative to potential output. The Breakthrough Institute study, for example, assumes a capacity factor greater than 80% for SMRs. The problem is that the typical system load factor, that is the average load divided by the peak load, ranges from 50% to 60%. A generation capacity factor of 80% means that the plant is producing 20% more electricity than the system needs. It also means that other generation sources such as solar and wind will be pushed aside by this amount in the grid. Because the SMRs cannot ramp up and down to the same degree as load swings, not only daily but also seasonally, the system will still need load following fossil-fuel plants or storage. It is just the flip side of filling in for the intermittency of renewables.

To truly operate within the generation system in a manner that directly displaces fossil fuels, an SMR will have to operate at a 60% capacity factor or less. Accommodating renewables will lower that capacity factor further. Decreasing the capacity factor from 80% to 60% will increase the cost of an SMR by a third. This would increase the projected cost in the Breakthrough Institute report for 2050 from $41 per megawatt-hour to $55 per megawatt-hour. Renewables with storage are already beating this cost in 2022 and we don’t need to wait 30 years.

And the Breakthrough Institute study relies questionable assumptions about learning by doing in the industry. First, it assumes that conventional nuclear will experience a 5% learning benefit (i.e., costs will drop 5% for each doubling of capacity). In fact, the industry shows a negative learning rate--costs per kilowatt have been rising as more capacity is built. It is not clear how the SMR industry will reverse this trait. Second, the learning by doing effect in this industry is likely to be on a per plant rather than per megawatt or per turbine basis as has been the case with solar and turbines. The very small unit size for solar and turbine allows for off site factory production with highly repetitive assembly, whereas SMRs will require substantial on-site fabrication that will be site specific. SMR learning rates are more likely to follow those for building construction than other new energy technologies.

Finally, the report does not discuss the risk of catastrophic accidents. The probability of a significant accident is about 1 per 3,700 reactor operating years. Widespread deployment of SMRs will vastly increase the annual risk because that probability is independent of plant size. Building 1,000 SMRs could increase the risk to such a level that these accidents could be happening once every four years.

The Fukushima nuclear plant catastrophe is estimated to have cost $300 billion to $700 billion. The next one could cost in excess of $1 trillion. This risk adds a cost of $11 to $27 per megawatt-hours.

Adding these risk costs on top of the adjusted capacity factor, the cost ranges rises to $65 to $82 per megawatt-hour.

The real lessons from California’s 2000-01 electricity crisis and what they mean for today’s markets

The recent reliability crises for the electricity markets in California and Texas ask us to reconsider the supposed lessons from the most significant extended market crisis to date– the 2000-01 California electricity crisis. I wrote a paper two decades ago, The Perfect Mess, that described the circumstances leading up to the event. There have been two other common threads about supposed lessons, but I do not accept either as being true solutions and are instead really about risk sharing once this type of crisis ensues rather than being useful for preventing similar market misfunctions. Instead, the real lesson is that load serving entities (LSEs) must be able to sign long-term agreements that are unaffected and unfettered directly or indirectly by variations in daily and hourly markets so as to eliminate incentives to manipulate those markets.

The first and most popular explanation among many economists is that consumers did not see the swings in the wholesale generation prices in the California Power Exchange (PX) and California Independent System Operator (CAISO) markets. In this rationale, if consumers had seen the large increases in costs, as much as 10-fold over the pre-crisis average, they would have reduced their usage enough to limit the gains from manipulating prices. Consumers should have shouldered the risks in the markets in this view and their cumulative creditworthiness could have ridden out the extended event.

This view is not valid for several reasons. The first and most important is that the compensation to utilities for stranded assets investment was predicated on calculating the difference between a fixed retail rate and the utilities cost of service for transmission and distribution plus the wholesale cost of power in the PX and CAISO markets. Until May 2000, that difference was always positive and the utilities were well on the way to collecting their Competition Transition Charge (CTC) in full before the end of the transition period March 31, 2002. The deal was if the utilities were going to collect their stranded investments, then consumers rates would be protected for that period. The risk of stranded asset recovery was entirely the utilities’ and both the California Public Utilities Commission in its string of decisions and the State Legislature in Assembly Bill 1890 were very clear about this assignment.

The utilities had chosen to support this approach linking asset value to ongoing short term market valuation over an upfront separation payment proposed by Commissioner Jesse Knight. The upfront payment would have enabled linking power cost variations to retail rates at the outset, but the utilities would have to accept the risk of uncertain forecasts about true market values. Instead, the utilities wanted to transfer the valuation risk to ratepayers, and in return ratepayers capped their risk at the current retail rates as of 1996. Retail customers were to be protected from undue wholesale market risk and the utilities took on that responsibility. The utilities walked into this deal willingly and as fully informed as any party.

As the transition period progressed, the utilities transferred their collected CTC revenues to their respective holding companies to be disbursed to shareholders instead of prudently them as reserves until the end of the transition period. When the crisis erupted, the utilities quickly drained what cash they had left and had to go to the credit markets. In fact, if they had retained the CTC cash, they would not have had to go the credit markets until January 2001 based on the accounts that I was tracking at the time and PG&E would not have had a basis for declaring bankruptcy.

The CTC left the market wide open to manipulation and it is unlikely that any simple changes in the PX or CAISO markets could have prevented this. I conducted an analysis for the CPUC in May 2000 as part of its review of Pacific Gas & Electric’s proposed divestiture of its hydro system based on a method developed by Catherine Wolfram in 1997. The finding was that a firm owning as little as 1,500 MW (which included most merchant generators at the time) could profitably gain from price manipulation for at least 2,700 hours in a year. The only market-based solution was for LSEs including the utilities to sign longer-term power purchase agreements (PPAs) for a significant portion (but not 100%) of the generators’ portfolios. (Jim Sweeney briefly alludes to this solution before launching to his preferred linkage of retail rates and generation costs.)

Unfortunately, State Senator Steve Peace introduced a budget trailer bill in June 2000 (as Public Utilities Code Section 355.1, since repealed) that forced the utilities to sign PPAs only through the PX which the utilities viewed as too limited and no PPAs were consummated. The utilities remained fully exposed until the California Department of Water Resources took over procurement in January 2001.

The second problem was a combination of unavailable technology and billing systems. Customers did not yet have smart meters and paper bills could lag as much as two months after initial usage. There was no real way for customers to respond in near real time to high generation market prices (even assuming that they would have been paying attention to such an obscure market). And as we saw in the Texas during Storm Uri in 2021, the only available consumer response for too many was to freeze to death.

This proposed solution is really about shifting risk from utility shareholders to ratepayers, not a realistic market solution. But as discussed above, at the core of the restructuring deal was a sharing of risk between customers and shareholders–a deal that shareholders failed to keep when they transferred all of the cash out of their utility subsidiaries. If ratepayers are going to take on the entire risk (as keeps coming up) then either authorized return should be set at the corporate bond debt rate or the utilities should just be publicly owned.

The second explanation of why the market imploded was that the decentralization created a lack of coordination in providing enough resources. In this view, the CDWR rescue in 2001 righted the ship, but the exodus of the community choice aggregators (CCAs) again threatens system integrity again. The preferred solution for the CPUC is now to reconcentrate power procurement and management with the IOUs, thus killing the remnants of restructuring and markets.

The problem is that the current construct of the PCIA exit fee similarly leaves the market open to potential manipulation. And we’ve seen how virtually unfettered procurement between 2001 and the emergence of the CCAs resulted in substantial excess costs.

The real lessons from the California energy crisis are two fold:

  • Any stranded asset recovery must be done as a single or fixed payment based on the market value of the assets at the moment of market formation. Any other method leaves market participants open to price manipulation. This lesson should be applied in the case of the exit fees paid by CCAs and customers using distributed energy resources. It is the only way to fairly allocate risks between customers and shareholders.
  • LSEs must be able unencumbered in signing longer term PPAs, but they also should be limited ahead of time in the ability to recover stranded costs so that they have significant incentives to prudently procure resources. California’s utilities still lack this incentive.

That California owns its water doesn’t mean that the state can just take it back without paying for it

The researchers at the UC Davis Center for Watershed Sciences wrote an insightful blog on “Considerations for Developing An Environmental Water Right in California.” However one passage jumped out at me that has troubling economic implications:

The potential for abuse is particularly troubling when the State is using public funds to buy water, which technically belongs to the people of the state and which the State can already regulate to achieve the same aims.

It’s not helpful to refer to the fiction that the somehow the state can award water rights, on which entities make economic investments based on private uses, and then turn around and try to claim that the state can just take those rights back without any compensation. That’s a foolish perspective that will lead mispricing and misallocation of water use. It is reasonable to assert that the state can claim a right of first refusal on transactions or even that a rights holder can’t withhold sale of a water right to the state, but in either case, the rights holder does receive compensation. The state’s right can easily be interpreted as that of a landlord who has a long term lease agreement with a tenant, and the tenancy agreement can be terminated with compensation to that tenant.

Close Diablo Canyon? More distributed solar instead

More calls for keeping Diablo Canyon have coming out in the last month, along with a proposal to match the project with a desalination project that would deliver water to somewhere. (And there has been pushback from opponents.) There are better solutions, as I have written about previously. Unfortunately, those who are now raising this issue missed the details and nuances of the debate in 2016 when the decision was made, and they are not well informed about Diablo’s situation.

One important fact is that it is not clear whether continued operation of Diablo is safe. Unit No. 1 has one of the most embrittled containment vessels in the U.S. that is at risk during a sudden shutdown event.

Another is that the decision would require overriding a State Water Resources Control Board decision that required ending the use of once-through cooling with ocean water. That cost was what led to the closure decision, which was 10 cents per kilowatt-hour at current operational levels and in excess of 12 cents in more likely operations.

So what could the state do fairly quickly for 12 cents per kWh instead? Install distributed energy resources focused on commercial and community-scale solar. These projects cost between 6 and 9 cents per kWh and avoid transmission costs of about 4 cents per kWh. They also can be paired with electric vehicles to store electricity and fuel the replacement of gasoline cars. Microgrids can mitigate wildfire risk more cost effectively than undergrounding, so we can save another $40 billion there too. Most importantly they can be built in a matter of months, much more quickly than grid-scale projects.

As for the proposal to build a desalination plant, pairing one with Diablo would both be overkill and a logistical puzzle. The Carlsbad plant produces 56,000 acre-feet annually for San Diego County Water Agency. The Central Coast where Diablo is located has a State Water Project allocation of 45,000 acre-feet which is not even used fully now. That plant uses 35 MW or 1.6% of Diablo’s output. A plant built to use all of Diablo’s output could produce 3.5 million acre-feet, but the State Water Project would need to be significantly modified to move the water either back to the Central Valley or beyond Santa Barbara to Ventura. All of that adds up to a large cost on top of what is already a costly source of water of $2,500 to $2,800 per acre-foot.

What rooftop solar owners understand isn’t mythological

Severin Borenstein wrote another blog attacking rooftop solar (a pet peeve of his at least a decade because these weren’t being installed in “optimal” locations in the state) entitled “Myths that Solar Owners Tell Themselves.” Unfortunately he set up a number of “strawman” arguments that really have little to do with the actual issues being debated right now at the CPUC. Here’s responses to each his “myths”:

Myth #1 – Customers are paid only 4 cents per kWh for exports: He’s right in part, but then he ignores the fact that almost all of the power sent out from rooftop panels are used by their neighbors and never gets to the main part of the grid. The utility is redirecting the power down the block.

Myth #2 – The utility sells the power purchased at retail back to other customers at retail so the net so it’s a wash: Borenstein’s claim ignores the fact that when the NEM program began the utilities were buying power that cost more than the retail rate at the time. During NEM 1.0 the IOUs were paying in excess of 10c/kwh for renewable power (RPS) power purchase agreements (PPAs). Add the 4c/kWh for transmission and that’s more than the average rate of 13c/kWh that prevailed during that time. NEM 2.0 added a correction for TOU pricing (that PG&E muffled by including only the marginal generation cost difference by TOU rather than scaling) and that adjusted the price some. But those NEM customers signed up not knowing what the future retail price would be. That’s the downside of failing to provide a fixed price contract tariff option for solar customers back then. So now the IOUs are bearing the consequences of yet another bad management decision because they were in denial about what was coming.

Myth #3 – Rooftop solar is about disrupting the industry: Here Borenstein appears to be unaware of the Market Street Railway case that states that utilities are not protected from technological change. Protecting companies from the consequences of market forces is corporate socialism. If we’re going to protect shareholders from risk (and its even 100% protection), then the grid should be publicly owned instead. Sam Insull set up the regulatory scam a century ago arguing that income assurance was needed for grid investment, and when the whole scheme collapsed in the Depression, the Public Utility Holding Company Act of 1935 (PUHCA)was passed. Shareholders need to pick their poison—either be exposed to risk or transfer their assets public ownership, but wealthy shareholders should not be protected.

Myth #3A – Utilities made bad investments and should bear the risks: Borenstein is arguing since the utilities have run the con for the last decade and gotten approval from the CPUC, they should be protected. Yet I submitted testimony repeatedly starting in 2010 both PG&E’s and SCE’s GRCs that warned that they had overforecasted load growth. I was correct—statewide retail sales are about the same today as they were in 2006. Grid investment would have been much different if those companies had listened and corrected their forecasts. Further the IOUs know how to manipulate their regulatory filings to ensure that they still get their internally targeted income. Decoupling that ensures that the utility receives its guaranteed income regardless of sales further shields them. From 1994 to 2017, PG&E hit its average allowed rate of return within 0.1%. (More on this later.) A UCB economics graduate student found that the return on equity is up to 4% too high (consistent with analysis I’ve done).

Myth #3B – Time to take away the utility’s monopoly: No, we no longer need to have monopoly electric service. The same was said about telecommunications three decades ago. Now we have multiple entities vying for our dollars. The CPUC conducted a study in 1999 that was included in PG&E’s GRC proposed decision (thanks to the late Richard Bilas) that showed that economies of scale disappeared after several hundred thousand customers (and that threshold is likely lower now.) And microgrids are becoming cost effective, especially as PG&E’s rates look like they will surpass 30 cents per kWh by 2026.

Myth #4 – There aren’t barriers to the poor putting panels on their roofs: First, the barriers are largely regulatory, not financial. The CPUC has erected them to prevent aggregation of low-income customers to be able to buy into larger projects that serve these communities.

Second, there are many market mechanisms today where those with lower income are offered products or services at a higher long term price in return for low or no upfront costs. Are we also going to heavily tax car purchases because car leasing is effectively more expensive? What about house ownership vs. rentals? There are issues to address with equity, but to zero in on one small example while ignoring the much wider prevalence sets  up another strawman argument.

Further, there are better ways to address the inequity in rooftop solar distribution. That inequity isn’t occurring duo to affordability but rather because of split incentives between landlords and tenants.

A much easier and more direct fix would be to modify Public Utilities Code Sections 218 to allow local sales among customers or by landlords or homeowner associations to tenants and 739.5 to allow more flexibility in pricing those sales. But allowing those changes will require that the utilities give up iron-fisted control of electricity production.

Myth #5 – Rooftop solar is the only thing that makes it cost-effective to electrify: Borenstein focuses on the what source of high rates. Rooftop solar might be raising rates, but it probably delivered as much in offsetting savings. At most those customers increased rates by 10%, but utility rates are 70-100% above the direct marginal costs of service. The sources of that difference are manifest. PG&E has filed in its 2023 GRC a projected increase in the average standard residential rate to 38 cents per kWh by 2026, and perhaps over 40 cents once undergrounding to mitigate wildfire is included. The NREL studies on microgrids show that individual home microgrids cost about 34 cents per kWh now and battery storage prices are still dropping. Exiting the grid starts to look a lot more attractive.

Maybe if we look only at the status quo as unchanging and accept all of the utilities’ claims about their “necessary” management decisions and the return required to attract investors, then these arguments might hold water. But none of these factors are true based on the empirical work presented in many forums including at the CPUC over the last decade. These beliefs are not so mythological.

Finally, Borenstein finishes with “(a)nd we all need to be open to changing our minds as a result of changing technology and new data.” Yet he has been particularly unyielding on this issue for years, and has not reexamined his own work on electricity markets from two decades ago. The meeting of open minds requires a two-way street.

Getting EVs where we need them in multi family and low-income communities

They seem to be everywhere. A pickup rolls up to a dark house in a storm during the Olympics and the house lights come on. (And even powers a product launch event when the power goes out!) The Governator throws lightning bolts like Zeus in a Super Bowl ad touting them. The top manufacturer is among the most valuable companies in the world and the CEO is a cultural icon. Electric vehicles (EVs) or cars are making a splash in the state.

The Ford F-150 Lightning pick up generated so much excitement last summer that it had to increase its initial roll out from 40,000 to 80,000 to 200,000 due to demand. General Motors answered with electric versions of the Silverado and Hummer. (Dodge is bringing up the rear with its Ram and Dakota pickups.)

Much of this has been spurred by California’s EV sales mandates that date back to 1990. The state now plans to phase out the sale of new cars and passenger trucks entirely by 2035, with 35% of sales by 2026. In the first quarter of 2022, EVs were 16% of new car sales.

While EVs look they will be here to stay, the question is where will drivers be able to charge up? That means recharging at home, at work, and on the road when needed. The majority of charging—70% to 80%–occurs at home or at work. Thanks to the abundance of California’s renewable energy, largely from solar power including from rooftops, the most advantageous time is in the middle of the day. The next big hurdle will be putting charging stations where they are needed, most valuable and accessible to those who don’t live in conventional single-family housing.

The state has about 80,000 public and shared private chargers, of which about 10% are DC “fast chargers” that can deliver 80% capacity in about 30 minutes. Yet we likely need 20 times more chargers that what we have today.

Multi-family housing is considered a prime target for additional chargers because of various constraints on tenants such as limitations on installing and owning a charging station and sharing of parking spaces. Community solar panels can be outfitted with charging stations that rely on the output of the panels.

California has a range of programs to provide incentives and subsidies for installing chargers. Funding for another 5,000 chargers was recently authorized. The state funds the California Electric Vehicle Infrastructure Project (CALeVIP) that provides direct incentives and works with local partners plan and install Level 2 and DC fast charging infrastructure. This program has about $200 million available. The program has 13 county and regional projects that contribute $6,000 and more for Level 2 chargers and often $80,000 for a DC fast charger. A minimum of 25% of funds are reserved for disadvantaged and low-income communities. In many cases, the programs are significantly oversubscribed with waiting lists, but the state plans to add enough funding for an additional 100,000 charging stations in the 2022-23 fiscal year, with $900 million over the next four years.

California’s electric utilities also fund charging projects, although those programs open and are quickly oversubscribed.

  • Southern California Edison manages the Charge Ready program with a focus on multi-family properties including mobilehome parks. The program offers both turn-key installation and rebates. SCE’s website provides tools for configuring a parking lot for charging.
  • San Diego Gas & Electric offered Power Your Drive to multi-family developments, with 255 locations currently. SDG&E has added the Power Your Drive Extension to add another 2,000 charging stations over the next two years. SDG&E will provide up to $12,000 for Level 2 chargers and additional maintenance funding.
  • Pacific Gas & Electric offered the EV Charge program in which PG&E will pay for, own, maintain and coordinate construction of infrastructure from the transformer to the parking space, as well as support independent ownership and operation. The program is not currently taking applications however. PG&E’s website offers other tools for assessing the costs and identifying vendors for installing chargers.
  • PG&E is launching a “bidirectional” EV charging pilot program with General Motors that will test whether EVs can be used to improve electric system reliability and resilience by using EVs as back up energy storage. The goal is to extend the program by the end of 2022. This new approach may provide EV owners with additional value beyond simply driving around town. PG&E also is setting up a similar pilot with Ford.
  • Most municipally-owned electric utilities offer rebates and incentives as well..

Community residents have a range of incentives available to them to purchase an EV.

  • The state offers $750 through the Clean Fuel Reward on the purchase of a new EV. .
  • California also offers the Clean Vehicle Rebate Project that offers $1,000 to $7,000 for buying or leasing a (non-Tesla) to households making less than $200,000 or individuals making less than $135,000. Savings depend on location and vehicle acquired.
  • Low-income households can apply for a state grant to purchase a new or used electric or hybrid vehicle, plus $2,000 for a home charging station, through the Clean Vehicle Assistance Program. The income standards are about 50% higher than those establishing eligibility for the CARE utility rate discount. The average grant is about $5,000.
  • The federal government offers a tax credit of up to $7,500 depending on the make and model of vehicle.
  • Car owners also can scrap their gasoline-fueled cars for $1,000 to $1,500, depending on household income.
  • Several counties, including San Diego and Sonoma, have offered EV purchase incentives to county residents. Those programs open and fill fairly quickly.

The difference between these EVs coming down the road (yes, that’s a pun) and the current models is akin to the difference between flip phones and smart phones. One is a single function communication device, and we use the latter to manage our lives. The marketing of EVs could shift course to emphasize these added benefits that are not possible with a conventional vehicle. We can expect a similar transformation in how we view energy and transportation as the communication and information revolution.

A reply: two different ways California can keep the lights on amid climate change

Mike O’Boyle from Energy Innovation wrote an article in the San Francisco Chronicle listing four ways other than building more natural gas plants to maintain reliability in the state. He summarizes a set of solutions for when the electricity grid can get 85% of its supply from renewable sources, presumably in the next decade. He lists four options specifically:

  • Off shore wind
  • Geothermal
  • Demand response and management
  • Out of state imports

The first three make sense, although the amount of geothermal resources is fairly limited relative to the state’s needs. The problem is the fourth one.

California already imports about a fifth of its electric energy. If we want other states to also electrify their homes and cars, we need to allow them to use their own in-state resources. Further, the cost of importing power through transmission lines is much higher than conventional analyses have assumed. California is going to have to meet as much of its demands internally as possible.

Instead, we should be pursuing two other options:

  • Dispersed microgrids with provisions for conveying output among several or many customers who can share the system without utility interaction. Distributed solar has already reduced the state’s demand by 12% to 20% since 2006. This will require that the state modify its laws regulating transactions among customers and act to protect the investments of those customers against utility interests.
  • Replacing natural gas in existing power plants with renewable biogas. A UC Riverside study shows a potential of 68 billion cubic feet which is about 15% of current gas demand for electricity production. Instead of using this for home cooking, it can meet the limited peak day demands of the electricity grid.

Both of these solutions can be implemented much more quickly than an expanded transmission grid and building new resources in other states. They just take political will.

The evidence is clear: masks have been a highly effective deterrent to the spread of COVID-19

The San Francisco Chronicle ran an op-ed by four physicians claiming that “Mask mandates are not effective” (Open Forum, April 19). They are part of a larger group that are advocating for the “Urgency of Normal.” Parents have used their views to call for ending mask mandates in schools as being ineffective.

However, these experts’ analysis ignores the strongest evidence of the effectiveness of masks. We had a “control” during the 2019-21 period — the dramatic decline in the influenza rate.

In the 2019-20 season, 22,000 died of flu based on data from the Centers for Disease Control and Prevention (CDC). In the 2020-21 season, about 750 died–a decline of 96%. In 2021-22, deaths are estimated to be up to 7,700 which is still at least 60% below pre-pandemic levels. We had many more social interactions but still had mask mandates in many settings which leads to the conclusion that masks have been a major contributor to reducing transmission of both influenza and COVID-19.

Part of the decline might be from some dying from COVID instead, but overlap in cases was far from 100%. The one constant throughout has been the prevalence of masks. Epidemiological data is much more compelling than the quasi-controlled studies that the physicians refer to, especially when we have such a clear control. The experts must fully explain the dramatic decline in flu mortality before they can dismiss the effectiveness of masks.

What “Electrify Everything” has wrong about “reduce, reuse, recycle”

Saul Griffith has written a book that highlights the role of electrification in achieving greenhouse gas emission reductions, and I agree with his basic premise. But he misses important aspects about two points. First, the need to reduce, reuse and recycle goes well beyond just energy consumption. And second, we have the ability to meet most if not all of our energy needs with the lowest impact renewable sources.

Reduce, reuse and recycle is not just about energy–it’s also about reducing consumption of natural resources such as minerals and biomass, as well as petroleum and methane used for plastics, and pollution caused by that consumption. In many situations, energy savings are only a byproduct. Even so, almost always the cheapest way to meet an energy need is to first reduce its use. That’s what energy efficiency is about. So we don’t want to just tell consumers to continue along their merry way, just switch it up with electricity. A quarter to a third our global GHG emissions are from resource consumption, not energy use.

In meeting our energy needs, we can largely rely on solar and wind supplemented with biofuels. Griffith asserts that the U.S. would need 2% of its land mass to supply the needed electricity, but his accounting makes three important errors. First, placing renewables doesn’t eliminate other uses of that land, particularly for wind. Acreage devoted to wind in particular can be used also for different types of farming and even open space. In comparison, fossil-fuel and nuclear plants completely displace any other land use. Turbine technology is evolving to limit avian mortality (and even then its tall buildings and household cats that cause most bird deaths). Second most of the solar supply can be met on rooftops and covering parking lots. These locations are cost effective compared to grid scale sources once we account for transmission costs. And third, our energy storage is literally driving down the road–in our new electric vehicles. A 100% EV fleet in California will have enough storage to meet 30 times the current peak load. A car owner will be able to devote less than 5% of their battery capacity to meet their home energy needs. All of this means that the real footprint can be much less than 1%.

Nuclear power has never lived up to its promise and is expensive compared to other low-emission options. While the direct costs of current-technology nuclear power is more than 12 cents a kilowatt-hour when adding transmission, grid-scale renewables are less than half of that, and distributed energy resources are at least comparable with almost no land-use footprint and able to provide better reliability and resilience. In addition, the potential of catastrophic events at nuclear plants adds another 1 to 3 cents per kilowatt-hour. Small modular reactors (SMR) have been promoted as a game changer, but we have been waiting for two decades. Nuclear or green hydrogen may emerge as economically-viable options, but we shouldn’t base our plans on that.

Guidelines For Better Net Metering; Protecting All Electricity Customers And The Climate

Authors Ahmad Faruqui, Richard McCann and Fereidoon Sioshansi[1] respond to Professor Severin Borenstein’s much-debated proposal to reform California’s net energy metering, which was first published as a blog and later in a Los Angeles Times op-ed.