Reconciling Census “On the Map” commuter patterns with other employment data: A case study in Davis

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Several years ago, a friend asserted that only 25,000 Davis residents were employed out of 56,000 adults, and concluded that the city had an overwhelming number of retirees. He had pulled the data from the U.S. Census “On the Map” tool that is frequently used by planners and transportation consultants. Unfortunately, the number is wrong when compared to every other available data source. While On the Map provides correct values for neighboring cities such as Woodland and West Sacramento, the large discrepancy for Davis shows that analysts using this tool should double check their results before presenting them.

The correct number of Davis residents who are working is 31,600 to 34,000 as reported in two other Census reports, Quick Facts and the American Communities Survey (ACS), and the state’s Employment Development Department (EDD). That is a gap of 6,500 to 9,000 or 20% to 26%. The mystery is why is there such a large discrepancy?

The likely answer is that the On the Map tool is failing to account for those who work from home. The ACS shows 31,650 residents working in Davis but only 26,080 commuting to work. In another table, the ACS reports that 7,200 people work from home out of 32,800 reported as employed, which about equal to the gap between On the Map and the other data sources. A compounding factor is that On the Map shows that the contiguous University of California, Davis has 15,000 employees commuting to campus when the university reports that only 11,000 work there.[1] Davis’ unique relationship with UCD, which is not within its city limits, probably creates confusion in the underlying methodology.

Figure 1 compares four different accountings of Davis employed residents and workers. An additional source beyond the three mentioned previously is the UCD Institute of Transportation Studies’ Campus Travel Survey which has data back to 2007.  Based on the UCD survey, 5,000 Davis and UCD residents work on campus, while 6,400 commute in from elsewhere (more on that later).

Figure 1

When the 5,000 UCD employees including students are added to the 4,000 who live and commute within Davis plus the 7,200 working at home, we find that 16,500 live and work within the Davis/UCD sphere. And when the 3,600 Davis residents working at UCD are subtracted from the 21,000 commuting out of the city limits, the number of actual out of town commuters is 17,600. Given the total number of jobs in the sphere is 34,150, the number of workers commuting into Davis/UCD is 17,700. Figure 2 compares these three categories which have quite similar values.

Figure 2

An important trend in the UCD Travel Survey is how much change has occurred in the number of employees live in Davis and work on campus. In 2007, almost 50% of employees lived and worked in Davis; in the latest 2023 survey, or 37% or 4,150 reside in Davis. That is a loss of 1,400 resident workers. If the percentage loss is applied to the entire Davis workforce, a reasonable assumption as a common response to higher housing prices, then Davis has lost 4,500 in-town workers since 2007.

Another valuable insight from the Travel survey is that about one-third of in-town workers commute to work via car, while 92% of out of town commuters come by car. If this pattern applies more broadly to Davis residents, then commuting traffic should decrease significantly for affordable housing built to return workers back to living in Davis.

[1] On the Map shows only 1,319 living on campus so it is clearly excluding the 20,000 plus students who reside in campus housing.

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

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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. 

Modern climate change is now 27 times faster than historic global warming mass extinction events

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Steve Hampton has updated his original analysis from 2019 when he worked at the California Department of Fish and Wildlife as an economist. The warming rate has now increased to 27 times any previous event. This chart is sobering for anyone who believes that the current warming is part of a natural cycle. This points to a potentially catastrophic result. Steve wrote recently “it’s now about 18x, not 10x, faster than the other fastest warming.”

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

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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.

PG&E already has $300 million to contribute to removing Potter Valley

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PG&E announced that it projects the cost of decommissioning the Scott and Van Horn Dams in the Potter Valley Project will cost $532 million. However, by 2029 PG&E will have already collected from ratepayers $321 million towards that cost in depreciation expenses.

PG&E makes capital investments in generation, transmission and distribution equipment, and then recovers those investments on an annual basis akin to a mortgage payment. The annual cost recovery rate is computed as a sum of the cost of capital, defined as shareholder return and debt interest rate, plus the depreciation expense which is calculated based on the expected life of the equipment.

Depreciation has two parts. The first goes towards recovery of the initial cost of construction. This is on top of the authorized rate of return that covers debt interest and shareholders return on equity. The second is the salvage value which is the expected value of the remaining components at the end of the life of the asset. Except in the case of dams, that salvage value is negative due to the cost of decommissioning.

PG&E is collecting these depreciation expenses including decommissioning costs for its entire fleet of hydropower projects. In effect, PG&E has created an insurance fund for its full portfolio of projects and the cost of any single decommissioning comes from this portfolio insurance fund. While PG&E placed a 25% probability that Potter Valley would be decommissioned, it calculated a portfolio-wide probability of decommissioning at 22%. Many of these projects will not be decommissioned for at least another half century as they were recently relicensed and probably even longer given the value of these assets for power production. Those unexpended decommissioning funds collected for projects likely to operate for the foreseeable future (e.g., the Feather River Project) are intended to be spent on actual projects such as Potter Valley rather than just to continue to accrue income for shareholders and creditors.

As part of its triennial General Rate Case (GRC) application, PG&E estimated the costs to decommission hydropower facilities as part of depreciation studies used to compute capital cost recovery rates. In Chapter 8 of its GRC filing in Application 18-12-009, filed December 2018,[1] PG&E reported the estimated 2022 decommissioning cost for Potter Valley at $196.3 million. PG&E estimated the total decommissioning costs for the projects included in their list of hydropower projects was $830.0 million.

Based on PG&E’s collection of $196 million by 2022 towards Potter Valley’s decommissioning and the authorized rate of return on investment of 7.27%, PG&E will have $321 million already banked in 2029 to commit to the decommissioning. This leaves $211 million or 40% of PG&E’s projected cost to be paid in addition from other sources, including ratepayers.

As an aside, PG&E’s cost estimate is in line with initial estimates our project team made for the Two Basin Solution coalition in 2020. We also found that each of the options cost approximately the same, similar to the results another team I worked on projected in 2006 for decommissioning the Klamath Project.

[1] PG&E, “Hydro Decommissioning WPS Exhibit 5 Chapter 8.pdf”, A.18-12-009, December 2018.

The Jolt: California’s solar blame-game (a podcast interview)

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In Wednesday’s episode of The Jolt, Sam looks into why California’s rooftop solar rollout is at risk of stalling.

  • Richard McCann, an expert on California’s energy system and founding partner of the M.Cubed consultancy, joins The Jolt to explain where the state’s officials are making mistakes and what needs to be done to fix them.
  • To reach its 2045 carbon neutrality goal, California needs to build a lot of renewable energy. Rooftop solar has reached about 16 gigawatts of capacity in the state and is a major part of the power mix.
  • But new policy changes, designed to bring down power prices, could derail the rooftop sector’s impressive progress and stunt future growth.

California wants to kill rooftop solar — all because officials were duped by this flawed theory

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I wrote this article (with editorial assistance) in the San Francisco Chronicle on how California regulators and policy makers are looking to the wrong “villain” as the root of California’s high electricity rates. The problem is derived directly from utility spending which has increased one-to-one with rate increases.

We have published a deeper analysis of this issue in a white paper, and I have written other posts that discuss deeper issues and responses to rebuttals elsewhere on this blog.

CAISO Transmission Costly for New Generation

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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.

How California got such high rates: the history of missed utility forecasts

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A key driver in rising California electricity rates has been distribution costs as shown in the chart above. The distribution rate component has been increasing in lock step with utilities’ revenue requirements since at least 2002. Purported load departure has had no measurable impact on rates as the value of energy efficiency and distributed energy resources have closely mirrored the displaced utility spending over that period.

The most likely source of the increase in distribution costs is overforecasting load growth in the utilities’ General Rate Cases (GRC) after 2006. As described in this California Solar & Storage Association (CalSSA) whitepaper, customer investment in rooftop solar displaced load growth and CAISO peak demands have remained flat, but utility forecasts failed to account for this.

While testifying on behalf of the Agricultural Energy Consumers Association (AECA) in PG&E and SCE GRC Phase IIs from 2009 to 2018 we presented data comparing the accuracy of the utilities forecasts to those from the California Energy Commission’s Integrated Energy Policy Report (IEPR). The IEPR forecasts were consistently much more accurate (and still biased high.) (We moved on to different issues after 2018.)

The first chart shows how PG&E consistently misforecasted. SCE shows the same biased errors in the second chart. An important source of this error appears to be the utilities failing to reconcile the sum of local planning area and division forecasts with the overall system forecast. We asked for data showing this reconciliation but never received evidence of this critical task. Starting in 2018, however, the utilities started using local area forecasts created by the CEC which mitigates this source of error.

Nevertheless, the utilities requested, and the CPUC authorized, large investments that increased the distribution rate base which then rolls into the revenue requirements and rates. The assets installed in excess of demand simply accumulated in the investment ratebase and the additional excess from the next GRC was layered on top. The two charts below show for PG&E and SCE the cumulative amount of overforecast over three GRCs. These imply that each utility was authorized to build substantially more infrastructure than what was actually needed. For PG&E this amounted to 99% by 2019 and for SCE, 76% more by 2017.

These investments facilitated by the forecast errors kept accreting but the CPUC never went back to audit whether theses assets were actually used and useful. If not used and useful, the CPUC could act to disallow recovery of these costs until load growth is sufficient to create a need for these lines and transformers.

In PG&E’s 1996 GRC, AECA showed that the utility was planning to add substantial distribution infrastructure in the farmlands around Fresno for suburban growth that was unlikely to materialize. The CPUC agreed with us and refused to authorize that investment. It took substantial effort by this intervenor to prepare that analysis, but it demonstrated the effectiveness of such oversight that has not been duplicated by the CPUC elsewhere.

This lack of oversight and action is one reason why the policy of decoupling, which separates cost recovery from sales, has failed to control costs in California. Decoupling may have reduced utilities’ opposition to energy efficiency (although now they are coming after rooftop solar which has an identical effect as energy efficiency), but the utilities quickly discovered that the CPUC did not have either the capabilities or the appetite to penalize overinvestment. This is the root cause of California’s high rates.

White paper on how rooftop solar is really a benefit to all ratepayers

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In cooperation with the California Solar & Storage Association, M.Cubed is releasing a white paper Rooftop Solar Reduces Costs for All Ratepayers.

As California policy makers seek to address energy affordability in 2025, this report shows why rooftop solar can and has helped control rate escalation. This research stands in direct contrast to claims that rooftop solar is to blame for rising rates. The report shows that the real reason electricity rates have increased dramatically in recent years is out-of-control utility spending and utility profit making, enabled by a lack of proper oversight by regulators.

This work builds on the original short report issued in November 2024, and subsequent replies to critiques by the Public Advocates Office and Professor Severin Borenstein. The supporting workpapers can be found here.

Policy makers wanting to address California’s affordability crisis should reject the utility’s so-called “solar cost shift” and instead partner with consumers who have helped save all ratepayers $1.5 billion in 2024 alone by investing in rooftop solar. The state should prioritize these resources that simultaneously reduce carbon, increase resiliency, and minimize grid spending. This realignment of energy priorities away from what works for investor-owned utilities – spending more on the grid – and toward what works for consumers – spending less – is particularly important in the face of increased electricity consumption due to electrification. More rooftop solar is needed, not less, to control costs for all ratepayers and meet the state’s clean energy goals.

Utilities have peddled a false “cost shift” theory that is based on the concept of “departing load.” Utilities claim that the majority of their costs are fixed. When a customer generates their own power from onsite solar panels, the utilities claim this forces all other ratepayers to pick up a larger share of their “fixed” costs. A close look at hard data behind this theory, however, shows a different picture.

While California’s gross consumption – the “plug load” that is actual electricity consumption – has grown, that growth has been offset by customer-sited rooftop solar. This has kept the state’s peak consumption from the grid remarkably flat over the past twenty years, despite population growth, temperature increases, increased economic activity, and the rise in computers and other electronics in homes and businesses. Rooftop solar has not caused departing load in California. It has avoided load growth. By keeping our electric load on the grid flat, rooftop solar has avoided expensive grid expansion projects, in addition to reducing generation expenses, lowering costs for everyone.

Contrary to messaging from utilities and their regulators, California electricity consumption still peaks in mid-afternoon on hot summer days. There has been so much focus on the evening “net peak,” depicted by the “duck curve,” that many people have lost sight of the true peak. The annual peak in plug load happens when the sun is shining brightest. Clear, hot days lead to both high electricity usage from air conditioning and peak solar output.

The “net peak” is grid-based consumption minus generation from utility-scale solar and wind farms. It is an important dynamic to look at as we seek to reduce non-renewable sources of energy, and it shows us that energy storage will be essential going forward. However, an exclusive focus on net peak misses a bigger picture, particularly when looking at previously installed resources, and hides the value of solar energy.
California’s two million rooftop solar systems installed under net metering, including those that do not have batteries, continue to reduce statewide costs year after year by reducing the true peak. While most new solar systems now have batteries to address the evening net peak, historic solar continues to play a critical role in addressing the mid-day true peak.

Utilities and their regulators ignore these facts and focus the blame of rising rates on consumers seeking relief via rooftop solar. Politicians looking to address a growing crisis of energy affordability in California should reject the scapegoating of working- and middle-class families who have invested their own money in rooftop solar, and should instead promote the continued growth of this important distributed resource to meet growing needs for electricity.

The state is at a crossroads. As we power more of our cars, appliances, and heating with electricity, usage will increase dramatically. Relying entirely on utilities to deliver that energy from faraway power plants on long-distance power lines would involve massive delays and cause costs to rise even higher. Aggressive rooftop solar deployment could offset significant portions of the projected demand increase from electrification, helping control costs in the future.

The real reason for rate increases is runaway utility spending, driven by the utilities’ interest in increasing profits. Utility spending on grid infrastructure at the transmission and distribution levels has increased 130%-260% for each of the utilities over the past 8-12 years. These increases in spending track at a nearly 1:1 ratio with rate increases. This demonstrates that rates have gone up because utility spending has gone up. If utility costs were anything close to fixed and rates kept going up, there could be room for a cost shift argument. Or, if utility spending increased and rates increased significantly more, there could be a cost shift. The data shows neither of these trends. Rates have been increasing commensurate with spending, demonstrating that it is utility spending increases that have caused rates to increase, not consumers investing in clean energy.

Inspired by this faulty approach to measuring solar costs and benefits, the CPUC rolled out a transition from net metering to net billing that was abrupt and extreme. It has caused massive layoffs of skilled solar professionals and bankruptcies or closures of long-standing solar businesses. The poorly managed policy change set the market back ten years. A year and a half after the transition, the market still has not recovered.
California needs more rooftop solar and customer-sited batteries to contain costs and thereby rein in rate increases for all California ratepayers. To get the state back on track, policy makers need to stop attacking solar and adopt smart policies without delay.

• Respect the investments of customers who installed solar under NEM-1 and NEM-2. Do not change the terms of those contracts.
• Reject solar-specific taxes or fees in all forms, via the CPUC, the state budget, or local property taxes.
• Cut red tape in permitting and interconnection, and restore the right of solar contractors to install batteries. Do not use contractor licensing rules at the CSLB to restrict solar contractors from installing batteries.
• Establish a Million Solar Batteries initiative that includes virtual power plants and targeted incentives.
• Fix perverse utility profit motives that drive utilities to spend ratepayer money inefficiently, and even unnecessarily, and that motivate them to fight rooftop solar and other alternative ways to power California families and businesses.
• Launch a new investigation into utility oversight and overhaul the regulatory structure such that government regulators have the ability to properly scrutinize and contain utility spending.

California should be proud of its globally significant rooftop solar market. This solar development has diversified resources, served as a check on runaway utility spending, and helped clean the air all while tapping into private investments in clean energy. As the state looks to decarbonize its economy, the need to generate energy while minimizing capital intensive investments in grid infrastructure makes distributed solar and storage an even higher priority. State regulators need to stop being weak in utility oversight and exercise bold leadership for affordable clean energy that will benefit all ratepayers. California can start by getting back to promoting, not attacking, rooftop solar and batteries for all consumers.