In March of 2018, clean energy advocates in Massachusetts were pushing for a few key priorities: increasing the RPS, extending net metering caps (again), pushing back on aggressive utility proposals for monthly reliability charges for solar energy, and establishing more ambitious long-term goals for energy storage. In the middle of these efforts, Republican Governor Charlie Baker introduced a $1.4 billion bond authorization bill focused on climate mitigation and adaptation. The Governor surprised everyone by including in the bill an interesting new policy, a Clean Peak Standard.
The language in the bill was limited in its details but essentially directed the Department of Energy Resources (DOER) to promulgate regulations that will do several things:
- DOER must work with ISO New England to define a Clean Peak Standard, not to exceed more than 10% of total demand hours.
- All retail electricity suppliers will be required to supply a “minimum percentage of kilowatt-hour sales” from clean peak resources.
- DOER will determine what technologies qualify as clean resources (presumed to be RPS Class I eligible technologies).
- Cost increases will be contained to no more than $.0005/kWh.
- The standard will expire in 2040.
The concept behind the CPS is to create a market-based program, similar to an RPS, that will provide a premium for cleaner sources of energy or demand reduction during peak windows when prices and GHG emissions are higher. Massachusetts is not the first state to propose a CPS; both Arizona and California have proposals that have not yet been implemented. To date, in Massachusetts the CPS has been well received and appears to be progressing through the legislature. However, as is true with any complicated policy, the devil is in the details and the Governor’s bill is pretty light on the details.
Depending on the final regulations, there are several important decisions that could dramatically affect the program. The first is deciding what will qualify as clean. As mentioned above, the assumption has been that the regulations will default to RPS Class I technologies. But what about demand management programs? Will “negawatts” qualify for a CPS incentive? Could the definition be expanded to include alternative portfolio standard (APS) technologies? What are the GHG implications if they are?
Although the CPS could be a driver for demand management programs, it appears that the primary goal is to promote energy storage and it would likely encourage the deployment of renewables paired with storage—essentially making renewables “dispatchable.” However, it’s not quite that simple. Advocates of “stand-alone” storage systems (systems that charge from the grid) argue that the GHG benefits of stand-alone and renewable-paired systems are the same.
Wait, you say. How could this be? Surely a storage system that gets its power from a clean energy resource must be better for GHG emissions than one that is charged from the grid, right? Well, yes and no. The argument points out that when a paired system charges its battery, it is preventing that energy from going onto the grid. Therefore, its GHG emissions impact is not that of the wind or solar plant from which it charges, but rather the marginal unit (usually fossil-powered) that is required to come online to offset the energy that is not coming from the clean resource.
Another way to think about the “marginality” issue is to look not at how the battery is charged but when. If the system is charging when there is an over-generation of clean energy (think middle of the day for CAL ISO’s famous duck curve when demand is low but solar production is very high), the marginal unit comes from clean energy. So whether the storage system is paired with renewables or not, the GHG impact is zero under this scenario. Conversely, if the battery is charging when there is less renewable power going into the grid and the marginal unit is a traditional fossil resource, then regardless of where the storage system gets its energy, it has the same GHG impact as the fossil-based marginal unit. From a grid perspective, this means that we value storage strictly for its attribute to store energy and separate it from the generation attributes.
This approach may make sense for running the grid, but what does this mean for energy consumers? Again, the devil is in the details but from a behind-the-meter perspective there are many reasons to consider combining renewables (likely solar) and storage. The first is that when a storage system is combined with a solar energy system, it can qualify for the Federal Investment Tax Credit. The second is that in states with solar programs, charging a battery from your own solar system is the cheapest option. Third, many consumers face high demand charges and capacity charges and a storage system can dramatically lower these costs. In areas with time-of-use rates, it also enables consumers to arbitrage. Fourth, the storage system would enhance resiliency and continuity of operations.
The fifth benefit is the ability to drive additional revenues—for example, participating in forward capacity markets or potentially a CPS. However, there is currently a debate as to who should own behind-the-meter storage capacity: developers and system owners, or the electric distribution companies? This debate is being hashed out in states with high demand charges like New York and Massachusetts. Energy consumers and developers would be smart to watch their DPU dockets closely as this important, but not well understood, issue is being decided.
Lastly, even if customers own their capacity rights, it is unclear if they would participate in a CPS. Currently, C&I energy consumers are still sitting on the fence when it comes to energy storage, even though they could save thousands or even millions of dollars a year. A recent study by the National Renewable Energy Laboratory showed that energy storage offered compelling payback windows for 189,000 commercial customers in Massachusetts—those paying more than $15 per kilowatt. Yet, with the exception of projects that have received demonstration grants from the state, very few storage systems have been built. This irrational economic behavior is typical of nascent technologies where the risks are not well understood. Would we expect a program like a CPS where there could be penalties for non performance to encourage these customers? The increased variability, combined with the threat of penalties, is unlikely to get them off the fence.
When it comes to the potential impacts of a CPS, much of it will depend on the final regulations and how the issues mentioned above are decided. However, it’s probably safe to conclude that a CPS will send market signals that will incentivize storage and establish a long-term market. How much it will directly benefit energy consumers is still TBD. It’s also safe to conclude that it is unlikely a CPS will benefit energy consumers and promote behind the meter storage in the short term. Indeed, since a CPS has an Alternative Compliance Payment (ACP) function similar to a RPS, there is a chance retail suppliers may just pay the ACP and little storage will actually be deployed until the requirement is escalated or storage costs decrease.
Here we face a bit of a chicken and egg problem. Yes, a CPS will send the right pricing signals, but without an installed base, an efficient supply chain, and lower soft costs, EDCs may just pay the ACP. However, there is a way to jumpstart the market and directly help energy consumers by encouraging energy storage and its associated benefits
—energy storage rebates. Similar to the early days of solar energy and electric vehicles, where the risks and benefits are not well understood, rebates are a great way to jumpstart a market, drive down soft costs, and help consumers reach that tipping point to move ahead with a project. They are also a good complement to a CPS and can serve as a three- to five-year bridge program to help the market mature while also directly lowering costs for consumers in addition to the grid and resiliency benefits.
So yes, a CPS holds great potential for Massachusetts and other states as an efficient market-based approach to develop energy storage and its associated benefits, but it may take a long time and may potentially only increase costs in the short-term without significant deployment of storage. BTM rebate programs are the perfect complement to a CPS. More recently, businesses and clean energy advocacy groups have proposed a BTM rebate program based on a similar program in California called Self Generation Incentive Program (SGIP).
The proposal, called MOR Storage, has been well received in the legislature and by the Department of Energy Resources. The question then becomes how to pay for it. Traditionally, a program like this would have been paid for, ironically, by ACP payments. However, due to the success of both the RPS and the APS, costs are now so low that EDCs are seldom paying the ACP. This is where the last part of the debate gets decided.
Through a systems benefits charge and revenue from the Regional Greenhouse Gas Initiative, Massachusetts has become a national leader in energy efficiency programs. These significant resources could be directed towards active demand management programs like energy storage rebates. The timing is excellent as the Energy Efficiency Advisory Council (EEAC) is currently setting its next three year budget. However, Active Demand Management (ADM) is a bit outside the usual scope of energy efficiency programs so we will have to see how willing they are to move beyond their traditional programs. That being said, the Energy Diversity Act (Chapter 188 ‘16) specifically mentions the use of Energy Efficiency funds for energy storage if the storage can be shown to provide sustainable peak load reductions. As they make their budgeting decisions, we think EEAC would be wise to remember that in Massachusetts, the top 1% of energy used during the highest demand periods costs 10% of the overall costs and the top 10% costs 40%. Jumpstart energy storage and drive down energy costs? What’s not to like?