Deciding if solar installation is suboptimal requires that the initial premises be specified correctly

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A recent article “Heterogeneous Solar Capacity Benefits, Appropriability, and the Costs of Suboptimal Siting” in the Journal of the Association of Environmental and Resource Economists finds that distributed solar (e.g., rooftop solar) is not being installed a manner that “optimally” mitigates air pollution damages from electricity generation across the U.S. Unfortunately the paper is built on two premises that do not reflect the reality of available options and appropriate pricing signals.

First, the authors appear to be relying on the premise that sufficient solar, grid-scale or distributed, can be installed cost-effectively across the U.S. While the paper includes geographic variations in generation per installed kilowatt of capacity, it says nothing about the similarly widely varying costs per kilowatt-hour. They do not acknowledge that panels in the Pacific Northwest will cost twice that of those in the Desert Southwest. This importance of this disparity is compounded by the underestimate of the social cost of carbon and the possible conflation of sulfur dioxide and particulate matter damages. 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is ranges from $50 to $150 per tonne in 2030 (and recent studies have estimated that this is too low), compared to the outdated $41 per tonne in the article. Most of the SO2 damages arise from creating PM so there is likely double counting for these criteria pollutants. (The study also ignore the strong correlation between GHG and SO2 emissions as coal is the biggest source of both.) The study also fails to account for the enormous transmission costs that would be incurred moving solar output from the Desert Southwest to the Northeast to mitigate the purported damages.

Second, the authors try to claim that rooftop solar has not relieved transmission congestion by looking at grid congestion prices. The problem is that this method is like looking at an empty barn and saying a horse never lived there. Congestion pricing is based on the current transmission capacity situation. It says nothing about the history of transmission congestion or the ability and efforts to look forward to mitigate congestion. The study found that congestion prices were often negative or small in areas with substantial rooftop solar capacity. That doesn’t show that the solar capacity has little value–instead it shows that it actually relieved the congestion effectively–a completely opposite conclusion.

In contrast, the California Independent System Operator (CAISO) calculated in 2017 (contemporaneously with the article’s baseline) that at least $2.6 billion in transmission projects had been deferred. And given the utilities’ poor records on load forecasting, these savings have likely grown substantially. CAISO had anticipated and already relieved the congestion that the authors’ purported metric was searching for.

This disparity in economic results highlights the nature of investing in long-lived infrastructure that requires multiple years to build–one cannot wait for a shortfall to emerge to respond because that’s too late. Instead, one must anticipate those events and act even when its uncertain. This study is yet another example of how relying on the premise that short-run electricity market prices are reflective of long-run marginal costs is mistaken and should be set aside for policy analysis.

PG&E takes a bold step on enabling EV back up power, but questions remain

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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:

  • 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?

Are PG&E’s customers about to walk?

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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.

A cheaper wildfire mitigation solution: using microgrids instead of undergrounding

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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.)

Why utility prices cannot be set using short-run marginal costs

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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.

What is the real threat to electrification? Not solar rooftops

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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.

Has rooftop solar cost California ratepayers more than the alternatives?

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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.

Are fixed charges the solution to the solar rooftop dilemma?

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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.

Understanding core facts before moving forward with NEM reform

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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 distribution system 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.

A misguided perspective on California’s rooftop solar policy

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Severin Borenstein at the Energy Institute at Haas has taken another shot at solar rooftop net energy metering (NEM). He has been a continual critic of California’s energy decentralization policies such as those on distribution energy resources (DER) and community choice aggregators (CCAs). And his viewpoints have been influential at the California Public Utilities Commission.

I read these two statements in his blog post and come to a very different conclusions:

“(I)ndividuals and businesses make investments in response to those policies, and many come to believe that they have a right to see those policies continue indefinitely.”

Yes, the investor owned utilities and certain large scale renewable firms have come to believe that they have a right to see their subsidies continue indefinitely. California utilities are receiving subsidies amounting to $5 billion a year due to poor generation portfolio management. You can see this in your bill with the PCIA. This dwarfs the purported subsidy from rooftop solar. Why no call for reforming how we recover these costs from ratepayers and force shareholder to carry their burden? (And I’m not even bringing up the other big source of rate increases in excessive transmission and distribution investment.)

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.

Along with the effort to kill CCAs, the apparent proposed solution is to concentrate all power procurement into the hands of three large utilities who haven’t demonstrated a particularly adroit ability at managing their portfolios. Why should we put all of our eggs into one (or three) baskets?

Borenstein continues to rely on an incorrect construct for cost savings created by rooftop solar that relies on short-run hourly wholesale market prices instead of the long-term costs of constructing new power plants, transmission rates derived from average embedded costs instead of full incremental costs and an assumption that distribution investment is not avoided by DER contrary to the methods used in the utilities’ own rate filings. He also appears to ignore the benefits of co-locating generation and storage locally–a set up that becomes much less financially viable if a customer adds storage but is still connected to the grid.

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.