The U.S. energy storage market remains on track for a record-setting year, and due to increasing economies of scale and technology advances, costs are coming down, promising still greater things further down the road. 

The median price for utility-scale systems in the first quarter of 2015 was $900 per kWh, and that price didn't fall significantly in the second quarter. But, the low end of the price range went from $800 per kWh in Q1 to $750 per kWh last quarter, explained Senior Energy Storage Analyst Ravi Manghani, lead author on GTM Research’s quarterly energy storage monitor. The report, prepared along with the Energy Storage Association, was released last week.

“When the low end of the range goes down,” Manghani said, “it is an indication the rest of the market will follow.”

The downward trend in costs is being pushed by batteries themselves, but a variety of factors is putting pressure on system prices across the value chain, Manghani said.

Tesla’s April announcement that it would produce batteries at $250 per kWh is pushing other battery manufacturers, Manghani said. “They see that as the magic number to get to.”

Tesla and other manufacturers are not likely to get to that price point this year, Manghani said, but it will come in the near future.

Utility-scale batteries in PJM lead growth

The U.S. energy storage industry deployed 40.7 MW of capacity in Q2 2015, nine times the capacity installed in Q2 2014 and six times the capacity brought online in Q1 of this year. Along with 5.6 MW of cumulative installed capacity deployed in Q1, the year’s total is approaching 50 MW and Manghani expects 2015 “to be the biggest year for U.S. energy storage deployment in history.”

The numbers remain small but, "the trend is clear," Manghani said. "This is a market on a growth trajectory.”

The biggest source of growth continues to be in utility-scale capacity, GTM reported. Invenergy’s 31.5 MW project, incorporating a BYD lithium-ion battery system, went online to provide frequency regulation for the PJM Interconnection regional transmission system in Q2, constituting the bulk of new capacity.

PJM’s frequency regulation needs are also expected to drive growth in Q3. Invenergy is expected to bring another 31.5 MW BYD battery system online and RES Americas has announced two 19.8 MW projects for PJM in Q3, Manghani said.

PJM’s first mover status in the use of utility-scale storage for grid support makes it the dominant force in the sector, according to the report. Since Q1 2013, the system operator has added 100 MW of utility-scale storage, over four times the amount California’s added in that timeframe.

The next biggest growth in U.S. chemical energy storage in Q2 was in the non-residential, behind-the-meter (BTM) sector. It “is on a definite upward trajectory,” Manghani said. The sector’s 4.9 MW was its biggest quarter ever and an over 300% jump from Q1’s 1.4 MW.

Residential storage capacity increased 61% from Q1 to Q2 of this year, but the total of between 30 kW and 40 kW remains small, representing only 1% of Q2’s total deployment.

Most of the non-residential and residential growth continues to be in California, driven by incentives from its Self-Generation Incentive Program (SGIP), according to Manghani. The program’s combination of up front incentives and performance based incentives are calculated to return up to 60% of the cost of the storage system, he said.

The state’s policymakers see storage as a solution to the growing “duck curve” concern, Manghani said. It could resolve the dilemma of having too much solar generation in the early afternoon and too much demand early in the evening by holding that early afternoon sun until it could be used to help meet the early evening demand peak.

The leading vendors in the non-residential segment of the market are Tesla, Green Charge Network, Stem, Coda, and Sharp, according to Manghani. In the residential market, the leaders are Tesla, Outback Power, Sony, and SMA.

There is no surprise in Tesla’s leadership or in the other leaders, except in the case of SMA. It is a major player in the inverter space but seems to be looking to crash a new market.

In the non-residential space, the leading vendors tend to do their own integration, Manghani said. In the residential space, perhaps as a measure of SGIP, most of the new capacity is part of solar plus storage systems and the work is being done largely by solar installers.

Policies shaping the future of utility-scale storage

Earlier this year, PJM’s ancillary services market was seen as a key to battery storage growth. Federal Energy Regulatory Commission (FERC) Order 784 had required grid operators to find ways to monetize fast-response frequency regulation services provided by energy storage systems. PJM took the implementation lead with an effective signal, the operational element, and an effective capacity multiplier, the compensation element.

In Q1 2015, Manghani said, the New England system operator (ISO NE) and the Southwest Power Pool (SPP) implemented compensation and market mechanisms similar to PJM’s. This suggested there would be new opportunities in ancillary services markets other than PJM for utility-scale storage providers. But those markets are still emerging.

A new PJM market and a new system policy could change energy storage providers’ role on that system.

Beyond a certain point on the supply curve, increased fast frequency regulation creates diminishing returns, and PJM’s market activity suggests it is either near or at that point, Manghani explained. New market rules are being designed to avoid sending price signals to add more storage capacity for this function.

“This is PJM’s indication the premium for fast frequency regulation will not last indefinitely,” Manghani said.

On the other hand, FERC just approved PJM’s proposed capacity performance market model, he said, making it conceivable that battery storage systems could shift from frequency regulation to capacity service. Those systems already deployed and under construction might have to adjust, to release “multiple hours of resource availability instead of the sub-one-hour discharge durations used for frequency regulation,” Manghani said.

It is not yet clear which market storage providers would prefer, and it is possible they would bid into both and operate their systems to meet the needs of whichever market they were serving. 

In Texas, HB 3732 altered the Texas Economic Development Act, narrowing its incentives to create large scale Compressed Air Energy Storage (CAES) and removing incentives from battery systems. It is good news for two proposed multi-hundred MW CAES projects, Manghani said. But it is not yet clear the Texas projects will become the first new U.S. operational systems in decades for the notoriously problematic technology.

Factors guiding BTM storage growth

Potentially more significant than developments on the utility's side of the meter are emerging policies likely to guide the behind-the-meter storage market for both homes and businesses. 

Both the California Public Utilities Commission’s Distributed Resource Plan (DRP) and the New York Public Service Commission’s Reforming the Energy Vision (REV) will lead the nation into an almost futuristic use of BTM storage, Manghani said.

“Behind the meter storage, along with the distributed generation it is being installed with, will be aggregated and used in system-level grid service applications,” he explained.

A test aggregation program in Kentucky is also underway and Massachusetts has begun studying grid moderization, though in the absence of state policies. In California, where utilities are mandated to build or purchase 1.3 GW of storage by 2020, a pilot project from Stem and Pacific Gas & Electric successfully bid aggregated battery storage into CAISO real-time markets for the first time last week. 

“California and New York have historically been ahead of the curve so it is natural others will move in the same direction,” Manghani said. “Not all policy activities are growing at the same pace and not all will lead to more storage this year or next year, but the trend is toward a growing market.”

There are three factors that could disrupt current trends, he said. It could be accelerated if more states move more quickly to time varying pricing because that would increase the value of self-generation like rooftop solar stored for use when prices are higher.

The trend could be either accelerated or decelerated by the kinds of changes in net energy metering (NEM) being pushed by utilities from the West Coast to New England, depending on how the imposed rate design remunerates electricity use. 

Finally, the trend could be decelerated if policy initiatives like the DRP and the REV are turned back, leaving customers with a diminished value proposition for their distributed resources.

The momentum in the California and New York regulatory proceedings make the first and third factors unlikely. It is not clear what the ultimate outcome of the NEM fights will be. But, Manghani said, “these things could change the economics overnight.”