Six Policy Catalysts Driving the Battery Storage Industry

June 9, 2020 – On June 8th, Capstone held a conference call exclusively for clients with the Energy Storage Association (ESA) to review the federal and state policy landscape and the probabilities of congressional action to extend clean energy tax credits.

We believe there are strong market signals for battery storage and other forms of energy storage in states that are embracing deep decarbonization goals, regardless of the outcome of the 2020 elections. However, a 2020 Democratic sweep of the White House with majorities in the House and Senate would undoubtedly supercharge policy tailwinds for the industry. Solar plus storage deployments are very well-positioned for high growth rates, with favorable outlooks for Clearway Energy Inc. (CWEN, $4.4 billion market cap), Innergex Renewable Energy (INE on the Toronto exchange, $3.4 billion market cap), and Tesla Inc. (TSLA, $175 billion market cap). Shares are up about 30% for Clearway and Innergex and more than 75% for Tesla since we wrote about those companies last June.

While industry growth will likely continue for lithium-ion batteries, we expect it also will branch out into other chemistries and other forms of energy storage capable of much longer storage duration times, including pumped hydro, compressed air, and flow batteries.

Below, we share the six key policy drivers that we believe are impactful to the pace of battery storage technology deployment ahead of the election:

1. COVID-19 Disruptions

While the impacts of COVID-19 ripple through the clean tech industry, battery storage has fared well with strong deployment numbers for Q1 2020. Modest delays are expected in Q2 due to social-distancing measures creating lag time with on-site deployments. Delays are expected in the behind-the-meter asset class as many businesses have temporarily closed. Despite the COVID-related issues, fundamental demand drivers remain intact.

2. Clean Energy Tax Credit Extensions

Democrats are poised to release a clean energy tax credit discussion draft in early July 2020. It will be modeled in part after the Growing Renewable Energy and Efficiency Now (GREEN) Act, which was informally circulated in November 2019. This package and its timing are largely expected to be messaging tools. However, action on such a bill is possible during a lame-duck session and beyond, depending on the election outcomes. Such a bill would be strongly favored by Democrats, and chances of enactment increase if Democrats turn the White House and Senate in the November elections.

The act would expand tax credits for new non-hydro renewable generation in an effort to double their market share to 19%–26% from the current 10%. Specifically, standalone energy storage technology could be eligible for an expanded investment tax credit (ITC) of 30% through the end of 2024, with a phase-down to 26% in 2025, and 22% in 2026. The GREEN Act includes provisions that would translate some tax credits into cash payments—allowing an asset to “cash in” at 85% of the value of the tax credit. Such a provision would be particularly meaningful during the COVID-19 recovery years when taxes could be reduced due to lower productivity during the virus. Thus, cash payments may be more impactful than tax credits.  

Currently, battery storage technology can be eligible for the ITC if it receives the majority of its recharging from solar generation sources. Allowing standalone battery storage under the ITC would untie storage from specific configurations so that storage assets can be used where they are most valuable. In addition, transmission and distribution (T&D) infrastructure could be unlocked, and pairing energy storage with wind or hydropower could gain more traction. Most importantly, the move could stimulate a wave of retrofits to add storage capacity to existing solar arrays, which would add resiliency, increase flexibility, and improve the economics of the distributed solar generators.

If renewable tax credits are extended and standalone battery storage is included, we believe battery storage growth will likely accelerate.

3. PJM Interconnection and FERC’s Minimum Offer Price Rule

In December 2019, the Federal Energy Regulatory Commission (FERC) issued a ruling that requires state-subsidized energy assets competing in the PJM Interconnection capacity market to adhere to bidding floors—or minimum offer prices (MOPR)—to ensure such assets do not artificially suppress capacity market prices. While FERC is still finalizing the rules, newly deployed battery storage assets that receive direct state funding could lose the ability to earn capacity payments due to the MOPR, presenting headwinds to battery storage in PJM states—as financing could become more difficult absent capacity revenues.

However, the policy for storage assets is still unclear, and not all forms of storage deployment are likely to trigger the MOPR. The Energy Storage Association believes PJM has some discretion in this matter, which will depend on the underlying economics of the project. If state policy, like that in Virginia, pushes storage assets through direct procurement, such rate-based assets would trigger the MOPR. New York and Maryland have tax credit policies that also would likely trigger the MOPR. There is a gray area around service contracts with utilities. Hybrid resources, like solar plus storage, present even more opportunity—and ambiguity—because if solar assets are subject to the MOPR, then it may be possible to decouple the assets so the storage is a merchant asset, escaping the MOPR but retaining the ITC.

The MOPR policy conflicts with many state decarbonization goals. States like Illinois, Maryland, and New Jersey are exploring removing capacity from PJM in favor of other state-based clean procurement mechanisms. We believe if the White House changes parties after the November election, a democratic majority at FERC would significantly modify the MOPR rule or abolish it altogether.

4. State Energy Storage Programs

State energy storage programs, including energy storage mandates, clean-peak programs, and other incentives are important policy tools in leveraging battery storage deployment. The most important state programs address the following underlying market conductions:

  • Access barriers: Interconnections and market access issues are paramount. Even in states with ample battery storage mandates, deployment can grind to a halt without appropriate interconnection priority policies.
  • Competition issues: FERC deals with these issues in Order 841, which addresses access for battery storage technology in all wholesale markets for all products (energy, capacity, ancillary services). In vertically integrated states, ESA’s goal is to have energy storage assets considered in all planning and procurement processes, including integrated resources planning (IRP).
  • Valuation and compensation: Rules for markets were developed before storage was widely available, so the implementation of FERC Order 841, which addresses barriers to entry for storage. Regional transmission organization (RTO) policies are further shaping important value-stacking provisions where an asset can earn revenue in the energy, capacity, and ancillary products markets, sometimes simultaneously.
  • Targets, mandates, incentives, and utility programs: These programs draw the greatest interest as they create certainty for asset managers around finance streams for projects.

5. Spotlight on Storage Plus Solar

Hybrid resources, like solar plus storage, are gaining market share. In some markets, hybrids are outpacing standalone storage queue requests. In the Electric Reliability Council of Texas (ERCOT), the energy arbitrage that storage enables is meaningful, particularly because Texas Interconnection is a market without capacity payments, so selling energy when prices are highest is a central market strategy. Storage can enable more strategic energy offerings by storing electricity for discharge during the demand peak, which is often a couple of hours after the peak for solar generation.

According to a Lawrence Berkeley National Laboratory (LBNL) and the Electric Power Research Institute study, “the added value of such a [solar plus storage] hybrid plant in wholesale power markets given recent pricing trends is $13 to $31 per MWh in the combined energy and capacity market in California and $1 to $9 per MWh in the energy-only power market in Texas.” The LBNL study found significant increases in battery storage pairings with solar and emerging pairings with wind generators: “In the interconnection queues, a quarter of all proposed solar projects are combined with batteries, with 4% of wind projects also proposed as hybrids. In California, almost 2/3 of solar projects are proposed as hybrids.” These trends are presented graphically in Exhibit 1.

Exhibit 1: Estimated Standalone Battery Storage and Storage Plus Renewable Capacity in Each Independent System Operator Queue

Source: Lawrence Berkeley National Laboratory and the Electric Power Research Institute

6. Public Utility Regulatory Policy Act (PURPA)

The PURPA statute originates in the 1970s and mandates that utilities procure renewable generation—whether they want to or not—if it is produced by a qualifying renewable facility (QF) at specified rates. In September 2019, FERC proposed to revise its PURPA interpretations that would reduce the volume of QFs and the generosity of contract terms. The impact of this policy revision on battery storage, if it is finalized, would be somewhat muted because FERC has declined to be dispositive on exactly how battery storage fits into PURPA.   

Instead, FERC has left the issue to the states, which usually deliberate through their public service commission. These reforms would be more impactful in vertically integrated states where QFs have driven solar. We believe if the White House changes parties after the November elections, a democratic majority at FERC would modify its PURPA interpretation policy to be more generous toward renewable and storage contracts.