Tag Archives: electrification

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.

Are fixed charges the solution to the solar rooftop dilemma?

A recent post at the Energy Institute at Haas proposed that all residential ratepayers should pay the “solar tax” in the recently withdrawn proposed decision from the California Public Utilities Commission through a connection fee. I agree that charging residential a connection charge is a reasonable solution. (All commercial and agricultural customers in California already pay such a charge.) The more important question though is what that connection fee should be?

Much less of the distribution costs are “fixed” than many proponents understand–we can see an example of the ability to avoid large undergrounding costs by installing microgrids as an example. Southern California Edison has repeatedly asked for a largely fixed “grid charge” for the last dozen years and the intervening ratepayer groups have shown that SCE’s estimate is much too high. A service connection costs about $10-$15/month, not more than $50 per month. So what might be the other elements of a fixed monthly charge rather than collecting these revenues through a volumetric rate as is done today?

A strong economic argument can be made that if the utility is collecting a fixed charge for upstream T&D capacity, then a customer should be able to trade that capacity that they have paid for with other customers. In the face of transaction costs, that market would devolve down to the per kWh price managed by the utility acting as a dealer–just what we have today.

Other candidates abound. How to recover stranded costs really requires a conversation about how much of those costs shareholders should shoulder. Income distributional public purpose costs should be collected from taxes, not rates. Energy efficiency is a resource that should be charged in the generation component, not distribution, and should be treated like other generation resources in cost recovery. The problem is that decoupling which was used to encourage energy efficiency investment has become a backdoor way to recover stranded costs without any conversation about whether that is appropriate–rates go up as demand decreases with little reduction in revenue requirements. So what the connection charge should be becomes quite complex.

What to do about Diablo Canyon?

The debate over whether to close Diablo Canyon has resurfaced. The California Public Utilities Commission, which support from the Legislature, decided in 2018 to close Diablo by 2025 rather than proceed to relicensing. PG&E applied in 2016 to retire the plant rather than relicense due to the high costs that would make the energy uneconomic. (I advised the Joint CCAs in this proceeding.)

Now a new study from MIT and Stanford finds potential savings and emission reductions from continuing operation. (MIT in particular has been an advocate for greater use of nuclear power.) Others have written opinion articles on either side of the issue. I wrote the article below in the Davis Enterprise addressing this issue. (It was limited to 900 words so I couldn’t cover everything.)

IT’S OK TO CLOSE DIABLO CANYON NUCLEAR PLANT
A previous column (by John Mott-Smith) asked whether shutting down the Diablo Canyon nuclear plant is risky business if we don’t know what will replace the electricity it produces. John’s friend Richard McCann offered to answer his question. This is a guest column, written by Richard, a universally respected expert on energy, water and environmental economics.

John Mott-Smith asked several questions about the future of nuclear power and the upcoming closure of PG&E’s Diablo Canyon Power Plant in 2025. His main question is how are we going to produce enough reliable power for our economy’s shift to electricity for cars and heating. The answers are apparent, but they have been hidden for a variety of reasons.
I’ve worked on electricity and transportation issues for more than three decades. I began my career evaluating whether to close Sacramento Municipal Utility District’s Rancho Seco Nuclear Generating Station and recently assessed the cost to relicense and continue operations of Diablo after 2025.
Looking first at Diablo Canyon, the question turns almost entirely on economics and cost. When the San Onofre Nuclear Generating Station closed suddenly in 2012, greenhouse gas emissions rose statewide the next year, but then continued a steady downward trend. We will again have time to replace Diablo with renewables.
Some groups focus on the risk of radiation contamination, but that was not a consideration for Diablo’s closure. Instead, it was the cost of compliance with water quality regulations. The power plant currently uses ocean water for cooling. State regulations required changing to a less impactful method that would have cost several billion dollars to install and would have increased operating costs. PG&E’s application to retire the plant showed the costs going forward would be at least 10 to 12 cents per kilowatt-hour.
In contrast, solar and wind power can be purchased for 2 to 10 cents per kilowatt-hour depending on configuration and power transmission. Even if new power transmission costs 4 cents per kilowatt-hour and energy storage adds another 3 cents, solar and wind units cost about 3 cents, which totals at the low end of the cost for Diablo Canyon.
What’s even more exciting is the potential for “distributed” energy resources, where generation and power management occurs locally, even right on the customers’ premises rather than centrally at a power plant. Rooftop solar panels are just one example—we may be able to store renewable power practically for free in our cars and trucks.
Automobiles are parked 95% of the time, which means that an electric vehicle (EV) could store solar power at home or work during the day and for use at night. When we get to a vehicle fleet that is 100% EVs, we will have more than 30 times the power capacity that we need today. This means that any individual car likely will only have to use 10% of its battery capacity to power a house, leaving plenty for driving the next day.
With these opportunities, rooftop and community power projects cost 6 to 10 cents per kilowatt-hour compared with Diablo’s future costs of 10 to 12 cents.
Distributed resources add an important local protection as well. These resources can improve reliability and resilience in the face of increasing hazards created by climate change. Disruptions in the distribution wires are the cause of more than 95% of customer outages. With local generation, storage, and demand management, many of those outages can be avoided, and electricity generated in our own neighborhoods can power our houses during extreme events. The ad that ran during the Olympics for Ford’s F-150 Lightning pick-up illustrates this potential.
Opposition to this new paradigm comes mainly from those with strong economic interests in maintaining the status quo reliance on large centrally located generation. Those interests are the existing utilities, owners, and builders of those large plants plus the utility labor unions. Unfortunately, their policy choices to-date have led to extremely high rates and necessitate even higher rates in the future. PG&E is proposing to increase its rates by another third by 2024 and plans more down the line. PG&E’s past mistakes, including Diablo Canyon, are shown in the “PCIA” exit fee that [CCA] customers pay—it is currently 20% of the rate. Yolo County created VCEA to think and manage differently than PG&E.
There may be room for nuclear generation in the future, but the industry has a poor record. While the cost per kilowatt-hour has gone down for almost all technologies, even fossil-fueled combustion turbines, that is not true for nuclear energy. Several large engineering firms have gone bankrupt due to cost overruns. The global average cost has risen to over 10 cents per kilowatt-hour. Small modular reactors (SMR) may solve this problem, but we have been promised these are just around the corner for two decades now. No SMR is in operation yet.
Another problem is management of radioactive waste disposal and storage over the course of decades, or even millennia. Further, reactors fail on a periodic basis and the cleanup costs are enormous. The Fukuyama accident cost Japan $300 to $750 billion. No other energy technology presents such a degree of catastrophic failure. This liability needs to be addressed head on and not ignored or dismissed if the technology is to be pursued.

Electric vehicles as the next smartphone

In 2006 a cell phone was portable phone that could send text messages. It was convenient but not transformative. No one seriously thought about dropping their landlines.

And then the iPhone arrived. Almost overnight consumers began to use it like their computer. They emailed, took pictures and sent them to their friends, then searched the web, then played complex games and watched videos. Social media exploded and multiple means of communicating and sharing proliferated. Landlines (and cable) started to disappear, and personal computer sales slowed. (And as a funny side effect, the younger generation seemed to quit talking on the phone.) The cell phone went from a means of one-on-one communication to a multi-faceted electronic tool that has become our pocket computer.

The U.S. population owning a smartphone has gone from 35% to 85% in the last decade. We could achieve similar penetration rates for electric vehicles (EVs) if we rethink and repackage how we market EVs to become our indispensable “energy management tool.” EVs can offer much more than conventional cars and we need to facilitate and market these advantages to sell them much faster.

EV pickups with spectacular features are about to be offered. These EVs may be a game changer for a different reason than what those focused on transportation policy think of–they offer households the opportunity for near complete energy independence. These pick ups have both enough storage capacity to power a house for several days and are designed to supply power to many other uses, not just driving. Combined with solar panels installed both at home and in business lots, the trucks can carry energy back and forth between locations. This has an added benefit of increasing reliability (local distribution outages are 15 times more likely than system levels ones) and resilience in the face of increasing extreme events.

This all can happen because cars are parked 90-95% of the time. That offers power source reliability in the same range as conventional generation, and the dispersion created by a portfolio of smaller sources further enhances that availability. Another important fact is that the total power capacity for autos on California’s road is over 2,000 gigawatts. Compared to California’s peak load of about 63 gigawatts, this is more than 30 times more capacity than we need. If we simply get to 20% penetration of EVs of which half have interconnective control abilities, we’ll have three times more capacity than we would need to meet our highest demands. There are other energy management issues, but solving them are feasible when we realize there will not be a real physical constraint.

Further, used EV batteries can be used as stationary storage, either in home or at renewable generation to mitigate transmission investments. EVs can transport energy between work and home from solar panels.

The difference between these EVs and the current models is akin to the difference between flip phones and smart phones. One is a single function device and the we use the latter to manage our lives. The marketing of EVs should shift course to emphasize these added benefits that are not possible with a conventional vehicle. The barriers are not technological, but only regulatory (from battery warranties and utility interconnection rules).

As part of this EV marketing focus, automakers should follow two strategies, both drawn from smart phones. The first is that EV pick ups should be leased as a means of keeping model features current. It facilitates rolling out industry standards quickly (like installing the latest Android update) and adding other yet-more attractive features. It also allows for more environmentally-friendly disposal of obsolete EVs. Materials can be more easily recycled and batteries no longer usable for driving (generally below 70% capacity) can be repurposed for stand-alone storage.

The second is to offer add on services. Smart phone companies have media streaming, data management and all sorts of other features beyond simple communication. Automakers can offer demand management to lower, or even eliminate, utility bills and appliance and space conditioning management placed onboard so a homeowner need not install a separate system that is not easily updated.

How to increase renewables? Change the PCIA

California is pushing for an increase in renewable generation to power its electrification of buildings and the transportation sector. Yet the state maintains a policy that will impede reaching that goal–the power cost indifference adjustment (PCIA) rate discourages the rapidly growing community choice aggregators (CCAs) from investing directly in new renewable generation.

As I wrote recently, California’s PCIA rate charged as an exit fee on departed customers is distorting the electricity markets in a way that increases the risk of another energy crisis similar to the debacle in 2000 to 2001. An analysis of the California Independent System Operator markets shows that market manipulations similar to those that created that crisis likely led to the rolling blackouts last August. Unfortunately, the state’s energy agencies have chosen to look elsewhere for causes.

The even bigger problem of reaching clean energy goals is created by the current structure of the PCIA. The PCIA varies inversely with the market prices in the market–as market prices rise, the PCIA charged to CCAs and direct access (DA) customers decreases. For these customers, their overall retail rate is largely hedged against variation and risk through this inverse relationship.

The portfolios of the incumbent utilities, i.e., Pacific Gas and Electric, Southern California Edison and San Diego Gas and Electric, are dominated by long-term contracts with renewables and capital-intensive utility-owned generation. For example, PG&E is paying a risk premium of nearly 2 cents per kilowatt-hour for its investment in these resources. These portfolios are largely impervious to market price swings now, but at a significant cost. The PCIA passes along this hedge through the PCIA to CCAs and DA customers which discourages those latter customers from making their own long term investments. (I wrote earlier about how this mechanism discouraged investment in new capacity for reliability purposes to provide resource adequacy.)

The legacy utilities are not in a position to acquire new renewables–they are forecasting falling loads and decreasing customers as CCAs grow. So the state cannot look to those utilities to meet California’s ambitious goals–it must incentivize CCAs with that task. The CCAs are already game, with many of them offering much more aggressive “green power” options to their customers than PG&E, SCE or SDG&E.

But CCAs place themselves at greater financial risk under the current rules if they sign more long-term contracts. If market prices fall, they must bear the risk of overpaying for both the legacy utility’s portfolio and their own.

The best solution is to offer CCAs the opportunity to make a fixed or lump sum exit fee payment based on the market value of the legacy utility’s portfolio at the moment of departure. This would untie the PCIA from variations in the future market prices and CCAs would then be constructing a portfolio that hedges their own risks rather than relying on the implicit hedge embedded in the legacy utility’s portfolio. The legacy utilities also would have to manage their bundled customers’ portfolio without relying on the cross subsidy from departed customers to mitigate that risk.