Revamped Solar Initiative in New Jersey
New Jersey has been a good market for solar developers, but recent legislative changes have created more opportunities, especially for developers of utility-scale projects.
New Jersey is the fifth smallest US state by area, but it has more solar installations than any other state except for California. The primary reason is a solar renewable portfolio standard that the state has had in place since 2004. It requires electric utilities in New Jersey to turn in renewable energy credits each year for generating electricity from solar facilities the utilities own, or by purchasing such credits from independent solar generators, representing 306 gigawatt hours of power production between June 2010 and May 2011. This amount is scheduled to increase to 5,316 gigawatt hours by 2026. The program has created a solar-only renewable energy credit market.
Table 1 shows the amount of solar RECs — called SRECs — that New Jersey utilities are required to have each year over time. The
Table 1: SREC Requirements and SACP Price by Energy Year
SREC Requirement (gWh)
% Increase in SREC Requirement
* Actual result reported by the New Jersey Office of Clean Energy.
** Estimate provided by the New Jersey Office of Clean Energy based on energy year 2009 consumption; actual amount will be 0.2210% of electricity sales.
† SACP prices for energy years 2017–2026 not yet published.
credits are measured in megawatt hours. Any utility that fails to turn in the required number of credits must make solar alternative compliance payments — called SACPs — to the state in the amount of that year’s predetermined SACP price (currently at $675) per megawatt hour of shortfall. This places a cap on how much a utility will be willing to pay for credits in the open market.
Recent legislative changes have increased predictability of pricing and reduced the regulatory risk for new entrants into the market.
The New Jersey renewable portfolio standard, or RPS, promotes a wide variety of alternative energy technologies, including wind, biomass, landfill gas and hydroelectric generation. These sources are split into class I and class II, with the more technologically-advanced generation methods in class I. Since 2004, solar has been separated from both classes and given its own mandated level of use within the overall New Jersey RPS. The financial effect of this approach becomes clear when observing the price of credits. From June 2008 to September 2009, class I credits sold at an estimated average of $12 per megawatt hour and class II credits sold at an estimated average of $1 per megawatt hour. During the same period, SRECs sold at a weighted-average price of $544.85 per megawatt hour.
From 2004 to 2010, the solar set aside in the state RPS was expressed as a percentage of the overall RPS. However, the state converted the solar goal from a percentage of the RPS to an absolute megawatt hour target in January 2010. At the end of each energy year, June 1 to May 31, utilities are required to hold solar renewable energy credits based on their pro rata shares of all electricity supplied at retail in the state.
Prices for SACPs for utilities that fall short of their SREC holdings requirements are higher than for shortfalls in other RECs for which alternate compliance payments are made at a rate of $50 per credit. The market price for these alternate compliance payments is well above the current market price for credits at $12 and $1 for class I and class II RECs, respectively. The low prices for normal RECs is due to the ability to buy credits from generators in neighboring states and the wider variety of technologies available for generating these types of credits.
Solar projects earn one SREC for each megawatt hour produced. SRECs are tracked on an electronic platform allowing real-time monitoring as well as trading of SRECs. SRECs are labeled with the vintage of the year in which they are produced, and may be sold in the current or next two energy years.
Projects generate SRECs for 15 years, after which point the projects produce less valuable class I credits.
Recent Legal and Regulatory Changes
New Jersey has made other recent changes to its program besides setting a fixed target for solar output in megawatt hours.
The solar output targets start at 306 gigawatt hours in 2011 and increase to 5,316 gigawatt hours in 2026.
The Public Utilities Commission has been directed to set solar alternative compliance payments for 15 years into the future rather than the current eight. Because SACPs must be purchased in the event of a shortage of SRECs, these projections of SACP prices provide support to future SREC prices. Table 1 shows the current SACP prices.
The state moved recently to allow SRECs to be traded for up to three years. Giving each credit a longer life makes it more likely that an independent generator will be able to get value for them. Buyers are more likely to commit to purchase them.
Historically, New Jersey delegated great power to regulators, who could change previously published SACP prices. This caused price uncertainty that impaired the financeability of solar projects.
The state now prohibits the Board of Public Utilities from reducing previously published SACP prices. Therefore, the price ceiling will not drop unexpectedly. Once published, project developers and their financing counterparties can only expect these amounts to change as a result of action by the New Jersey legislature — still a risk, but a diminished one.
The Board of Public Utilities is also barred legally from modifying certain solar-project related contracts entered into by electric utilities after the contracts have been approved. SREC purchase contracts with terms of 10 to 15 years have been successfully financed. However, current regulations cap project output levels at 500 kilowatts — well below the output of utility-scale projects.
The net metering cap of two megawatts has been eliminated, allowing projects of all sizes to benefit from net metering.
To avoid a long-term oversupply situation, there will be an automatic 20% increase in the solar RPS target if the number of SRECs generated meets or exceeds the requirement for three consecutive reporting years starting with energy year 2013 and the average SREC price for all SRECs purchased by utilities decreases in the same three consecutive reporting years.
While the supply of SRECs in New Jersey is increasing due to continuing investment in solar projects, the solar RPS requirement continues to outpace production and is expected to do so for the foreseeable future. In energy year 2009, the solar RPS required 130,267 SRECs, but the market supplied only 75,532. According to the New Jersey Office of Clean Energy, based on energy year 2009 consumption levels, the 2010 solar RPS will require approximately 180,000 SRECs to be purchased while solar installations are expected to produce approximately 140,000 SRECs. The shortfall of 40,000 SRECs will be covered by SACPs at the 2010 rate of $693 per megawatt hour — totaling $27,272,000 in payments.
While additional projects will continue to come on line, the 2011 SRPS will require utilities to turn in 306,000 SRECs, representing an increase of approximately 70% from energy year 2010 projections. The SACP price in 2011 will be $675. This trend of rapid solar RPS requirement growth — over 20% per year — continues through energy year 2015, as shown in Table 1.
Table 2 shows the growth in the solar RPS standard from energy year 2007 to energy year 2012, as well as the mix of SRECs and SACPs used to meet these requirements.
New Jersey, like most states, is facing budget deficits. There has been no indication that the SREC program is in any danger since it is a source of funding for the state — not spending. However, the state has cut funding for a rebate program for small solar installations of up to 50 kilowatts.
Maximizing Value of SREC
There are several ways for developers, especially those seeking to develop utility-scale projects, to maximize the value of their SRECs, including demonstrating an ability to bring production on line in 2010 and 2011, addressing utility concerns that sellers will fail to deliver contracted SRECs, and adopting a strategy to match risk tolerance appropriately with the forward pricing curve.
Given the current shortage of SRECs, it is critical to show speed to market. Utilities are expected to be forced to pay the SACP during the near term to satisfy a portion of their requirements. Because most would prefer to be able to enter into negotiated agreements to lessen this cost and lend support to the solar industry, the shortage presents an immediate opportunity for developers with new SRECs.
However, the shortage of SRECs is not likely to last into the medium term in light of the increasing number of solar installations coming on line. The New Jersey Office of Clean Energy estimates that 69 megawatts of solar capacity will be installed in energy year 2010. SRECs produced in each succeeding energy year will not be as valuable because SACP prices decline over time.
Another means of maximizing the value of SRECs is to lessen purchaser risk of non-delivery. Utility experience to date is that many SREC contracts have been negotiated for projects that failed to deliver SRECs on time or at all. As result, the market is generally skeptical of new entrants. To date, companies have addressed this skepticism through a combination of demonstrating their experience in successful solar projects, presenting a record of on-time construction performance in other power projects, and, often times reluctantly, through the use of performance security in the form of letters of credit or guaranties.
The market for long-term SREC sales has not been very liquid. As a result, utility-scale projects will probably require strategies to use both bundled and unbundled sales to best match the forward price curve with the requirements of their equity investors and lenders. For instance, although lenders may express a strong preference for a single purchaser of all of a project’s SRECs, this is currently difficult to achieve for larger projects because utilities are reluctant to become overly reliant on one supplier. This reluctance to enter into larger contracts may dissipate with time as the number of SRECs each utility must have continues to increase.
Unbundled sales are currently the most common approach to maximizing value. In this arrangement, the power generated from a project is sold separately from the SRECs.
SREC purchase agreements in the current market generally run three years, with five-year contracts less common but possible, and seven-year contracts rare and deeply discounted. In three-year contracts with creditworthy counterparties, reported SREC pricing has been in the $575 to $600 range. (The three-year average SACP price for 2011-2013 is $658.) In five-year contracts, reported SREC pricing for the fourth and fifth years has dropped to the $400 to $450 range. (The three-year average SACP price for 2014-2015 is $617.) Very few contracts over five years have been reported, making generalizations difficult, but the information available indicates a drop in SREC pricing in sixth and seventh years to between $200 and $300. (The 2016 SACP is $594; the 2017 SACP has not yet been published.)
Given the disparity between the long-term offers and SACP prices, it may be better not to contract for sales of SRECs longer than two to three years unless a long-term contract is needed to obtain financing.
In bundled sales, projects sell both electricity and SRECs to the same purchaser. A potential benefit to this approach is the certainty of revenue that it provides to financing parties and the possibility to avoid the steep discount in SREC pricing that we have witnessed in the unbundled market in contracts greater than three years.
Although this approach would be the easiest to finance, it has not been widely adopted because, as in unbundled sales, terms of greater than three years are rare given the regulatory uncertainty with longer contracts. There are indications that bundled contracts may be considered by utilities for utility-scale projects in limited circumstances.
Even in situations where a bundled or unbundled approach is taken, projects typically do not contract to sell the full amount of expected power and SRECs to minimize underproduction risk.
When less than all of the SRECs are sold in a contract, the remainder may be sold in the spot market. Numerous brokers and aggregators handle Dutch-auction or electronic market sales which, in energy year 2010, have led to sales of SRECs at or above 95% of the SACP price of $693.