PG&E made exciting announcements about partnerships with GMandFord last week to test using electric vehicles (EVs) for backup power for residential customers. (Ford also announced an initiative to create an open source charging standard.) PG&E also announced an initiative to install circuit breakers that facilitate use of onsite backup power. PG&E is commended for stepping forward to align its corporate strategy with the impending technology wave that could increase consumer energy independence.
I wrote about the promise of EVs in this role (“Electric vehicles as the next smartphone”) when I was struck by Ford’s F-150 Lightning ads last summer and how the consumer segment that buys pickups isn’t what we usually think of as the “EV crowd.” These initiatives could be game changers.
That said, several questions arise about PG&E’s game plan and whether the utility is still planning to hold customers captive:
How does PG&E plan to recover the costs for what are “beyond the meter” devices that typically is outside of what’s allowed? And how are the risks in these investments to be shared between shareholders and ratepayers? Will PG&E get an “authorized” rate of return with default assurances of costs being approved for recovery from ratepayers? How will PG&E be given appropriate incentives on making timely investments with appropriate risk, especially given the utility’s poor track record in acquiring renewable resources?
What will be the relationships between PG&E and the participating auto manufacturers? Will the manufacturers be required to partner with PG&E going forward? Will the manufacturers be foreclosed from offering products and services that would allow customers to exit PG&E’s system through self generation? Will PG&E close out other manufacturers from participating or set up other access barriers that prevent them from offering alternatives?
Delivering PG&E’s “personal microgrid backup power transfer meter device” is a good first step, but it requires disconnecting the solar panels to use, which means that it only support fossil fueled generators and grid-connected batteries. This device needs a switch for the solar panels as well. Further, it appears the device will only be available to customers who participate in PG&E’s Residential Generator and Battery Rebate Program. Can PG&E continue to offer this feature to vendors who offer only fossil-fueled generators? How will PG&E mitigate the local air pollution impacts from using fossil-fueled back up generators (BUGs) for extended periods? (California already has 8,000 megawatts of BUGs.)
How will these measures be integrated with the planned system reinforcements in PG&E’s 2022 Wildfire Mitigation Plan Update to reduce the costs of undergrounding lines? Will PG&E allow these back up sources and devices for customers who are interested in extended energy independence, particularly those who want to ride out a PSPS event?
How will community choice aggregators (CCAs) or other local governments participate? Will communities be able to independently push these options to achieve their climate action and adaptation plan (CAAP) goals?
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.
One commentator on the Energy Institute at Haas’ blog entitled “Everyone Should Pay a ‘Solar Tax’” points out that one version of economic theory holds that short run marginal cost is the appropriate metric for composing efficient prices. And he points out that short-run (SRMC) and long-run marginal costs (LRMC) should converge in equilibrium. So he implicitly says that long run marginal costs are the appropriate metric if as a stable long-run measure is based, as he states, on forecasts.
Even so, he misses an important aspect–using the SRMC for pricing relies on important conditions such as (1) relatively free entry and exit, (2) producers bear full risk for their investments, and (3) no requirements exist for minimum supply (i.e., no reserve margins). He points out that utilities overbuild their transmission and distribution (and I’ll point out their generation) systems. I would assert that is because of the market failures related to the fact that the conditions I listed above are missing–entry is restricted or prohibited, customers bear almost all of the risk, and reserve margins largely eliminates any potential for scarcity rents. In fact, California explicitly chose its reserve margin and resource adequacy procurement standards to eliminate the potential for pricing in the scarcity rents necessary for SRMC and LRMC to converge.
He correctly points out that apparent short run MC are quite low (not quite as close to zero as he asserts though)–a statement that implies that he expects that SRMC in a correctly functioning market would be much higher. In fact, as he states, the SRMC should converge to the LRMC. The fact is that SRMC has not risen to the LRMC on an annual average basis in decades in California (briefly in 2006, 2001 and 2000 (when generators exerted market power) and then back to the early 1980s). So why continue to insist that we should be using the current, incorrect SRMC as the benchmark when we know that it is wrong and we specifically know why its wrong? That we have these market failures to maintain system reliability and address the problems of network and monopolistic externalities is why we have regulation.
The solution is not to try to throw out our current regulatory scheme and then let the market price run free in the current institutional structure with a single dominant player. Avoiding market dominance is the raison d’etre for economic regulation. If that is the goal, the necessary first step is introducing and sustaining enough new entrants to be able to discipline the behavior of the dominant firm. Pricing reform must follow that change, not precede it. Competitive firms will not just spontaneously appear due to pricing reform.
It’s not clear that utilities “must” recover their “fixed” investments costs. Another of the needed fixes to the current regulatory scheme to improve efficiency is having utilities bear the risks of making incorrect investment decisions. Having warned (correctly) the IOUs about overforecasting demand growth for more than a dozen years now, they will not listen such analyses unless they have a financial incentive to do so.
Contrary to claims by this and other commentators, It is not efficient to charge customers a fixed charge beyond the service connection cost (which is about $10/month for residential customers for California IOUs). If the utility charges a fixed cost for the some portion of the rest of the grid, the efficient solution must then allow customers to sell their share of that grid to other customers to achieve Pareto optimal allocations among the customers. We could set up a cumbersome, high transaction cost auction or bulletin board to facilitate these trades, but there is at least another market mechanism that is nearly as efficient with much lower transaction costs–the dealer. (The NYSE uses a dealer market structure with market makers acting as dealers.) In the case of the utility grid, the utility that operates the grid also can act as the dealer. The most likely transaction unit would bein kilowatt-hours. So we’re left back where we started with volumetric rates. The problem with this model is not that it isn’t providing sufficient revenue certainty–that’s not an efficiency criterion. The problem is that the producer isn’t bearing enough of the risk of insufficient revenue recovery.
An alternative solution may be to set the distribution volumetric rate at the LRMC with no assurance of revenue requirement on that portion, and then recover the difference between average cost and LRMC in a fixed charge. This is the classic “lump sum” solution to setting monopoly pricing. The issue has been how to allocate those lump sum payments. However, the true distribution LRMC appears to be higher than average costs now based on how average rates have been rising.
The real threat to electrification are the rapidly escalating costs in the distribution system, not some anomaly in rate design related to net energy metering. As I have written here several times, rooftop solar if anything has saved ratepayers money so far, just as energy efficiency has done so. PG&E’s 2023 GRC is asking for a 66% increase in distribution rates by 2026 and average rates will approach 40 cents/kWh. We need to be asking why are these increases happening and what can we do to make electricity affordable for everyone.
Perhaps most importantly, the premise that there’s a “least cost” choice put forward by economists at the Energy Institute at Haas among others implies that there’s some centralized social welfare function. This is a mythological construct created for the convenience of economists (of which I’m one) to point to an “efficient” solution. Other societal objectives beyond economic efficiency include equitably allocating cost responsibility based on economic means, managing and sharing risks under uncertainty, and limiting political power that comes from economic assets. Efficiency itself is limited in what it tells us due to the multitude of market imperfections. The “theory of the second best” states that in an economic sector with uncorrected market failures, actions to correct market failures in another related sector with the intent of increasing economic efficiency may actually decrease overall economic efficiency. In the utility world for example, shareholders are protected from financial losses so revenue shortfalls are allocated to customers even as their demands fall. This blunts the risk incentive that is central to economic efficiency. Claiming that adding a fixed charge will “improve” efficiency has little basis without a complete, fundamental assessment of the sector’s market functionality.
The real actors here are individual customers who are making individual decisions in our current economic resource allocation system, and not a central entity dictating choices to each of us. Different customers have different preferences in what they value and what they fear. Rooftop installations have been driven to a large extent by a dread of utility mismanagement that makes expectations about future rates much more uncertain.
The single most important trait of a market economy is the discipline imposed by appropriately assigning risk burden to the decision make and not pricing design. The latter is the tail wagging the dog. Market distortions are universally caused by separating consequences from decisions. And right now the only ability customers have to exercise control over their electricity bills is to somehow exit the system. If we take away that means of discipline we will never be able to control electricity rates in a way that will lead to effective electrification.
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.
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 movie Don’t Look Up has been getting “two thumbs up” from a certain political segment for speaking to truth in their view. An existential threat from a comet is used metaphorically to describe the resistance to the import of climate change risk. After watching the film I have a somewhat different take away that speaks a different truth to those viewers who found the message resonating most. Instead of blaming our political system, we should have a different take away that we can act on collectively.
Don’t Look Up reveals several errors and blind spots in the scientific and activist communities in communicating with the public and influencing decision making. The first is a mistaken belief that the public is actually interested in scientific study beyond parlor room tricks. The second is believing that people will act solely based on shrill warnings from scientists acting as high priests. The third (which isn’t addressed in the film) is failing to fully acknowledge what people see that they may lose by responding to these calls for change. Instead these communities should reconsider what they focus on and how they communicate.
The movie opens with the first error–the astronomers’ long winded attempt to explain all of the analysis that went into their prediction. Most people don’t see how science has any direct influence on their lives–how is digging up dinosaurs or discovering the outer bounds of the universe relevant to every day living? It’s a failure of our education system, but we can’t correct to help now. Over the last several years the message on climate change has changed to highlight the apparent effects on storms and heat waves, but someone living in Kansas doesn’t see how rising sea levels will affect them. A long explanation about the mechanics and methods just loses John Q. Public (although there is a small cadre that is fascinated) and they tune out. It’s hard to be disciplined with a simple message when you find the deeper complexity interesting, but that’s what it will take.
Shrill warnings have never been well received, no matter the call. We see that today with the resistance to measures to suppress the COVID-19 pandemic. James Hansen at NASA first raised the alarm about climate change in the 1980s but he was largely ignored due to his righteousness and arrogance in public. He made a serious error in stepping well outside of his expertise to assert particular solutions. The public has always looked to who they view as credible, regardless of their credentials, for guidance. Academics have too often assumed that they deserve this respect simply because they have “the” credential. That much of the public views science as mysterious with little more basis than religion does not help the cause. Instead, finding the right messengers is key to being successful.
Finally, and importantly overlooked in the film, a call to action of this magnitude requires widespread changes in behaviors and investments. People generally have worked hard to achieve what they have and are risk averse to such changes that may severely erode their financial well-being. For example, as many as 1 in 5 private sector jobs are tied to automobiles and fossil fuel production. One might extoll the economic benefits of switching to renewable electricity but workers and investors in these sectors are uncertain about their futures with no clear pathways to share in this new prosperity. Without addressing a truly valid means of resolving these risks beyond the tired “retraining” shibboleth, this core and its sympathizers will resist meaningful change.
Effecting these solutions likely require sacrifice from those who benefit from these changes. Pointing to benefit-cost analyses that rely on a “faux” hypothetical transaction to justify these solutions really is no better than the wealthy asserting asserting that they deserve to keep most of their financial gains simply because that’s how the market works. Compensating owners of these assets and making what appears to be inefficient decisions to maintain impacted communities may seem unfair for a variety of reasons, but we need to overcome our biases embedded in our favored solutions to move forward.
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.
Vibrant Clean Energy released a study showing that inclusion of large amounts of distributed energy resources (DERs) can lower the costs of achieving 100% renewable energy. Commentors here have criticized the study for several reasons, some with reference to the supposed economies of scale of the grid.
While economies of scale might hold for individual customers in the short run, the data I’ve been evaluating for the PG&E and SCE general rate cases aren’t necessarily consistent with that notion. I’ve already discussed here the analysis I conducted in both the CAISO and PJM systems that show marginal transmission costs that are twice the current transmission rates. The rapid rise in those rates over the last decade are consistent with this finding. If economies of scale did hold for the transmission network, those rates should be stable or falling.
On the distribution side, the added investment reported in those two utilities’ FERC Form 1 are not consistent with the marginal costs used in the GRC filings. For example the added investment reported in Form 1 for final service lines (transmission, services, meters or TSM) appears to be almost 10 times larger than what is implied by the marginal costs and new customers in the GRC filings. And again the average cost of distribution is rising while energy and peak loads have been flat across the CAISO area since 2006. The utilities have repeatedly asked for $2 billion each GRC for “growth” in distribution, but given the fact that load has been flat (and even declining in 2019 and 2020), that means there’s likely a significant amount of stranded distribution infrastructure. If that incremental investment is for replacement (which is not consistent with either their depreciation schedules or their assertions about the true life of their facilties and the replacement costs within their marginal cost estimates), then they are grossly underestimating the future replacement cost for facilities which means they are underestimating the true marginal costs.
I can see a future replacement liability right outside my window. The electric poles were installed by PG&E 60+ years ago and the poles are likely reaching the end of their lives. I can see the next step moving to undergrounding the lines at a cost of $15,000 to $25,000 per house based on the ongoing mobilehome conversion program and the typical Rule 20 undergrounding project. Deferring that cost is a valid DER value. We will have to replace many services over the next several decades. And that doesn’t address the higher voltage parts of the system.
We have a counterexample of a supposed monopoly in the cable/internet system. I have at least two competing options where I live. The cell phone network also turned out not to be a natural monopoly. In an area where the PG&E and Merced ID service territories overlap, there are parallel distribution systems. The claim of a “natural monopoly” more likely is a legal fiction that protects the incumbent utility and is simpler for local officials to manage when awarding franchises.
If the claim of natural monopolies in electricity were true, then the distribution rate components for SCE and PG&E should be much lower than for smaller munis such as Palo Alto or Alameda. But that’s not the case. The cost advantages for SMUD and Roseville are larger than can be simply explained by differences in cost of capital. The Division/Office of Ratepayer Advocates commissioned a study by Christensen Associates for PG&E’s 1999 GRC that showed that the optimal utility size was about 500,000 customers. (PG&E’s witness who was a professor at UC Berkeley inadvertently confirmed the results and Commissioner Richard Bilas, a Ph.D. economist, noted this in his proposed decision which was never adopted because it was short circuited by restructuring.) Given that finding, that means that the true marginal cost of a customer and associated infrastructure is higher than the average cost. The likely counterbalancing cause is an organizational diseconomy of scale that overwhelms the technological benefits of size.
Finally, generation no longer shows the economies of scale that dominated the industry. The modularity of combined cycle plants and the efficiency improvement of CTs started the industry down the rode toward the efficiency of “smallness.” Solar plants are similarly modular. The reason why additional solar generation appears so low cost is because much of that is from adding another set of panels to an existing plant while avoiding additional transmission interconnection costs (which is the lion’s share of the costs that create what economies of scale do exist.)
The VCE analysis looks a holistic long term analysis. It relies on long run marginal costs, not the short run MCs that will never converge on the LRMC due to the attributes of the electricity system as it is regulated. The study should be evaluated in that context.