Reinventing Fixed Charges
Income-based monthly fees could address affordability while reducing distorted electricity rates.
California leaders tout their pathbreaking initiatives to address both the climate crisis and economic inequality. But the way we charge for one of the most basic household needs – electricity – is undermining both of those efforts. The electricity rate structures of the state’s investor-owned utilities (IOUs) are discouraging building electrification and other important investments for reducing carbon emissions, while at the same time imposing a disproportionate burden on low-income customers.
Everyone knows that California IOUs, who serve over 70% of residential customers, have some of the highest electricity rates in the country. And they collect those revenues from households almost entirely through volumetric (i.e., priced per kilowatt-hour) charges. Those volumetric rates, however, cover much more than the cost of providing each additional kWh.
Why are California Electricity Rates So High?
State policymakers have poured the cost of myriad public policy goals into electricity rates – subsidies for rooftop solar and EV charging stations, support for nascent high-cost renewable energy technologies, reduced rates for low-income customers, energy efficiency programs, wildfire mitigation and compensation, and improving air and water purity in schools, among others. Plus, many electricity system fixed costs, including most of the cost of transmission and distribution, are also covered in those volumetric rates, but don’t really change with your electricity usage.
The result – as shown by research here and here – is that volumetric rates are two or more times higher than the actual incremental cost of providing electricity. This means households have too little incentive to switch to electricity from natural gas, gasoline, or other higher-carbon fuels for household and transportation services. They also have too much incentive to install rooftop solar and outfit their basements with big batteries, when the same carbon reductions could be achieved at lower cost with large-scale renewables and storage.
How to Cover the Revenue Gap
In ongoing research, Meredith Fowlie, Jim Sallee, and I (with the excellent assistance of our graduate student, Marshall Blundell) are examining what causes the gap between price and the incremental cost of providing a kWh, and looking closely at who ends up paying for the gap. In essence, the rate structure imposes a volumetric tax on electricity – a surcharge on each kWh – in order to cover state energy policies and other costs that don’t vary with the amount of electricity households use.
We wanted to compare the distributional implications of collecting revenue through this volumetric tax on electricity versus other sources of revenue, such as state income tax, sales tax or gasoline tax. Using government consumption data for households in California, we compared how much customers in the lowest income bracket spend on electricity and other goods compared to consumers in higher income brackets. The figure above suggests that the highest-income quintile of households only spend about twice as much on electricity as the poorest quintile. But they spend about three times as much on gasoline, about four times as much on all goods other than electricity, and over four times as much on goods covered by the state sales tax.
In other words, we are paying for these fixed costs through a tax that is substantially more regressive than a sales tax or a tax on gasoline, both of which are generally viewed as pretty regressive ways to raise revenues. The figure below shows just why those are viewed as regressive taxes. It’s the same as the figure above, but rescaled to fit in average income, which is 17 times higher for the highest quintile than for the lowest. Paying for these costs through even a flat tax on income would be far, far more progressive than through raising electricity prices.
Back at the beginning of 2020 (about a decade ago), when we were starting this project, I suspected that one implication might be that it would be a good idea to move many of the public policy programs off of electricity rates and on to the state budget, financed in the general fund, i.e., mostly through income taxes. Back then, California had a budget surplus. Raising that idea now just triggers laughter.
Reinventing Fixed Charges
When we have discussed this research with utility executives and with consumer advocates, there is remarkable agreement on the problem. But the agreement ends when the utilities propose their solution: monthly fixed charges. Utility managers get all gushy over fixed charges, which bring greater revenue certainty and lower volumetric prices that encourage more usage of their product. But consumer advocates start to turn a purplish-red color (or maybe that’s just Zoom) at the suggestion of increasing fixed charges, because that means charging every household the same amount (which would be a flat line at the bottom if it were on these graphs). Standard fixed charges are even more regressive than a volumetric tax on electricity.
Fixed charge advocates have countered that the charge could be reduced or waived for low-income households, such as the one-third of households on the CARE rate. But that still treats the other two-thirds of customers – from lower-middle income to extremely wealthy – the same. And, the CARE program is not exactly closely monitored. Income level is verified for only 1% of the households who sign up for the program, and there is little penalty for falsely claiming eligibility.
While brainstorming alternative funding sources, we realized that fixed charges could be efficient and equitable if they were truly income-based and income-verified. Who has the information to do that? The taxman.
Broadly, here’s how it would work: Households would pay a substantial monthly fixed charge, and then on their state tax return they would document the payments by submitting a utility ID that would be matched with billing information from their utility. That would automatically trigger a refund of all or part of their fixed charge payments depending on their income. The state would then collect the rebated revenue from the utility.
To implement this, some institutional barriers would need to be overcome: California’s Franchise Tax Board would need additional personnel to manage this process; utilities would have to be able to exchange information and money with the FTB; not all utility customers file state income taxes (though it would be worthwhile for a rebate of many hundreds of dollars); and some low-income customers would face cash flow issues. The cash flow problem could be addressed by allowing customers to stipulate their income in advance and pay the associated lower fixed charge, subject to verification when they file taxes.
Is this approach really feasible? Yes! The federal Earned Income Tax Credit has worked in a very similar way for decades, with households getting a refundable tax credit based on the income they demonstrate on their tax return. California introduced its own EITC in 2015, which operates the same way. And the Affordable Care Act’s subsidies for low-income households follow this approach, including allowing households to stipulate their income and qualify for the subsidy upfront, which is then verified and potentially adjusted when they file their tax return.
Electricity rate design in California today is seriously broken, both in the distorted incentives it creates and in the regressive impact. That will only worsen as more high-income households install solar and, now, batteries. At some point soon, we need to create a system that is not just environmentally sustainable, but also financially sustainable and equitable. Income-based fixed charges could help attain all three goals.
 Undocumented residents can, and many do, file tax returns. The information is not supposed to be shared with immigration authorities, which it seems California could credibly commit to.
Keep up with Energy Institute blogs, research, and events on Twitter @energyathaas.
Suggested citation: Borenstein, Severin. “Reinventing Fixed Charges” Energy Institute Blog, UC Berkeley, November 16, 2020, https://energyathaas.wordpress.com/2020/11/16/reinventing-fixed-charges/
Severin Borenstein View All
Severin Borenstein is Professor of the Graduate School in the Economic Analysis and Policy Group at the Haas School of Business and Faculty Director of the Energy Institute at Haas. He received his A.B. from U.C. Berkeley and Ph.D. in Economics from M.I.T. His research focuses on the economics of renewable energy, economic policies for reducing greenhouse gases, and alternative models of retail electricity pricing. Borenstein is also a research associate of the National Bureau of Economic Research in Cambridge, MA. He served on the Board of Governors of the California Power Exchange from 1997 to 2003. During 1999-2000, he was a member of the California Attorney General's Gasoline Price Task Force. In 2012-13, he served on the Emissions Market Assessment Committee, which advised the California Air Resources Board on the operation of California’s Cap and Trade market for greenhouse gases. In 2014, he was appointed to the California Energy Commission’s Petroleum Market Advisory Committee, which he chaired from 2015 until the Committee was dissolved in 2017. From 2015-2020, he served on the Advisory Council of the Bay Area Air Quality Management District. Since 2019, he has been a member of the Governing Board of the California Independent System Operator.
This solution begs the bigger question: If we need to subsidize the fixed costs of privately owned utility costs, why do we have privately owned utility companies? The obvious answer here is first to move to public ownership of the utility network, and then delve into what are the best solutions addressing both costs above marginal costs and public purpose program costs (which are two very different problems.)
I’ll also note that in California, SCE and PG&E come to very different estimates of the “marginal” costs on the distribution side of their operations. They are closer on the generation side, but the problems there are not about economies of scale (the excess costs are from poor portfolio management and AB 57) or public purpose program costs (there are none) so that’s a different discussion than the one presented in this blog post.
“This solution begs the bigger question: If we need to subsidize the fixed costs of privately owned utility costs, why do we have privately owned utility companies?”
Who is talking about subsidizing a utility’s costs? The subsidies that are being discussed here are for low-income customers – not the utilities that serve them.
You have created a straw man as an excuse for attacking the IOUs (again).
I have yet to see evidence that volumetric, flat, per-kWh rates have not always been the most economically-efficient and equitable way to avail everyone in society of reliable, affordable electricity.
To get there would first require eliminating self-dealing within energy monopolies, however – the principal reason why California electricity prices have skyrocketed since 2005. Then, “recoupling” profit with sales of electricity, and eventually doing away with complex “rate design” schemas entirely. Utility monopolies would be compensated based on cost of production, operations, maintenance, necessary capital costs, with a regulated rate of return as profit.
It’s not nearly as complicated as some want it to be. Maybe complication itself is the problem?
Tying to follow the flow of cash: If the state pays a rebate through the tax system to customers and then collects the amount of the rebate from the utility, how has the utility been able to recover revenues sufficient to cover its costs? Would the fixed charge have to be set higher to accommodate the payment to the state?
“Would the fixed charge have to be set higher to accommodate the payment to the state?”
“The problem is not so much rate design as it is the excessive revenue requirements of the California IOUs.”
Jim, I disagree.
Undoubtedly, there are excessive costs included in the IOU revenue requirements, though far less than what you have described, (e.g., disallowing high executive compensation would hardly move the needle) even of those excess costs were surgically removed the current rate designs in California would still be a major problem.
TOU rates are certainly better than the absurd inclining block rates they replace but they are still static rates, thus are only marginally more efficient than flat rates. A recent study by LBNL demonstrated this.
1) Are you saying that both public purpose programs and fixed system costs (like transmission and distribution) should be paid for via taxes instead of utility bills? It seems odd for electric system costs, even if fixed, to not be included in rates.
2) If you are not suggesting that fixed costs be paid in taxes, it looks like you still included those costs in your calculation of how regressive the “volumetric tax on electricity” is, didn’t you? This would make your resulting numbers misleading re how regressive the “volumetric tax” is, wouldn’t it?
3) You do not address the underlying policy question of which public purpose programs are appropriately paid for via rates and which should be paid for via taxes (or not paid for by the public at all). This seems fundamental.
4) As a previous comment noted, your solution is “clunky.” One example – you acknowledge that low income customers might have cash flow problems paying a “substantial” monthly fixed charge. Yes, they would. But your fix is to allow them to “stipulate their income in advance,” which would presumably require those customers (who may be working three jobs to make ends meet) to take another step. This does not appear to be a workable fix.
Lowering the price of a scarce good is hardly going to be the right way to constrain its demand. Lowing the marginal price of energy will surely lead to increased consumption; so this proposal must be about far more social outcomes than economic ones.
Currently the high cost of electricity has encouraged people with capital avaiable to invest in conservation and renewables, lowering the marginal cost will reduce that without adding some exotic mechansims. Similarly, it would be a break in faith with those who have already invested in these technologies based on reasonable estimates of future energy costs. E.g. cut way back on the electricity price and those solar panels you bought just became a rip-off. That bridge will have been burnt. No one will invest–unless more exotic mechanism are added somehow.
A good argument is that an electric infrastructure benefits all and, like roads or schools, should be mostly paid for through taxes. A horrible argument is that the price of a currently unreliable energy source should be lowered to make people fuel switch.
“Currently the high cost of electricity has encouraged people with capital avaiable to invest in conservation and renewables,…”
True. But it is not clear that this is bad; it is possible to over-invest in both of these activities. Energy conservation is viewed as a sacred cow but, in fact, it has a tangible economic value and spending more for it reduces the collective societal welfare. The same is even more true for small-scale rooftop solar. another sacred cow. The one counterargument to be made in favor of promoting both of these sacred cows is the external benefits associated with lower emissions. But those benefits can also be quantified and included in the volumetric rate so there is little reason for providing conservation and solar with a blank check.
Regarding the issue of disenfranchising owners of rooftop solar, the CPUC has already grandfathered the rates they pay. But a more fundamental question is why should they be indemnified for making risky investments and force their neighbors to pick up the tab? While I suspect that most people investing in rooftop solar (or worse, signing contracts with third-party providers, e.g., SolarCity) did not understand the risk they were taking, is it a good policy to reward ignorance? And notice that the third-party providers were clever enough to shift all of the market risk to their customers through the long-term leasing contracts the customers signed.
“A good argument is that an electric infrastructure benefits all and, like roads or schools, should be mostly paid for through taxes.”
And an equally good argument can be made for charging tolls for using roads. Schools are a different situation because there are substantial collective societal benefits derived from an educated populace.
“A horrible argument is that the price of a currently unreliable energy source should be lowered to make people fuel switch.”
I don’t understand your reference to a “…unreliable energy source.” Do you mean renewable energy?
“Energy conservation is viewed as a sacred cow but, in fact, it has a tangible economic value and spending more for it reduces the collective societal welfare. ”
“Social welfare” is not measured solely through current monetary value and singular measures of “efficiencies”. Economists due themselves a disservice by trying to claim that they can measure overall societal well being with a single metric (And I’m a Ph.D. economist.) Social welfare must include other measures such as equitable distribution, unmeasured environmental damages, and risk reduction (and I’m sure others can add to this list). The papers cited in this blog only go part way towards measuring environmental impacts and none of the others.
“Regarding the issue of disenfranchising owners of rooftop solar, the CPUC has already grandfathered the rates they pay.”
Incorrect. The CPUC has only grandfathered non TOU tiered rate structures for pre-2017 residential NEM customers, but not the actual rates. Other solar customers are on new TOU rates that are based on expected TOU periods in 2024 (not the current ones) and those rates also are not at a fixed amount. Even more changes are coming to NEM rates.
(Robert, you have made so many incorrect statements about the situation in California that I suggest that you no longer attempt to make factual statements about what’s happening here. You may have better knowledge about other places in the U.S. and you can contribute with commentary about those places.)
“And an equally good argument can be made for charging tolls for using roads.”
You are ignoring the benefits from network externalities. When a customer drives to a business who’s cost per unit falls with more customers, who is benefitting from the trip–the customer or the business? How to allocate the benefits between a group that is interconnected by a network is a very difficult problem. And road tolls only make sense on congested single-strand roads. Tolls on surface streets that are not congested make no sense from a standard economic efficiency point.
Just a few clarifications.
CPUC does NOT grandfather rates for rooftop solar. My PG&E rates have changed 2-3 times since I put in my rooftop solar in. I wish I had my original rates. The points made by others that local solar and storage are not being treated with the same consideration as the big boys are well taken.
I referred to the grid as an unreliable. energy source. The electric grid goes down (for one reason or another) much more often than rooftop solar or natural gas goes down. I am rather happy that I can get heat, hot water and a cook, when the grid is down.
The argument about societal benefit is the same for all of them. There is societal benefit from an educated populous from having easy access for goods and services and for having a flexible electric grid. While the final solution may be different for each, they all have societal benefits and costs and it is a reasonable public policy debate.
“CPUC does NOT grandfather rates for rooftop solar. My PG&E rates have changed 2-3 times since I put in my rooftop solar in. I wish I had my original rates.”
Professor, three questions:
1. When you say your rates changed, do you mean the rate design changed or just the price level(s).
2. If only the level(s) changed, are you complaining because it (they) went up?
3. If your rate design changed, did you install your system after July 1, 2017 (when the grandfathering arrangement expired)?
“1. When you say your rates changed, do you mean the rate design changed or just the price level(s).
2. If only the level(s) changed, are you complaining because it (they) went up?
3. If your rate design changed, did you install your system after July 1, 2017 (when the grandfathering arrangement expired)”
I have had solar panels for about 13 years on my home and PG&E put me on a TOU tariff then. That peak period was much earlier in the afternoon, with a very large difference between on-peak and off peak rate which worked as planned. Twice now they have cancelled the tariff I was using and put me on one that was less favorable in that regard. The current one is much later in the day for peak time, with a smaller difference between peak and off-peak.
The normal incremental increase in all the rates over time would have been fine, but they changed the structure as a whole to be much more in their favor. The peak rates used to be when I generated a lot, which was the incentive to invest. Now not at all. It is interesting to note that they treated ENRON better than their customers.
Given the focus of the piece is on how to tackle the regressive nature of existing electricity rates, I’m not overly concerned about breaking the faith with “people with capital” who were already wealthy enough to invest in things like solar panels and batteries. They will be fine. Also, their brand new Tesla EV will have gotten a hell of a lot cheaper to run, so they might come out ahead anyway. Electrification of transportation and heating is surely far more important to tackling climate change than trying to squeeze even more conservation out of existing electricity uses.
“Similarly, it would be a break in faith with those who have already invested in these technologies based on reasonable estimates of future energy costs. E.g. cut way back on the electricity price and those solar panels you bought just became a rip-off. That bridge will have been burnt. No one will invest–unless more exotic mechanism are added somehow.
I have been saying for years that we need to treat customers’ investments the same way that we treat generators’ investments. Customers make investments with expectations about future prices and they are far from being sufficiently savvy about regulatory issues to understand how prices will change. Even local governments do not fully understand. (I know this from direct experience.) The shift in TOU periods has come as a shock to many who invested based on the old regime. Why can’t we give customers who make this type of investment a long term price commitment for the life of the investment? Customers shouldn’t be left at 100% price risk while generators are 100% protected in long term PPAs. That’s a recipe for underinvestment in conservation and distributed energy resources and overinvestment in large generators.
“I have been saying for years that we need to treat customers’ investments the same way that we treat generators’ investments.”
I fully agree with you that customers and unregulated generators should be treated in an equal fashion regarding cost recovery on risky investments.
Back in 2014 the CPUC grandfathered customers who invested in rooftop solar prior to July 1, 2017 (the order was forward-looking) by allowing these customers to stay on the rate design (i.e., the increasing block rates) that was in effect when they installed their panels – for 20 years – essentially the projected economic life of the solar panels.
I haven’t followed this issue in recent years so I don’t know what actions the CPUC has since taken on this issue but clearly a huge cohort of solar customers were protected from rate design changes. Those who invested after the 2017 cutoff date should have known that their rate design could change because the CPUC clearly telegraphed this possibility in its order.
Your proposal to offer rooftop solar customers PPAs is an interesting idea. It would require the customer to sell its solar output to a counterparty, most likely the distribution utility. This is the Buy-All, Sell-All model that Austin Energy was first to implement in 2012. I expanded on that concept in an article published last year in Public Utilities Fortnightly, “Buying Solar Energy by the Minute, Aligning Benefits with Costs,” But, of course, the customers choosing this option would have to give up the Net Metering subsidies that they currently receive.
Secondly, it is not quite accurate to say that a generator with a PPA is insulated rom risk because the generator gives up the opportunity to benefit if spot energy prices increase by more than what was forecasted at the time the PPA was signed. Generators with the ability to balance sheet finance a plant have the option to simply ride the spot market.
“That’s a recipe for underinvestment in conservation and distributed energy resources and overinvestment in large generators.”
You have over-reached with this statement.
All three types of investment are (or at least should be) made based on forecasts of future energy prices. The way they are financed does affect the decision to invest or not to invest, primarily because of the tax savings that flow from the use of debt financing. But note that all investors can use debt to finance their projects, including those Harry Homeowners who can take out Home Equity loans and deduct the interest payments.
“Why can’t we give customers who make this type of investment a long term price commitment for the life of the investment?”
Um, because no one else benefits from their investment? Because no one else wants to assume their risk? So many reasons.
“That’s a recipe for underinvestment in conservation… ”
Electricity from the sun and wind, we’re told, is free and creates no emissions. If so, why would we need to conserve energy, much less invest in it?
“and [underinvestment in] distributed energy resources…”
You would prefer to set up distributed generation like public schools in the 1950s, i.e. “separate but equal”? Seems that didn’t work out so well.
Investments in energy efficiency and self generation provide exactly the same benefits to other customers as generation itself. If we think of generation as removing a portion of load to be served (which is exactly how the CAISO and IOUs calculate the “net peak” by subtracting renewable generation), then self generation and energy efficiency ALSO removes a portion of the load to be served. Reducing metered load is conceptually the same as adding generation, with the added advantage of avoided line loss.
“Electricity from the sun and wind, we’re told, is free and creates no emissions.”
No one has made such a ludicrous claim. Cheaper is not equivalent to free. Since this still has a cost, reducing demand can be cost effective.
“You would prefer to set up distributed generation like public schools in the 1950s, i.e. “separate but equal”? ”
First, all new technologies evolve from being more expensive and riskier, which means that the wealthier are the first consumers. Cars, refrigerators, cell phones all followed this path. Then as production increases, costs fall and the technology becomes more widely available. Solar panels have shown a remarkable cost decline that have made them affordable for most homeowners. The equity barrier now is not income or cost but rather home ownership. 45% of residents in California are tenants and they can’t install solar without investment from landlords. The agency problem is the biggest problem to be addressed now.
I love the diagnosis of the problem, both from an environmental impact and economic justice perspective. The proposed solution feels clunky to me, a complicated alternative to the simpler solution of funding these public purpose initiatives via income (or property ad valorem?) taxes. Which gets me to wondering, do the utilities not have access to other metrics that would serve as a more progressive basis for a graduated grid connection fee than kWh? What about peak demand? What about building square footage, assessed value, property taxes, etc? Those are publicly available data points.
“do the utilities not have access to other metrics that would serve as a more progressive basis for a graduated grid connection fee than kWh? What about peak demand? What about building square footage, assessed value, property taxes, etc? Those are publicly available data points.”
Very incisive observation.
In the past I have advocated for sizing the fixe monthly customer charge based on the maximum demand that the customer can place on the system, i.e., the physical size of the fuse connected to his meter. This would differentiate between residential customers and the larger C&I customers and also between residential customers living in small homes (or condos/apartments) and those living in McMansions. But at the low end it would not significantly differentiate between low-income and middle-income customers because the fuses in the line drops come in standard sizes. I think that Severin’s solution is a more elegant way of resolving this issue.
You mentioned differentiating on the basis of peak demand. Assuming you don’t mean imposing a demand charge, this actually is a way to get around the problem of standardized line drop capacities. The customer’s monthly fixed charge could be sized based on maximum non- coincident demand in a previous baseline period, such as the previous month or year, and adjusted on a rolling basis. However, this may create an incentive for the customer to game the system (which I haven’t fully thought through).
Imposing demand charges is a bad idea because they are are not dynamic, thus are not economically efficient. As a result, they impose disincentives to consume that are either too small or too large, thereby causing unnecessary societal losses. The best way to efficiently constrain demand is through dynamic, real time pricing.
Again, a correction with more information about California–customer charges are already differentiated by proxies for size. C&I charges can vary by 100 fold between small agricultural pumps and large industrial plants. The cost differences between residential hookups are relatively small, and much more dependent on the distance from the distribution line to the meter, so rural customers are much more expensive to serve than a large house in the middle of San Francisco. Connecting a 200 amp service is less than $500 more than 100 amp service according to SCE, which adds about $3 per month to the cost of service.
Assessed value and property taxes don’t work in California due to the effects of Proposition 13, which caps increases on the assessed value of property (and corresponding taxes). Properties get reassessed at market value upon sale, so the effect is that properties with similar market values will have widely varying assessed values.
Proposition 13 had created huge inequities. I have a friend who purchased his home in Pacific Heights (in San Francisco) back in the early 1970s. It is now worth around $5 million. His property tax is only $4000 per year! And this is a guy whose income is in the top 1 percent.
Proposition 13 is also denying California tax revenues that it sorely needs in light of the pandemic.
Dr. Borenstein correctly notes that California IOU electricity rates are too high. His solution, however, is not to bring them down, but to rearrange them to reduce the incremental price of electricity for those who want to use more power.
Perhaps we should start with an assessment of WHY they are higher. There are many reasons. Some of these, perhaps, do not belong in electricity rates at all.
First, California’s PUC has allowed an extremely generous return on equity and a very high equity capitalization ratio. While utilities across the border in Canada get by with an 8% ROE and a 35% equity capitalization rate, the PUC allows an ROE of 10.2% (SDG&E) to 10.3% (SCE).
Second, the very high enrollment in CARES creates a huge revenue deficiency (discounts to qualifying households). This is a social equity and economic justice program, which should probably be paid from the state general fund, not from higher electricity prices.
Third, the California utilities have invested in some high-cost resources, from Diablo Canyon (operating costs are about twice the total cost of new wind and solar power, plus it produces half of its power at low-demand hours) to early wind, solar, and geothermal contracts.
Fourth, for some reason the Commission allows recovery of extraordinary executive compensation in rates. Any compensation in excess of what state agency managers are paid should be the responsibility of shareholders, not bill payers. If the state can attract competent Governors for $209,747/year, why should we pay more for the head of a much smaller enterprise (the utility)?
Here are California current executive compensation rates for the top five executives:
Governor $209,747; Lieutenant Governor $157,310; Attorney General $182,189; Controller $167,796;
Treasurer $167,796; The total for the five positions: under $1 million/year.
Compare those to SCE’s top executive compensation for 2018 (probably higher now), from the Proxy Statement:
Pedro Pizarro, Corporate CEO: $9.777,523; Maria Rigatti, CFO: $2,968,777; Kevin Payne, Utility CEO: $3,088,188; Adam Umanoff, General Counsel: $2,002,190; J Andrew Murphy, Executive VP, $1,652,827; The total for the five positions: about $20 million for the year.
I’m not suggesting that the PUC limit what they are paid, only the portion of that which is allowed as an operating expense in the determination of fair, just, and reasonable rates, included in the revenue requirement, and recovered from consumers. Why should electric consumers pay more for the utility executives than it does for the PUC appointees that it charges with regulating them?
A better metric of the real cost of providing electric service in California would be the rates of the consumer-owned utilities, like LADWP, SMUD, Palo Alto, and Anaheim. Their executives make good money — but on the order of 50% more than the governor, not 5,000 percent more like Pizarro. Those rates are as much as 40% lower than those charged by the IOUs. Those utilities ALSO have early, expensive wind and solar contracts. They ALSO have (or had) ownership in nuclear projects. They ALSO have discounts for qualified low-income consumers.
The national average of electricity rates is 10.54 cents/kWh. The California average is 16.89 cents. See https://www.eia.gov/electricity/state/
A TOU rate for a utility with the national average rate overall would be about five cents/kWh off-peak, ten cents mid-peak, and twenty cents on-peak. That five cent rate would be extremely attractive for electrification of hot water with a heat pump water heater. It would be the equivalent of less than $1 /gallon for gasoline used in EVs.
The problem is not so much rate design as it is the excessive revenue requirements of the California IOUs.
“Diablo Canyon (operating costs are about twice the total cost of new wind and solar power…”
Nonsense, you’re comparing apples to oranges. Diablo Canyon generates dispatchable power on demand; wind and solar do not. A reasonable comparison would add in the costs of natural gas backup power including spinning reserves.
In fact, that’s exactly what the U.S. Energy Information Administration has done, and found nuclear energy is 17% cheaper to produce than gas turbines backing up small scale renewables.
Average Power Plant Operating Expenses for Major U.S. Investor-Owned Electric Utilities
I don’t see renewables in the EIA reference, and it shows only the operating costs, not the full capital investment costs. It’s an incomplete picture.
Since when is Diablo Canyon “dispatchable”? It has NEVER been run in that mode, despite the fact that PG&E could save substantial amounts by shutting it down from Feb to May each year.
“I don’t see renewables in the EIA reference…”
Read the footnotes (little words at the bottom): “Gas Turbine and Small Scale category consists of gas turbine, internal combustion, photovoltaic, and wind plants.”
“…it shows only the operating costs, not the full capital investment costs. It’s an incomplete picture.”
Non-operational costs aren’t shown for wind and solar either, and capital costs are the tip of the iceberg. With limited lifetime, outages, backup power, capacity factor, decremental payments, negative pricing, etc. included they’re even more expensive.
“Since when is Diablo Canyon “dispatchable”? It has NEVER been run in that mode…”
Dispatchable is not a “mode”, nor is baseload. Dispatchable means a source can be dispatched – turned on and off. Because the wind and sun can’t be turned on and off, and are unpredictably available, they’re considered “intermittent”, or “unreliable”.
“..despite the fact that PG&E could save substantial amounts by shutting it down from Feb to May each year…”
PG&E’s rate base includes their cost to generate electricity. They don’t lose a dime.
Diablo Canyon is not dispatchable, it is baseload (according to PG&E, its operator).
“Baseload” is a term used to describe demand, not supply.
Power from Diablo Canyon is both dispatchable and useful for meeting baseload demand. That has value.
Solar and wind are neither.
You are the only person who has made both of those statements. While I don’t agree with the author, I will note the title of his post: https://energycentral.com/c/ec/how-important-baseload-generation-capacity-us-power-grids-reliability
Diablo Canyon has NEVER been run in any type of “dispatchable” operation. PG&E claims that it is not operational in that mode.
No question that the public utilities in the state have lower energy prices for their customers than the big three. The CEC has documented some specifics over the years- I referenced one of their reports in the link below.
I’d love to be able to have SMUD provided our service but they said no way they wanted to pick up PG&E assets to service us up in the foothills. I will be paying about 100% more than a SMUD customer for my winter kWh’s-
This is a GREAT idea!
One of the greatest barriers to the adoption of economically efficient rate designs is opposition from the Consumer Advocates. This approach should placate them and allow the industry to finally progress by implementing truly dynamic rates.