Grid Pro Quo: Valuing Customer Solar on Utility Systems

A panel of experts at the Solar Washington Summit in October discussed how utilities value solar on their systems and the impact of utilities reaching their 4% net metering threshold. They also discussed compliance requirements such as resource adequacy and clean energy.

Donna Gerardi, Washington State Academy of Science 

To open the discussion, Donna Gerardi from the Washington State Academy of Science said that in 2024 the legislature requested the Academy to conduct a study to determine the value of distributed storage and engage the community. They were also asked to produce an internal report, which they released on June 30 and which is on the Academy website.

The Academy created an oversight committee of experienced members, scientists and engineers for the study, which was conducted between February and May 2025.

Interviewees were all interested in having their communities assist in meeting growing electricity demand, advancing Washington State's clean energy goals, meeting CETA goals, and enhancing community resilience and climate adaptation. Interviewees also mentioned improving grid reliability, managing peak load, ensuring equitable and fair compensation, promoting local economic development and expanding renewable energy access.

In 2025, the legislature asked the Academy to use the results to develop policy recommendations and options for utility regulators and governing bodies to use after the statutory 4%. (Note: Cumulative generating capacity available to net metering systems in utilities’ service territories is achieved when the cumulative generating capacity of net metering systems reaches 4% of the utility’s peak demand. Utilities that reach that level before June 30, 2029 have the option of developing a standard rate or tariff schedule that deviates from the net metering requirements of Washington State law RCW 80.60.030.). They will be submitting the final report by October 1, 2026. 

The committee will create examples and develop an approach that can compare equity impacts of different mechanisms. The committee will also create a toolkit for working through various scenario and a manual.

Panelist Introductions and Utility Status

Following that opening, moderator and Solar Washington board member Dever Haffner-Ratliffe asked the other utility panelists to introduce themselves. 

Greg Mendonca is the general manager at Okanagan County Electric Co-op, located in the Methow Valley. They are over the 4% cap.

John Rothlin is the manager of government relations for Avista Corporation, an investor-owned utility headquartered in Spokane. Its Washington service territory is the Inland Empire. Avista also has an electric service in northern Idaho, electric assets in Montana, and a small electric utility in Alaska. In Washington, Avista is about two thirds of the way to the 4% cap.

Suzy Oversvee is a program manager in the energy services department at Snohomish County PUD (SnoPUD). Its service territory is on Hamish County and Camino Island. It has about 330,000 customers and is the second largest public utility in the state. 

Matt Boast is the general manager of Kittitas PUD, which is in the center of the state and is one of three utilities in that county. Kittitas PUD has exceeded the net meter cap, and it was the first to deviate from net metering rates. Kittitas PUD has about 5,200 customers.

Dever said the only utility type not represented is a municipality, such as Seattle City Light or Tacoma Power.

Rationale for Rate Changes

Dever asked Matt to talk about why Kittitas PUD decided to change its rates when it hit the 4% cap. 

Matt explained that they didn't want to be the utility of “No”. “In our county, farmers and renters want sustainable business. They want to reduce their costs. They want to be able to produce energy on their own. The utility rate structure also needs to be sustainable. We could see that if we continued net metering and if solar continued to deploy fast, there was going to be a cost shift from people who could afford these systems to those who could not. By creating the wholesale rate, we make solar on par with our other resources. We're already between 93% and 96% clean.”

Greg added that, similar to Matt, the Co-op exceeded its cap. “We're member-owned. We're not for profit. Every dollar we make in margin, we give back to the members. Our board has seven elected members. They knew that if we said no, there'd be a lot of upset members. We haven't done a solar specific rate. We're on a path over the next three years to implement a residential demand charge, addressing our distribution costs. We do see an impact on existing net meter investments. It is different for folks putting solar on their rooftops now.”

Avista, as an investor of a utility, is regulated in a much different fashion, John explained. It is regulated by the Utilities and Transportation Commission in Washington, and by the Public Utilities Commission in Idaho. “When we seek to move to a different compensation structure, we will have to make the case before the commissions. In Idaho, we've not changed net metering. It's conceivable we have a different compensation model for Washington as we do for Idaho customers.”

Another utility said it is a ways out from the cap. Just because they get there doesn't mean they will switch on a dime. They don't want to pay customers. No decisions have been made.

Asked about why SnoPUD offered rebates for solar proactively, Suzy said that SnoPUD had leadership at the time that was interested in spurring the industry and recognized that it wasn't going to grow quickly. 

Impacts of Requirements

Dever noted that there are requirements, such as CETA, the Climate Commitment Act (CCA) and resource adequacy (RA). She asked how customer-owned solar plays into these policies.

One panelist said that CETA, for example, requires the utility to procure and use an amount of renewable or non-emitting energy equal to its load. It doesn’t see customer solar as a complying resource. They would need to omit resources or buy allowances or use emitting resources to meet resource adequacy. An E3 study shows that rooftop solar has about a 13% effective capacity in achieving resource adequacy during winter peaks. Other resources contribute more to meeting their resource requirements.

Another panelist said “we’re very concerned about RA. Our service territory is about 28 megawatts, we average about eight across the year, we are negative 20. That happens when it's dark. We do have significant solar in our system. It does provide a great example for us. We're not really able to meet our extreme times, 7am to 9 am.”

Another said things have changed for them in the past year. As of October 1, they switched BPA products. They were previously a block slice, market-facing customer. During extreme weather events, they spent a huge amount to secure energy to avoid rolling blackouts. Their new BPA product is called load following. They no longer need to be as concerned about daily peaks, as BPA is taking that risk away. They have a higher demand charge, which is changing how they look at programs. With CETA and EIA, they also have compliance requirements and need RECs. Now that they've shifted, it was advantageous to sell some resources, so they don't have a REC bank that they previously had. Also, SB 5445 is significant because it adds a way to quantify RECs through demand response. 

Another utility that used to go through a solar incentive program is starting to look at ways to partner with customers to leverage SB 5445 and other mechanisms to help with compliance requirements.

Utilities were required to create a clean energy implementation plan every four years, one person noted. A lot of utilities are looking at what types of energy resources they want to use to help meet CET as well as renewables management and energy efficiency. They also have to show they’re engaging customers to get their feedback.

Another panelist said they have been getting out into the community around their Integrated Resource Plan. The Plan has gotten a lot of responses about solar.

Another said they have good penetration of solar already and exceed the net metering requirements. “We really have been spoiled by hydro. But we're not going to conserve our way out of the future. We have to be creative in finding more resources.”  

Avista also has a lot of legacy hydro, John said. “We used to be known as Washington Water Power. We had several hydro-electric projects. It’s definitely a recognition of the value that hydro provides in our IRP. We have about 11 megawatts of distributed solar in our preferred resource strategy, and then in the out years about 300 megawatts of solar. The Clean Energy Transformation Act singles out solar as one of the tools that we can use to reduce the burdens and distribute equitable benefits of renewable energy and the clean energy transition.”

Solar and Revenue

Dever said some people assume that utilities are hesitant to encourage customers putting solar on the grid because it potentially causes a revenue loss. She asked panelists for their views. 

One person said there is an assumption that investors expect a return on their investment, so investor-owned utilities don't care for solar because it means reduced sales and reduced profits. The reality is that investor-owned utilities have moved to a rate structure called decoupling, which means they make money on a per-customer basis. They’re incentivized to do things like energy efficiency, which is the reason they want customers who want to produce their own energy even though it may mean diminished sales.

One said they use a cost-of-service study to address rate-making. They look at each type of customer - residential, irrigation, commercial, industrial - and at the costs for serving them. The rates should recover the cost to serve each individual customer. 

Another utility is in the middle of an AMI meter changeout project, which will deliver a lot of data. Small utilities like them read their meters once a month and don't have the data to tell when some areas are a problem. They’re getting new technology to be able to read the meters hourly, have demand and voltage information at each point of delivery and make good decisions.

Another had to shift from variable billing like kilowatt hours to fixed because they weren't able to capture or recover the cost for that classic customer, who was zeroing themselves out of the system. They had to increase their fixed charges.

Cost Shifts

Dever noted that as solar penetration increases, costs are going up. That cost shift is significant and it will vary amongst utilities. She asked how factors such as density and customers per mile impact how they manage infrastructure and rates.

One panelist said they often get compared locally to the municipal utility that's right next door. That municipal has more than 100 customers per mile of line. This utility has nine square miles and maintains 720 miles of line, with six customers per mile. 

Another said utilities should clear up how they talk about this cost shift. If the six customers per mile become net meter customers, the adjacent six-mile customers have to pay for the cost of those two miles. And if those six customers in that second mile are low income or fixed income or a vulnerable population, their rates go up. Customers will see some of these demand costs, because utilities need to be fair about how they’re allocating costs to each type of customer.

The Future of Charges and Net Metering 

Dever asked whether panelists are looking at increasing demand charges, and what the next phase is for utilities.

One person said utilities will have to be flexible and think outside of the box. If customers have cars that have batteries that can support their house, for example, utilities will have to come up with rate structures.

Another person observed that they've chosen to embed most of the costs of serving electric customers into rates. As they look at net metering and PV interaction, the principle they will look at is whether the customer is paying for the services they receive from the grid and whether they are receiving compensation for the benefits they provide to the grid. 

Another panelist said that the coming years will see a huge shift away from talking about energy and towards talking about buildings, capacity, resource adequacy and standalone solar. Hydro is being limited, firm generation is being retired, and building is not happening fast enough. The state is not permitting things fast enough. If a blackout happens, things will shift. Policymakers will care about capacity, firm capacity, serving, and reliability. This region specifically is moving towards caring about capacity and resource adequacy.

To close the session, Donna said the panel highlighted the diversity of considerations in the energy market here in the state and why the work the Academy is doing cannot produce a single number as a valuation for solar and storage. There is clearly a complex array of individual considerations.