The local grid, utilities and DERs

I’ve written before about my local electrical cooperative’s approach to solar energy. Today I got the coop’s annual report in the mail and the announcement for their annual meeting in a couple of weeks. Since I’m nominally a stakeholder (although technically a cooperative, Beltrami Electric is a member of Touchstone Energy, a Virginia-based federation of about 750 local energy utilities that in some ways seems more like a corporation than like a coop—but that’s a story for another day), I’ll probably attend. The annual report includes an advertisement for their “Northern Solar” project, which is coming soon. It consists of an 80-kW DC community solar array. You can “buy” the output of the 180 450 kWh/yr panels in amounts ranging from half a panel to your total annual usage. Or you can subscribe to receive your power from the array when it is completed, and pay an extra fee of about 5¢ per kilowatt hour each month to get solar electricity.


While I guess it’s a good first step, I have a couple of issues with the plan. First, is the utility actually going to sell only the array’s actual production? How many customers can the array accommodate? Will the utility turn away customers willing to pay a higher price (50% higher than the regular rate) for their electricity, given there will be absolutely no way for the customer to tell what “flavor” of electricity is actually being delivered to them? What’s the fallback plan if the utility has X number of subscribers but it’s cloudy all month and not a lot of power is produced? Who gets the solar power in that scenario, and who gets dropped down to the standard (but lower-cost) electricity? Or if solar output is jus a fraction of what’s expected in a given month, do all customers just end up buying more “regular” power at the lower rate?

This scheme is so full of potential problems I’m surprised the utility prefers it to net metering household rooftop solar. The coop’s objection to net metering a couple of years ago was that if some customers used rooftop solar panels or windmills to lower their metered usage, it would transfer the “fixed costs” of the system to the rest of the users. According to the utility’s Energy Services and Facilities Manager,

historically electrical service has been sold based on the volume of electricity one uses, most do not understand that much of the cost is actually for the operation and capital expense of the delivery, transmission and generation systems, which must be constructed to meet the consumers combined peak usage period. The actual variable expense to produce a given volume of kWh over a period of time is a small portion of the total cost, basically it is fuel cost. 

This seems like an accounting issue to me. What he’s basically saying is that the price of a kilowatt hour of electricity is based on two things, the (fuel) cost of the energy and the cost of the infrastructure needed to get it to you—but they lump those two costs into one and don’t want to consider them separately. Seems to me it would be pretty simple to figure out the cost of the infrastructure and charge everybody connected to the grid an equal portion, and then bill customers for the actual energy they use. That way, even somebody who was producing 100% or more of their monthly needs could still be billed an access charge that covered their “share” of the infrastructure as long as they chose to stay attached to the grid. That seems like it would be fair to everybody. And not impossible to do—according to the annual report, 70% of the coop’s operating revenue was spent on “Cost of Power” and 8.1% on “Maintenance and Operations.”

In order to try to understand this from the utility’s point of view (and understand what might motivate them to embrace change), I read a white paper today, published by Tesla subsidiary SolarCity’s Grid Engineering division, called “A Pathway to the Distributed Grid.” The paper said that estimates for the investment needed to modernize the U.S. grid between 2010 and 2030 exceed $1.5 trillion. SolarCity’s pitch is that distributed energy resources (DERs) are essential to creating a 21st century grid—not just because customers want them, but because they’ll make the system more robust and resilient, and a lot less expensive.


Using data from Pacific Gas and Electric’s (PG&E) 2017 General Rate Case filing and standard economic models from the California Public Utilities Commission, the paper produced a benefit-cost analysis that estimated net societal benefits to California of more than $1.4 billion by 2020 from implementing the DERs (basically rooftop solar with batteries and smart inverters) projected to be deployed between 2016 and 2020. While California’s savings was admittedly higher due to the high cost of kilowatt hours there, the study suggests savings could be achieved anywhere by implementing DERs.

The benefits came in two flavors: direct savings from power generated by the DERs, and reduced or avoided costs from lower transmission requirements on the system. Higher usage, especially at peak-load periods, increases the marginal cost of power by using higher-cost generation or buying power on the market. And higher usage drives infrastructure investment and wears out equipment faster (transformers and transmission lines operating near the top of or above their specs are less efficient and wear out years sooner). The study concluded that “DERs reduce the net load at individual customer premises. A portfolio of optimized DERs dispersed across a distribution circuit in turn reduces the net load for all equipment along that distribution circuit. Distribution equipment, such as substation transformers, operating at reduced loading will benefit from increased equipment life and higher operational efficiency.”


The problem, the paper suggests, is that a series of perverse incentives encourages utilities to avoid DERs. A perverse incentive occurs when a decision-maker is rewarded for taking an action that is not in the customer’s interest (or oftentimes even her own) because of economic rules designed long ago to meet conditions that no longer apply. Specifically, most electric utilities are regulated under a “cost plus” pricing model, which “compensates utilities with an authorized rate of return [in the form of the rates they are allowed to charge] on prudent capital investments made to provide electricity services.” The fact that rooftop solar, batteries, and smart inverters are not owned by the utility is the problem, because the regulatory model gives utilities a “fundamental incentive…to build more utility-owned infrastructure in order to profit more” by boosting their rates. This incentive “conflicts with the public interest as the grid becomes more customer-centric and distributed.” Utilities expand their infrastructure investments because that allows them to charge more—California’s rate base has doubled in the last decade while consumption of electricity has been flat.


So you can hardly blame the utilities from fighting DERs. They think DERs are going to have a negative effect on load levels during sunlight hours and then add nothing during peak usage hours in the evening. But even if they could be convinced that battery storage and smart inverters offered a legitimate value-add, they are still incented against DERs based on outdated regulations. The challenge is to convince utilities and their regulators to move to a new paradigm where they are well-compensated for doing what society actually needs them to do. That’s not unlike the idea I mentioned earlier, of splitting the cost of energy into an infrastructure part and a power-generation part. Tomorrow I’ll read the coop’s financial statement in the annual report more closely and in a couple of weeks I’ll attend the annual meeting; maybe something will occur to me.