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
California is concerned that entities that emit greenhouse gases (GHG) have accrued a too-large bank of allowances through the Air Resources Board (CARB) cap-and-trade program (CATP.) The excess is estimated at 321 million allowances (one allowance equals one metric tonne of carbon dioxide equivalent (CO2e) emissions). This is more an a year’s worth of allowances. About half of these were issued for free to eligible energy utilities and energy-intensive trade-exposed (EITE) companies.
The state could consider purchasing back a certain portion to reduce the backlog and increase the market price so as to further encourage reductions in GHG emissions by retiring those allowances. Prices in the last allowance auction ranged from $28 to $34 per allowance/tonne. If California bought back half or 160 million allowances at those prices, it would cost $4.5 to $5.5 billion. That would create effectively a reduction of 160 million tonnes in future GHG emissions.
That should be compared to the various benchmarks for the benefits and costs of reducing GHG emissions. The currently accepted social cost of GHG emissions developed by the U.S. Environmental Protection Agency (US EPA) is ranges from $50 to $150 per tonne in 2030 (and recent studies have estimated that this is too low.) That would create a net social benefit from $2.5 to $19.6 billion.
CARB’s AB 32 Scoping Plan update estimates the average cost of reductions without the CATP to be $70 per tonne in 2030. The incremental avoided costs of the CATP are estimated at $220 per tonne. The net avoided costs on this basis would range from $5.7 to $30.4 billion.
PG&E made exciting announcements about partnerships with GM and Ford 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:
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 several isolated microgrids 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 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.
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