Tag Archives: electricity rates

Discerning what drives rate increases is more complex than shown in LBNL study

2 Replies

The renewables policy team at Lawrence Berkeley National Laboratory (LBNL) released a study maintaining that it identifies the primary drivers of rate increases in the U.S. LBNL also issued a set of slides summarizing the study but there discrepancies between the two. (This post focuses on the study.)

First, this group of authors have been important leaders in tracking technology costs and resource alternatives at a micro level. You can find many of their studies cited in my various posts on renewables and distributed energy resources (DER). This time the authors may have stretched a bit too far.

Unfortunately this study is much more about correlation than causality. The authors hint at a more complex story that would require much more sophisticated regression analysis (e.g., two or three stage and fixed effects regressions) to untangle. Yet the report uses the term “driver” numerous places when “correlation” or “association” would be more appropriate.

Observations about Table 2 that displays the regression results and the discussion about findings in Section 4:

  • 4.2 Price trends varied by state: Prices rose in states that are internalizing environmental and other costs while states with falling rates were continuing to impose environmental hazards and other costs on their citizens as a subsidy to utility shareholders.
  • 4.4 Finding that rising growth decreases rates (load delta): This finding confuses a shift in customer composition with overall causality. The study found it was rising commercial loads, not overall loads, that decreased rates. That means the share of lower cost commercial customers increased, so, of course, the average rate decreased. The residential rates were unchanged statistically.
  • 4.5 Behind the meter (BTM) solar: the most egregious error. The authors acknowledge this issue is problematic with many different viewpoints, but then plow ahead anyway. Customers find the most effective way to respond to rising rates is to install their own generation. This is classic economic cause and effect, yet the authors run a model assuming the reverse.

The problem is that they accept as given the utility narrative that rooftop customers are shirking cost responsibility while ignore the cost saving from serving load themselves. The authors also buy into the false narrative that utilities have substantial “fixed” costs—every other industry that has large fixed costs recover those through variable charges.  That the BTM variable is strongly negative for the 2017-22 period and then positive for 2019-24 is an analytic red flag. (The negative value for the RPS effect from 2016-2021 just as California’s most expensive renewables came on line compared to the other periods is another red flag in the regression analysis overall.)

Our analysis shows instead how California NEM customers have saved money for other customers. The authors do not include that critique of the studies done in California in their citations. We also deeply critiqued the E3 study of Washington’s NEM program, finding numerous analytic and conceptual errors. (Ahmad Faruqui would disavow his Sergici et al 2019 study included as a supporting citation in the LBNL study.)

There are two fundamental conceptual errors in these underlying analyses that the LBNL authors rely on: 1) that utilities have the right to serve 100% of customer loads and customers must pay for the privilege to self serve with their own generation, and 2) that utilities are entitled to full recovery of all of their costs even when sales decrease. Neither of these premises hold in any other industry (even natural gas and water utilities).

Notably they found no statistical effect from energy efficiency programs yet the impacts on utility sales and revenues are identical to BTM solar. No one is calling for customers who install LED lighting, insulation or more efficient appliances to increase their contribution utility revenue requirements to be “fair.” The one difference is that DERs present the opportunity to truly “cut the cord” with the utility if rates become excessive. This is further evidence that this finding that rooftop solar unduly raises the rates for other customers is false and misleading.

  • 4.9 Wildfire spending as a source of cost increases: the authors attribute a 6 cents/kWh increase in California wildfire spending. That’s incorrect (the PAO took PG&E’s assertion without checking it) as we have tracked the total utility spending—it’s only about 10% or less than 4 cents/kWh of IOU rates. But a portion of that increase already happened prior to 2019, and the wildfire bond adder wasn’t an increase but rather a repurposing of an existing bond cost recovery charge. The rate increase attributable to wildfire spending is less than 3 cents on a statewide basis (rolling in the municipals, e.g., LADWP & SMUD).

The real reason for California rate increases are: 1) unusual exposure to natural gas prices because the IOUs have not hedged power purchases 2) increase in resource adequacy prices because of multiple changes in how this handled (the underlying reason being to squeeze CCAs), 3) unregulated spending in distribution infrastructure the IOUs starting in 2010 and 3) a 150% increase in transmission investment to deliver grid scale renewable generation since 2012. 

A key policy tool intended to promote energy efficiency is instead being used against saving energy

2 Replies

A cornerstone policy meant to promote energy efficiency is now being used as a weapon against energy savings. Decoupling the recovery of utilities’ costs and profits from electricity sales was intended to remove utilities’ opposition to promoting California’s resource loading order of using energy efficiency and distributed energy resources first.[1] Instead, protecting those revenue requirements and the associated utility profits, thus avoiding financial risk to shareholders, has become the paramount objective of the state’s decoupling policy at the expense of both reducing dependence on utility generation and increasing consumer sovereignty.[2] We are told that we need to increase our energy consumption to reduce the energy rates for those who have not reduced their utility purchases. The intent of decoupling has been turned on its head.

The premise of the ”cost shift” argument that asserts saving energy by one customer causes higher rates for other customers relies on an interpretation of decoupling whereby utility shareholders are shielded from suffering any financial losses caused by consumers turning elsewhere to find their energy services. This is one logical extension of decoupling, albeit not the one intended by those who originated this concept. Under this flawed rubric, each customer has an obligation to pay a share of the utility’s fixed and stranded costs. When a customer reduces their usage and their electricity bill, they are shirking this obligation according to the cost-shift argument.

Using the underlying rationale that utilities are guaranteed to recover their costs once approved by the CPUC and FERC, whether a customer-installed resource has a cost more or less than the social marginal cost is irrelevant unless that marginal cost is higher than the retail rate. Under this reasoning the customer owes the full amount of the retail rate and only receives a credit for saving energy that cannot exceed the marginal cost. The customer still owes the difference between the retail rate and the marginal cost and other customers must pick up that foregone sales revenue from the savings. Once a utility is authorized to collect a set amount of revenues, a customer has no escape from the corporate burden.

That presumption eliminates the ability to use market discipline through consumer choice to control rates (except moving out of state or to a municipal utility area). Under this reasoning, the only means of containing utility rates and mitigating bills is via regulatory action by the CPUC and FERC.

The problem is that regulators were supposed to strictly cap utility spending so that consumers could make their own choices about how to best meet their energy needs.[3] The utilities discovered that the regulators were not so vigilant and that the utilities could easily justify added utility-owned resources that were rolled into revenue requirements. The recovery of those costs was then protected from risk of either competition from customer resources or prudency review by policies implementing decoupling.

As a result, California’s utility rates have skyrocketed over the last two decades, with grid costs rising four times faster than inflation. These have reached crisis levels and state policy makers are desperately searching for easy solutions. Hence, the “cost shift” myth identifies the “true villains”—those customers who thought they were doing the right thing. Now they need to be punished.

When faced with declining sales and revenues, every other business cannot simply demand that customers make up the difference between the business’ current costs and its falling revenues. The business instead must either cut costs or provide a better service or product that attracts back those or other customers. The innovation motivated by this “creative destruction” as Joseph Schumpeter described it is at the core of the benefits we accrue from a market economy. Hinder that process and we get stagnation. The phased deregulation of the electricity market started with the 1978 PURPA is an important example of innovation was unleashed by removing the utilities’ ability to veto customers’ investments in their own resources. Without PURPA and the subsequent reforms, we would never had the technological revolution that both gives cost effective renewable energy resources and customers more control over their own energy use.

“Fixed” costs are not an explanation for rising rates

We also know that the supposed “fixed” costs of the utility system are not large. Generation and transmission resources are constantly redeployed among customers which is normal market functionality; these are not fixed costs, rather they are reallocated to customers who use more of those facilities. This is why grocery stores don’t charge customers to simply enter a store where 80% of the costs are don’t change with individual sales. Even in the distribution circuits, customers share most of the network with other customers; these costs are not fixed per-customer. Cell companies rarely require more than 12-month contracts with similar cost structures. (Three-year contracts are for paying off new phones and can be avoided by purchasing unlocked phones.)

The facts are that the various policy program costs are about the same as they have been for two decades at 10% of rates (and within that portion, energy efficiency should be classified as a resource cost just like generation), and the lion’s share of wildfire-related costs, which are only another 10%, were added four years ago and have risen only slightly since. Meanwhile PG&E increased its rates 50% over the last four years and the other two have or will increase their rates substantially.

The CPUC issued an order that the utilities impose a fixed charge of $24 per month for standard residential customers to cover those purported fixed costs. That’s approximately equal to the share of utility costs that might be considered fixed or related to state policy directives.

Rapidly rising rates is evidence that marginal costs are higher than retail rates and customer investment in new resources saves all ratepayers money

A key premise of the cost-shift argument is that these customers’ loads now being met by energy efficiency and DERs can be served by the existing utility system at little additional cost. In other words, these customers departed a system already built to accommodate their usage. That’s incorrect as one customer’s reduced load is an opportunity for another customer’s increased load to be served without an additional generation, transmission and distribution investment at today’s inflated costs.  My more efficient refrigerator makes room for my neighbor’s hot tub, electric vehicle, or perhaps a needed medical appliance.

This premise overlooks that these customer resources have met at least a quarter on the energy demand since 2000. The true customer peak is three hours earlier and at least 12,000 megawatts higher than the metered CAISO peak. Based on historic utility costs over that period, annual utility revenue requirements would have increased $14 billion. California already struggled to bring on enough renewable energy over that period—the costs and environmental consequences of using utility generation would likely be even higher.

Claims that customers who save energy cause higher bills for other customers is premised on the unfounded notion that customers are departing from an already existing system built to accommodate their growing future demand. The cost shift analysis starts with today’s situation and then assumes that a customer who installs energy efficiency or rooftop solar is leaving a system already built to serve their current load.

Customers have also added additional loads, including more than one million electric vehicles.  But for the reduction in loads from customer-installed resources, these additional loads would have required billions of dollars of investment in power supply and distribution capacity.  Now, in many cases utilities built the additional capacity anyway – and it is a shortcoming of regulation that these costs were allowed into customer rates when the needed capacity was supplied by customer resources.

The fact is that a utility system is an aging and dynamic network that is constantly retiring and acquiring equipment to serve an ever-changing group of customers. For California, loads were forecasted to grow another 20% from 2005 to now. Instead, those loads have been flat as consumers have acquired their own resources, including LED lights, insulation, smart thermostats, double paned windows, insulation or solar panels. The metered peak shifted three hours later in the day, but the true customer peak still occurs mid-afternoon but it is met by customer-owned resources instead. A fifth of the true customer peak is now served by rooftop solar and a quarter of the state’s energy load comes from energy efficiency plus DERs. Much of that solar output is captured costlessly in hydro storage and used to meet that later peak.  Any analysis must look at what it would have cost over those two decades to build the resources to serve those loads that instead are now served by individually-invested savings and generation.

We know that generation costs were significantly higher than that today’s costs (thanks to innovation) and that resources located at the point of use saves 30% or more in avoided peak losses and reserve power capacity. We know that those customer resources displaced adding new transmission that costs three times more than the average that is charged in retail rates. We know that the utilities consistently overforecasted the need for distribution infrastructure without consequence, and that the transmission and distribution rate components increased about 300% over the last two decades which is four times faster than inflation. Meanwhile, we also know that utility rates increased at the same pace as utility costs reflected in revenue requirements. This is important because if a other ratepayers were picking up the bills for customers who conserve and self generate, the rates would be increasing faster than revenue requirements as demand decreased. This is the essential element of the “death spiral” concept. There is no evidence of a death spiral yet.

The belief that these “departed” loads could have been served at little additional cost is unfounded based on the empirical evidence. If we conservatively use the average retail generation rate or 8.8 cents per kilowatt-hour in 2023 as representative of the true marginal cost,[4] add 12.5 cents per kilowatt-hour for the marginal cost of transmission, and then add an average of 4.4 cents per kilowatt-hour for avoided distribution costs from the utilities general rate case applications, the base avoided cost is 25.7 cents per kilowatt-hour. We then adjust the generation and transmission costs for 7% line losses and a 15% reserve margin, we are at 30.6 cents per kilowatt-hour for the actual marginal cost at the customer meter. In comparison, the average retail rate was only 27.8 cents per kilowatt in 2023 so customers investing in energy efficiency and rooftop solar are reducing incremental costs by 10%. And of course, this does not include environmental benefits, local economic activity or improved local energy resiliency. The total cost to serve the 89,000 gigawatt-hours saved would be $17 billion or a 30% increase in revenue requirements.

As is often the case, diagnosing the problem doesn’t mean that we have an immediate solution. That said, the objective should be to put utility shareholders at risk for excessive investments made based on optimistic growth forecasts. Having “used and useful” standards for asset utilization rates and unit-of-production depreciation are ways of extending cost recovery that lowers rates. However, those types of solutions are likely to move utilities back to opposing EE programs. The best solution is to create a competitive EE utility like the NW Energy Efficiency Alliance.

Today, we see that California is still struggling to bring on enough clean energy resources to meet its ambitious climate change mitigation goals. Diablo Canyon’s retirement was delayed and the state is not even approaching the threshold for installing renewables to meet the SB 100 clean energy target of 100% by 2045. The only viable alternatives are greater reliance on aggressive energy efficiency paired with electrification and customer-owned renewable generation. Misinterpreting the intention of decoupling should not be used as a barrier to reaching our goals.

[1] California first instituted decoupling in 1978 and then paused it in 1996 for restructuring. The system was restarted in 2002.

[2] It literally takes killing customers to put a utility at financial risk. See “ SDG&E Customers Should Not Pay for 2007 Wildfires: SCOTUS,” NBC 7 News, https://www.nbcsandiego.com/news/local/us-supreme-court-sdge-wildfires-costs-lines-utility-fire-damage/1966157/, October 8, 2019; “PG&E receives maximum sentence for 2010 San Bruno explosion,” ABC 7 News, https://abc7news.com/post/pg-e-receives-maximum-sentence-for-2010-san-bruno-explosion/1722674/, January 28. 2017; “Ex-PG&E execs to pay $117M to settle lawsuit over wildfires,” AP News, https://apnews.com/article/wildfires-business-fires-lawsuits-california-450c961a4c6b467fcfb5465e7b9c5ae7, September 29, 2022; “PG&E Pleads Guilty On 2018 California Camp Fire: ‘Our Equipment Started That Fire’,” NPR CapRadio, https://www.npr.org/2020/06/16/879008760/pg-e-pleads-guilty-on-2018-california-camp-fire-our-equipment-started-that-fire, June 16, 2020. SCE may be facing a similar risk after the Easton Fire in January 2025. “Southern California Edison likely to incur ‘material losses’ related to Eaton fire, executive says,” LA Times, https://www.latimes.com/business/story/2025-04-30/edison-earnings-eaton-fire-losses, April 30, 2025.

[3] Decoupling delinked profits from actual sales and instead linked them to forecasted sales used to justify infrastructure investment. This removed the risk of overforecasting sales and perhaps falling short on recovering costs. And we see evidence of that practice in both PG&E’s and SCE’s forecasts used to justify investments from 2009 to 2018. The regulatory failure is that the CPUC didn’t go back and audit whether the investments were justified given that the sales didn’t materialize. Decoupling only works with a regulatory scheme that gives strong incentives for cost control.

[4] The 2024 rates were much higher for the utilities but it’s more difficult to calculate the average.

CAISO Transmission Costly for New Generation

2 Replies

The California utilities have added substantial new generation over the last two decades while peak demand and energy loads have remained fairly constant. Based on Energy Information Administration data for 2012 to 2023 in the California Independent System Operator (CAISO) area, 75.7% of the generation added other than plant repowering is for renewables meeting the state’s Renewable Portfolio Standard.[1] Most of these new plants are located remotely from the majority of customer loads so transmission lines must be built to deliver that energy.

Over the same period from 2012 to 2023, the total annual transmission revenue requirements for the three investor-owned utilities (IOU) in the CAISO (i.e., PG&E, SCE and SDG&E), rose from $2.217 billion to $5.487 billion or 147%.[2] That is 7.8% per year.  The chart below compares the increase in transmission revenue and the addition of generation over that period.

Transmission spending is driven largely by additions of generation. This fact is particularly evident when transmission costs rise so rapidly despite no significant load growth. For this reason, the marginal or incremental cost should be expressed in dollars per kilowatt or kilowatt-hour. And because 76% of the new generation is for renewable energy, not for peak reliability, kilowatt-hours of energy is the best metric.

Using these two data sources, we updated the incremental or marginal cost for transmission using the change in annual revenue requirements as a proxy for the direct cost. The chart at the top shows how transmission revenue requirement increases relate to generation additions. Based on this analysis, the marginal cost of transmission is $125 per megawatt-hour or $0.1246 per kilowatt-hour.[3] Given that retail transmission rates for the three IOUs have on average increased 250% to $0.04016 per kilowatt-hour, this result is consistent with the economic principle that marginal costs are above average costs when average costs are rising.

[1] EIA 923, https://www.eia.gov/electricity/data/eia923/, and EIA 861, https://www.eia.gov/electricity/data/eia861/

[2] CPUC, AB 67 Reports to the Legislature.

[3] The R-squared is 0.881, and the standard error is $0.0138 per kilowatt-hour.

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

9 Replies

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

27 Replies

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.

“Fixed costs” do not mean “fixed charges”

1 Reply

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

7 Replies

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.

What rooftop solar owners understand isn’t mythological

1 Reply

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

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

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

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

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

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

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

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

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

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

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

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

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

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

1 Reply

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

https://cacurrent.com/guest-juice-reforming-how-californias-utilities-charge-for-electricity-and-recover-costs-to-make-environmental-gains/

Proposing a Clean Financing Decarbonization Incentive Rate

11 Replies

by Steven J. Moss and Richard J. McCann, M.Cubed

A potentially key barrier to decarbonizing California’s economy is escalating electricity costs.[1] To address this challenge, the Local Government Sustainable Energy Coalition, in collaboration with Santa Barbara Clean Energy, proposes to create a decarbonization incentive rate, which would enable customers who switch heating, ventilation and air conditioning (HVAC) or other appliances from natural gas, fossil methane, or propane to electricity to pay a discounted rate on the incremental electricity consumed.[2] The rate could also be offered to customers purchasing electric vehicles (EVs).

California has adopted electricity rate discounts previously to incentivize beneficial choices, such as retaining and expanding businesses in-state,[3] and converting agricultural pump engines from diesel to electricity to improve Central Valley air quality.[4]

  • Economic development rates (EDR) offer a reduction to enterprises that are considering leaving, moving to or expanding in the state.  The rate floor is calculated as the marginal cost of service for distribution and generation plus non-bypassable charges (NBC). For Southern California Edison, the current standard EDR discount is 12%; 30% in designated enhanced zones.[5]
  • AG-ICE tariff, offered from 2006 to 2014, provided a discounted line extension cost and limited the associated rate escalation to 1.5% a year for 10 years to match forecasted diesel fuel prices.[6] The program led to the conversion of 2,000 pump engines in 2006-2007 with commensurate improvements in regional air quality and greenhouse gas (GHG) emission reductions.[7]

The decarbonization incentive rate (DIR) would use the same principles as the EDR tariff. Most importantly, load created by converting from fossil fuels is new load that has only been recently—if at all–included in electricity resource and grid planning. None of this load should incur legacy costs for past generation investments or procurement nor for past distribution costs. Most significantly, this principle means that these new loads would be exempt from the power cost indifference adjustment (PCIA) stranded asset charge to recover legacy generation costs.

The California Public Utility Commission (CPUC) also ruled in 2007 that NBCs such as for public purpose programs, CARE discount funding, Department of Water Resources Bonds, and nuclear decommissioning, must be recovered in full in discounted tariffs such as the EDR rate. This proposal follows that direction and include these charges, except the PCIA as discussed above.

Costs for incremental service are best represented by the marginal costs developed by the utilities and other parties either in their General Rate Case (GRC) Phase II cases or in the CPUC’s Avoided Cost Calculator. Since the EDR is developed using analysis from the GRC, the proposed DIR is illustrated here using SCE’s 2021 GRC Phase II information as a preliminary estimate of what such a rate might look like. A more detailed analysis likely will arrive at a somewhat different set of rates, but the relationships should be similar.

For SCE, the current average delivery rate that includes distribution, transmission and NBCs is 9.03 cents per kilowatt-hour (kWh). The average for residential customers is 12.58 cents. The system-wide marginal cost for distribution is 4.57 cents per kilowatt-hour;[8] 6.82 cents per kWh for residential customers. Including transmission and NBCs, the system average rate component would be 7.02 cents per kWh, or 22% less. The residential component would be 8.41 cents or 33% less.[9]

The generation component similarly would be discounted. SCE’s average bundled generation rate is 8.59 cents per kWh and 9.87 cents for residential customers. The rates derived using marginal costs is 5.93 cents for the system average and 6.81 cent for residential, or 31% less. For CCA customers, the PCIA would be waived on the incremental portion of the load. Each CCA would calculate its marginal generation cost as it sees fit.

For bundled customers, the average rate would go from 17.62 cents per kWh to 12.95 cents, or 26.5% less. Residential rates would decrease from 22.44 cents to 15.22 cents, or 32.2% less.

Incremental loads eligible for the discounted decarb rate would be calculated based on projected energy use for the appropriate application.  For appliances and HVAC systems, Southern California Gas offers line extension allowances for installing gas services based on appliance-specific estimated consumption (e.g., water heating, cooking, space conditioning).[10] Data employed for those calculations could be converted to equivalent electricity use, with an incremental use credit on a ratepayer’s bill. An alternative approach to determine incremental electricity use would be to rely on the California Energy Commission’s Title 24 building efficiency and Title 20 appliance standard assumptions, adjusted by climate zone.[11]

For EVs, the credit would be based on the average annual vehicle miles traveled in a designated region (e.g., county, city or zip code) as calculated by the California Air Resources Board for use in its EMFAC air quality model or from the Bureau of Automotive Repair (BAR) Smog Check odometer records, and the average fleet fuel consumption converted to electricity. For a car traveling 12,000 miles per year that would equate to 4,150 kWh or 345 kWh per month.

[1] CPUC, “Affordability Phase 3 En Banc,” https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/affordability, February 28-March 1, 2022.

[2] Remaining electricity use after accounting for incremental consumption would be charged at the current otherwise applicable tariff (OAT).

[3] California Public Utilities Commission, Decision 96-08-025. Subsequent decisions have renewed and modified the economic development rate (EDR) for the utilities individually and collectively.

[4] D.05-06-016, creating the AG-ICE tariff for Pacific Gas & Electric and Southern California Edison.

[5] SCE, Schedules EDR-E, EDR-A and EDR-R.

[6] PG&E, Schedule AG-ICE—Agricultural Internal Combustion Engine Conversion Incentive Rate.

[7] EDR and AG-ICE were approved by the Commission in separate utility applications. The mobile home park utility system conversion program was first initiated by a Western Mobile Home Association petition by and then converted into a rulemaking, with significant revenue requirement implications. 

[8] Excluding transmission and NBCs.

[9] Tiered rates pose a significant barrier to electrification and would cause the effective discount to be greater than estimated herein.  The estimates above were based on measuring against the average electricity rate but added demand would be charged at the much higher Tier 2 rate. The decarb allowance could be introduced at a new Tier 0 below the current Tier 1.

[10] SCG, Rule No. 20 Gas Main Extensions, https://tariff.socalgas.com/regulatory/tariffs/tm2/pdf/20.pdf, retrieved March 2022.

[11] See https://www.energy.ca.gov/programs-and-topics/programs/building-energy-efficiency-standards;
https://www.energy.ca.gov/rules-and-regulations/building-energy-efficiency/manufacturer-certification-building-equipment;https://www.energy.ca.gov/rules-and-regulations/appliance-efficiency-regulations-title-20