Research spotlight: Solar cost shift negligible, DER valuation efforts advancing slowly

New studies from LBNL and Rhodium detail the latest findings in distributed energy resource valuation

Recent research into the cost and value of distributed resources gives a snapshot of how the policy debate over them is developing in the United States.

On the cost question, a new report from Lawrence Berkeley National Laboratory (LBNL) details the relatively small rate impacts from distributed solar and allays concerns about the perceived cost shift. On the benefit side, another paper commissioned by the Department of Energy shows distributed energy resources (DER) are not yet accurately valued, but could change the energy paradigm when they are.

“Whoever figures out a broad, technology-neutral way to value and compensate all resources on the distribution grid based on location and time through some sort of market-based process is going to fully capture and harness the potential of DER,” said John Larsen, executive director at the Rhodium Executive and lead author of the DOE-commissioned paper.

That report — “What Is It Worth? The State of the Art in Valuing Distributed Energy Resources” — assesses “over 100 different peer-reviewed papers on DER,” he said.

“The U.S. regulatory system was put in place for utilities and their distribution systems but is not set up to properly value the grid services that DER can provide,” Larsen said. “Either they are not valued at all or they are valued in ways that are blunt and don’t send the price signals needed to optimize their use.”

The LBNL paper — “Putting the Potential Rate Impacts of Distributed Solar into Context” — illustrates Larsen’s point. State legislatures and regulatory commissions from Maine to California continue to debate the threat of a perceived shift of costs imposed by distributed solar owners on other utility customers. But the numbers show they may be barking up the wrong tree.

“In most cases, the effects of distributed solar on retail electricity prices are, and will continue to be, quite small compared to many other issues,” LBNL Energy Researcher and paper lead author Galen Barbose told Utility Dive.

Those concerned about a rate impact imposed by the skyrocketing growth of distributed solar “should realize that, even though solar is growing fast, it's starting from a very small base … Most utilities do not get to even a 1% penetration by 2030.”

The LBNL paper reflects a growing body of knowledge on the impacts of DER on utility rates, but researchers say efforts to model full value of the resources remain nascent, hampered by utility business models that do not encourage their adoption. By drawing on the recent findings and early state valuation efforts, policymakers can design market structures and encourage technologies that help utilities optimize DER deployment for the grid.

The rate impacts of distributed solar

The LBNL researchers narrowed the many questions being asked about distributed solar in regulatory proceedings to the one question of how much the solar impacts utility rates, Barbose said.

“The central conclusion is that for utilities, commissions, and others concerned about keeping rates low, there are in most cases other areas that offer a bigger bang for the buck than distributed solar rate structures."

The study focuses on three key parameters in a cost-of-service-based retail electricity price and uses a broad range of representative assumptions from existing studies. The value of solar to the utility derived for the paper’s rate impact calculations is “at the lower end of the range,” Barbose said.

The second key parameter is the compensation rate for solar energy-generated electricity sent to the utility’s grid that would potentially impact rates.

The rate impact estimates from the paper “were based on retail rate net energy metering with volumetric rates,” Barbose said. “That has been the most common form of solar compensation for residential customers.”

The third key parameter is the level of distributed solar penetration, which is its generation’s percentage of total retail electricity sales. It was 0.4% at the end of 2015, according to LBNL.

Penetration “is the lynchpin to the conclusions because the rate impact scales proportionately to it,” Barbose said.

For most U.S. utilities, penetration levels will likely remain low. “That is why, for most utilities, the rate impacts have been and will continue to be rather small,” he said.

At 0.4% of total U.S. retail electricity sales, distributed solar “likely entails no more than a $0.0003/kWh long-run increase in U.S. average retail electricity prices, and far smaller than that for most utilities,” the paper reports.

Even in 2030, with the currently forecasted exponential growth, distributed solar “would likely yield no more than roughly a $0.002/kWh increase in U.S. average retail electricity prices, and less than a $0.001/kWh increase in most states, where distributed solar penetration is projected to remain below 1% of electricity sales,” the study adds.

Four U.S. utilities, all in Hawaii, have over 10% penetrations. Three other states, Arizona, New Mexico, and Connecticut, are projected to exceed 10% by 2030. Seven may get to 5% penetrations. Some utilities in those states will have penetration levels that impact rates, the researchers wrote.


At high penetrations, and with retail rate net metering and no fixed or demand charges, the average electricity price would increase no more than about $0.005/kWh, according to the report. At LBNL’s projected state 2030 penetration rates, the average retail price impact would increase no more than about $0.002/kWh.

The LBNL study compared the rate impacts of distributed solar to the impacts from several other factors, including energy efficiency programs and policies, natural gas prices, and capital expenditures (CapEx) by electric utilities.

“Energy efficiency has had, and is likely to continue to have, a far greater impact on electricity sales,” LBNL researchers found. “Utility energy efficiency programs and federal appliance efficiency standards together reduced U.S. retail electricity sales in 2015 by an amount 35-times larger than that of distributed solar.”

Based on conservative assumptions, savings from energy efficiency through 2030 would cause the average electricity price to increase no more than about $0.008/kWh.

The volatility of natural gas prices make rate impact projections more difficult. LBNL-developed parameters project a 10% probability that prices in 2030 will be at least $1.90/MMBtu higher than currently expected. This would cause the average electricity price to increase by about $0.008/kWh.

The biggest impact on retail electricity prices through 2030 will be from utility capital expenditures (CapEx), according to the report. They have increased about 6% per year since 2000, despite relatively flat load growth.

Based on a range of assumptions about future investments and capital costs, the research projects CapEx will cause the average electricity price to increase through 2030 by $0.016/kWh to $0.036/kWh.

Those results imply that the impact of rooftop solar on utility rates will remain modest in most service areas, and policymakers looking to keep prices low can do more by addressing other parts of the rate structure.Barbose, however, cautioned not to read too much into the rate findings.

“Rate impacts is one narrow item and this is not a comprehensive prioritizing,” he said. “It does not answer all the relevant questions a utility or a commission would need to answer in making a choice between priorities.”

CapEx may be warranted regardless of the rate impacts, Barbose added. “But a commission or utility should be aware that reducing CapEx offers a bigger opportunity to keep retail prices lower than changes in the compensation for distributed solar or energy efficiency.”

In its conclusion, the LBNL paper briefly mentions three factors that could affect the value of distributed solar to utilities. All three – directing deployment to locations with the most investment deferral potential, leveraging the capabilities of smart technologies, and increasing incentives for solar plus storage or demand response – are at the cutting edge of DER valuation, as described in the Rhodium paper for DOE.

The grid benefits of DER

Doing this study “changed my view of the role DER can play,” Rhodium’s Larsen said. “The U.S. regulatory system is set up to support central operation and dispatch and big ticket CapEx driven by regulated utilities’ profit motives. That works against DER.”

The heated regulatory “conflagrations” over rate design across the U.S. reflect this point, the paper argues. Some stakeholders defend rates that support proven and reliable technologies, while others want rates that value “recent innovations in generation, storage and information technologies.”

If DER are employed strategically, they can lower system costs and improve system reliability, Rhodium researchers note. But, they warn, “if they are not deployed and integrated properly, DER could impose new system costs and challenges to reliability.”

At the center of the challenge regulators face is identifying the services DER “can or should provide, determining the value of those services, and compensating them accordingly,” Rhodium argues. As penetrations increase, the questions become more critical.

“The pace of DER growth, especially of solar PV, has accelerated, and the numbers are getting big enough to matter,” Larsen said. “Tens of thousands of homes operating as mini-power plants on the distribution grid look to utilities like an army of competition and every kWh they produce is a kWh the utility cannot recover to cover its fixed costs.”

The electric power system can be more flexible, affordable, and cleaner if DER "are fairly compensated for the net value of the services they provide” and “fully considered in distribution utility planning and operations,” the paper argues.

The best example of how the existing regulatory system fails DER is the time invested in a heated value conversation about solar PV and net metering, Larsen said. “Yet net metering does not send the right signals to utilities, customers, or developers.”

Net metering does not signal where or when PV can deliver system value and it does not compensate based on performance, he said. “It is just: ‘when you generate, we pay you, and when you don’t, you pay us.’ That might be useful for the solar industry in the short term but it does not make for a more flexible and dynamic distributed grid.”

The debate must extend beyond solar PV and net metering, Larsen said. “DER is going to get “more popular and more widespread. That is the march that we are on.”

That point was underscored by the recent release of a manual for valuing DER by the National Association of Regulatory Utility Commissioners, which advises U.S. state power regulators.

To allow DER to compete alongside other resources, regulators must eliminate “inconsistent and incomplete” DER valuation and enable multiple “technology neutral, market-based valuation approaches” that best suit the different technologies.

Examples are emerging, Rhodium reports. Demand response providers can bid into some wholesale markets. Benefit-cost tests have emerged to value energy efficiency technologies. Solar PV, however, remains over- or under-valued by an outdated net metering debate.

“Market-based valuation approaches can account for the locational, temporal, and technological profiles of specific DERs,” Rhodium argues. Moving toward them will be an important step in establishing price signals that can direct the deployment of DERs to where they are most valuable on the distribution system and can adjust for changing grid dynamics as deployment increases.”

The various capabilities of distributed resources make finding technologically-agnostic valuation schemes both challenging and essential


Locational and temporal solutions

There is no “one-size-fits-all solution” to DER valuation, the Rhodium paper reports.

Any regulatory ratemaking that pushes a more granular approach would be “a step forward” and would benefit of grid operators, DER providers, and customers, Larsen said. The difficulty is that technologies allowing actionable responses by customers to new rate designs are not in place.

Time-of-use (TOU) rate designs now being proposed send temporal price signals to value solar PV when it is most useful to the grid, Larsen said. And they change the value of distributed solar-plus-storage systems because customer-generated solar can be stored for use when the retail power price is high.

But the smart technologies that deliver the real-time price information necessary to take advantage of TOU rates are not widely available, Larsen said.

Another example is competitive bidding on distribution service contracts offered by utilities, he said. That kind of technology-neutral, market-based competition allows DER to compete. But few utilities have assimilated the system information necessary to offer those opportunities.

Other examples of potentially effective market mechanisms include “competitive utility procurement of solar PV energy services, the use of the infrastructure-as-a-service model, and the design and implementation of a Distribution System Operator or Independent DSO model that would allow for competitive markets for a variety of energy services within the distribution system,” according to the paper.

Potentially effective regulatory changes include “allowing utilities to receive new revenue streams from providing value added services or by incentivizing utilities to create more value from existing and new assets,” Rhodium adds.

“Whoever cracks this nut could really benefit,” Larsen said. “But without a new framework that will allow DER to compete, innovation that delivers new lower cost technologies may not be possible.”

Utilities could be the drivers of that change, Larsen said, but only “if they are unshackled from the CapEx rate of return conundrum."

The current framework give utilities no incentive to consider lower CapEx options like DER that might provide the same or better service, because they would get a lower rate of return. “With a way to monetize DER services, incorporate them into standard planning, and own them, utilities might do it all,” Larsen said.

Valuation efforts in the field

If the mechanisms to allow accurate DER pricing remain unclear, Larsen said the end goal is less so.

“Almost everybody who is working on the future the electric power system is pushing for market-enabling methods,” he said. The question has dominated solar valuation proceedings in Hawaii, California, and New York. It has also been central to grid modernization and other proceedings across the country.

Autumn Proudlove, senior policy analyst at the North Carolina Clean Energy Technology Center, details state proceedings on solar and DER valuation. She said the progress “varies by state and utility territory.

“States with established power markets are much further along,” she said.

In general, there is more progress on temporal than on locational valuation, she added. “There is a lot of consensus on time varying rates. We saw that in the Colorado settlement [on a net metering successor program].”

Implementation of both types of valuation are limited by technical system capabilities, she said, echoing Larsen. Smart meters and displays that make actionable customer responses possible are needed for time varying rates and more granular distribution system information is required to accurately attribute locational value.

In California, “they are making good progress considering how big a change in paradigm this is,” said Commissioner David Hochschild of the California Energy Commission. “California used to be powered by just 200 power plants. Now, if you include rooftop solar, we have 600,000 power plants.”

Jim Baak, grid integration director at Vote Solar, an advocacy group, agreed there is progress, but said results to date are “somewhat crude,” he said.

“It will take some time to get better, more accurate results.”

Progress in California is better than in New York in some ways but New York has an edge in others, he added.

“California utilities are ahead of New York in the sense that they've deployed smart meter capabilities and have, to varying degrees, modeled their distribution systems using advanced sensing and SCADA system monitoring and control systems,” he said. “Utilities in New York have not fully deployed AMI and to my knowledge do not yet have their systems modeled.”

Analyzing the hosting capacity of the distribution system is “the first step in determining locational value,” Baak said. “The next step is to analyze the locational net benefits, based on geographically granular avoided costs. Again, California is ahead, but still has a long way to go.”

The process will stay focused on distribution system investment deferral in the near term, he expects. Ultimately, the need is for new tariffs, programs, incentives, and markets through which DER can be monetized.

“New York is ahead in the sense that they have created the vision for where the market will evolve,” Baak said. “Somewhere between the two approaches is the best approach for the evolution of the energy industry.”

David Jacot, director of efficiency solutions at the Los Angeles Department of Water and Power, offered a utility point of view. “We see the benefits but our efforts are still nascent,” he said. “Timely reductions in energy use or timely additions of renewables at certain regions of the grid are critically important. But there are a lot of moving parts in managing those things.”

With its Distributed Energy Resources Intergration Strategy, LADWP is assessing how and where DER could be applied to things like blackouts, he added. “But how do you value and monetize avoiding a blackout?”

The the effort to identify DER locational and temporal values “is only a couple of years old,” noted Karl Rabago, director of the Pace Energy and Climate Center and a former Texas utility commissioner.

They could be accurately attributed if utilities could provide “sub-nodal marginal distribution capacity costs at 1, 5, and 10 year increments and locational marginal prices at a sub-nodal level,” he said.

With that data, which utilities do not yet provide, DER providers could compete with other providers of distribution system infrastructure, Rabago said.

“But wherever they are procuring to meet distribution system upgrade needs, they are beginning to “understand with greater granularity what that value is," he added. "That will open up – through RFPs or standing offers or another procurement or market mechanism – the understanding of what a DER is worth.”

Filed Under: Solar & Renewables Energy Storage Distributed Energy Regulation & Policy