Competitive solar-plus-storage moves closer to reality
Incentives and economics result in more pairings of solar power and energy storage.
Solar-plus-storage projects are becoming more competitive with other, more traditional resources, as more projects are cropping up.
Earlier this month, EnSync Energy Systems signed a power purchase agreement for a solar-plus-storage project at a housing complex in Oahu, Hawaii.
Last month, Origis Energy USA and Sterling Municipal Light Department completed the first community solar-plus-storage project in Massachusetts. And in March Cypress Creek Renewables commissioned 12 solar-plus-storage projects that provide energy to customers served by the Brunswick Electric Membership Corp. in North Carolina.
The EnSync project is designed for 750 kW of solar power backed up by 500 kWh of storage. The Origis project is for 1 MW of solar power and 2 MWh of energy storage. Cypress Creek's Brunswick EMC project consists of 12 individual projects that pair 500 kW of solar and a 500 kW / 1MWh battery system from Lockheed Martin.
"We are definitely seeing more and more projects that combine solar and storage," Caileen Gamache, senior counsel with Norton Rose Fulbright, told Utility Dive. What started as small, behind-the-meter projects, is starting to get bigger, according to Gamache.
Solar-plus-storage projects could be competitive without any federal tax incentives in California by 2020, Paul Denholm, senior energy analyst at the National Renewable Energy Laboratory (NREL), told Utility Dive. Denholm added that the time is not far off when these project pairings will be competitive with gas-fired peaking plants in other locations such as the Southwest.
"Solar-plus-storage could be competitive in a sizeable fraction of the United States, but it is hard to say exactly when, mostly because of fluctuations in the cost of natural gas," Denholm said.
The analysis is not static. One of the chief inputs in NREL's analysis is the cost of lithium ion batteries which are expected to continue to trend downward. But natural gas prices are also a factor because they often determine the operating costs of fossil fuel plants.
The go-to metric for those comparisons is the levelized cost of electricity (LCOE), which measures the lifetime costs of a technology or project divided by its output. But "LCOE is only half the cost; it doesn't account for value," Denholm said.
"Accounting for value gets tricky," Denholm said. "You need to understand what a project is offsetting. When storage is added to a project, the costs always goes up, but it makes a project more valuable."
In doing its analysis, NREL makes assumptions about the price of natural gas and runs energy simulation models on the cost to run other resources. Next, NREL does year-long simulations of a project using cost estimates that look 20 years into the future to come up with a benefit/cost ratio to evaluate the attractiveness of various PV and storage configurations under a range of conditions.
That analysis includes a capacity value for storage, Denholm said. Even in markets without a capacity market, it is possible to get paid for capacity through resource adequacy payments or payments for the value of capacity that are built into bilateral contracts. However, Denholm said he is more conservative in considering revenues from ancillary services.
There are so many energy storage developers crowding into the market to take advantage of ancillary market revenues that "we tend to think those payments will be worth less" going forward, he says.
Even though the value of capacity is subject to the same curve of diminishing returns, it is "a much, much bigger market," says Denholm. "Capacity is needed everywhere." The total market for ancillary services is about 2.5 GW, but the capacity market is larger by an order of magnitude, he says.
NREL's analysis also shows the same saturation effect for solar power. As solar penetration increases, NREL finds that the benefit/cost ratio of a stand-alone solar project declines, but that ratio increases when the project is coupled with energy storage capability.
However, there are also trade-offs between different types of solar-plus-storage projects. In an August 2017 report, NREL looked at four configurations for solar-plus-storage projects: independent systems that are not co-located, AC-coupled systems that are co-located but do not share an inverter, DC-coupled systems that are co-located and share an inverter, and tightly DC-coupled systems charged entirely by solar power that share location and at least one inverter.
Benefit/Cost Ratio for PV plus storage in California in a 2020 scenario with two different levels of PV penetration and the 30% ITC
NREL's analysis found that independent systems have the highest costs and, in most cases, a lower benefit/cost ratio than coupled systems, which have greater efficiencies and lower costs. But the analysis becomes more complex with DC-coupled systems.
If a DC-coupled system is able to access a full range of revenue streams, it can have a high benefit/cost ratio, but if the system is tightly coupled — only charging with solar power — it can lose revenues because the system cannot be optimally dispatched. The trade-off, however, is that only batteries charged by solar power are eligible for the federal investment tax credit (ITC). The 30% value of the ITC is enough to make up for the loss of revenues, producing the highest overall value of the various configurations, according to NREL's analysis. But while operating a solar-plus-storage system in a tightly coupled manner may benefit the owner, it does not necessarily provide the highest value to the grid, the NREL analysis found.
The ITC requirements also pose a risk to solar-plus-storage developers, which they often try to share with offtakers. ITC limitations are often one of the most heavily negotiated items in a PPA for a solar-plus-storage project, says Gamache.
Those are all factors that go into estimating the market for a solar-plus-storage project.
"As we think about developing new projects, we think it's important to understand where the markets are going and what will be the most effective design for the system," Brian Knowles, director for energy storage at Cypress Creek Renewables, told Utility Dive via email. "Additionally, it's critical to understand certain dynamics playing out on the grid as that may lead to a need to shift our PV production."
Knowles says he is seeing a lot of "encouraging policy developments around energy storage right now." And, as a result, "we think it's important to give ourselves the optionality storage can provide for our assets early on in the development cycle."
Knowles says it is hard to estimate how many of Cypress Creek's projects will end up having integrated energy storage, but "given momentum of the industry right now it could be the majority of them."
Pairing up in the residential market
Energy storage is also becoming a factor in the residential solar market. Battery costs can pose a high barrier to entry in the residential storage market, but regulations in some markets are creating opportunities for combining storage with rooftop solar installations. In addition, as NREL points out, storage has a much smaller footprint than solar panels and can be deployed to defer new transmission and distribution investments or to replace peaking capacity in urban areas. Those benefits are hard to replicate in the utility-scale market.
Already the economics of solar-plus-storage work in Hawaii and California, Anne Hoskins, chief policy officer at Sunrun, told Utility Dive.
"We are seeing strong demand" for Brightbox, Sunrun's home solar and battery service, Hoskins says. Brightbox was launched in Massachusetts less than three months ago and nearly 10% of customers have already added storage to their solar service. In California, more than 20% of new sales to direct customers include a Brightbox, and in parts of Southern California that total is as high as 50% of sales.
One of the key drivers of solar-plus-storage in California is the state's switch from net metering to time-of-use rates. "We saw tremendous interest from customers" in Brightbox when the state imposed TOU rates on solar customers, Hoskins said.
On the East Coast, Hoskins sees "a huge opportunity" in helping customers with resiliency. Customers are paying $7,000 to $10,000 for a backup generator that will be rarely used. Instead, they could invest in a solar-plus-storage system that could be continuously used to provide power, with backup capabilities when needed, Hoskins said.
Sunrun is also looking at states such as New York, where regulators are encouraging utilities to consider non-wires alternatives. When customers are willing to make investments, Hoskins asked, why should utilities invest billions of dollars on grid resiliency programs whose costs get passed on to ratepayers?
If regulators continue to set policies that are punitive to customers, more customers will turn away from the grid, Hoskins said. Utilities have a role in maintaining the system, but the unanswered question, she says, is the role of the utility in this distributed system. Meanwhile, there are "customers asking for storage, and we are going to be ready for that," Hoskins said.
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