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Q&A: SREC Underwriting Issues Related to Financing Solar Projects

Published by Tony Grappone, Novogradac & Company LLP RETC Working Group on Wednesday, September 1, 2010

Journal cover September 2010   Download PDF

Question: Are lenders underwriting permanent loans for solar projects that are dependent upon realizing future Solar Renewable Energy Certificate (SREC) revenues?

Answer: Some are. However, projects that have entered into long-term fixed-price SREC contracts are generally perceived as much more “bankable” than those attempting to trade their SRECs based on fluctuating market conditions over time.

As several states abandon costly rebate programs in favor of Solar Renewable Energy Certificate (SREC) programs, new issues are emerging that should be considered in order to complete project finance. The move from rebates to SRECs shifts subsidies based on eligible costs incurred to one that is based on the production of clean energy. In essence, SRECs are viewed as a more viable mechanism for achieving states’ renewable energy portfolio standards (RPS). Because SRECs are based on a project’s long-term production of clean energy, the ultimate amount of subsidy is uncertain, which complicates the process for satisfying a lender’s underwriting criteria.

Using the SREC program in Massachusetts as an example provides a look at various issues that should be considered when project financiers evaluate which strategy to execute.

Massachusetts Solar Carve-Out ProgramIn January 2010, the Solar Carve-Out program took effect in Massachusetts and from that date forward new eligible solar projects will generate SRECs  instead of a one-time rebate for costs incurred. (For detailed information about project eligibility and participating in the Massachusetts SREC program, contact: [email protected] or go to and search for solar carve out.)

Under the Massachusetts SREC program, utilities other than municipal light districts are required to include a minimum percentage of certain renewable energy sources in the total amount of electricity they sell during the year. Electricity produced from the sun is one of the eligible sources. Utilities can meet their requirement by accumulating SRECs purchased from owners of solar projects. If utilities fail to accumulate enough SRECs during a given compliance period, they may be subject to what is known as an alternative compliance payment (ACP). An ACP is essentially a levy against utilities for failing to produce/sell a minimum amount of qualified clean energy. The ACP in Massachusetts is $600 per megawatt hour (MWh), or 60 cents per kilowatt hour (kWh). This is known as the ceiling price and it is the maximum amount a utility could be required to pay for the shortfall of accumulated SRECs. Therefore, if a utility falls short of its goal to accumulate 1,000 MWh worth of SRECs it could be subject to an ACP of $600,000.  In order to avoid the ACP, utilities can purchase SRECs from project owners at a price between $300/MWh, or 30 cents/kWh (known as the floor price) and the ceiling price.

Project owners plan to sell their SRECs in one of two ways. First, they can accumulate SRECs and sell them based on fluctuating market conditions, hoping that utilities struggle to meet their goals and thus pay prices substantially higher than the floor price. This option is appealing to owners who are confident utilities will fall short of their goal by an amount sufficient enough for them to buy SRECs at prices substantially above the floor price. However, by selling SRECs based on market conditions over time, owners assume  the risk for significant variability in the realization of SREC revenues.  

The second option is for owners to enter into long-term fixed-price contracts with SREC aggregators or brokers, which are companies that purchase SRECs from owners and bundle them into larger batches that are then sold to utilities. By doing this, owners will enter into multiyear fixed-price contracts (i.e. five years) through which the aggregators agree to purchase the owners’ SRECs at a set price. This option is appealing to owners because it takes variability out of the process and provides a predictable stream of cash flow. However, because this option shifts the price variation to the aggregator, the prices offered in contracts could likely be either the floor price or something perceived as substantially below market. Thus owners will naturally feel as though they are leaving significant revenues on the table by entering into long-term fixed-price SREC contracts.  

And so the debate begins ... To hold or not to hold?

Fortunately there are two very powerful forces helping owners decide which option to choose: time and money. Owners usually have commitments under their power purchase agreements (PPAs) to finish their projects on or before a certain date. In addition, owners typically need permanent loan proceeds to fully finance their projects. Thus the owners only have so much time to raise the funds they need to complete their projects. Lenders generally perceive projects without long-term fixed-price SREC contracts as riskier.  Instead, in order to satisfy their underwriting criteria, lenders usually prefer long-term fixed-price SREC contracts from creditworthy aggregators.  As owners approach the date by which they must complete their projects they become more willing to accept the strict underwriting criteria that persists because of the lagging economy, which is to negotiate the best fixed-price contract available. However, owners will also generally wait as long as they can in order to maximize the best contract terms possible.

This means the renewable energy industry can expect a flurry of activity during the fourth quarter of 2010 as owners and utilities converge on each of their deadlines, both having significant financial ramifications to each. The owners have a deadline to complete their projects and the utilities have a deadline to meet their RPS quota. It will be interesting to see how prices are ultimately determined.

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