Tag Archives: California

California’s perceived “solar glut” problem is actually a “nuclear glut” problem

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Several news stories have asserted that California has a “glut” of solar power that is being wasted and sold at a loss to other states. The problem is that the stories mischaracterize the situation, both in cause and magnitude.

The Diablo Canyon nuclear power units were scheduled to be retired in 2024 and 2025 due to having reached the end of their license and concerns around public safety from the aging plant. As a result, state energy regulators launched an aggressive renewable energy and battery storage procurement process in 2018 following the decision to close Diablo Canyon. Those added resources are now coming online to offset the anticipated loss of energy output from Diablo Canyon’s closure.

However, despite those additional renewable resources, the state legislature and Governor Newsom then extended the life of Diablo Canyon in 2022 to 2030. Diablo Canyon’s 2,200 megawatts of around-the-clock energy production – which adds up to 18 million megawatt hours a year – is the true source of grid management issues, particularly during the spring when the majority of energy curtailments occur.

This imbalance is exacerbated by the large swings in the state’s hydropower production, from 17 million megawatt hours during a dry 2022 to 30 million megawatt hours in a wet 2023. These swings are inherent in California’s power system, and related curtailments were common for decades before solar was on the scene. In other words, California will always need to have excess energy in wet years if it wants sufficient power in the other two-thirds of the years that are average or dry. Diablo Canyon’s year-round, around the clock output only makes that glut worse.

Not only is Diablo Canyon’s extension clogging up transmission lines and driving curtailment, it is also a high cost energy resource. PG&E initially claimed the Diablo Canyon power would cost about 5.5 cent per kilowatt hour, which is near the average cost of the California Independent System Operator’s (CAISO) energy purchases. Instead, PG&E is asking the California Public Utilities Commission to charge more than 9 cents per kilowatt hour, nearly double the cost of the average energy purchase.

Instead of blaming and halting California’s clean energy progress, an easier solution that would solve most of the curtailment issue would be to shut down Diablo Canyon from March to May, when energy demand is lowest in the state. This is when loads are lowest and hydro output the highest. Reducing at least some of Diablo Canyon’s 18 million megawatt hours per year, would more than offset the 3.2 million megawatt hours of solar energy that were curtailed in 2024. Diablo Canyon would still be available to meet summertime peaks. That would save ratepayers money and reduce the need to sell excess generation at a loss. 

California is already addressing other causes of curtailments by installing more storage capacity. It would be foolish to reduce solar generation now when we will need it in the near future to match the additional storage capacity. 

How California’s Rooftop Solar Customers Benefit Other Ratepayers Financially to the Tune of $1.5 Billion

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The California Public Utilities Commission’s (CPUC) Public Advocates Office (PAO) issued in August 2024 an analysis that purported to show current rooftop solar customers are causing a “cost shift” onto non-solar customers amounting to $8.5 billion in 2024. Unfortunately, this rather simplistic analysis started from an incorrect base and left out significant contributions, many of which are unique to rooftop solar, made to the utilities’ systems and benefitting all ratepayers. After incorporating this more accurate accounting of benefits, the data (presented in the chart above) shows that rooftop solar customers will in fact save other ratepayers approximately $1.5 billion in 2024.

The following steps were made to adjust the original analysis presented by the PAO:

  1. Rates & Solar Output: The PAO miscalculates rates and overestimates solar output. Retail rates were calculated based on utilities’ advice letters and proceeding workpapers. They incorporate time-of-use rates according to the hours when an average solar customer is actually using and exporting electricity.  The averages are adjusted to include the share of net energy metering (NEM 1.0 and 2.0) and net billing tariff (NBT or “NEM 3.0”) customers (8% to 18% depending on the utility) who are receiving the California Alternate Rates for Energy program’s (CARE) low-income rate discount. (PAO assumed that all customers were non-CARE). In addition, the average solar panel capacity factor was reduced to 17.5% based on the state’s distributed solar database.[1] Accurately accounting for rates and solar outputs amounts to a $2.457 billion in benefits ignored by the PAO analysis.
  2. Self Generation: The PAO analysis included solar self-consumption as being obligated to pay full retail rates. Customers are not obligated to pay for energy to the utility for self generation. Solar output that is self-consumed by the solar customer was removed from the calculation. Inappropriately including self consumption as “lost” revenue in PAO analysis amounts to $3.989 billion in a phantom cost shift that should be set aside.
  3. Historic Utility Savings: The PAO fails to account for the full and accurate amount of savings and the shift in the system created by rooftop solar that has lowered costs and rates. The historic savings are based on distributed solar displacing 15,000 megawatts of peak load and 23,000 gigawatt-hours of energy since 2006 compared to the California Energy Commission’s (CEC) 2005 Integrated Energy Policy Report forecast.[2] Deferred generation capacity valuation starts with the CEC’s cost of a combustion turbine[3] and is trended to the marginal costs filed in the most recent decided general rate cases. Generation energy is the mix of average California Independent System Operator (CAISO) market prices in 2023,[4] and utilities’ average renewable energy contract prices.[5] Avoided transmission costs are conservatively set at the current unbundled retail transmission rate components. Distribution investment savings are the weighted average of the marginal costs included in the utilities’ general case filings from 2007 to 2021. Accounting for utility savings from distributed solar amounts to $2.165 billion ignored by the PAO’s calculation.
  4. Displaced CARE Subsidy: The PAO analysis does not account for savings from solar customers who would otherwise receive CARE subsidies. When CARE customers buy less energy from the utilities, it reduces the total cost of the CARE subsidy born by other ratepayers. This is equally true for energy efficiency. The savings to all non-CARE customers from displacing electricity consumption by CARE customers with self generation is calculated from the rate discount times that self generation. Accounting for reduced CARE subsidies amounts to $157 million in benefits ignored by the PAO analysis.
  5. Customer Bill Payments: The PAO analysis does not account for payments towards fixed costs made by solar customers. Most NEM customers do not offset all of their electricity usage with solar.[6] NEM customers pay an average of $80 to $160 per month, depending on the utility, after installing solar.[7] Their monthly bill payments more than cover what are purported fixed costs, such as the service transformer. A justification for the $24 per month customer charge was a purported under collection from rooftop solar customers.[8] Subtracting the variable costs represented by the Avoided Cost Calculator from these monthly payments, the remainder is the contribution to utility fixed costs, amounting to an average of $70 per month. (In comparison for example, PG&E proposed an average fixed charge of $51 per month in the income graduated fixed charge proceeding.[9]) There is no data available on average NBT bills, but NBT customers also pay at least $15 per month in a minimum fixed charge today.[10] Accounting for fixed cost payments adds $1.18 billion in benefits ignored by the PAO analysis.

The correct analytic steps are as follows:

NEM Net Benefits = [(kWh Generation [Corrected] – kWh Self Use) x Average Retail Rate Compensation [Corrected] )]
– [(kWh Generation [Corrected] – kWh Self Use) x Historic Utility Savings ($/kWh)]
– [CARE/FERA kWh Self Use x CARE/FERA Rate Discount ($/kWh)]
– [(kWh Delivered x (Average Retail Rate ($/kWh) – Historic Utility Savings $(kWh))]

NBT Net Benefits = [(kWh Generation [Corrected] – kWh Self Use) x Average Retail Rate Compensation [Corrected])]
– [(kWh Generation [Corrected] – kWh Self Use) x Avoided Cost (Corrected) ($/kWh)]
– [CARE/FERA kWh Self Use x CARE/FERA Rate Discount ($/kWh)]
– [(Net kWh Delivered x (Average Retail Rate ($/kWh) – Historic Utility Savings $(kWh))]

This analysis is not a value of solar nor a full benefit-cost analysis. It is only an adjusted ratepayer-impact test calculation that reflects the appropriate perspective given the PAO’s recent published analysis. A full benefit-cost analysis would include a broader assessment of impacts on the long-term resource plan, environmental impacts such as greenhouse gas and criteria air pollutant emissions, changes in reliability and resilience, distribution effects including from shifts in environmental impacts, changes in economic activity, and acceleration in technological innovation. Policy makers may also want to consider other non-energy benefits as well such local job creation and supporting minority owned businesses.

This analysis applies equally to one conducted by Severin Borenstein at the University of California’s Energy Institute at Haas. Borenstein arrived at an average retail rate similar to the one used in this analysis, but he also included an obligation for self generation to pay the retail rate, ignored historic utility cost savings and did not include existing bill contributions to fixed costs.

The supporting workpapers are posted here.

Thanks to Tom Beach at Crossborder Energy for a more rigorous calculation of average retail rates paid by rooftop solar customers.

[1] PAO assumed a solar panel capacity factor of 20%, which inflates the amount of electricity that comes from solar. For a more accurate calculation see California Distributed Generation Statistics, https://www.californiadgstats.ca.gov/charts/.

[2] This estimate is conservative because it does not include the accumulated time value of money created by investment begun 18 years ago. It also ignores the savings in reduced line losses (up to 20% during peak hours), avoided reserve margins of at least 15%, and suppressed CAISO market prices from a 13% reduction in energy sales.

[3] CEC, Comparative Costs of California Central Station Electricity Generation Technologies, CEC-200-2007-011-SF, December 2007.

[4] CAISO, 2023 Annual Report on Market Issues & Performance, Department of Market Monitoring, July 29, 2024.

[5] CPUC, “2023 Padilla Report: Costs and Cost Savings for the RPS Program,” May 2023.

[6] Those customers who offset all of their usage pay minimum bills of at least $12 per month.

[7] PG&E, SCE and SDG&E data responses to CALSSA in CPUC Proceeding R.20-08-020, escalated from 2020 to 2024 average rates.

[8] CPUC Decision 24-05-028.

[9] CPUC Proceeding Rulemaking 22-07-005.

[10] The average bill for NBT customer is not known at this time.

How to properly calculate the marginal GHG emissions from electric vehicles and electrification

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Recently the questions about whether electric vehicles increase greenhouse gas (GHG) emissions and tracking emissions directly to generation on a 24/7 basis have gained saliency. This focus on immediate grid-created emissions illustrates an important concept that is overlooked when looking at marginal emissions from electricity. The decision to consume electricity is more often created by a single large purchase or action, such as buying a refrigerator or a new electric vehicle, than by small decisions such as opening the refrigerator door or driving to the grocery store. Yet, the conventional analysis of marginal electricity costs and emissions assumes that we can arrive at a full accounting of those costs and emissions by summing up the momentary changes in electricity generation measured at the bulk power markets created by opening that door or driving to the store.

But that’s obviously misleading. The real consumption decision that created the marginal costs and emissions is when that item is purchased and connected to the grid. And on the other side, the comparative marginal decision is the addition of a new resource such as a power plant or an energy efficiency investment to serve that new increment of load.

So in that way, your flight to Boston is not whether you actually get on the plane, which is like opening the refrigerator door, but rather your purchase of the ticket which led to the incremental decision by the airline to add another scheduled flight. It’s the share of the fuel use for that added flight which is marginal, just as buying a refrigerator is responsible for the share of the energy from the generator added to serve the incremental long-term load.

There are growing questions about the use of short run market prices as indicators of market value of generation assets for a number of reasons. This paper critiquing “surge” pricing on the grid has one set of aspects that undermine that principle.

Meredith Fowley at the Energy Institute at Haas compared two approaches to measuring the additional GHG emissions from a new electric vehicle. The NREL paper uses the correct approach of looking at longer term incremental resource additions rather than short run operating emissions. The hourly marginal energy use modeled by Holland et al (2022) is not particularly relevant to the question of GHG emissions from added load for several reasons and for that reason any study that doesn’t use a capacity expansion model will deliver erroneous results. In fact, you will get more accurate results from relying on a simple spreadsheet model using capacity expansion than a complex production cost hourly model.

In the electricity grid, added load generally doesn’t just require increased generation from existing plants, but rather it induces investment in new generation (or energy savings elsewhere, which have zero emissions) to meet capacity demands. This is where economists make a mistake thinking that the “marginal” unit is additional generation from existing plants–in a capacity limited system such as the electricity grid, its investment in new capacity.

That average emissions are falling as shown in Holland et al while hourly “marginal” emissions are rising illustrates this error in construction. Mathematically that cannot be happening if the marginal emission metric is correct. The problem is that Holland et al have misinterpreted the value they have calculated. It is in fact not the first derivative of the average emission function, but rather the second partial derivative. That measures the change in marginal emissions, not marginal emissions themselves. (And this is why long-run marginal costs are the relevant costing and pricing metric for electricity, not hourly prices.) Given that 75% of new generation assets in the U.S. were renewables, it’s difficult to see how “marginal” emissions are rising when the majority of new generation is GHG-free.

The second issue is that the “marginal” generation cannot be identified in ceteris paribus (i.e., all else held constant) isolation from all other policy choices. California has a high RPS and 100% clean generation target in the context of beneficial electrification of buildings and transportation. Without the latter, the former wouldn’t be pushed to those levels. The same thing is happening at the federal level. This means that the marginal emissions from building decarbonization and EVs are even lower than for more conventional emission changes.

Further, those consumers who choose beneficial electrification are much more likely to install distributed energy resources that are 100% emission free. Several studies show that 40% of EV owners install rooftop solar as well, far in excess of the state average, (In Australia its 60% of EV owners.) and they most likely install sufficient capacity to meet the full charging load of their EVs. So the system marginal emissions apply only to 60% of EV owners.

There may be a transition from hourly (or operational) to capacity expansion (or building) marginal or incremental emissions, but the transition should be fairly short so long as the system is operating near its reserve margin. (What to do about overbuilt systems is a different conversation.)

There’s deeper problem with the Holland et al papers. The chart that Fowlie pulls from the article showing that marginal emissions are rising above average emissions while average emissions are falling is not mathematically possible. (See for example, https://www.thoughtco.com/relationship-between-average-and-marginal-cost-1147863) For average emissions to be falling, marginal emissions must be falling and below average emissions. The hourly emissions are not “marginal” but more likely are the first derivative of the marginal emissions (i.e., the marginal emissions are falling at a decreasing rate.) If this relationship holds true for emissions, that also means that the same relationship holds for hourly market prices based on power plant hourly costs.

All of that said, it is important to incentivize charging during high renewable hours, but so long as we are adding renewables in a manner that quantitatively matches the added EV load, regardless of timing, we will still see falling average GHG emissions.

It is mathematically impossible for average emissions to fall while marginal emissions are rising if the marginal emission values are ABOVE the average emissions, as is the case in the Holland et al study. What analysts have heuristically called “marginal” emissions, i.e., hourly incremental fuel changes, are in fact, not “marginal”, but rather the first derivative of the marginal emissions. And as you point out the marginal change includes the addition of renewables as well as the change in conventional generation output. Marginal must include the entire mix of incremental resources. How marginal is measured, whether via change in output or over time doesn’t matter. The bottom line is that the term “marginal” must be used in a rigorous economic context, not in a casual manner as has become common.

Often the marginal costs do not fit the theoretical mathematical construct based on the first derivative in a calculus equation that economists point to. In many cases it is a very large discreet increment, and each consumer must be assigned a share of that large increment in a marginal cost analysis. The single most important fact is that for average costs to be rising, marginal costs must be above average costs. Right now in California, average costs for electricity are rising (rapidly) so marginal costs must be above those average costs. The only possible way of getting to those marginal costs is by going beyond just the hourly CAISO price to the incremental capital additions that consumption choices induce. It’s a crazy idea to claim that the first 99 consumers have a tiny marginal cost and then the 100th is assigned the responsibility for an entire new addition such as another flight scheduled or a new distribution upgrade.

We can consider the analogy to unit commitment, and even further to the continuous operation of nuclear power plants. The airline scheduled that flight in part based on the purchase of the plane ticket, not on the final decision just before the gate was closed. Not flying saved a miniscule amount of fuel, but the initial scheduling decision created the bulk of the fuel use for the flight. In a similar manner a power plant that is committed several days before an expected peak load burns fuels while idling in anticipation of that load. If that load doesn’t arrive, that plant avoids a small amount of fuel use, but focusing only on the hourly price or marginal fuel use ignores the fuel burned at a significant cost up to that point. Similarly, Diablo Canyon is run at a constant load year-round, yet there are significant periods–weeks and even months–where Diablo Canyon’s full operational costs are above the CAISO market clearing price average. The nuclear plant is run at full load constantly because it’s dispatch decision was made at the moment of interconnection, not each hour, or even each week or month, which would make economic sense. Renewables have a similar characteristic where they are “scheduled and dispatched” effectively at the time of interconnection. That’s when the marginal cost is incurred, not as “zero-cost” resources each hour.

Focusing solely on the small increment of fuel used as a true measure of “marginal” reflects a larger problem that is distorting economic analysis. No one looks at the marginal cost of petroleum production as the energy cost of pumping one more barrel from an existing well. It’s viewed as the cost of sinking another well in a high cost region, e.g., Kern County or the North Sea. The same needs to be true of air travel and of electricity generation. Adding one more unit isn’t just another inframarginal energy cost–it’s an implied aggregation of many incremental decisions that lead to addition of another unit of capacity. Too often economics is caught up in belief that its like classical physics and the rules of calculus prevail.

A Residential Energy Retrofit Greenhouse Gas Emission Offset Reverse Auction Program

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In most local California jurisdictions, the largest share of stationary emissions will continue to come from the existing buildings. On the other hand, achieving zero net energy (ZNE) or zero net carbon (ZNC) for new developments can be cost prohibitive, particularly if incremental transportation emissions are included. A Residential Retrofit Offset Reverse Auction Program (Retrofit Program) aims to balance emission reductions from both new and existing buildings s to lower overall costs, encourage new construction that is more energy efficient, and incentivize a broader energy efficiency marketplace for retrofitting existing buildings.

The program would collect carbon offset mitigation fees from project developers who are unable to achieve a ZNE or ZNC standard with available technologies and measures. The County would then identify eligible low-income residential buildings to be targeted for energy efficiency and electrification retrofits. Contractors then would be invited to bid on how many buildings they could do for a set amount of money.

The approach proposed here is modeled on the Audubon Society’s and The Nature Conservacy’s BirdReturns Program.[1] That program contracts with rice growers in the Sacramento Valley to provide wetlands in the Pacific Flyway. It asks growers to offer a specified amount of acreage with given characteristics for a set price–that’s the “reverse” part of the auction.

A key impediment to further adoption of energy efficiency measures and appliances is that contractors do not have a strong incentive to “upsell” these measures and products to consumers. In general, contractors pass through most of the hardware costs with little markup; their profits are made on the installation and service labor. In addition, contractors are often asked by homeowners and landlords to provide the “cheapest” alternative measured in initial purchase costs without regard to energy savings or long-term expenditures.

The Retrofit Program is intended to change the decision point for contractors to encourage homeowners and landlords to implement upgrades that would create homes and buildings that are more energy efficient. Contractors would bid to install a certain number of measures and appliances that exceed State and local efficiency standards in exchange for payments from the Retrofit Program. The amount of GHG reductions associated with each type of measure and appliance would be predetermined based on a range of building types (e.g., single-family residential by floor-size category, number of floors, and year built). The contractors can use the funds to either provide incentives to consumers or retain those funds for their own internal use, including increased profits. Contractors may choose to provide more information to consumers on the benefits of improved energy efficiency as a means of increasing sales. Contractors would then be compensated from the Offset Program fund upon showing proof that the measures and appliances were installed. The jurisdiction’s building department would confirm the installation of these measures in the normal course of its permit review work.

Funds for the Retrofit Program would be collected as part of an ordinance for new building standards to achieve the no-net increase in GHG emissions. It also could be included as a mitigation measure for projects falling under the purview of the California Environmental Quality Act (CEQA.)

The Retrofit Program would be financed by mitigation payments made by building developers to achieve a no-net increase in GHG emissions. Buildings would be required to meet the lowest achievable GHG emission levels, but then would pay to mitigate any remainders, including for transportation, charged at the current State Cap and Trade Program auction price for an extended collection of annual allowances[2] that cover emissions for the expected life of the building (e.g., 40 years) (CARB 2024).

M.Cubed proposed this financing mechanism for Sonoma County in its climate action plan.

[1] See https://birdreturns.org/

[2] Referred to as a “strip” in the finance industry.

A Working Lands Carbon Mitigation Bank Program

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A number of counties in California are largely agricultural, with a few small communities. Most of that agricultural land is intensively farmed, much of it irrigated. This situation presents the opportunity to sequester large amounts of carbon relative to the total greenhouse gas emissions from all county activities. In other words, the county can approach a level of net-zero emissions with a surplus available to share with other jurisdictions, particularly with those in within a county.

Since many of these counties are already planning to use this sequestration strategy to meet its own emission reduction goals, these reductions will be real, additional, and verifiable, meeting the gold standard for use as credits by other jurisdictions. The county has a strong incentive to ensure that these reductions are of sufficient quality to meet its own targets, which should make these attractive to other jurisdictions, unlike other credits offered in the marketplace.

A county would establish a Carbon Mitigation Bank using a similar framework to habitat conservation mitigation banks.[1] The county would establish the parameters that achieve the requisite carbon sequestration and then collect in-lieu fees to cover the costs of the bank’s expenses. By expanding the number of jurisdictions contributing and receiving coverage, overall carbon emissions can be reduced more cost-effectively.

Sequestration from working lands can be achieved at a lower cost than most alternatives. For this reason, a county can use its surplus to finance much of its share of the sequestration program by offering it to cities in the county at a margin above the implementation cost sufficient to cover the county’s share of the costs as well. For example, it may cost $50 per CO2e ton sequestered, and the County may use only half of the potential sequestration to meet its own target. The County could then offer its surplus credits to the other jurisdictions at $100 per ton, which is likely less than the cost of additional reductions elsewhere, to cover the full program costs.

M.Cubed proposed this financing mechanism for both Yolo and Sonoma in their climate action plans. Both counties could potentially sequesters hundreds of thousands of tons annually, implying this could be a major revenue source for meeting broader targets.

“Fixed costs” do not mean “fixed charges”

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The California Public Utilities Commission has issued a proposed decision that calls for a monthly fixed charge of $24 for most customers. There is no basis in economic principles that calls for collecting “fixed costs” (too often misidentified) in a fixed charge. This so-called principle gets confused with the second-best solution for regulated monopoly pricing where the monopoly has declining marginal costs that are below average costs which has a two part tariff of a lump sum payment and variable prices at marginal costs. (And Ramsey pricing, which California uses a derivative of that in equal percent marginal cost (EPMC) allocation, also is a second-best efficient pricing method that relies solely on volumetric units.) The evidence for a natural monopoly is that average costs are falling over time as sales expand.

However, as shown by the chart above for PG&E’s distribution and transmission (and SCE’s looks similar), average costs as represented in retail rates are rising. This means that marginal costs must be above average costs. (If this isn’t true then a fully detailed explanation is required—none has been presented so far.) The conditions for regulated monopoly pricing with a lump sum or fixed charge component do not exist in California.

Using the logic that fixed costs should be collected through fixed charges, then the marketplace would be rife with all sorts of entry, access and connection fees at grocery stores, nail salons and other retail outlets as well as restaurants, car dealers, etc. to cover the costs of ownership and leases, operational overhead and other invariant costs. Simply put that’s not the case. All of those producers and providers price on a per unit basis because that’s how a competitive market works. In those markets, customers have the ability to choose and move among sellers, so the seller is forced to recover costs on a single unit price. You might respond, well, cell providers have monthly fixed charges. But that’s not true—those are monthly connection fees that represent the marginal cost of interconnecting to a network. And customers have the option of switching (and many do) to a provider with a lower monthly fee. The unit of consumption is interconnection, which is a longer period than the single momentary instance that economists love because they can use calculus to derive it.

Utility regulation is supposed to mimic the outcome of competitive markets, including pricing patterns. That means that fixed cost recovery through a fixed charge must be limited to a customer-dedicated facility which cannot be used by another customer. That would be the service connection, which has a monthly investment recovery cost of about $10 to $15/month. Everything else must be priced on a volumetric basis as would be in a competitive market. (And the rise of DERs is now introducing true competition into this marketplace.)

The problem is that we’re missing the other key aspect of competitive markets—that investors risk losing their investments due to poor management decisions. Virtually all of the excess stranded costs for California IOUs are due poor management, not “state mandates.” You can look at the differences between in-state IOU and muni rates to see the evidence. (And that an IOU has been convicted of killing nearly 100 people due to malfeasance further supports that conclusion.)

There are alternative solutions to California’s current dilemma but utility shareholders must accept their portion of the financial burden. Right now they are shielded completely as evidenced by record profits and rising share prices.

Opinion: What’s wrong with basing electricity fees on household incomes

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I coauthored this article in the Los Angeles Daily News with Ahmad Faruqui and Andy Van Horn. We critique the proposed income-graduated fixed charge (IGFC) being considered at the California Public Utilities Commission.

Retail electricity rate reform will not solve California’s problems

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Meredith Fowlie wrote this blog on the proposal to drastically increase California utilities’ residential fixed charges at the Energy Institute at Haas blog. I posted this comment (with some additions and edits) in response.

First, infrastructure costs are responsive to changes in both demand and added generation. It’s just that those costs won’t change for a customer tomorrow–it will take a decade. Given how fast transmission retail rates have risen and have none of the added fixed costs listed here, the marginal cost must be substantially above the current average retail rates of 4 to 8 cents/kWh.

Further, if a customer is being charged a fixed cost for capacity that is being shared with other customers, e.g., distribution and transmission wires, they should be able to sell that capacity to other customers on a periodic basis. While many economists love auctions, the mechanism with the lowest ancillary transaction costs is a dealer market akin a grocery store which buys stocks of goods and then resells. (The New York Stock Exchange is a type of dealer market.) The most likely unit of sale would be in cents per kWh which is the same as today. In this case, the utility would be the dealer, just as today. So we are already in the same situation.

Airlines are another equally capital intensive industry. Yet no one pays a significant fixed charge (there are some membership clubs) and then just a small incremental charge for fuel and cocktails. Fares are based on a representative long run marginal cost of acquiring and maintaining the fleet. Airlines maintain a network just as utilities. Economies of scale matter in building an airline. The only difference is that utilities are able to monopolistically capture their customers and then appeal to state-sponsored regulators to impose prices.

Why are California’s utility rates 30 to 50% or more above the current direct costs of serving customers? The IOUs, and PG&E in particular, over procured renewables in the 2010-2012 period at exorbitant prices (averaging $120/MWH) in part in an attempt to block entry of CCAs. That squandered the opportunity to gain the economics benefits from learning by doing that led to the rapid decline in solar and wind prices over the next decade. In addition, PG&E refused to sell a part of its renewable PPAs to the new CCAs as they started up in the 2014-2017 period. On top of that, PG&E ratepayers paid an additional 50% on an already expensive Diablo Canyon due to the terms of the 1996 Settlement Agreement. (I made the calculations during that case for a client.) And on the T&D side, I pointed out beginning in 2010 that the utilities were overforecasting load growth and their recorded data showed stagnant loads. The peak load from 2006 was the record until 2022 and energy loads have remained largely constant, even declining over the period. The utilities finally started listening the last couple of years but all of that unneeded capital is baked into rates. All of these factors point not to the state or even the CPUC (except as an inept monitor) as being at fault, but rather to the utilities’ mismanagement.

Using Southern California Edison’s (SCE) own numbers, we can illustrate the point. SCE’s total bundled marginal costs in its rate filing are 10.50 cents per kWh for the system and 13.64 cents per kWh for residential customers. In comparison, SCE’s average system rate is 17.62 cents per kWh or 68% higher than the bundled marginal cost, and the average residential rate of 22.44 cents per kWh is 65% higher. From SCE’s workpapers, these cost increases come primarily from four sources.

  1. First, about 10% goes towards various public purpose programs that fund a variety of state-initiated policies such as energy efficiency and research. Much of this should be largely funded out of the state’s General Fund as income distribution through the CARE rate instead. And remember that low income customers are already receiving a 35% discount on rates.
  2. Next, another 10% comes roughly from costs created two decades ago in the wake of the restructuring debacle. The state has now decreed that this revenue stream will instead be used to pay for the damages that utilities have caused with wildfires. Importantly, note that wildfire costs of any kind have not actually reached rates yet. In addition, there are several solutions much less costly than the undergrounding proposed by PG&E and SDG&E, including remote rural microgrids.
  3. Approximately 15% is from higher distribution costs, some of which have been created by over-forecasting load growth over the last 15 years; loads have remained stagnant since 2006.
  4. And finally, around 33% is excessive generation costs caused by paying too much for purchased power agreements signed a decade ago.

An issue raised as rooftop solar spreads farther is the claim that rooftop solar customers are not paying their fair share and instead are imposing costs on other customers, who on average have lower incomes than those with rooftop solar. Yet the math behind the true rate burden for other customers is quite straightforward—if 10% of the customers are paying essentially zero (which they are actually not), the costs for the remaining 90% of the customers cannot go up more than 11% [100%/(100%-10%) = 11% ]. If low-income customers pay only 70% of this—the 11%– then their bills might go up about 8%–hardly a “substantial burden.” (70% x 11% = 7.7%)

As for aligning incentives for electrification, we proposed a more direct alternative on behalf of the Local Government Sustainable Energy Coalition where those who replace a gas appliance or furnace with an electric receive an allowance (much like the all-electric baseline) priced at marginal cost while the remainder is priced at the higher fully-loaded rate. That would reduce the incentive to exit the grid when electrifying while still rewarding those who made past energy efficiency and load reduction investments.

The solution to high rates cannot come from simple rate design; as Old Surfer Dude points out, wealthy customers are just going to exit the grid and self provide. Rate design is just rearranging the deck chairs. The CPUC tried the same thing in the late 1990s with telcom on the assumption that customers would stay put. Instead customers migrated to cell phones and dropped their land lines. The real solution is going to require some good old fashion capitalism with shareholders and associated stakeholders absorbing the costs of their mistakes and greed.

In the LA Times – looking for alternative solutions to storm outages

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I was interviewed by a Los Angeles Times reporter about the recent power outages in Northern California as result of the wave of storms. Our power went out for 48 hours New Year’s Eve and again for 12 hours the next weekend:

After three days without power during this latest storm series, Davis resident Richard McCann said he’s seriously considering implementing his own microgrid so he doesn’t have to rely on PG&E.

“I’ve been thinking about it,” he said. McCann, whose work focuses on power sector analysis, said his home lost power for about 48 hours beginning New Year’s Eve, then lost it again after Saturday for about 12 hours.

While the storms were severe across the state, McCann said Davis did not see unprecedented winds or flooding, adding to his concerns about the grid’s reliability.

He said he would like to see California’s utilities “distributing the system, so people can be more independent.”

“I think that’s probably a better solution rather than trying to build up stronger and stronger walls around a centralized grid,” McCann said.

Several others were quoted in the article offering microgrids as a solution to the ongoing challenge.

Widespread outages occurred in Woodland and Stockton despite winds not being exceptionally strong beyond recent experience. Given the widespread outages two years ago and the three “blue sky” multi hour outages we had in 2022 (and none during the September heat storm when 5,000 Davis customers lost power), I’m doubtful that PG&E is ready for what’s coming with climate change.

PG&E instead is proposing to invest up to $40 billion in the next eight years to protect service reliability for 4% of their customers via undergrounding wires in the foothills which will raise our rates up to 70% by 2030! There’s an alternative cost effective solution that would be 80% to 95% less sitting before the Public Utilities Commission but unlikely to be approved. There’s another opportunity to head off PG&E and send some of that money towards fixing our local grid coming up this summer under a new state law.

While winds have been strong, they have not been at the 99%+ range of experience that should lead to multiple catastrophic outcomes in short order. And having two major events within a week, plus the outage in December 2020 shows that these are not statistically unusual. We experienced similar fierce winds without such extended outages. Prior to 2020, Davis only experienced two extended outages in the previous two decades in 1998 and 2007. Clearly the lack of maintenance on an aging system has caught up with PG&E. PG&E should reimagine its rural undergrounding program to mitigate wildfire risk to use microgrids instead. That will free up most of the billons it plans to spend on less than 4% of its customer base to instead harden its urban grid.

Per Capita: Climate needs more than just good will

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I wrote this guest column in the Davis Enterprise about the City’s Climate Action and Adaptation Plan. (Thank you John Mott-Smith for extending the privilege.)

Dear Readers, the guest column below was written by Richard McCann, a Davis resident and expert on energy and climate action plans.

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The city of Davis is considering its first update of its Climate Action and Adaptation Plan since 2010 with a 2020-2040 Plan. The city plans to update the CAAP every couple of years to reflect changing conditions, technologies, financing options, laws and regulations.

The plan does not and cannot achieve a total reduction in greenhouse gas emissions simply because we do not control all of the emission sources — almost three-quarters of our emissions are from vehicles that are largely regulated by state and federal laws. But it does lay out a means to putting a serious dent in the overall amount. 

The CAAP offers a promising future and accepts that we have to protect ourselves as the climate worsens. Among the many benefits we can look forward to are avoiding volatile gas prices while driving cleaner, quieter cars; faster and more controllable cooking while eliminating toxic indoor air; and air conditioning and heating without having to make two investments while paying less.

To better adapt, we’ll have a greener landscape, filtered air for rental homes, and community shelter hubs powered by microgrids to ride out more frequent extreme weather.

We have already seen that adding solar panels raises the value of a house by as much as $4,000 per installed kilowatt (so a 5 kilowatt system adds $20,000). We can expect similar increases in home values with these new technologies due to the future savings, safety and convenience. 

Several state and federal laws and rules foretell what is coming. By 2045 California aims to be at zero net GHG emissions. That will require retiring all of the residential and commercial gas distribution lines. PG&E has already started a program to phase out its lines. A change in state rules will remove from the market several large natural gas appliances such as furnaces by 2030.

In addition, PG&E will no longer offer subsidies to developers to install gas lines to new homes starting next year. The U.S. Environmental Protection Agency appears poised to push further the use of electric appliances in areas with poor air quality such the Sacramento Valley. (Renewable gas and hydrogen will be too expensive and there won’t be enough to go around.)

Without sales to new customers or for replaced furnaces, the cost of maintaining the gas system will rise substantially so switching to electricity for cooking and water heating will save even more money. The CAAP anticipates this transition by having residents begin switching earlier. 

In addition, the recently enacted federal Inflation Reduction Act offers between $400 and $800 billion into funding these types of changes. The California Energy Commission’s budget for this year went from $1 billion to $10 billion to finance these transitions. The CAAP lays out a process for acquiring these financial sources for Davis and its residents. 

That said, some have objected to the CAAP as being too draconian and infringing on personal choices. The fact is that we are now in the midst of a climate emergency — the City Council endorsed this concern with a declaration in 2019. We’re already behind schedule to head off the worst of the threatening impacts. 

We won’t be able to rely solely on voluntary actions to achieve the reductions we need. That the CAAP has to include these actions proves that people have not been acting on their own despite a decade of cajoling since the last CAAP. While we’ve been successful at encouraging voluntary compliance with easy tasks like recycling, we’ve used mandatory permitting requirements to gain compliance with various building standards including energy efficiency measures. (These are usually enforced at point-of-sale of a house.)

We have a choice of mandatory ordinances, incentives through taxes or fees, and subsidies from grants and funds — voluntary just won’t deliver what’s needed. We might be able to financially help those least able to afford changing stoves, heaters or cars, but those funds will be limited. The ability to raise taxes or fees is restricted due to various provisions in the state’s constitution. So we are left with mandatory measures, applied at the most opportune moments. 

Switching to electricity for cooking and water heating may involve some costs, some or most of which will be offset by lower energy costs (especially as gas rates go up.) If you have an air conditioner, you’re likely already set up for a heat pump to replace your furnace — it’s a simple swap. Even so, you can avoid some costs by using a 120-volt induction cooktop instead of 240 volts, and installing a circuit-sharing plug or breaker for large loads to avoid panel upgrades. 

The CAAP will be fleshed out and evolve for at least the next decade. Change is coming and will be inevitable given the dire situation. But this change gives us opportunities to clean our environment and make our city more livable.