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As solar matures, rate design and incentive debates grow ever more complex

The newest national solar policy update finds policymakers considering more detailed programs to compensate DER owners and cover grid costs

The newest update on distributed energy policy action shows legislators and regulators around the U.S. stepping up their game.

There were 134 policy actions on distributed energy resources (DERs) in 40 states during the first quarter of 2017, making clear that interest in the sector remains high from utility commissions and state legislatures.

Debates about net metering, the typical compensation mechanism for distributed solar, continue in a number of states. But the emerging trend is toward more complex rate design and DER compensation proposals from utilities, a new report finds, sparking more nuanced responses from vendors and regulators.

“New concepts are emerging each quarter and the trend is toward complexity in both net-metering and rate design,” said Autumn Proudlove, manager of policy research at the North Carolina Clean Energy Technology Center (CETC) and lead author of “The 50 States of Solar: Q1 2017 Quarterly Report.”

Granular analysis of customer behaviors allow policymakers to propose detailed rate design reforms that send more precise price signals, she added. The report describes progress on new approaches to rate design from New York to Hawaii and Maine to Arizona.

But those new designs are raising new questions, according to Proudlove.

Complicated rate schemes can confuse customers," she said. "Do you want a more precise price signal that customers may not respond to, or do you want something simpler?”

An answer to her question may be in an emerging trend toward pilot programs that will test the innovative rate designs. The CETC identified five pilot proposals in Q1 2017 that came on the heels of six in Q4 2016. Their outcomes will likely be noticed nationally and help policymakers address the complexity of new rate designs.

"Pilot programs are being used mainly to test time-varying rates, residential demand charges, and community solar,” Proudlove said. “Many are related to high-profile proceedings, so the impact is significant.”

Most states had policy action related to distributed solar in the first quarter of 2017
 

 

Policy action in Q1

The Clean Energy Technology Center’s reports detail “proposed and enacted legislative, regulatory, and rate design changes affecting the value proposition of distributed solar PV.”

Of the five policy actions the CETC hilighted in the first quarter of the year, two were rate design issues. Overall, fixed charge requests remained the most popular rate design reform. The CETC recording 46 pending or decided fixed charge proposals in 23 states and D.C. to increase residential customers’ monthly fixed charges or minimum bills by 10% or more.

 

Rate design actions

While fixed charges were most popular, utility proposals from Oncor in Texas and Eversource in Massachusetts exemplified the trend toward more complex rate designs. The utilities floated demand-based minimum bills for DER-owning residential customers as an alternative to traditional fixed charges.

“Structured as minimum bills, these demand charges would only be charged to the extent that a customer’s total bill falls below the demand charge,” the report explains. Both represent “a hybrid between a fixed charge, a demand charge, and a minimum bill” for owners of DER, Proudlove said.

One objection to imposing demand charges on residential customers is that a customer may not have the capability or the tools to limit usage during system peak demand periods, Proudlove said. Another is that a customer’s demand peak may not coincide with or impact the system peak.

If the minimum bills were meant to be a more palatable alternative to fixed charges, they failed to catch on with solar supporters. Christian Roselund, Americas editor at PV Magazine, called the Oncor proposal “a fixed-charge Frankenstein” when it was filed, and argued the new rates could limit the value proposition for rooftop solar in Texas.

But compromise was evident in some states during Q1. A settlement between Arizona Public Service (APS) and DER advocates was probably the quarter’s highest profile rate design decision. Some 30 stakeholders agreed to the negotiated General Rate Case (GRC) deal that replaces proposed mandatory demand charges with four alternatives, including a time-of-use (TOU) rate option without a demand charge.

It is a first step toward gradually moving all APS customers to some form of TOU rate, APS Director of Regulatory Affairs Greg Bernosky said.

The settlement built on the Arizona Corporation Commission Value of Solar ruling that eliminates retail rate NEM compensation. The parties agreed to a new compensation credit of $0.129/kWh for exported electricity, to be recalculated regularly based on market and system conditions.

The GRC settlement also provides a 20-year grandfathering period for solar customers and limits the average APS rate increase to 4.6%.

The settlement will damage the solar value proposition in Arizona, said Sunrun Vice President Alex McDonough, but not enough that installers will have to cease business operations there.

Proudlove said the new optional rates will function as pilots and give utilities insight into their effectiveness. Demand charges can be difficult for customers, depending on how they are structured,” she said. “This is a really great opportunity to see what happens.”

NEM successor tariff actions

Another two of the CETC’s top five Q1 policy actions focused on NEM. Overall, there were changes to NEM either pending or enacted in 21 states.

Maine’s Public Utilities Commission put the fourth U.S. NEM successor tariff in place. Like those in Hawaii, Nevada, and Arizona, Maine’s new compensation will be less than the retail rate. Unlike the others, the CETC reports, it is “a buy-all, sell-all policy, which gradually reduces the transmission and distribution credit paid to customer generators."

The other successor tariffs are forms of “net billing,” which allow solar owners to defer the full retail rate for onsite produced and consumed electricity, Proudlove said. They essentially earn the retail rate for their self-generated electricity and only face the below-retail rate for exported generation.

A “buy-all, sell-all” arrangement – which in May also became law in Indiana – sells all solar generated electricity at a below retail rate to the grid and requires solar owners to pay retail for all kWh they consume.

“Unless the credit rate from the ‘buy-all, sell-all’ is higher than retail rate it’s reducing your compensation,” Proudlove said.

The tariff imposed by the Maine PUC became necessary when the legislature narrowly rejected a compromise incentive to take the place of retail rate net metering. The coalition of utilities, environmentalists, and advocates for consumers and DER who proposed the innovative design remain unconvinced of the approved tariff’s viability.

It becomes official in January 2018 and there is “a bit of a gold rush as folks install solar to qualify for the 15 year grandfathering provision before the new rule takes effect,” said Tim Schneider, head of the Consumer Advocate's Office, who led the coalition's unsuccessful fight for its net metering successor.

“The legislature is currently looking at proposals that would undo the Commission's ruling,” he added. “But given the governor's vocal opposition to solar, it'll be tough sledding.”

Indiana’s successor tariff became the second U.S. “buy-all, sell-all” rate when it was approved by the Republican-dominated state legislature and signed into law by Gov. Eric Holcomb (R).

It provides grandfathering for current solar owners, but the net metering credit will drop to only 25% above the wholesale electricity rate when the current NEM cap is reached. This will take Indiana’s 28th place ranking for installed solar capacity lower, warned a statement from the Center for Biological Diversity.

Proudlove offered two reasons why open commission proceedings like Maine’s tend to be better than legislative initiatives like Indiana’s for altering NEM. First, open proceedings allow stakeholders to be heard and to locate common ground, she said. Second, what is done by lawmakers can only be undone by lawmakers, while commissions can reconsider their rulings.

DER valuation actions

The last of the report’s five highlighted policy actions was the New York Public Service Commission value of distributed energy resources (VDER) decision. It was the most noteworthy of the first quarter’s DER valuation and net metering benefit proceedings in 14 states and D.C.

The ruling requires compensation for a DER’s exported electricity to be based on the resource’s “Value Stack.” This new structure includes the locational marginal price, capacity value, environmental benefits value, and market transition credit, but does not set precise numbers. The exact values will be set in further REV proceedings.

The VDER was the necessary next step toward an NEM successor tariff in the state’s landmark Reforming the Energy Vision (REV) proceedings, Proudlove said. It will first be used for community and central station solar projects. Rooftop solar will continue to be compensated at the temporary settlement rate.

New York’s is the first definitive move toward value-based compensation instead of avoided-cost compensation for a successor tariff, she added.

“Other states will may see this as a model,” she said. “But coming up with the value is really the tricky part and everyone will be watching New York to see what happens.”

The big picture

Four overarching policy themes characterized 2017’s first quarter, the CETC report concludes. One is completely unsurprising.

Lots of NEM changes

Not surprisingly, Q1 2017 saw 15 states address NEM, with at least 65 bills on NEM brought before state legislatures. The bills covered everything “from equipment requirements to aggregate cap” but the bulk addressed the compensation rate and virtual net metering.

An example is the New Hampshire commission proceeding on a net metering successor ordered by lawmakers in H.B. 1116.

The regulatory debate left commissioners with the dilemma of choosing between two settlement proposals. A DER advocates proposal keeps NEM in place but drops compensation to 75% of the present rate in September 2017 and to 50% at the beginning of 2019. It calls for compensation to be reset in January 2021 at a rate determined by a future VDER study.

A separate, utility-backed settlement agreement calls on NH's PUC to move from NEM to net billing and  compensate exported electricity at the utilities’ avoided cost.

The commission’s final decision, due in early June, is expected to include joint recommendations for TOU rate and demand charge pilots, a locational value study, and a VDER study.

Complicated 'hybrid' charges for solar customers

The next big theme is the emerging trend toward rate designs with charges “that do not fit neatly within the traditional definitions of fixed charges, demand charges, and minimum bills,” the CETC reports. “This is an area to watch.”

The Oncor and Eversource proposals topped the CETC’s list. Another example is a proposal from a coalition of Louisiana utilities for solar compensation.

Entergy Louisiana, SWEPCO, Cleco, and the Association of Louisiana Electric Cooperatives proposed 2-channel billing, a type net billing. Exported electricity would be compensated at the utilities’ avoided cost. Entergy and SWEPCO accepted time-varying rates as an option to study if combined with an increased fixed charge or a demand charge.

Louisiana DER advocates supported retail rate NEM but recognized the possibility of time-varying or location-based rates. Sierra Club proposed considering a minimum bill.

Fixed charge increases flop

Of the 12 residential fixed charge cases decided during the quarter, regulators approved an average of 19% of the utility’s proposed increase, the CETC reported. Including two withdrawn proposals from Indianapolis Power and Light and Empire District Electric lowers the average to 16%.

The biggest fixed charge increase approved was $3/month, for Tucson Electric Power, but it was only 30% of the utility’s proposed hike. Southwestern Public Service (SPS) and DTE Electric got the biggest proportion of their proposals, 50%, approved. DTE asked for a $3/month increase and got $1.50. SPS asked for $1/month and got $0.50.

 

Community solar’s steady course

There were policy actions on community solar in 12 states in Q1 2017, including new legislation for statewide policy in at least five states. Following policy approvals by Illinois and Rhode Island lawmakers in 2016, Virginia became the 17th state to adopt a comprehensive law in Q1 2017 as community solar continued its state-by-state expansion. Proposals in Nebraska, New Mexico, Nevada, and Montana await legislative consideration.

But the most noteworthy example of community solar policy action during Q1 was the approval from Hawaii’s PUC to include TOU rates in the state’s community-based renewable energy (CBRE) program.

The commission rejected a CBRE plan from the Hawaiian Electric Companies, the state’s dominant electricity provider, and built the program around a PUC staff alternative proposal that included TOU rates.

The program will offer Mid-Day, On-Peak, and Off-Peak rates, with higher compensation for generation sent to the grid at peak periods.

Proudlove said Hawaii’s program follows the emerging pattern of “more detailed rate designs with more elements to them.”

Filed Under: Solar & Renewables Distributed Energy Regulation & Policy
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