Tag Archives: net energy metering

What rooftop solar owners understand isn’t mythological

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Severin Borenstein wrote another blog attacking rooftop solar (a pet peeve of his at least a decade because these weren’t being installed in “optimal” locations in the state) entitled “Myths that Solar Owners Tell Themselves.” Unfortunately he set up a number of “strawman” arguments that really have little to do with the actual issues being debated right now at the CPUC. Here’s responses to each his “myths”:

Myth #1 – Customers are paid only 4 cents per kWh for exports: He’s right in part, but then he ignores the fact that almost all of the power sent out from rooftop panels are used by their neighbors and never gets to the main part of the grid. The utility is redirecting the power down the block.

Myth #2 – The utility sells the power purchased at retail back to other customers at retail so the net so it’s a wash: Borenstein’s claim ignores the fact that when the NEM program began the utilities were buying power that cost more than the retail rate at the time. During NEM 1.0 the IOUs were paying in excess of 10c/kwh for renewable power (RPS) power purchase agreements (PPAs). Add the 4c/kWh for transmission and that’s more than the average rate of 13c/kWh that prevailed during that time. NEM 2.0 added a correction for TOU pricing (that PG&E muffled by including only the marginal generation cost difference by TOU rather than scaling) and that adjusted the price some. But those NEM customers signed up not knowing what the future retail price would be. That’s the downside of failing to provide a fixed price contract tariff option for solar customers back then. So now the IOUs are bearing the consequences of yet another bad management decision because they were in denial about what was coming.

Myth #3 – Rooftop solar is about disrupting the industry: Here Borenstein appears to be unaware of the Market Street Railway case that states that utilities are not protected from technological change. Protecting companies from the consequences of market forces is corporate socialism. If we’re going to protect shareholders from risk (and its even 100% protection), then the grid should be publicly owned instead. Sam Insull set up the regulatory scam a century ago arguing that income assurance was needed for grid investment, and when the whole scheme collapsed in the Depression, the Public Utility Holding Company Act of 1935 (PUHCA)was passed. Shareholders need to pick their poison—either be exposed to risk or transfer their assets public ownership, but wealthy shareholders should not be protected.

Myth #3A – Utilities made bad investments and should bear the risks: Borenstein is arguing since the utilities have run the con for the last decade and gotten approval from the CPUC, they should be protected. Yet I submitted testimony repeatedly starting in 2010 both PG&E’s and SCE’s GRCs that warned that they had overforecasted load growth. I was correct—statewide retail sales are about the same today as they were in 2006. Grid investment would have been much different if those companies had listened and corrected their forecasts. Further the IOUs know how to manipulate their regulatory filings to ensure that they still get their internally targeted income. Decoupling that ensures that the utility receives its guaranteed income regardless of sales further shields them. From 1994 to 2017, PG&E hit its average allowed rate of return within 0.1%. (More on this later.) A UCB economics graduate student found that the return on equity is up to 4% too high (consistent with analysis I’ve done).

Myth #3B – Time to take away the utility’s monopoly: No, we no longer need to have monopoly electric service. The same was said about telecommunications three decades ago. Now we have multiple entities vying for our dollars. The CPUC conducted a study in 1999 that was included in PG&E’s GRC proposed decision (thanks to the late Richard Bilas) that showed that economies of scale disappeared after several hundred thousand customers (and that threshold is likely lower now.) And microgrids are becoming cost effective, especially as PG&E’s rates look like they will surpass 30 cents per kWh by 2026.

Myth #4 – There aren’t barriers to the poor putting panels on their roofs: First, the barriers are largely regulatory, not financial. The CPUC has erected them to prevent aggregation of low-income customers to be able to buy into larger projects that serve these communities.

Second, there are many market mechanisms today where those with lower income are offered products or services at a higher long term price in return for low or no upfront costs. Are we also going to heavily tax car purchases because car leasing is effectively more expensive? What about house ownership vs. rentals? There are issues to address with equity, but to zero in on one small example while ignoring the much wider prevalence sets  up another strawman argument.

Further, there are better ways to address the inequity in rooftop solar distribution. That inequity isn’t occurring duo to affordability but rather because of split incentives between landlords and tenants.

A much easier and more direct fix would be to modify Public Utilities Code Sections 218 to allow local sales among customers or by landlords or homeowner associations to tenants and 739.5 to allow more flexibility in pricing those sales. But allowing those changes will require that the utilities give up iron-fisted control of electricity production.

Myth #5 – Rooftop solar is the only thing that makes it cost-effective to electrify: Borenstein focuses on the what source of high rates. Rooftop solar might be raising rates, but it probably delivered as much in offsetting savings. At most those customers increased rates by 10%, but utility rates are 70-100% above the direct marginal costs of service. The sources of that difference are manifest. PG&E has filed in its 2023 GRC a projected increase in the average standard residential rate to 38 cents per kWh by 2026, and perhaps over 40 cents once undergrounding to mitigate wildfire is included. The NREL studies on microgrids show that individual home microgrids cost about 34 cents per kWh now and battery storage prices are still dropping. Exiting the grid starts to look a lot more attractive.

Maybe if we look only at the status quo as unchanging and accept all of the utilities’ claims about their “necessary” management decisions and the return required to attract investors, then these arguments might hold water. But none of these factors are true based on the empirical work presented in many forums including at the CPUC over the last decade. These beliefs are not so mythological.

Finally, Borenstein finishes with “(a)nd we all need to be open to changing our minds as a result of changing technology and new data.” Yet he has been particularly unyielding on this issue for years, and has not reexamined his own work on electricity markets from two decades ago. The meeting of open minds requires a two-way street.

Guidelines For Better Net Metering; Protecting All Electricity Customers And The Climate

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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.

https://cacurrent.com/guest-juice-reforming-how-californias-utilities-charge-for-electricity-and-recover-costs-to-make-environmental-gains/

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.

Transmission: the hidden cost of generation

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The cost of transmission for new generation has become a more salient issue. The CAISO found that distributed generation (DG) had displaced $2.6 billion in transmission investment by 2018. The value of displacing transmission requirements can be determined from the utilities’ filings with FERC and the accounting for new power plant capacity. Using similar methodologies for calculating this cost in California and Kentucky, the incremental cost in both independent system operators (ISO) is $37 per megawatt-hour or 3.7 cents per kilowatt-hour in both areas. This added cost about doubles the cost of utility-scale renewables compared to distributed generation.

When solar rooftop displaces utility generation, particularly during peak load periods, it also displaces the associated transmission that interconnects the plant and transmits that power to the local grid. And because power plants compete with each other for space on the transmission grid, the reduction in bulk power generation opens up that grid to send power from other plants to other customers.

The incremental cost of new transmission is determined by the installation of new generation capacity as transmission delivers power to substations before it is then distributed to customers. This incremental cost represents the long-term value of displaced transmission. This amount should be used to calculate the net benefits for net energy metered (NEM) customers who avoid the need for additional transmission investment by providing local resources rather than remote bulk generation when setting rates for rooftop solar in the NEM tariff.

  • In California, transmission investment additions were collected from the FERC Form 1 filings for 2017 to 2020 for PG&E, SCE and SDG&E. The Wholesale Base Total Revenue Requirements submitted to FERC were collected for the three utilities for the same period. The average fixed charge rate for the Wholesale Base Total Revenue Requirements was 12.1% over that year. That fixed charge rate is applied to the average of the transmission additions to determine the average incremental revenue requirements for new transmission for the period. The plant capacity installed in California for 2017 to 2020 is calculated from the California Energy Commission’s “Annual Generation – Plant Unit”. (This metric is conservative because (1) it includes the entire state while CAISO serves only 80% of the state’s load and the three utilities serve a subset of that, and (2) the list of “new” plants includes a number of repowered natural gas plants at sites with already existing transmission. A more refined analysis would find an even higher incremental transmission cost.)

Based on this analysis, the appropriate marginal transmission cost is $171.17 per kilowatt-year. Applying the average CAISO load factor of 52%, the marginal cost equals $37.54 per megawatt-hour.

  • In Kentucky, Kentucky Power is owned by American Electric Power (AEP) which operates in the PJM ISO. PJM has a market in financial transmission rights (FTR) that values relieving the congestion on the grid in the short term. AEP files network service rates each year with PJM and FERC. The rate more than doubled over 2018 to 2021 at average annual increase of 26%.

Based on the addition of 22,907 megawatts of generation capacity in PJM over that period, the incremental cost of transmission was $196 per kilowatt-year or nearly four times the current AEP transmission rate. This equates to about $37 per megawatt-hour (or 3.7 cents per kilowatt-hour).

Can Net Metering Reform Fix the Rooftop Solar Cost Shift?: A Response

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A response to Severin Borenstein’s post at UC Energy Institute where he posits a large subsidy flowing to NEM customers and proposes an income-based fixed charge as the remedy. Borenstein made the same proposal at a later CPUC hearing.

The CPUC is now considering reforming the current net energy metering (NEM) tariffs in the NEM 3.0 proceeding. And the State Legislature is considering imposing a change by fiat in AB 1139.

First, to frame this discussion, economists are universally guilty of status quo bias in which we (since I’m one) too often assume that changing from the current physical and institutional arrangement is a “cost” in an implicit assumption that the current situation was somehow arrived at via a relatively benign economic process. (The debate over reparations for slavery revolve around this issue.) The same is true for those who claim that NEM customers are imposing exorbitant costs on other customers.

There are several issues to be considered in this analysis.

1) In looking at the history of the NEM rate, the emergence of a misalignment between retail rates that compensate solar customers and the true marginal costs of providing service (which are much more than the hourly wholesales price–more on that later) is a recent event. When NEM 1.0 was established residential rates were on the order of 15 c/kWh and renewable power contracts were being signed at 12 to 15 c/kWh. In addition, the transmission costs were adding 2 to 4 c/kWh. This was the case through 2015; NEM 1.0 expired in 2016. NEM 2.0 customers were put on TOU rates with evening peak loads, so their daytime output is being priced at off peak rates midday and they are paying higher on peak rates for usage. This despite the fact that the difference in “marginal costs” between peak and off wholesale costs are generally on the order of a penny per kWh. (PG&E NEM customers also pay a $10/month fixed charge that is close to the service connection cost.) Calculating the net financial flows is more complicated and deserve that complex look than what can be captured in a simple back of the envelope calculation.

2) If we’re going to dig into subsidies, the first place to start is with utility and power plant shareholders. If we use the current set of “market price benchmarks” (which are problematic as I’ll discuss), out of PG&E’s $5.2 billion annual generation costs, over $2 billion or 40% are “stranded costs” that are subsidies to shareholders for bad investments. In an efficient marketplace those shareholders would have to recover those costs through competitively set prices, as Jim Lazar of the Regulatory Assistance Project has pointed out. One might counter those long term contracts were signed on behalf of these customers who now must pay for them. Of course, overlooking whether those contracts were really properly evaluated, that’s also true for customers who have taken energy efficiency measures and Elon Musk as he moves to Texas–we aren’t discussing whether they also deserve a surcharge to cover these costs. But beyond this, on an equity basis, NEM 1.0 customers at least made investments based on an expectation, that the CPUC did not dissuade them of this belief (we have documentation of how at least one county government was mislead by PG&E on this issue in 2016). If IOUs are entitled to financial protection (and the CPUC has failed to enact the portfolio management incentive specified in AB57 in 2002) then so are those NEM customers. If on the other hand we can reopen cost recovery of those poor portfolio management decisions that have led to the incentive for retail customers to try to exit, THEN we can revisit those NEM investments. But until then, those NEM customers are no more subsidized than the shareholders.

3) What is the true “marginal cost”? First we have the problem of temporal consistency between generation vs. transmission and distribution grid (T&D) costs. Economists love looking at generation because there’s a hourly (or subhourly) “short run” price that coincides nicely with economic theory and calculus. On the other hand, those darn T&D costs are lumpy and discontinuous. The “hourly” cost for T&D is basically zero and the annual cost is not a whole lot better. The current methods debated in the General Rate Cases (GRC) relies on aggregating piecemeal investments without looking at changing costs as a whole. Probably the most appropriate metric for T&D is to calculate the incremental change in total costs by the number of new customers. Given how fast utility rates have been rising over the last decade I’m pretty sure that the “marginal cost” per customer is higher than the average cost–in fact by definition marginal costs must be higher. (And with static and falling loads, I’m not even sure how we calculated the marginal costs per kwh. We can derive the marginal cost this way FERC Form 1 data.) So how do we meld one marginal cost that might be on a 5-minute basis with one that is on a multi-year timeframe? This isn’t an easy answer and “rough justice” can cut either way on what’s the truly appropriate approximation.

4) Even if the generation cost is measured sub hourly, the current wholesale markets are poor reflections of those costs. Significant market distortions prevent fully reflecting those costs. Unit commitment costs are often subsidized through out of market payments; reliability regulation forces investment that pushes capacity costs out of the hourly market, added incremental resources–whether for added load such as electrification or to meet regulatory requirements–are largely zero-operating cost renewables of which none rely on hourly market revenues for financial solvency; in California generators face little or no bankruptcy risk which allows them to underprice their bids; on the flip side, capacity price adders such as ERCOT’s ORDC overprices the value of reliability to customers as a backdoor way to allow generators to recover investments through the hourly market. So what is the true marginal cost of generation? Pulling down CAISO prices doesn’t look like a good primary source of data.

We’re left with the question of what is the appropriate benchmark for measuring a “subsidy”? Should we also include the other subsidies that created the problem in the first place?

AB1139 would undermine California’s efforts on climate change

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Assembly Bill 1139 is offered as a supposed solution to unaffordable electricity rates for Californians. Unfortunately, the bill would undermine the state’s efforts to reduce greenhouse gas emissions by crippling several key initiatives that rely on wider deployment of rooftop solar and other distributed energy resources.

  • It will make complying with the Title 24 building code requiring solar panel on new houses prohibitively expensive. The new code pushes new houses to net zero electricity usage. AB 1139 would create a conflict with existing state laws and regulations.
  • The state’s initiative to increase housing and improve affordability will be dealt a blow if new homeowners have to pay for panels that won’t save them money.
  • It will make transportation electrification and the Governor’s executive order aiming for 100% new EVs by 2035 much more expensive because it will make it much less economic to use EVs for grid charging and will reduce the amount of direct solar panel charging.
  • Rooftop solar was installed as a long-term resource based on a contractual commitment by the utilities to maintain pricing terms for at least the life of the panels. Undermining that investment will undermine the incentive for consumers to participate in any state-directed conservation program to reduce energy or water use.

If the State Legislature wants to reduce ratepayer costs by revising contractual agreements, the more direct solution is to direct renegotiation of RPS PPAs. For PG&E, these contracts represent more than $1 billion a year in excess costs, which dwarfs any of the actual, if any, subsidies to NEM customers. The fact is that solar rooftops displaced the very expensive renewables that the IOUs signed, and probably led to a cancellation of auctions around 2015 that would have just further encumbered us.

The bill would force net energy metered (NEM) customers to pay twice for their power, once for the solar panels and again for the poor portfolio management decisions by the utilities. The utilities claim that $3 billion is being transferred from customers without solar to NEM customers. In SDG&E’s service territory, the claim is that the subsidy costs other ratepayers $230 per year, which translates to $1,438 per year for each NEM customer. But based on an average usage of 500 kWh per month, that implies each NEM customer is receiving a subsidy of $0.24/kWh compared to an average rate of $0.27 per kWh. In simple terms, SDG&E is claiming that rooftop solar saves almost nothing in avoided energy purchases and system investment. This contrasts with the presumption that energy efficiency improvements save utilities in avoided energy purchases and system investments. The math only works if one agrees with the utilities’ premise that they are entitled to sell power to serve an entire customer’s demand–in other words, solar rooftops shouldn’t exist.

Finally, this initiative would squash a key motivator that has driven enthusiasm in the public for growing environmental awareness. The message from the state would be that we can only rely on corporate America to solve our climate problems and that we can no longer take individual responsibility. That may be the biggest threat to achieving our climate management goals.