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.
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Just as I was posting this, our power went out in strong winds. Local outages are an at least annual event, with at least three lasting for a day or more. In contrast, I’ve experienced one G&T outage in August 1996. While anecdotal, this is consistent with the data.