True Value: To get to tomorrow's grid, DER grid services must be compensated right today
Enabling and compensating the true value of all the services storage offers is no easy matter.
The accelerating transformation of the solar industry into the solar-plus-storage industry was clear at Solar Power International (SPI) 2018, making questions about the true value of aggregating the resources to serve customers and the grid more urgent.
Much conference chatter surrounded getting technology, markets and policy for solar, storage and distributed energy resources (DERs) to work together. Developers that expect real market penetration to follow policy solutions brought some of the hottest questions regarding the advancement of DER.
"How fast it happens depends on the underlying compensation and rate design."
Chief Policy Officer, Sunrun
"In high penetration markets, the bulk of solar sold is now being sold with storage, and solar-plus-storage will supplant standalone solar over time," according to former Maryland public utilities commissioner Anne Hoskins, now Chief Policy Officer for leading distributed solar-plus-storage builder, Sunrun. "How fast it happens depends on the underlying compensation and rate design."
Compensation must recognize the full range of behind-the-meter services and grid services offered by resources paired with storage, industry leaders said in panel discussions and private interviews with Utility Dive. As it stands, storage's true value proposition is only fully realized by compensation for many services not yet established in rates, contracts or utility-led programs. Compensation for customer-owned technologies' full range of capabilities will be increasingly important as developers aggregate them and seek to monetize the grid services they can deliver.
Most storage today is at transmission system scale. But behind-the-meter storage and other DERs have grown rapidly and are forecast by industry leaders to play a bigger role.
"Instead of seeing storage as a limitation, utilities might see it as part of a new business model built around revenue sharing with end users."
Director of regulatory strategy and utility initiatives, Sonnen
It is "widely agreed" that battery energy storage offers 13 monetizable services, Ani Backa, Sonnen director of regulatory strategy and utility initiatives, told Utility Dive. She referred to the findings of a 2015 Rocky Mountain Institute (RMI) paper on battery energy storage economics regarding more than a dozen grid services featured in the graphic below.
"A formal process to study those 13 services could help identify and quantify use cases for the distribution system that have instant value to utilities," Backa added. "Instead of seeing storage as a limitation, utilities might see it as part of a new business model built around revenue sharing with end users."
Market growth for storage dwarfs solar
Both the U.S. solar photovoltaic (PV) and storage industries are expanding. PV is bouncing back after being slowed by import-tariffs imposed in 2017, which are now stepping down and will terminate in 2021. The 8.5 GW of utility-scale solar procured in the first half of 2018 was the industry's biggest first-half procurement, according to the newest Wood Mackenzie-Solar Energy Industries Association (SEIA) market report.
Residential PV was essentially flat, year-over-year, which was "an encouraging sign of market stabilization after a year in which the market contracted 15%," the report added. Non-residential PV fell 8%, but corporate procurement of utility-scale solar continued to grow and now represents 12% of projects being developed.
Overall, the report forecasts 2018 will match 2017's 10.9 GW and growth will "more than double over the next five years." By 2023, annual installed capacity is expected to be over 14 GW.
That is dwarfed by storage's current and expected growth, according to Wood Mackenzie Director of Storage Ravi Manghani. U.S. storage grew 300% year over year, from about 50 MWh in Q2 2017 to about 150 MWh in Q2 2018. Installed capacity growth is estimated at over 800% from under 300 MW in 2017 to almost 2,000 MW in 2023. The 431 MWh capacity reached in 2017 is forecast to reach 11,744 MWh in 2023.
Growth will be driven by falling contract prices for utility-scale projects, Manghani said during an SPI panel. Within five years, standalone storage contracts are likely to be priced competitively with natural gas peaker plants, and within ten years storage will "almost always" beat natural gas peaker plants on price, he added.
The competitiveness of solar-plus-storage as a replacement for peaker plants is very location specific, according to Lon Huber, Navigant's energy director. But by the mid-2020s, "about 13 GW of storage will have been the preferred resource for providing generation services," he said.
Compensation challenges: The coming change in storage
The energy storage sector's growth forecasts assume no changes in technology, market rules or policy. Technology will almost certainly change the competitiveness equation. And changes imposed by Federal Energy Regulatory Commission's Order 841 market rules are expected to be significant.
If policy recognizes the multiple values that storage can deliver, both in front of and behind customers' meters, it could match the power of technology advances and market rules as a gamechanger.
Utility-scale solar and solar-plus-storage developers are increasingly bidding into utility solicitations. The low cost of solar and the falling cost of battery storage have made their bids competitive. But DER developers are pursuing two newer opportunities for which recognition of the true value of the many services storage offers is critical: non-wires solutions (NWS) and system-wide services.
DER as a non-wires solutions
DER can be a cost-effective NWS to solve a specific site's need for costly new or upgraded generation or transmission and distribution system infrastructure.
For DER developers to deliver an NWS, the value proposition must be right, Sunrun vice president of energy services Audrey Lee told Utility Dive. "Developers can focus their deployment of residential solar-plus-storage in specific areas where a utility identifies a need, but that increases their sales and marketing costs," Lee said.
To be confident the value proposition for meeting the requirements of a solicitation is there, developers need extensive information about the utility's system, she said.
New York leads in using aggregated DERs as an NWS. The Brooklyn Queens Demand Management project by Consolidated Edison deferred a $1.2 billion substation upgrade with a $200 million expenditure that delivered 69 MW of DER, including energy efficiency, energy storage and demand response.
New York's regulators and utilities rolled out NWS solicitations slowly, but included sophisticated data on system needs in them, Lee said. "That made the value proposition clearer."
"When utilities publish the data that describes their needs, we are able to apply our technologies and our understanding of customer impacts and know how to meet those needs cost-effectively."
Vice president of energy services, Sunrun
If DER providers know what and where the opportunities are, they can make informed bids based on the subset of services the utility will compensate, she said.
The Glendale Water and Power solicitation for an NWS to replace its Glendale, California Grayson power plant offered another type of information equally vital to understanding potential compensation, Lee said. It was the 8,760-hour annual load profile for the capacity need at the plant's location.
"When utilities publish the data that describes their needs, we are able to apply our technologies and our understanding of customer impacts and know how to meet those needs cost-effectively," Lee said. "We need that 8,760 data."
But there are a lot of transaction costs in working out bilateral contracts with utilities, she said. Alternative approaches could be regulator-approved programs, like those for demand response, or regulator-approved published utility tariffs that act as price signals.
These alternatives would require pre-published system-wide analyses of the utility's territory showing "the values that could be supplied by deploying DER across any specified set of substations," Lee said. "We are not there yet."
Including an "8760 load profile" in a solicitation is a forward-looking concept, but a utility's load changes over time, limiting that profile's value, Wood Mackenzie's Manghani told Utility Dive. Providing distribution grid maps is another way of delivering information needed by DER providers.
"Both are better than the common utility practice of announcing an overall resource requirement and telling providers to figure out what to offer," he said. Neither is as good as giving DER providers system size and dispatch requirements and a long-term 8760 load profile derived from system planning data, he added.
"Policies are behind the curve because the technology is evolving faster and the price curve is coming down faster than expected."
DER policy manager, Southern Company
System-wide services from DER
The second opportunity for DER developers is in using aggregated customer-sited DER across a distribution system to meet system-wide needs.
There are few established tariffs to compensate aggregated behind-the-meter DER and the programs that compensate it are based on the demand response construct, Lee told Utility Dive. "New rates, programs or contracts are needed because that construct does not recognize or compensate battery discharging as generation, and only recognizes battery charging as a load-reducing demand response tool."
Utilities are increasingly aware of the need to recognize the fuller range of capabilities and services, according to industry representatives. "Policies are behind the curve because the technology is evolving faster and the price curve is coming down faster than expected," Howard Smith, Southern Company DER policy manager said during a panel discussion.
"Solar with storage is the future."
Senior director of regulatory analytics, PG&E
"Solar with storage is the future," said Margot Everett, Pacific Gas and Electric (PG&E) senior director of regulatory analytics and rates, in a different panel discussion. "But rate design is not the solution for compensation because if rates are designed as incentives for new technologies, they may distort other rates."
With cost-effective storage controlled by digital technology, "we are moving from a hardware world to a software and services world," Ted Ko, Stem policy director, said in the same panel. "In the hardware world, rates and policies were designed to accomplish one thing. Rates, policies and programs for the software and services world need to enable doing multiple things at different times."
At current costs, the value proposition of behind-the-meter storage depends on deriving compensation from a stack of services and "that's what we want storage to do," Ko said. "The technology is already in place. A more dynamic rate design will allow it to provide services for the customer and the grid. Policy and regulation on compensation need to catch up."
PG&E's Everett disagreed. "Rate design is to send price signals to customers about where and how much electricity to use," she said. "Compensation is the pay back the customer can receive for making the investment and it should be separate from rate design."
There is a win-win compensation proposition that addresses the concerns of both the end user and the utility, Sonnen's Backa told Utility Dive.
A national compensation roadmap?
"Utilities across the country recognize the 13 use cases defined by the RMI paper on battery energy storage economics," Backa said. "That could be the basis for a national dialogue, and each state commission could use the conclusions of that dialogue in a non-litigated regulatory proceeding to determine its own use cases and compensation values."
"Customer-sited, behind-the-meter energy storage can technically provide the largest number of services to the electricity grid," RMI concluded. But batteries go "unused or underutilized for well over half of the system's lifetime," and the true value of storage is maximized by the use of its "stack" of potential services.
"[Policymakers] should identify the value streams not being fully monetized and lay out a policy roadmap that each state commission can use to create a mechanism that compensates those value streams."
Policy Director, Stem
Sunrun's Lee was skeptical about the practicality of a national dialogue. "But it might work like California's storage multi-use applications rulemaking," she said. "Those guiding principles have fed into utility solicitations."
California's multi-use applications for storage are thought to be the first state-level revenue stacking rules for energy storage. The 11 rules build on the RMI foundation by defining which types of services can go to which grid levels, how those services can be used and how they should be compensated. They are expected to accelerate the use of storage to supply the grid with things like capacity and ancillary services.
Backa's idea of a national dialogue on storage compensation is "intriguing," said PG&E's Everett, adding "values that are explicit" are "something to pursue."
Such a dialogue could create some needed certainty in the market or "at least provide a starting point" for developers, Wood Mackenzie's Manghani said.
Policymakers should do more than enable the 13 services that storage can technically provide, Stem's Ko added. "They should identify the value streams not being fully monetized and lay out a policy roadmap that each state commission can use to create a mechanism that compensates those value streams."