Solar power provides more than just electricity. It offers a source of clean, job-creating energy as well as services to the grid, among other benefits. For these reasons, a majority of states have decided to require a certain percentage of electricity be sourced from solar and other renewable energy technologies. These are commonly referred to as Renewable Portfolio Standards (RPS). The growth of solar has led to questions of how best to incentivize its continued adoption to meet RPS goals.
The traditional way to do so has been through the creation of a renewable energy credit (REC) market. Owners of solar and other renewable energy sources earn these credits based upon how much renewable energy their systems generate. A typical solar homeowner will produce one credit per year, for every 1,000 kWhs of electricity they produce. (or one megawatt hour) These credits can then be sold on a market, similar to a stock or bond. Utilities buy these credits from energy suppliers as a way to satisfy their RPS requirements.
New Jersey lawmakers are considering phasing out solar RECs (SRECs) completely in favor of other incentives. While the industry and solar supporters alike are pushing for a short-term extension of the SREC program to stabilize the solar market, the bigger question on everyone’s mind is, what comes next?
New Jersey’s solar market boomed between 2009 and early 2011. This was quickly followed by a dramatic drop in SREC prices in the summer of 2011, due to fears of a possible oversupply of SRECs. This caused anxiety among those who had recently financed solar panels and were using SRECs to help meet their payments. New Jersey lawmakers, wary of the volatility of the renewable energy credits, wish to avoid a rerun of the 2011 scenario. A similar phenomenon happened in Maryland in early 2016. The price of SRECs plummeted from $120 per certificate to about $18 a year later.
There are advantages and disadvantages to using SRECs as a means to promote solar. SRECs are a production-based incentive. Nathan Phelps, Program Manager, DG Regulatory Policy for Vote Solar, says this encourages larger solar projects to maximize kilowatt-hour production. Also, because of inflation and because SRECs are paid out over a long period rather than all at once, their future cost to the state government is continually reduced. “This is important in comparison to rebate programs,” Phelps said, “which normally provide the whole incentive in year one.”
One of the most important disadvantages to SRECs, according to Phelps, is that they are a tradable commodity. This means neither a customer nor a third-party-owned developer (depending on the circumstance) receives the full value of the incentive, because other parties obtain value by buying, selling, hedging and aggregating the certificates.
“SRECs (or RECs in general) can create jobs, but those jobs do not directly result in the development of solar,” Phelps said. “If the point of the incentive is to develop solar, then the incentive should – to the maximum extent possible – go directly to the owner of the solar system.”
Related to this concept of tradability is volatility. Because the price of SRECs depends upon their market value at any given time, that price cannot be fixed. Phelps sees the situation of Maryland’s falling SREC prices as a case in point.
“Since SRECs are a market-based incentive, if the market begins to crash, then the entire point of the program begins to fail,” Phelps said. “It creates problems for customers that have already built their systems, but are expecting some type of payback as a result of SRECs, and it creates uncertainty for future customers.”
Inversely, many policy makers argue this is exactly what SRECs are supposed to do—when there is abundant supply, the price is supposed to drop, and when there is a shortage of solar (compared to the legislated targets), the price goes up. In theory, according to these policy makers, it is the most efficient way to build the market.
The challenge, Phelps explains, is that this price volatility drives up the initial price of SRECs, as the market discounts future SREC prices. As a result, states sometimes offer SRECs at twice or two-and-a-half times the minimum price needed for the payback period of ten years, and this volatility makes it hard for developers to use the SRECs to obtain financing for their systems.
In Oregon’s recently enacted community solar program (see this recent Solar United Neighbors article), the SRECs that a community solar project may create can be either “retired” or retained by the owners or subscribers, but not sold to third parties. Jaimes Valdez, Policy Manager of Spark Northwest, believes that this was “a victory in a sense for the integrity of SREC markets”. However, he thinks, from a monetary sense, there could be more value to customers if SRECs could be sold or aggregated. Jeff Bissonnette, Executive Director of OSEIA, says that, in some situations, the SRECs could have been made part of an agreement between the developer and the participant that might have brought additional value. But this would have required additional consumer education and explanation and could have led to confusion, and so industry representatives in Oregon stopped pushing the idea.
Massachusetts’ Department of Energy Resources (DOER) chose to extend its popular SREC II program in January of this year. It did so because the program was seen as successful in incentivizing solar production in the state and not expensive to the state government. Additionally, a new program designed to supersede SREC2 – known as SMART – was not yet finalized. Massachusetts’ continued use of SRECs is only for the short term. The SMART program will replace SREC2, as DOER is attempting to reduce the costs of solar incentives by creating a fixed, predictable incentive over time. This incentive may be lower than SRECs currently are. For example, a solar homeowner might receive a fixed credit of $0.33 per kWh produced for the next ten years. In that case, the variable would not be the market price of SRECs, but the amount of solar energy actually produced by the homeowner. An approach like this would eliminate the efficiency of the tradable SREC market model, but it could ensure that a much larger part of the SREC benefit went to the solar owner/developer rather than third party finance companies, and aggregators.
Phelps strongly supports consumer education, no matter what the incentive program. “SRECs (and really any incentive program) tend to require a lot of education of customers. Any program (including SRECs) will only be successful if developers, financial entities and customers can understand and use the program.”
These questions and concerns over how to design a solar incentive to succeed the current SREC program are captivating the New Jersey solar industry at present. They will be addressed in the upcoming Energy Master Plan proceeding, a recurring review of the state’s energy programming.