August 8th, 2020 by Johnna Crider
The Solar Energy Industries Association (SEIA) recently discovered that the value of rooftop solar in Michigan is 24 cents per kWh. This is well above the net metering compensation paid to customers with solar roofs installed. SEIA’s Director of Rate Design, Kevin Lucas, shared this find in a Consumers Energy rate case testimony.
Lucas’s testimony was part of a joint testimony filed by the Environmental Law & Policy Center, on its own behalf and on behalf of the Ecology Center, the Great Lakes Renewable Energy Association, SEIA, and Vote Solar.
It is less costly to serve residential customers with solar than those without it. One major factor that contributes to the high value of rooftop solar is a drop in demand of customers with rooftop solar at the time of the system peak demand when compared to similar customers without solar. In other words, customers with rooftop solar lower the system peak demand, which, in turn, lowers the need for expensive generation and transmission capacity. This is one of several benefits rooftop solar offers the grid (and other ratepayers).
Lucas also testified that rooftop solar customers export much of their power during the utility’s critical peak hours (between 2:00 and 6:00 pm on weekdays). How much does this matter? At a time of “critical peak pricing,” customers must pay 95 cents per kWh (for afternoon power). Yikes!
“Lucas proposed that Michigan regulators establish residential rates in a way that shares the savings created by rooftop solar, between those who own rooftop solar and other residential customers,” PV Magazine writes. “He suggested that the savings be allocated 25% to rooftop solar owners, to incentivize further solar installations, and 75% to other residential customers, to drive residential rates down.”
The Brattle Report
Lucas also challenged several approaches that were used in a Brattle study. The study in question assessed the magnitude of residential net metering (NEM) subsides in many US states. The authors of this study created a methodology and applied it to all of the utilities based on a cost-of-service approach that focused on identifying the costs avoided by NEM customers. They found that the NEM policy led to substantial subsidy issues between distributed generation (DG) and non-DG customers. The range was between $20 through $100 per customer on a monthly basis and represented roughly around 25–200% of the monthly bills for residential DG customers of these utilities.
In his testimony, Lucas concluded that state regulators “should disregard the Brattle study upon which [the utility] relies.” In a 68-page testimony, Lucas described his critique of the utility’s analysis and presented his own. Lucas showed that residential NEM customers are less costly to serve than non-NEM customers and also showed that the proposed outflow credit is not a substitute for the proper treatment of outflow energy in the cost-of-service study. He explained why outflow energy should be included in the COSS since it reduced the load of the entire residential class during critical load hours. See below.
“The source and quality of data considered is very important. When evaluating proper data. NEM customers are actually less costly to serve than non-NEM customers. The Brattle study upon which the Company relies to show the cost of service of NEM customers should be disregarded. The Brattle study’s source data (that the Company provided) was substantially incomplete and required much data processing. Even after cleaning, the data was starkly different than an updated version of the NEM customer data.
“Brattle improperly adjusted the Company’s CCOSS model, and ultimately presented its results in a manner inconsistent with either the CCOSS or retail rate designs. The Company cannot substitute the proper treatment of outflow energy in the CCOSS by proposing an arbitrary outflow credit. Outflow energy should be included in the CCOSS because it legitimately reduces the load of the entire residential-class during critical load hours.
“The Company’s failure to do so penalizes the residential class as a whole by overstating the residential class’s load, and thus share of costs, which is derived from those critical load hours Using updated NEM customer data and a properly adjusted CCOSS, I used the Company’s own CCOSS model to demonstrate the cost to serve the average NEM customer was roughly $0.03 / kWh to $0.035 / kWh less than for the average non-NEM customer. I also show that NEM customers are less expensive to serve than similarly-sized non-NEM customers, largely due to the meaningful reduction in load during the key hours that are used to allocate costs.
“Finally, I calculated an updated outflow credit based on the CCOSS model using two methods. The first method models the outflow load profile in the CCOSS, while the second maps cost by allocator to energy TOU periods. I also posit that an adder that is conceptually similar to critical peak pricing that should be included in the outflow rate. Using the TOU period mapping method, I calculate an appropriate credit rate of $0.23957 / kWh, with an adder that ranges between $0.02739 / kWh and $0.05341 / kWh depending on the 4CP method and treatment of outflow energy in the CCOSS.”
— SEIA’s Director of Rate Design, Kevin Lucas in his testimony.
Value of Solar
Along with Kevin Lucas’ testimony on behalf of SEIA, other experts who agreed that Michigan regulators should conduct a statewide study into the value of solar also testified. William Kenworthy, Vote Solar’s regulatory director for the Midwest, recommended that the state’s regulators “initiate a comprehensive statewide study into the value of solar.” Dr. Gabriel Chan from the University of Minnesota, while testifying personally, not professionally, offered Minnesota’s approach to the value of solar analysis as a useful model.
In the Minnesota study, the methodology used by the participating utility is based on the enabling statute, stakeholder input, and guidance from the Minnesota Department of Commerce. Some of the key aspects of the methodology are:
- A standard PV rating convention.
- Methods for creating an hourly PV production time-series. These represent the aggregate output of all PV systems in the service territory per unit capacity corresponding to the output of a PV resource on the margin.
- Requirements for calculating the electricity losses of the transmission and distribution systems.
- Methods for performing technical calculations for avoided energy, effective generation capacity and effective distribution capacity.
- Economic methods for calculating each value component (e.g., avoided fuel cost, capacity cost, etc.)
- Requirements for summarizing input data and final calculations in order to facilitate PUC and stakeholder review.
The report offers two tables that illustrate the transparency and understanding among stakeholders and regulators. A final step in the methodology calls for the conversion of the 25-year levelized value to an equivalent inflation-adjusted credit. The utility will then use the first-year value as the credit for solar customers and will adjust each year using the latest Consumer Price Index data. You can read more about that here.
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