Authors Ahmad Faruqui, Richard McCann and Fereidoon Sioshansi[1] respond to Professor Severin Borenstein’s much-debated proposal to reform California’s net energy metering, which was first published as a blog and later in a Los Angeles Times op-ed.
by Steven J. Moss and Richard J. McCann, M.Cubed
A potentially key barrier to decarbonizing California’s economy is escalating electricity costs.[1] To address this challenge, the Local Government Sustainable Energy Coalition, in collaboration with Santa Barbara Clean Energy, proposes to create a decarbonization incentive rate, which would enable customers who switch heating, ventilation and air conditioning (HVAC) or other appliances from natural gas, fossil methane, or propane to electricity to pay a discounted rate on the incremental electricity consumed.[2] The rate could also be offered to customers purchasing electric vehicles (EVs).
California has adopted electricity rate discounts previously to incentivize beneficial choices, such as retaining and expanding businesses in-state,[3] and converting agricultural pump engines from diesel to electricity to improve Central Valley air quality.[4]
The decarbonization incentive rate (DIR) would use the same principles as the EDR tariff. Most importantly, load created by converting from fossil fuels is new load that has only been recently—if at all–included in electricity resource and grid planning. None of this load should incur legacy costs for past generation investments or procurement nor for past distribution costs. Most significantly, this principle means that these new loads would be exempt from the power cost indifference adjustment (PCIA) stranded asset charge to recover legacy generation costs.
The California Public Utility Commission (CPUC) also ruled in 2007 that NBCs such as for public purpose programs, CARE discount funding, Department of Water Resources Bonds, and nuclear decommissioning, must be recovered in full in discounted tariffs such as the EDR rate. This proposal follows that direction and include these charges, except the PCIA as discussed above.
Costs for incremental service are best represented by the marginal costs developed by the utilities and other parties either in their General Rate Case (GRC) Phase II cases or in the CPUC’s Avoided Cost Calculator. Since the EDR is developed using analysis from the GRC, the proposed DIR is illustrated here using SCE’s 2021 GRC Phase II information as a preliminary estimate of what such a rate might look like. A more detailed analysis likely will arrive at a somewhat different set of rates, but the relationships should be similar.
For SCE, the current average delivery rate that includes distribution, transmission and NBCs is 9.03 cents per kilowatt-hour (kWh). The average for residential customers is 12.58 cents. The system-wide marginal cost for distribution is 4.57 cents per kilowatt-hour;[8] 6.82 cents per kWh for residential customers. Including transmission and NBCs, the system average rate component would be 7.02 cents per kWh, or 22% less. The residential component would be 8.41 cents or 33% less.[9]
The generation component similarly would be discounted. SCE’s average bundled generation rate is 8.59 cents per kWh and 9.87 cents for residential customers. The rates derived using marginal costs is 5.93 cents for the system average and 6.81 cent for residential, or 31% less. For CCA customers, the PCIA would be waived on the incremental portion of the load. Each CCA would calculate its marginal generation cost as it sees fit.
For bundled customers, the average rate would go from 17.62 cents per kWh to 12.95 cents, or 26.5% less. Residential rates would decrease from 22.44 cents to 15.22 cents, or 32.2% less.
Incremental loads eligible for the discounted decarb rate would be calculated based on projected energy use for the appropriate application. For appliances and HVAC systems, Southern California Gas offers line extension allowances for installing gas services based on appliance-specific estimated consumption (e.g., water heating, cooking, space conditioning).[10] Data employed for those calculations could be converted to equivalent electricity use, with an incremental use credit on a ratepayer’s bill. An alternative approach to determine incremental electricity use would be to rely on the California Energy Commission’s Title 24 building efficiency and Title 20 appliance standard assumptions, adjusted by climate zone.[11]
For EVs, the credit would be based on the average annual vehicle miles traveled in a designated region (e.g., county, city or zip code) as calculated by the California Air Resources Board for use in its EMFAC air quality model or from the Bureau of Automotive Repair (BAR) Smog Check odometer records, and the average fleet fuel consumption converted to electricity. For a car traveling 12,000 miles per year that would equate to 4,150 kWh or 345 kWh per month.
[1] CPUC, “Affordability Phase 3 En Banc,” https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/affordability, February 28-March 1, 2022.
[2] Remaining electricity use after accounting for incremental consumption would be charged at the current otherwise applicable tariff (OAT).
[3] California Public Utilities Commission, Decision 96-08-025. Subsequent decisions have renewed and modified the economic development rate (EDR) for the utilities individually and collectively.
[4] D.05-06-016, creating the AG-ICE tariff for Pacific Gas & Electric and Southern California Edison.
[5] SCE, Schedules EDR-E, EDR-A and EDR-R.
[6] PG&E, Schedule AG-ICE—Agricultural Internal Combustion Engine Conversion Incentive Rate.
[7] EDR and AG-ICE were approved by the Commission in separate utility applications. The mobile home park utility system conversion program was first initiated by a Western Mobile Home Association petition by and then converted into a rulemaking, with significant revenue requirement implications.
[8] Excluding transmission and NBCs.
[9] Tiered rates pose a significant barrier to electrification and would cause the effective discount to be greater than estimated herein. The estimates above were based on measuring against the average electricity rate but added demand would be charged at the much higher Tier 2 rate. The decarb allowance could be introduced at a new Tier 0 below the current Tier 1.
[10] SCG, Rule No. 20 Gas Main Extensions, https://tariff.socalgas.com/regulatory/tariffs/tm2/pdf/20.pdf, retrieved March 2022.
[11] See https://www.energy.ca.gov/programs-and-topics/programs/building-energy-efficiency-standards;
https://www.energy.ca.gov/rules-and-regulations/building-energy-efficiency/manufacturer-certification-building-equipment;https://www.energy.ca.gov/rules-and-regulations/appliance-efficiency-regulations-title-20
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.
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.
A recent post at the Energy Institute at Haas proposed that all residential ratepayers should pay the “solar tax” in the recently withdrawn proposed decision from the California Public Utilities Commission through a connection fee. I agree that charging residential a connection charge is a reasonable solution. (All commercial and agricultural customers in California already pay such a charge.) The more important question though is what that connection fee should be?
Much less of the distribution costs are “fixed” than many proponents understand–we can see an example of the ability to avoid large undergrounding costs by installing microgrids as an example. Southern California Edison has repeatedly asked for a largely fixed “grid charge” for the last dozen years and the intervening ratepayer groups have shown that SCE’s estimate is much too high. A service connection costs about $10-$15/month, not more than $50 per month. So what might be the other elements of a fixed monthly charge rather than collecting these revenues through a volumetric rate as is done today?
A strong economic argument can be made that if the utility is collecting a fixed charge for upstream T&D capacity, then a customer should be able to trade that capacity that they have paid for with other customers. In the face of transaction costs, that market would devolve down to the per kWh price managed by the utility acting as a dealer–just what we have today.
Other candidates abound. How to recover stranded costs really requires a conversation about how much of those costs shareholders should shoulder. Income distributional public purpose costs should be collected from taxes, not rates. Energy efficiency is a resource that should be charged in the generation component, not distribution, and should be treated like other generation resources in cost recovery. The problem is that decoupling which was used to encourage energy efficiency investment has become a backdoor way to recover stranded costs without any conversation about whether that is appropriate–rates go up as demand decreases with little reduction in revenue requirements. So what the connection charge should be becomes quite complex.
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.
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.
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.
Last month the California Public Utilities Commission (CPUC) issued a decision in Phase II of the PG&E 2020 General Rate Case that endorsed all but one of my proposals on behalf of the Agricultural Energy Consumers Association (AECA) to better align revenue allocation with a rational approach to using marginal costs. Most importantly the CPUC agreed with my observation that the energy system is changing too rapidly to adopt a permanent set of rate setting principles as PG&E had advocated for. For now, we will continue to explore options as relationships among customers, utilities and other providers evolve.
At the heart of the matter is the economic principle that prices are set most efficiently when they adhere to the marginal cost or the cost of producing the last unit of a good or service. In a “standard” market, marginal costs are usually higher than the average cost so a producing firm generates a profit with each sale. For utilities, this is often not true–the average costs are higher than the marginal costs, so we need a means of allocating those additional costs to ensure that the utilities continue to be viable entities. California uses a “second-best” economic method called “Ramsey pricing” that applies relative marginal costs to serve different customers to allocate revenue responsibility.
I made four key proposals on how to apply marginal cost principles for rate setting purposes:
PG&E settled with AECA on the first to change its agricultural load forecasting methodology in upcoming proceedings. The CPUC agreed with AECA’s positions on two of the other three (RECs in the MEC, and MCAC). And on the third related to MGCC, the adopted position differed little materially.
The most surprising was the choice to use the RCNLD costs for existing customer connections. The debate over how to calculate the MCAC has raged for three decades. Industrial customers preferred valuing all connections, new and existing, at the cost of new connection using the “real economic carrying cost” (RECC) method. This is most consistent with a simple reading of marginal cost pricing principles. On the other side, residential customer advocates claimed that existing connections were sunk costs and have a value of zero for determining marginal, inventing the “new customer only” (NCO) method. I explained in my testimony that the RECC method fails to account for the reduced value of aging connections, but that those connections have value in the market place through house prices, just as a swimming pool or a bathroom remodel adds value. The diminished value of those connections can be approximated using the depreciation schedules that PG&E applies to determine its capital-related revenue requirements. The CPUC has used the RCNLD method to set the value for the sale of PG&E assets to municipal utilities.
The CPUC agreed with this approach which essentially is a compromise between the RECC and NCO method. The RCNLD acknowledges the fundamental points of both methods–that existing customer connections represent an opportunity value for customers but those connections do not have the same value as new ones.
Pacific Gas & Electric has proposed to underground 10,000 miles of distribution lines to reduce wildfire risk, at an estimated cost of $1.5 to $2 million per mile. Meanwhile PG&E has installed fast-trip circuit breakers in certain regions to mitigate fire risks from line shorts and breaks, but it has resulted in a vast increase in customer outages. CPUC President Batjer wrote in an October 25 letter to PG&E, “[s]ince PG&E initiated the Fast Trip setting practice on 11,500 miles of lines in High Fire Threat Districts in late July, it has caused over 500 unplanned power outages impacting over 560,000 customers.” She then ordered a series of compliance reports and steps. The question is whether undergrounding is the most cost-effective solution that can be implemented in a timely manner.
A viable alternative is microgrids, installed at either individual customers or community scale. The microgrids could be operated to island customers or communities during high risk periods or to provide backup when circuit breakers cut power. Customers could continue to be served outside of either those periods of risk or weather-caused outages.
Because microgrids would be installed solely for the purpose of displacing undergrounding, the relative costs should be compared without considering any other services such as energy delivered outside of periods of fire risk or outages or increased green power.
I previously analyzed this question, but this updated assessment uses new data and presents a threshold at which either undergrounding or microgrids is preferred depending on the range of relative costs.
We start with the estimates of undergrounding costs. Along with PG&E’s stated estimate, PG&E’s 2020 General Rate Case includes a settlement agreement with a cost of $4.8 million per mile. That leads to an estimate of $15 to $48 million. Adding in maintenance costs of about $400 million annually, this revenue requirement translates to a rate increase of 3.2 to 9.3 cents per kilowatt-hour.
For microgrid costs, the National Renewable Energy Laboratory published estimated ranges for both (1) commercial or community scale projects of 1 megawatt with 2.4 megawatt-hours of storage and (2) residential scale of 7 kilowatts with 20 kilowatt-hours of storage. For larger projects, NREL shows ranges of $2.07 to $2.13 million; we include an upper end estimate double of NREL’s top range. For residential; the range is $36,000 to $38,000.
Using this information, we can make comparisons based on the density of customers or energy use per mile of targeted distribution lines. In other words, we can determine if its more cost-effective to underground distribution lines or install microgrids based on how many customers or how much load is being served on a line.
As a benchmark, PG&E’s average system density per mile of distribution line is 50.6 customers and 166 kW (or 0.166 MW).
The table below shows the relative cost effectiveness for undergrounding compared to community/commercial microgrids. If the load density falls below the value shown, microgrids are more cost effective. Note that the average density across the PG&E service area is 0.166 MW which is below any of the thresholds. That indicates that such microgrids should be cost-effective in most rural areas.
The next table shows the relative cost effectiveness for individual residential microgrids, and again if the customer density falls below the threshold shown, then microgrids save more costs. The average density for service area is 51 customers per line-mile which reflects the concentration of population in the Bay Area. At the highest undergrounding costs, microgrids are almost universally favored. In rural areas where density falls below 30 customers per line-mile, microgrids are less costly at the lower undergrounding costs.
PG&E has installed two community-scale microgrids in remote locations so far, and reportedly considering 20 such projects. However, PG&E fell behind on those projects, prompting the CPUC to reopen its procurement process in its Emergency Reliability rulemaking. In addition, PG&E has relied heavily on natural gas generation for these.
PG&E simply may not have the capacity to construct either microgrids or install undergrounded lines in a timely manner solely through its organization. PG&E already is struggling to meet its targets for converting privately-owned mobilehome park utility systems to utility ownership. A likely better choice is to rely on local governments working in partnership with PG&E to identify the most vulnerable lines to construct and manage these microgrids. The residential microgrids would be operated remotely. The community microgrids could be run under several different models including either PG&E or municipal ownership.
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