In the 1990s, California’s industrial customers threatened to build their own self-generation plants and leave the utilities entirely. Escalating generation costs due to nuclear plant cost overruns and too-generous qualifying facilities (QF) contracts had driven up rates, and the technology that made QFs possible also allowed large customers to consider self generating. In response California “restructured” its utility sector to introduce competition in the generation segment and to get the utilities out of that part of the business. Unfortunately the initiative failed, in a big way, and we were left with a hybrid system which some blame for rising rates today.
Those rising rates may be introducing another threat to the utilities’ business model, but it may be more existential this time. A previous blog post described how Pacific Gas & Electric’s 2022 Wildfire Mitigation Plan Update combined with the 2023 General Rate Application could lead to a 50% rate increase from 2020 to 2026. For standard rate residential customers, the average rate could by 41.9 cents per kilowatt-hour.
For an average customer that translates to $2,200 per year per kilowatt of peak demand. Using PG&E’s cost of capital, that implies that an independent self-sufficient microgrid costing $15,250 per kilowatt could be funded from avoiding paying PG&E bills.
The National Renewable Energy Laboratory (NREL) study referenced in this blog estimates that a stand alone residential microgrid with 7 kilowatts of solar paired with a 5 kilowatt / 20 kilowatt-hour battery would cost between $35,000 and $40,000. The savings from avoiding PG&E rates could justify spending $75,000 to $105,000 on such a system, so a residential customer could save up to $70,000 by defecting from the grid. Even if NREL has underpriced and undersized this example system, that is a substantial margin.
This time it’s not just a few large customers with choice thermal demands and electricity needs—this would be a large swath of PG&E’s residential customer class. It would be the customers who are most affluent and most able to pay PG&E’s extraordinary costs. If many of these customers view this opportunity to exit favorably, the utility could truly face a death spiral that encourages even more customers to leave. Those who are left behind will demand more relief in some fashion, but those customers who already defected will not be willing to bail out the company.
In this scenario, what is PG&E’s (or Southern California Edison’s and San Diego Gas & Electric’s) exit strategy? Trying to squeeze current NEM customers likely will only accelerate exit, not stifle it. The recent two-day workshop on affordability at the CPUC avoided discussing how utility investors should share in solving this problem, treating their cost streams as inviolable. The more likely solution requires substantial restructuring of PG&E to lower its revenue requirements, including by reducing income to shareholders.
PG&E released its 2022 Wildfire Mitigation Plan Update (2022 WMPU) That plan calls for $6 billion of capital investment to move 3,600 miles of underground by 2026. This is just over a third of the initial proposed target of 10,000 miles. Based on PG&E’s proposed ramping up, the utility would reach its target by 2030.
One alternative that could better control costs would be to install community and individual microgrids. Microgrids are likely more cost effective and faster means of reducing wildfire risk and saving lives. I wrote about how to evaluate this choice for relative cost effectiveness based on density of load and customers per mile of line.
Microgrids can mitigate wildfire risk by the utility turning off overhead wire service for extended periods, perhaps weeks at a time, during the highest fire risk periods. The advantage of a periodically-islanded microgrid is 1) that the highest fire risk coincides with the most solar generation so providing enough energy is not a problem and 2) the microgrids also can be used during winter storms to better support the local grid and to ride out shorter outages. Customers’ reliability may degrade because they would not have the grid support, but such systems generally have been quite reliable. In fact, reliability may increase because distribution grid outages are about 15 times more likely than system or regional outages.
The important question is whether microgrids can be built much more quickly than undergrounding lines and in particular whether PG&E has the capacity to manage such a buildout at a faster rate? PG&E has the Community Microgrid Enablement Program. The utility was recently authorized to build severalisolatedmicrogrids as an alternative to rebuilding fire-damaged distribution lines to isolated communities. Turning to local governments to manage many different construction projects likely would improve this schedule, like how Caltrans delegates road construction to counties and cities.
Controlling the costs of wildfire mitigation
Based on the current cost of capital this initial undergrounding phase will add $1.6 billion to annual revenue requirements or an additional 8% above today’s level. This would be on top of PG&E request in its 2023 General Rate Case for a 48% increase in distribution rates by 2023 and 78% increase by 2026, and a 31% increase in overall bundled rates by 2023 and 43% by 2026. The 2022 WMPU would take the increase to over 50% by 2026 (and that doesn’t’ include the higher maintenance costs). That means that residential rates would increase from 28.7 cents per kilowatt-hour today (already 21% higher than December 2020) to 36.4 cents in 2026. Building out the full 10,000 miles could lead to another 15% increase on top of all of this.
Turning to the comparison of undergrounding costs to microgrids, these two charts illustrate how to evaluate the opportunities for microgrids to lower these costs. PG&E states the initial cost per mile for undergrounding is $3.75 million, dropping to $2.5 million, or an average of $2.9 million. The first figure looks at community scale microgrids, using National Renewable Energy Laboratory (NREL) estimates. It shows how the cost effectiveness of installing microgrids changes with density of peak loads on a circuit on the vertical axis, cost per kilowatt for a microgrid on the horizontal axis, and each line showing the division where undergrounding is less expensive (above) or microgrids are less expensive (below) based on the cost of undergrounding. As a benchmark, the dotted line shows the average load density in the PG&E system, combined rural and urban. So in average conditions, community microgrids are cheaper regardless of the costs of microgrids or undergrounding.
The second figure looks at individual residential scale microgrids, again using NREL estimates. It shows how the cost effectiveness of installing microgrids changes with customer density on a circuit on the vertical axis, cost per kilowatt for a microgrid on the horizontal axis, and each line showing the division where undergrounding is less expensive (above) or microgrids are less expensive (below). As a benchmark, the dotted line shows the average customer density in the PG&E system, combined rural and urban. Again, residential microgrids are less expensive in most situations, especially as density falls below 75 customers per mile.
A movement towards energy self-sufficiency is growing in California due to a confluence of factors. PG&E’s WMPU should reflect these new choices in manner that can reduce rates for all customers.
(Here’s my testimony on this topic filed by the California Farm Bureau in PG&E’s 2023 General Rate Case on its Wildfire Management Plan Update.)
The Energy Institute’s blog has an important premise–that solar rooftop customers have imposed costs on other ratepayers with few benefits. This premise runs counter to the empirical evidence.
First, these customers have deferred an enormous amount of utility-scale generation. In 2005 the CEC forecasted the 2020 CAISO peak load would 58,662 MW. The highest peak after 2006 has been 50,116 MW (in 2017–3,000 MW higher than in August 2020). That’s a savings of 8,546 MW. (Note that residential installations are two-thirds of the distributed solar installations.) The correlation of added distributed solar capacity with that peak reduction is 0.938. Even in 2020, the incremental solar DER was 72% of the peak reduction trend. We can calculate the avoided peak capacity investment from 2006 to today using the CEC’s 2011 Cost of Generation model inputs. Combustion turbines cost $1,366/kW (based on a survey of the 20 installed plants–I managed that survey) and the annual fixed charge rate was 15.3% for a cost of $209/kW-year. The total annual savings is $1.8 billion. The total revenue requirements for the three IOUs plus implied generation costs for DA and CCA LSEs in 2021 was $37 billion. So the annual savings that have accrued to ALL customers is 4.9%. Given that NEM customers are about 4% of the customer base, if those customers paid nothing, everyone else’s bill would only go up by 4% or less than what rooftop solar has saved so far.
In addition, the California Independent System Operator (CAISO) calculated in 2018 that at least $2.6 billion in transmission projects had been deferred through installed distributed solar. Using the amount installed in 2017 of 6,785 MW, the avoided costs are $383/kW or $59/kW-year. This translates to an additional $400 million per year or about 1.1% of utility revenues.
The total savings to customers is over $2.2 billion or about 6% of revenue requirements.
Second, rooftop solar isn’t the most expensive power source. My rooftop system installed in 2017 costs 12.6 cents/kWh (financed separately from our mortgage). In comparison, PG&E’s RPS portfolio cost over 12 cents/kWh in 2019 according to the CPUC’s 2020 Padilla Report, plus there’s an increments transmission cost approaching 4 cents/kWh, so we’re looking at a total delivered cost of 16 cents/kwh for existing renewables. (Note that the system costs to integrate solar are largely the same whether they are utility scale or distributed).
Comparing to the average IOU RPS portfolio cost to that of rooftop solar is appropriate from the perspective of a customer. Utility customers see average, not marginal, costs and average cost pricing is widely prevalent in our economy. To achieve 100% renewable power a reasonable customer will look at average utility costs for the same type of power. We use the same principle by posting on energy efficient appliances the expect bill savings based on utility rates–-not on the marginal resource acquisition costs for the utilities.
And customers who would choose to respond to the marginal cost of new utility power instead will never really see those economic savings because the supposed savings created by that decision will be diffused across all customers. In other words, other customers will extract all of the positive rents created by that choice. We could allow for bypass pricing (which industrial customers get if they threaten to leave the service area) but currently we force other customers to bear the costs of this type of pricing, not shareholders as would occur in other industries. Individual customers are currently the decision making point of view for most energy use purposes and they base those on average cost pricing, so why should we have a single carve out for a special case that is quite similar to energy efficiency?
I wrote more about whether a fixed connection cost is appropriate for NEM customers and the complexity of calculating that charge earlier this week.
There is a general understanding among the most informed participants and observers that California’ net energy metering (NEM) tariff as originally conceived was not intended to be a permanent fixture. The objective of the NEM rate was to get a nascent renewable energy industry off the ground and now California has more than 11,000 megawatts of distributed solar generation. Now that the distributed energy resources industry is in much less of a need for subsidies, but its full value also must be recognized. To this end it is important to understand some key facts that are sometimes overlooked in the debate.
The true underlying reason for high rates–rising utility revenue requirements
In California, retail electricity rates are so high for two reasons, the first being stranded generation costs and the second being a bunch of “public goods charges” that constitute close to half of the distribution cost. PG&E’s rates have risen 57% since 2009. Many, if not most, NEM customers have installed solar panels as one way to avoid these rising rates. The thing is when NEM 1.0 and 2.0 were adopted, the cost of the renewable power purchase agreements (PPA) portfolios were well over $100/MWH—even $120MWH through 2019, and adding in the other T&D costs, this approached the average system rate as late as 2019 for SCE and PG&E before their downward trends reversed course. That the retail rate skyrocketed while renewable PPAs fell dramatically is a subsequent development that too many people have forgotten.
California uses Ramsey pricing principles to allocate these (the CPUC applies “equal percent marginal costs” or EPMC as a derivative measure), but Ramsey pricing was conceived for one-way pricing. I don’t know what Harold Hotelling would think of using his late student’s work for two way transactions. This is probably the fundamental problem in NEM rates—the stranded and public goods costs are incurred by one party on one side of the ledger (the utility) but the other party (the NEM customer) doesn’t have these same cost categories on the other side of the ledger; they might have their own set of costs but they don’t fall into the same categories. So the issue is how to set two way rates given the odd relationships of these costs and between utilities and ratepayers.
This situation argues for setting aside the stranded costs and public goods to be paid for in some manner other than electric rates. The answer can’t be in a form of a shift of consumption charges to a large access charge (e.g., customer charge) because customers will just leave entirely when half of their current bill is rolled into the new access charge.
The largest nonbypassable charge (NBC), now delineated for all customers, is the power cost indifference adjustment (PCIA). The PCIA is the stranded generation asset charge for the portfolio composed of utility-scale generation. Most of this is power purchase agreements (PPAs) signed within the last decade. For PG&E in 2021 according to its 2020 General Rate Case workpapers, this exceeded 4 cents per kilowatt-hour.
Basic facts about the grid
The grid is not a static entity in which there are no changes going forward. Yet the cost of service analysis used in the CPUC’s recent NEM proposed decision assumes that posture. Acknowledging that the system will change going forward depending on our configuration decisions is an important key principle that is continually overlooked in these discussions.
In California, a customer is about 15 times more likely to experience an outage due to distributionsystem problems than from generation/transmission issues. That means that a customer who decides to rely on self-provided resources can have a set up that is 15 times less reliable than the system grid and still have better reliability than conventional service. This is even more true for customers who reside in rural areas.
Upstream of the individual service connection (which costs about $10 per month for residential customers based on testimony I have submitted in all three utilities’ rate cases), customers share distribution grid capacity with other customers. They are not given shares of the grid to buy and sell with other customers—we leave that task to the utilities who act as dealers in that market place, owning the capacity and selling it to customers. If we are going to have fixed charges for customers which essentially allocated a capacity share to each of them, those customers also should be entitled to buy and sell capacity as they need it. The end result will be a marketplace which will price distribution capacity on either a daily $ per kilowatt or cents per kilowatt-hour basis. That system will look just like our current distribution pricing system but with a bunch of unnecessary complexity.
This situation is even more true for transmission. There most certainly is not a fixed share of the transmission grid to be allocated to each customer. Those shares are highly fungible.
What is the objective of utility regulation: just and reasonable rates or revenue assurance?
At the core of this issue is the question of whether utility shareholders are entitled to largely guaranteed revenues to recover their investments. In a market with some level of competitiveness, the producers face a degree of risk under normal functional conditions (more mundane than wildfire risk)—that is not the case with electric utilities, at least in California. (We cataloged the amount of disallowances for California IOUs in the 2020 cost of capital applications and it was less than one one-hundredth of a percent (0.01%) of revenues over the last decade.) When customers reduce or change their consumption patterns in a manner that reduces sales in a normal market, other customers are not required to pick up the slack—shareholders are. This risk is one of the core benefits of a competitive market, no matter what the degree of imperfection. Neither the utilities or the generators who sell to them under contract face these risks.
Why should we bother with “efficient” pricing if we are pushing the entire burden of achieving that efficiency on customers who have little ability to alter utilities’ investment decisions? Bottom line: if economists argue for “efficient” pricing, they need to also include in that how utility shareholders will participate directly in the outcomes of that efficient pricing without simply shifting revenue requirements to other customers.
As to the intent of the utilities, in my 30 year on the ground experience, the management does not make decisions that are based on “doing good” that go against their profit objective. There are examples of each utility choosing to gain profits that they were not entitled to. We entered into testimony in PG&E’s 1999 GRC a speech by a PG&E CEO talking about how PG&E would exploit the transition period during restructuring to maintain market share. That came back to haunt the state as it set up the conditions for ensuing market manipulation.
Each of these issues have been largely ignored in the debate over what to do about solar rooftop policy and investment going forward. It is time to push these to fore.
I read these two statements in his blog post and come to a very different conclusions:
“(I)ndividuals and businesses make investments in response to those policies, and many come to believe that they have a right to see those policies continue indefinitely.”
Why wasn’t there a similar cry against bailing out PG&E in not one but TWO bankruptcies? Both PG&E and SCE have clearly relied on the belief that they deserve subsidies to continue staying in business. (SCE has ridden along behind PG&E in both cases to gain the spoils.) The focus needs to be on ALL players here if these types of subsidies are to be called out.
“(T)he reactions have largely been about how much subsidy rooftop solar companies in California need in order to stay in business.”
We are monitoring two very different sets of media then. I see much more about the ability of consumers to maintain an ability to gain a modicum of energy independence from large monopolies that compel that those consumers buy their service with no viable escape. I also see a reactions about how this will undermine directly our ability to reduce GHG emissions. This directly conflicts with the CEC’s Title 24 building standards that use rooftop solar to achieve net zero energy and electrification in new homes.
Yes, there are problems with the current compensation model for NEM customers, but we also need to recognize our commitments to customers who made investments believing they were doing the right thing. We need to acknowledge the savings that they created for all of us and the push they gave to lower technology costs. We need to recognize the full set of values that these customers provide and how the current electric market structure is too broken to properly compensate what we want customers to do next–to add more storage. Yet, the real first step is to start at the source of the problem–out of control utility costs that ratepayers are forced to bear entirely.
The saying goes “No good deed goes unpunished.” The California Public Utilities Commission seems to have taken that motto to heart recently, and stands ready to penalize yet another group of customers who answered the clarion call to help solve the state’s problems by radically altering the rules for solar rooftops. Here’s three case studies of recent CPUC actions that undermine incentives for customers to act in the future in response to state initiatives: (1) farmers who invested in response to price incentives, (2) communities that pursued renewables more assertively, and (3) customers who installed solar panels.
Agriculture: Farmers have responded to past time of use (TOU) rate incentives more consistently and enthusiastically than any other customer class. Instead of being rewarded for their consistency, their peak price periods shifted from the afternoon to the early evening. Growers face much more difficulty in avoiding pumping during that latter period.
Since TOU rates were introduced to agricultural customers in the late 1970s, growers have made significant operational changes in response to TOU differentials between peak and off-peak energy prices to minimize their on-peak consumption. These include significant investments in irrigation equipment, storage and conveyance infrastructure and labor deployment rescheduling. The results of these expenditures are illustrated in the figure below, which shows how agricultural loads compare with system-wide load on a peak summer weekday in 2015, contrasting hourly loads to the load at the coincident peak hour. Both the smaller and larger agricultural accounts perform better than a range of representative rate schedules. Most notably agriculture’s aggregate load shape on a summer weekday is inverted relative to system peak, i.e., the highest agricultural loads occur during the lowest system load periods, in contrast with other rate classes.
All other rate schedules shown in the graphic hit their annual peak on the same peak day within the then-applicable peak hours of noon to 6 p.m. In contrast, agriculture electricity demand is less than 80% of its annual peak during those high-load hours, with its daily peak falling outside the peak period. Agriculture’s avoidance of peak hours occurred during the summer agricultural growing season, which coincided with peak system demand—just as the Commission asked customers to do. The Commission could not ask for a better aggregate response to system needs; in contrast to the profiles for all of the other customer groups, agriculture has significantly contributed to shifting the peak to a lower cost evening period.
The significant changes in the peak period price timing and differential that the CPUC adopted increases uncertainty over whether large investments in high water-use efficiency microdrip systems – which typically cost $2,000 per acre–will be financially viable. Microdrip systems have been adopted widely by growers over the last several years—one recent study of tomato irrigation rates in Fresno County could not find any significant quantity of other types of irrigation systems. Such systems can be subject to blockages and leaks that are only detectable at start up in daylight. Growers were able to start overnight irrigation at 6 p.m. under the legacy TOU periods and avoid peak energy use. In addition, workers are able to end their day shortly after 6 p.m. and avoid nighttime accidents. Shifting that load out of the peak period will be much more difficult to do with the peak period ending after sunset.
Contrary to strong Commission direction to incent customers to avoid peak power usage, the shift in TOU periods has served to penalize, and reverse, the great strides the agricultural class has made benefiting the utility system over the last four decades.
Community choice aggregators: CCAs were created, among other reasons, to develop more renewable or “green” power. The state achieved its 2020 target of 33% in large part because of the efforts of CCAs fostered through offerings of 50% and 100% green power to retail customers. CCAs also have offered a range of innovative programs that go beyond the offerings of PG&E, SCE and SDG&E.
Nevertheless, the difficulty of reaching clean energy goals is created by the current structure of the PCIA. The PCIA varies inversely with the market prices in the market–as market prices rise, the PCIA charged to CCAs and direct access (DA) customers decreases. For these customers, their overall retail rate is largely hedged against variation and risk through this inverse relationship.
The portfolios of the incumbent utilities are dominated by long-term contracts with renewables and capital-intensive utility-owned generation. For example, PG&E is paying a risk premium of nearly 2 cents per kilowatt-hour for its investment in these resources. These portfolios are largely impervious to market price swings now, but at a significant cost. The PCIA passes along this hedge through the PCIA to CCAs and DA customers which discourages those latter customers from making their own long term investments. (I wrote earlier about how this mechanism discouraged investment in new capacity for reliability purposes to provide resource adequacy.)
The legacy utilities are not in a position to acquire new renewables–they are forecasting falling loads and decreasing customers as CCAs grow. So the state cannot look to those utilities to meet California’s ambitious goals–it must incentivize CCAs with that task. The CCAs are already game, with many of them offering much more aggressive “green power” options to their customers than PG&E, SCE or SDG&E.
But CCAs place themselves at greater financial risk under the current rules if they sign more long-term contracts. If market prices fall, they must bear the risk of overpaying for both the legacy utility’s portfolio and their own.
Solar net energy metered customers: Distributed solar generation installed under California’s net energy metering (NEM/NEMA) programs has mitigated and even eliminated load and demand growth in areas with established customers. This benefit supports protecting the investments that have been made by existing NEM/NEMA customers. Similarly, NEM/NEMA customers can displace investment in distribution assets. That distribution planners are not considering this impact appropriately is not an excuse for failing to value this benefit. For example, PG&E’s sales fell by 5% from 2010 to 2018 and other utilities had similar declines. Peak loads in the CAISO balancing authority reach their highest point in 2006 and the peak in August 2020 was 6% below that level.
Much of that decrease appears to have been driven by the installation of rooftop solar. The figure above illustrates the trends in CAISO peak loads in the set of top lines and the relationship to added NEM/NEMA installations in the lower corner. It also shows the CEC’s forecast from its 2005 Integrated Energy Policy Report as the top line. Prior to 2006, the CAISO peak was growing at annual rate of 0.97%; after 2006, peak loads have declined at a 0.28% trend. Over the same period, solar NEM capacity grew by over 9,200 megawatts. The correlation factor or “R-squared” between the decline in peak load after 2006 and the incremental NEM additions is 0.93, with 1.0 being perfect correlation. Based on these calculations, NEM capacity has deferred 6,500 megawatts of capacity additions over this period. Comparing the “extreme” 2020 peak to the average conditions load forecast from 2005, the load reduction is over 11,500 megawatts. The obvious conclusion is that these investments by NEM customers have saved all ratepayers both reliability and energy costs while delivering zero-carbon energy.
The CPUC now has before it a rulemaking in which the utilities and some ratepayer advocates are proposing to not only radically reduce the compensation to new NEM/NEMA customers but also to change the terms of the agreements for existing ones.
One of the key principles of providing financial stability is setting prices and rates for long-lived assets such as solar panels and generation plants at the economic value when the investment decision was made to reflect the full value of the assets that would have been acquired otherwise. If that new resource had not been built, either a ratebased generation asset would have been constructed by the utility at a cost that would have been recovered over a standard 30-year period or more likely, additional PPAs would have been signed. Additionally, the utilities’ investments and procurement costs are not subject to retroactive ratemaking under the rule prohibiting such ratemaking and Public Utilities Code Section 728, thus protecting shareholders from any risk of future changes in state or Commission policies.
Utility customers who similarly invest in generation should be afforded at least the same assurances as the utilities with respect to protection from future Commission decisions that may diminish the value of those investments. Moreover, customers do not have the additional assurances of achieving a certain net income so they already face higher risks than utility shareholders for their investments.
Generators are almost universally afforded the ability to recover capital investments based on prices set for multiple years, and often the economic life of their assets. Utilities are able to put investments in ratebase to be recovered at a fixed rate of return plus depreciation over several decades. Third-party generators are able to sign fixed price contracts for 10, 20, and even 40 years. Some merchant generators may choose to sell only into the short-term “hourly” market, but those plants are not committed to selling whenever the CAISO demands so. Generators are only required to do so when they sign a PPA with an assured payment toward investment recovery.
Ratepayers who make investments that benefit all ratepayers over the long term should be offered tariffs that provide a reasonable assurance of recovery of those investments, similar to the PPAs offered to generators. Ratepayers should be able to gain the same assurances as generators who sign long-term PPAs, or even utilities that ratebase their generation assets, that they will not be forced to bear all of the risk of investing of clean self-generation. These ratepayers should have some assurance over the 20-plus year expected life of their generation investment.
Yet policymakers and stakeholders largely focus almost solely on increasing reserve margins to improve reliability. If we instead looked the most comprehensive means of improving reliability in the manner that matters to customers, we’d probably find that distributed energy resources are a much better fit. To the extent that DERs can relieve distribution level loads, we gain at both levels and not just at the system level with added bulk generation.
This approaches first requires a change in how resource adequacy is defined and modeled to look from the perspective of the customer meter. It will require a more extensive analysis of distribution circuits and the ability of individual circuits to island and self supply during stressful conditions. It also requires a better assessment of the conditions that lead to local outages. Increased resource diversity should lead to improved probability of availability as well. Current modeling of the benefits of regions leaning on each other depend on largely deterministic assumptions about resource availability. Instead we should be using probability distributions about resources and loads to assess overlapping conditions. An important aspect about reliability is that 100 10 MW generators with a 10% probability of outage provides much more reliability than a single 1,000 MW generator also with a 10% outage rate due to diversity. This fact is generally ignored in setting the reserve margins for resource adequacy.
We also should consider shifting resource investment from bulk generation (and storage) where it has a much smaller impact on individual customer reliability to lower voltage distribution. Microgrids are an example of an alternative that better focuses on solving the real problem. Let’s start a fundamental reconsideration of our electric grid investment plan.
This report by Next10 and the University of California Energy Institute was prepared for the CPUC’s en banc hearing February 24. The report compares average electricity rates against other states, and against an estimate of “marginal costs”. (The latter estimate is too low but appears to rely mostly on the E3 Avoided Cost Calculator.) It shows those rates to be multiples of the marginal costs. (PG&E’s General Rate Case workpapers calculates that its rates are about double the marginal costs estimated in that proceeding.) The study attempts to list the reasons why the authors think these rates are too high, but it misses the real drivers on these rate increases. It also uses an incorrect method for calculating the market value of acquisitions and deferred investments, using the current market value instead of the value at the time that the decisions were made.
We can explore the reasons why PG&E’s rates are so high, much of which is applicable to the other two utilities as well. Starting with generation costs, PG&E’s portfolio mismanagement is not explained away with a simple assertion that the utility bought when prices were higher. In fact, PG&E failed in several ways.
First, PG&E knew about the risk of customer exit as early as 2010 as revealed during the PCIA rulemaking hearings in 2018. PG&E continued to procure as though it would be serving its entire service area instead of planning for the rise of CCAs. Further PG&E also was told as early as 2010 (in my GRC testimony) that it was consistently forecasting too high, but it didn’t bother to correct thee error. Instead, service area load is basically at the save level that it was a decade ago.
Second, PG&E could have procured in stages rather than in two large rounds of request for offers (RFOs) which it finished by 2013. By 2011 PG&E should have realized that solar costs were dropping quickly (if they had read the CEC Cost of Generation Report that I managed) and that it should have rolled out the RFOs in a manner to take advantage of that improvement. Further, they could have signed PPAs for the minimum period under state law of 10 years rather than the industry standard 30 years. PG&E was managing its portfolio in the standard practice manner which was foolish in the face of what was occurring.
Third, PG&E failed to offer part of its portfolio for sale to CCAs as they departed until 2018. Instead, PG&E could have unloaded its expensive portfolio in stages starting in 2010. The ease of the recent RPS sales illustrates that PG&E’s claims about creditworthiness and other problems had no foundation.
I calculated the what the cost of PG&E’s mismanagement has been here. While SCE and SDG&E have not faced the same degree of exit by CCAs, the same basic problems exist in their portfolios.
Another factor for PG&E is the fact that ratepayers have paid twice for Diablo Canyon. I explain here how PG&E fully recovered its initial investment costs by 1998, but as part of restructuring got to roll most of its costs back into rates. Fortunately these units retire by 2025 and rates will go down substantially as a result.
In distribution costs, both PG&E and SCE requested over $2 billion for “new growth” in each of its GRCs since 2009, despite my testimony showing that growth was not going to materialize, and did not materialize. If the growth was arising from the addition of new developments, the developers and new customers should have been paying for those additions through the line extension rules that assign that cost responsibility. The utilities’ distribution planning process is opaque. When asked for the workpapers underlying the planning process, both PG&E and SCE responded that the entirety were contained in the Word tables in each of their testimonies. The growth projections had not been reconciled with the system load forecasts until this latest GRC, so the totals of the individual planning units exceeded the projected total system growth (which was too high as well when compared to both other internal growth projections and realized growth). The result is a gross overinvestment in distribution infrastructure with substantial overcapacity in many places.
For transmission, the true incremental cost has not been fully reported which means that other cost-effective solutions, including smaller and closer renewables, have been ignored. Transmission rates have more than doubled over the last decade as a result.
The Next10 report does not appear to reflect the full value of public purpose program spending on energy efficiency, in large part because it uses a short-run estimate of marginal costs. The report similarly underestimates the value of behind-the-meter solar rooftops as well. The correct method for both is to use the market value of deferred resources–generation, transmission and distribution–when those resources were added. So for example, a solar rooftop installed in 2013 was displacing utility scale renewables that cost more than $100 per megawatt-hour. These should not be compared to the current market value of less than $60 per megawatt-hour because that investment was not made on a speculative basis–it was a contract based on embedded utility costs.
A recent article by E3 and Form Energy in Utility Dive calls for more granular temporal modeling of the electric power system to better capture the constraints of a fully-renewable portfolio and the requirements for supporting technologies such as storage. The authors have identified the correct problem–most current models use a “typical week” of loads that are an average of historic conditions and probabilistic representations of unit availability. This approach fails to capture the “tail” conditions where renewables and currently available storage are likely to be sufficient.
But the answer is not a full blown hour by hour model of the entire year with many permutations of the many possibilities. These system production simulation models already take too long to run a single scenario due to the complexity of this giant “transmission machine.” Adding the required uncertainty will cause these models to run “in real time” as some modelers describe it.
Instead a separate analysis should first identify the conditions under which renewables + current technology storage are unlikely to meet demand sufficiently. These include drought that limits hydropower, extreme weather, and extended weather that limits renewable production. Then these conditions can input into the current models to assess how the system responds.
The two important fixes which has always been problem in these models are to energy-limited resources and unit commitment algorithms. Both of these are complex problems, and these models have not done well in scheduling seasonal hydropower pondage storage and in deciding which units to commit to meet a high demand several days ahead. (And these problems are also why relying solely on hourly bulk power pricing doesn’t give an accurate measure of the true market value of a resource.) But focusing on these two problems is much easier than trying to incorporating the full range of uncertainty for all 8,760 hours for at least a decade into the future.
We should not confuse precision with accuracy. The current models can be quite precise on specific metrics such as unit efficiency as different load points, but they can be inaccurate because they don’t capture the effect of load and fuel price variations. We should not be trying to achieve spurious precision through more complete granular modeling–we should be focusing on accuracy in the narrow situations that matter.
PG&E has been aggressively cutting down trees as part of its attempt to mitigate wildfire risk, but those efforts may be creating their own risks. Previously, PG&E has been accused of just focusing numeric targets over effective vegetation management. This situation is reminiscent of how the utilities pursued energy efficiency prior to 2013 with a seemingly single-minded focus on compact fluorescent lights (CFLs). And that focus did not end well, including leading to both environmental degradation and unearned incentives for utilities.
CFLs represented about 20% of the residential energy efficiency program spending in 2009. CFLs were easy for the utilities–they just delivered steeply discounted, or even free, CFLs to stores and they got to count each bulb as an “energy savings.” By 2013, the CPUC ordered the utilities to ramp down spending on CFLs as a new cost-effective technology emerged (LEDs) and the problem of disposing of mercury in the ballasts of CFLs became apparent. But more importantly, it turned out that CFLs were just sitting in closets, creating much fewer savings than estimated. (It didn’t help that CFLs turned out to have a much shorter life than initially estimated as well.) Even so, the utilities were able claim incentives from the California Public Utilities Commission. Ultimately, it became apparent that CFLs were largely a mistake in the state’s energy efficiency portfolio.
Vegetation management seems to be the same “easy number counting” solution that the utilities, particularly PG&E, have adopted. The adverse consequences will be significant and it won’t solve the problem in the long. Its one advantage is that it allows the utilities to maintain their status quo position at the center of the utility network.
Other alternatives include system hardening such as undergrounding or building microgrids in rural communities to allow utilities to deenergize the grid while maintaining local power. The latter option appears to be the most cost effective solution, but it is also the most threatening to the current position of the incumbent utility by giving customers more independence.
Economics Outside the Cube 