Last week, Utility Dive reported from the front lines of rate design reform, noting that leaders from the utility sector, renewables advocates and regulators have begun looking for more comprehensive ways to calculate utility rates after years of contention over net metering, fixed charges, and other rate issues.
But while sector leaders aim to chart a new path, the policy landscape they're seeking to change looks significantly different from the one they envision.
From Maine to Hawaii, regulators continue to be caught between the power of utilities and the passion of renewables advocates on a slew of distributed energy issues, and a new report points out that they aren't likely to subside anytime soon.
“Solar rebate incentives are decreasing, solar tax incentives are expiring, renewable portfolio standards are nearing their targets, net metering caps are being reached, and net metering and rate design are undergoing regulatory and legislative review,” notes a new report from the North Carolina Clean Energy Technology Center, "The 50 States Of Solar; A Quarterly Look At America’s Fast-Evolving Distributed Solar Policy Conversation."
Dockets on rate design, net energy metering (NEM), and distributed solar (DS) ownership are filled to the brim with filings, and nationwide uttilities remain unwavering in their commitment to prevent what they say is a shift of fixed system costs imposed by DERs owners on their non-DERs-owning customers.
DERs advocates, meanwhile, remain committed to their demand that utilities show them numbers that verify such a cost shift.
Uncertainty created by this turmoil is hampering both utilities and the renewables industry, the report notes.
“Despite strong near-term growth projections for distributed solar, mid- to long-term policy uncertainties pose a challenge for the industry,” the paper reports.
The NC CETC paper, published in partnership with Meister Consultants Group, examined distributed resource policy issues across the nation from the third quarter of 2015 and compiled five developments as the most significant:
- Expansion of utilities into rooftop solar, including initiatives by APS and TEP in Arizona, CPS Energy in Texas, Con Edison in New York and Georgia Power
- Challenges to NEM by California IOUs Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric that could impact the entire U.S. rooftop solar market.
- Numerous proposals from utilities for substantial increases in residential fixed customer charges, the most frequently proposed policy change
- Proposals from utilities in Arizona, California, Kansas, Oklahoma, and Texas for a demand charge for residential solar owners based on their highest period of usage in a billing period
- A proposal by NV Energy to eliminate retail rate NEM credits and impose a successor tariff that creates a new rate class for net metered customers with both time-of-use (TOU) rates and demand charges.
Utilities have also begun making proposals for fixed charges on all residential customers, not just solar customers, observed NC CETC Policy Analyst and paper co-author Benjamin Inskeep.
“Solar is the tip of the iceberg. It foreshadows other issues that are becoming increasing relevant as the energy industry changes.”
Net energy metering dockets
Nineteen states changed NEM or were working on changing it in Q3 2015.
Massachusetts, New Hampshire, New Jersey, New York, and Nevada are working on entirely new systems. California, Hawaii, Arizona, Nevada, and Maine are looking at successor tariffs. Regulators in Illinois, Minnesota, and Virginia are conforming their NEM rules in response to legislation. NEM was introduced in South Carolina and proposed for Mississippi.
The Q3 proposals would have “split” impacts, Inskeep said. Some expand NEM programs and some scale them back.
“Quite a number of states have come out with successors to NEM that diminish it,” he said. A Michigan proposal would transform NEM into “a buy all-sell all program that could be very detrimental to residential customers that want to go solar.”
Proposed changes in the Southwest and one enacted in Hawaii may be based on “solid reasoning” because of penetration levels, he said. An interesting development in that direction are NEM changes paired with time-of-use or time-varying rates, he added.
Value of solar and community solar dockets
During Q3 2015, 12 states published, proposed, or had ongoing regulatory discussions on “the proper value of distributed solar generation or net metering policies,” the paper reports.
“Solar valuation is another emerging trend,” Inskeep said. “If a state isn’t proposing a value of solar study or something similar to account for the costs and benefits, it is probably studying it. If not, it is a matter of when, not if.”
Value of solar (VOS) studies date to at least 2006, according to Pace Energy and Climate Center Executive Director Karl Rabago who, as an Austin Energy executive, led one of the earliest VOS implementations.
Now there are standardized approaches for important value components, new techniques to quantify others, and “they get better every time a new public VOS study appears,” Rabago added.
VOS is a “forward-looking approach that recognizes that the ad-hoc use of the retail rate for NEM was rough justice and analysis is appropriate,” he explained. “Minnesota Commissioner Nancy Lange called VOS the future because it shows a way to analyze value and set rates through that analysis, allowing regulators to escape simply being caught between utilities and solar advocates.”
A third important set of policy actions in Q3 2015 was around community solar policies or programs. New York and Hawaii directed their utilities to file tariffs enabling community solar projects. California furthered a program design and Oregon opened a community solar proceeding.
Minnesota regulators issued a clarifying ruling that opens the way for “an extremely robust community solar program in 2016,” Inskeep said. But a majority of states have not yet passed community solar laws, he added. “New policy will be needed to remove regulatory barriers and open those markets.”
Fixed charge and demand charge dockets
Twenty-six monthly fixed charge increases for residential customers were under consideration in Q3 2015 across 18 states. The biggest, of $10 per month or more, were proposed in Missouri, Kansas, Arizona, and Wisconsin.
“Last quarter we tracked over 30 utility proposals and we are looking only at increases of at least 10%,” Inskeep said. “The average increase of those 26 is 70%. These are unprecedentedly large changes in rate design principles.”
Utilities seeking such sharply increased monthly fixed charges are deviating from long-established rate design principles, according to Smart Rate Design for a Smart Future from the Regulatory Assistance Project (RAP). Any change in fixed monthly fees has traditionally been limited to when the number of customers changes.
“High fixed charges are punitive to small use customers,” explained Regulatory Assistance Project Sr. Advisor Jim Lazar, co-author of the RAP paper. And “because they have lower per-kWh energy charges, they result in increased usage of about 7% compared with flat rates and about 15% compared with inclining block rates.”
Because fixed charges are regressive and work against customer efficiency, they risk “putting the very viability of the industry in question,” the RAP paper concludes.
“Demand charges are similarly punitive to small-use customers for a different reason,” Lazar said. Small-use customers can share infrastructure but demand charges impose system costs on them as if they were a single big consumer using the infrastructure full time.
All but three of the fixed charge proposals are still pending, and most of those proposed over the last two years have been carefully scrutinized and regulated “because they diverge from the classic rate design principles that regulators have relied on for decades,” Inskeep said.
“Demand charges are part of good rate design for large users but I am more skeptical about adding them for residential customers, especially if they are discriminatory and just for solar customers,” he added.
In Q3 2015, state regulators approved or were considering such solar-or-DER-only charge increases for 19 utilities in 12 states. Structures included flat monthly charges, charges based on the capacity of the installed solar system, charges based on measured monthly peak generation, and increases to variable per-kWh charges that would apply only to NEM. Most are still pending.
“New Mexico denied a solar-only charge because it would violate state law by creating a discriminatory rate, but I don’t think many states have that kind of law,” Inskeep said.
It is not clear whether SolarCity’s federal suit against a Salt River Project solar-only charge will hold. A Wisconsin federal court’s rejection of a solar-only charge was due to inadequate evidence on the question, Inskeep said.
Solar ownership dockets
Third-party ownership (TPO) financing of solar, which was responsible for 72% of all distributed solar in 2014, is currently disallowed in Florida, Kentucky, North Carolina, Oklahoma, and South Carolina and the legality is unclear in about 20 other states, the paper reports. No new initiatives proposing it were filed in Q3.
Decisions on TPO financing are pending in Delaware and New Hampshire. A landmark test case is before the North Carolina commission.
Utility efforts to own solar is another "emerging trend,” the paper reports. They fall into two categories. Con Edison in New York and Georgia Power are operating through unregulated partners and face little pushback as long as they observe regulatory proprieties.
Tucson Electric Power, Arizona Public Service, and CPS Energy have won approval from their regulators for pilot programs to own solar arrays installed on their customers’ roofs. Responses from customers and the utilities’ local installer-partners have initially been enthusiastic. National solar installers are watching the programs warily.
“That area is poised for growth because utilities see distributed solar as a special opportunity,” Inskeep said. “They are trying to move past the idea of solar as a threat and find a way to make it work with their business model.”
Tone and content at the utility commissions
Both Rabago and Lazar have followed the listed dockets closely and participated in proceedings. Both say they are less concerned with the tenor of the proceedings than with some utilities' and regulators’ mistaken perspective.
“The main concern I have is that many of the analyses are backward looking,” Lazar said. “Instead of asking who should pay for past distribution system investments, they should be asking how to avoid future costs.”
Forward looking questions are about adding DERs to the system and recognizing that they are more valuable in today’s energy mix because they are cleaner, can reduce peak demand, and can defer the need to build new peaking power plants and more transmission and distribution system infrastructure. They also avoid fuel cost risk, fuel supply risk, and emissions, he added.
Too many utilities look backwards and say all the fixed costs are sunk, Rabago similarly said. They fail to recognize that any losses for sunk costs are due to their own forecasting failures.
“The market has seen the change coming," related to distributed resources, "and they could have, too.”
Utilities and also often fail to recognize the 10% rate of return they have been earning for decades covered the risk of sunk costs and should have been used to prepare for the transition they are now faced with, he said. Instead it has too often been used to “keep their stock prices and ratings high in the face of that risk.”
“About 98% of utility revenues are dictated by weather, commodity fuel prices, and general economic conditions, and they are focusing on the 2% dictated by distributed energy resources,” Rabago said.
Looking ahead: What’s in and what's out in DER policy
A minimum bill is no longer considered viable as a "more palatable" fixed charge by DERs advocates, Inskeep said. “Only California and Hawaii have enacted them and it doesn’t seem to be catching on. I’m not sure why.”
Reforms of the Public Utility Regulatory Policy Act (PURPA) of 1978 have, however, suddenly become relevant because low DERs costs can now meet established avoided cost requirements.
“The law says the utility has to take a small generator’s output if it matches the avoided cost,” Inskeep said. “But state regulators set that avoided cost, the standard contract length, and the acceptable system size.”
Idaho’s change of its standard contract from 20 years to 2 years will drastically reduce developers’ guaranteed revenue streams, he said. But North Carolina DERs advocates defeated a Duke Energy effort to impose a shortened contract length and a reduced system size, changes that might have stopped solar growth in the state.
“When the federal investment tax credit changes in 2017, PURPA may be vital for getting DERs on the grid,” Inskeep said.
In the coming quarter, NC CETC expects further work on the landmark successor NEM tariff in Hawaii and final decisions on successor tariffs in California and Nevada.
“California is about 50% of the residential solar market and if the utilities’ proposed fixed charges and NEM credit rate reductions are approved, it would have a tremendous impact,” Inskeep said.
Massachusetts and Vermont are likely to see decisions on NEM caps and credit rates that will be pivotal for DERs in New England. Mississippi’s regulators must make a decision on NEM by the end of the year.
With the dockets open now, the legislative actions in the works, and the reversion of the 30% federal tax credit to 10% for commercial solar and zero for residential solar at the end of 2016, “the year is shaping up to be a turning point,” Inskeep said.
