Posts Tagged ‘Renewable Portfolio Standard’

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SREC Price Determinants in 2011

Wednesday, February 23rd, 2011

What Will Drive SREC Prices in 2011?

Most market participants are familiar with the three basic drivers of solar renewable energy credit (SREC) prices – SREC supply, SREC demand, and state solar compliance penalties. Most of this information can be found on RTO and state commission websites and analyzing this data yields an adequate view of the current state of the SREC market. However, to fully understand the 2011 SREC markets, a better understanding of the drivers of supply and demand is required.

SREC Supply Forecast:

The price of panels and installation will be an important input in determining the future supply of SRECs. Panel prices and installation margins have decreased considerably over the last year, especially on the East Coast. Cheaper panels and installation margins mean more development and increased SREC supply. However, 2011 will also see the disappearance of many state solar rebate programs. States like Ohio, Pennsylvania, New Jersey, and the District of Columbia are finding their coffers running low for state money to support solar projects. This means that new projects in 2011 will have to rely more heavily on the value of SRECs, which should slow development and SREC supply considerably. We have also seen new interest from traditional banks, particularly in large scale solar projects, which should bring down the cost of financing for large scale developers. Private high yield investors have now moved into the commercial and light commercial space, which means more money for these projects but at a pricey cost. Together these market effects will work to determine SREC supply in 2011. For example, will panel prices and installation costs fall enough to compensate for the termination of many state solar rebate programs? These questions will be important to answer before estimating additional SREC supply in 2011.

SREC Demand Forecast:

SREC demand is legislated by the renewable portfolio standards in each state. Consequently, demand would appear to be easy to determine. However, an increasing number of long term SREC contracts and energy suppliers with their own projects will mean that the demand that appears to be in a market could already be “spoken for”. Furthermore, with compliance entities in some states filing for force majeure, demand that should be in the market may in fact be pardoned. Even with all of these moving parts, demand is remains far easier to predict than supply.

Comparing Supply and Demand:

The standard interstate analysis of supply and demand will become more complicated in 2011 as SREC sellers in states with crumbling SREC markets look to cross state lines to sell their SRECs into other states. Determining the pace of those cross-registrations and the flexibility of the market to move those SRECs from one state to another, keeping in mind that some portion of those SRECs are locked into long term contract, will be important to determining the supply and demand balances in each state. Brokers have also added some complication to the market, as offers and bids are multiplied across the market and often give the appearance of significance amounts of demand or supply. Neither of which is healthy for a developing market.

Legislative Changes:

Increased reliance by projects on SREC prices and increased scrutiny brought upon compliance entities to meet the RPS standards will both cause market participants to look more closely at RPS statutes to determine exactly what will and will not qualify in-state. Additionally, where SREC markets can no longer support solar development, the solar community will apply pressure to politicians to increase demand to support job growth in one of today’s few industries reporting job growth: solar.

In the end, the three primary market drivers will remain the same. But what is more important than today’s supply and demand are tomorrow’s. To get a clearer picture of those dynamics, one will have to combine a historic view of growth with the changing landscape ahead to arrive at any number of varied outcomes. After all, that is what makes a market.

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FERC Rulings on Solar Feed in-Tariffs

Wednesday, February 23rd, 2011

Solar feed-in tariffs (FIT) have served as one of the primary policy tools for increasing the deployment of solar energy in several countries. Yet a recent ruling by the Federal Energy Regulatory Commission (FERC) makes the future of solar FITs in the U.S. uncertain.

A feed in tariff is basically a subscription program where the owner of a solar system can sell their electricity at a fixed rate to utilities. The utilities are required to purchase the solar electricity at this determined rate, which is higher than the normal wholesale electricity price. Feed-in tariffs, highlighted in places such as Canada and Germany, have the potential to be great for solar deployment because they guarantee a certain cash flow, thus minimizing the risk for those financing solar.

However, there also drawbacks to FITs. In the U.S., the success or failure of such a policy would depend on the ability of the state legislature to determine the correct fixed rate for solar electricity that incentivizes solar without oversubsidizing it. This fixed rate contract for purchasing electricity is more dependent on government funding and consistent political will than market forces.

Regardless of whether you agree more strongly with the advantages or the disadvantages of a solar FIT, it is important to note the FERC ruling on FITs this past year and its likely consequences. On July 15th of last year, the interstate electricity regulators at FERC affirmed the fact that they had exclusive authority over wholesale electricity sales.

The ruling was necessary because the California Legislature in 2007 established a feed-in tariff program for small combined heat and power systems in the state. Some utilities protested this program under the language of the Federal Power Act. FERC’s ruling was originally confusing, although seemed to support the belief that state legislatures are severely limited in their ability to mandate premium, fixed-price requirements.

This ruling was controversial and eventually led to a clarification by FERC in October 2010 that states do have the authority for certain feed-in tariffs when they set their rates through the Public Utilities Regulatory Act (PURPA). A spokesperson explained that since utilities may be mandated to buy power from different sources of electricity, a multi-tiered approach is admissible where states can calculate the utilities’ avoided cost for each separate electricity source.

Moving forward, it is unclear whether these FERC rulings will encourage or discourage more state FITs. Renewable policy experts have noted that the FIT structure allowed under these FERC rulings does not really resemble European FITs and has limited ability to dramatically increase renewable energy generation.

One of the options for FITs that FERC explicitly allows is for a state to establish a targeted range (for example for PV systems between 10 kW and 50 kW only), and let the market set the price. This is significant because it highlights FERC’s preference towards market solutions because they have the potential to be self-correcting and continually incentivize solar cost reductions.

A market solution for solar deployment that already exists is a solar “carve out “in a state’s RPS, which creates Solar Renewable Energy Credits or SRECs. Trading SRECs allows the market to dictate an appropriate price based on a state’s alternative compliance penalty and supply and demand factors.

Many U.S. states already have solar carve outs and healthy SREC markets. In fact, a FERC spokesperson indicated that Renewable Energy Credits (RECs) may be needed in addition a FIT to get to sufficient levels of renewable energy deployment. States previously considering FITs can look towards SRECs as a favored policy tool for enabling solar deployment and adopt legislation accordingly.

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Why Installers Need to be Careful about the Future Value of SRECs

Friday, February 11th, 2011

Solar Renewable Energy Credits, or SRECs, are a key part of financing solar PV systems, typically covering 20 to 40% of installation costs. Therefore, it is critical that solar installers, homeowners, and businesses be prudent when projecting future values of SRECs.

An SREC is a tradable credit that represents the clean energy benefits of electricity generated from a solar electric system. Each time the electric system generates 1000 kWh, a SREC is issued that can be sold or traded separately from the power. SRECs are financially valuable because many states have Renewable Portfolio Standards (an RPS) with specific solar carve-outs that require energy suppliers to incorporate a certain percentage of solar generated electricity into their portfolio. Most energy suppliers do not have enough solar capacity to satisfy the RPS requirements with their own power and subsequently must purchase SRECs to meet the state requirement. This allows owners of solar systems to trade their SRECs as commodities and receive payments for them.

SRECs have functioned as an important tool for making solar systems more affordable, and therefore SRECs are typically a significant part of the sales pitch that installers use when explaining the economic benefits of going solar. Furthermore, as state grant and rebate programs diminish, SRECs represent a bigger piece of the way to finance solar. For example, in Ohio and D.C., state funds for solar rebate programs are currently depleted, and homeowners must now rely solely on the federal tax investment credit, SREC payments, and energy bill savings to offset the cost of their system.

In many states, the RPS requirements (that make SRECs valuable) increase annually until 2025. This leads some people to assume that SREC values will also increase annually as energy suppliers will need to purchase more SRECs to meet the solar carve our requirement. However, this is not necessarily the case. The amount of solar capacity is increasing along with RPS requirements, which means that in most states, the SREC values are actually coming down. For this reason, installers need to be honest and careful when describing the future value of SRECs, so that customers do not have false expectations about the ROI of their solar energy system.

In addition to the RPS requirement, the two key factors in determining SREC values are the Solar Alternative Compliance Penalty (SACP) and SREC supply.

The SACP is a fee that a regulated entity must surrender in the event they do not procure a sufficient amount of solar electricity. This fee acts as a price cap because a rational energy supplier would not be willing to purchase SRECs for greater than this value. The SACP is defined on a state-by-state basis, and virtually every state has a declining SACP schedule. For example, in Ohio the SACP declines by $50.00 every two years. The SACP alone will not determine the value of an SREC, but a declining SACP schedule will push the maximum value of SRECs down over time.

The supply of SRECs in the market is another essential factor to consider when predicting future values. Naturally, if there is a surplus of SRECs, then SREC prices will come down. This dynamic has already happened in states such as Pennsylvania and D.C., and solar system owners that locked into a long-term fixed contract are receiving higher values than those trying to trade on the spot market.

Since there is a lot of uncertainty about the future of SREC values, installers should make it clear that SRECs are a commodity and that their pricing can be quite volatile. They should also help their customers make an informed choice about how to sell their SRECs that accommodates their tolerance for SREC market risk. Installers will find that customers who have a good understanding of the SREC market volatility may be willing to accept a lot of risk and enter shorter contracts because they are bullish on the future of SREC markets. However, others may be risk adverse, and would prefer to lock in a fixed price for their SRECs for 3, 5, or even 10 year periods.

As long as installers adopt a cautious approach when discussing SRECs with clients, customers will sort themselves along the lines of risk preference.

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How to Navigate the Massachusetts SREC Market

Monday, January 24th, 2011

This morning I was speaking with a homeowner in western Massachusetts who had recently taken the plunge and invested in solar energy. Solar Renewable Energy Credits (SRECs) were on his mind. Specifically, he wanted information that would help him come to an informed and clear valuation of the SRECs generated by his system.

Due to the complexities of SREC markets in general and the peculiarities specific to Massachusetts, this homeowner’s interest in understanding how to value his SRECs is a refrain we at Sol Systems are hearing regularly.

Many homeowners are looking to understand the basic framework of the market; and in our mission to provide the resources to make solar simple for homeowners, we have prepared a summary of the major characteristics of the MA SREC market.. This summary will provide information geared specifically for residential system owners so they can make informed decisions on the monetization and valuation of their SRECs.

To begin, SRECs in Massachusetts are used by regulated energy suppliers and utilities to comply with the solar carve-out of the Massachusetts Renewable Portfolio Standard (RPS). For example, if NStar puts under contract 10 million megawatts hours of electricity in 2011 for delivery in 2011, and the solar carve-out for 2011 is set by the Massachusetts Department of Energy Resources at 0.10%, then NStar must purchase 10,000 SRECs (10 million MWH * 0.10%). In the event that NStar does not purchase sufficient SRECs to meet their compliance obligation, they are obligated to pay a penalty of $600.00 for each megawatt hour (1 SREC = 1 MWH of solar). The $600.00 penalty is defined as the Alternative Compliance Penalty (ACP), and this penalty effectively sets a cap on SREC values in Massachusetts.

Homeowners are eligible to sell their SRECs in a variety of ways. One option is to place the SRECs posted to their NEPOOL GIS account into the Clearing House Auction (NEPOOL GIS is a regulatory body that tracks each generator’s production, and mints SRECs to reflect the production). The MA Clearinghouse Auction is an online state-sponsored program that allows homeowners to deposit SRECs into an account in order to auction the SRECs at a fixed price of $300.00, minus a 5% administration fee (i.e. fixed price of $285.00). The Auction occurs once a year, no later than July 31. While the Clearinghouse attempts to create a price floor of $285 for the SRECs, there is no guarantee the SRECs will be purchased.
In the event a homeowner is interested in other options, the MA Department of Energy and Resources has compiled a webpage of market resources. The market resources lists companies, like Sol Systems that can assist homeowners in monetizing their SRECs.

Sol Systems offers customers in Massachusetts a variety of services that can meet their risk and reward profile, while also providing clarity on how to value their SRECs. For those interested in security, Sol Systems can offer a lump sum upfront payment for the sale of the rights to their SRECs. Or, for those interested in the most competitive pricing but little long-term security, Sol Systems can offer a 1-year brokerage service. Depending on the size of your system, the brokerage fee may be waived as well. Or, for those interested in a moderate valuation, Sol Systems also offers a utility-backed 3-year fixed price contract of $400.00 per SREC.

Sometimes homeowners express an interest in negotiating an SREC transaction directly with a regulated entity, and when I speak with people interested in doing this, they often recite their interest in “cutting out the middle man”. While this point of view might be valid (and possible) in some industries, it can lead to loss of value in the SREC space (in any case, most energy suppliers are not willing to negotiate with small system owners). On the other hand, established SREC aggregators (like Sol Systems) who represent thousands of customers can leverage their position with an energy supplier to secure more competitive pricing than would have otherwise been garnered through a one-off transaction between a very large entity and a homeowner with a small number of SRECs for sale.

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The Distributed Generation Amendment Act of 2011: Critical for DC’s Solar Community

Thursday, January 20th, 2011

District of Columbia Council Member, Mary Cheh, recently introduced one of the more important pieces of legislation the District’s solar community has seen in some time: the Distributed Generation Amendment Act of 2011.  This bill sets a framework and goals for the District that will ensure the development of a robust solar community by creating jobs, providing a price hedge against rising energy costs, strengthening the local transmission grid, and producing significant localized environmental benefits.

The bill accomplishes these goals in two ways.

1.      It increases the solar renewable portfolio standard (RPS) requirements for the District so that these requirements look more like the policies of surrounding states: Maryland, Delaware, and New Jersey.  This sets up the long-term foundation for the solar community, and positions the District as one of the leading cities to attract and retain investment in solar.

2.      It ensures that only solar systems actually located on the District’s distribution grid qualify towards DC’s RPS, or solar energy goals. This has the added effect of stimulating local economic development while ensuring DC reaps the many benefits of distributed solar energy.

What is a Renewable Portfolio Standard (RPS)?

A renewable portfolio standard is a state-legislated policy (in this case, the District’s policy) that requires energy suppliers to provide a portion of their electricity from renewable energy in a state.  This means that for every unit of electricity provided to the district, a certain percentage must come from wind, solar, biomass, etc.

The District’s RPS has a specific requirement for solar, which means that for every unit of electricity sold, a portion (.04% in 2011) must come specifically from solar.  Energy suppliers can meet this requirement by:

(1)   Supplying solar electricity from solar systems they build, or

(2)   Paying a solar energy system owner (like a homeowner) to supply it for them.  This is accomplished by purchasing the solar renewable energy credits (SRECs), something akin to carbon credits, associated with the solar system. SRECs are key to making solar affordable and they are fundamental for making solar systems economical for homeowners and businesses.

RPS legislation like the District’s is now very common. Altogether, 36 states have a RPS or similar legislation and 16 states have a RPS with a solar carve-out similar to that in DC.

The Distributed Generation Amendment Act of 2011 makes some critical changes to the RPS that will ensure its effectiveness in the future.

Why is solar beneficial to the District of Columbia?

The District of Columbia currently imports almost 100% of all of its energy supply. Solar generation, and more specifically, distributed solar generation provides significant social, environmental, and economic benefits.  Some benefits of local solar generation include:

  • Increasing the stability and reliability of the distribution grid
  • Reducing pollutants such as NOx and SOx
  • Diversifying the District’s fuel sources
  • Decreasing the price vulnerability District rate-payers incur by relying solely upon fossil fuel sources, which have significant variable costs
  • Reducing the heat-islanding affects found in DC
  • Reducing the demand for energy during the middle of the day, and specifically during the summer.  This aligns with peak demand, and disproportionately offsets highly polluting “peaker” units
  • Creating jobs in the District of Columbia

The Distributed Generation Amendment Act of 2011 bill forges the foundation necessary for sustainable industry growth for years to come, while creating many more local green collar jobs (over 600 have been created so far) and a significant revenue stream for the city through increased tax revenues.

What are the benefits of the legislation for a homeowner?

A residential system owner can save a substantial amount of money on their utility bills by installing a solar energy system, typically between 30-50% (or $400-800 annually), depending on the size of their system. Homeowners can also sell the green attributes associated with their energy production in the form of solar renewable energy credits (SRECs). The average homeowner can earn between $900-1800 annually by selling SRECs. Energy suppliers buy these SRECs to meet their RPS goals.  This is why an effective renewable portfolio standard (RPS) is so critical for solar financing.

The Distributed Generation Act of 2011 provides homeowners and businesses with a significant economic incentive to go solar.  The legislation creates a long-term and sustainable market for solar renewable energy credits (SRECs) which solar system owners can sell to energy suppliers.  The legislation also ensures that the market for SRECs will remain stable and strong into the future, which will spur solar development and investment in the District.

For the District’s environmental community, this bill moves us towards a more sustainable future, while also creating jobs and helping local industry.  It is well crafted, with significant support from the solar industry, and it is a piece of legislation worthy of community support.

If you want to help the District lay the foundation for a sustainable solar community and spur solar development in the city, we urge you to contact your DC council member .

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Connecticut: the Next Big SREC Market?

Monday, January 10th, 2011

Recent shifts in the political landscape indicate that Connecticut will be the next state to legislate a Solar Renewable Energy Credit (SREC) marketplace. A SREC marketplace allows solar energy system owners to trade their SRECs (the environmental attributes associated with 1 megawatt hour of solar electricity production) on a secondary market at a competitive price. Although Connecticut does not currently have a robust SREC market, the state has a Renewable Portfolio Standard with relatively ambitious targets and a newly elected governor who has voiced his support for solar.

Enacted in 1998, Connecticut’s RPS mandates that 23% of the retail electricity load come from renewable electricity by January 1, 2020. Renewable technologies in the RPS are differentiated into Classes 1, 2, and 3, with solar and wind electricity both being designated as Class 1 technologies. Electricity suppliers can comply with Class 1 annual requirements by procuring Renewable Energy Credits (“RECs”) from facilities located within the ISO New England area (i.e. Connecticut, Maine, Massachusetts, Rhode Island, Vermont, and New Hampshire). In addition, RECs from systems located in states outside of the ISO New England area, such as Pennsylvania and Delaware, are eligible for compliance purposes. If electricity suppliers fail to generate or purchase sufficient RECs to meet their renewable energy requirements, they must submit an Alternative Compliance Penalty (ACP). The current ACP in CT is $55.00 per REC or megawatt hour.

In the spring of 2010, Assembly Bill 493 was passed by the Connecticut House and Senate, but vetoed by former Governor Rell. This bill, “An Act Reducing Electricity Costs and Promoting Renewable Energy”, would have defined a specific requirement for solar energy technologies, and would have created a more stringent non-compliance penalty. If passed, the legislation would have increased the value of SRECs. Connecticut’s current Governor, Dan Malloy, has, in the past, voiced support for the passage of this legislation and stated that he would have signed the bill. However, to date, no solar legislation or discussion drafts are available for analysis.

As the solar topic continues to gather steam inside and outside of Connecticut, Sol Systems would like to note a list of provisions that will be central to any new future solar legislation in Connecticut.

1. The Alternative Compliance Penalty (ACP): The ACP largely determines the ceiling value for an SREC. A higher ACP can lead to higher SREC prices, resulting in a better payoff for those investing in solar energy. For example, neighboring Massachusetts is a state that has helped enact an SREC market by creating a $600.00 ACP; as a result, SRECs in Massachusetts are currently fetching prices between $275-$500.

2. System Eligibility: Currently, Connecticut is an “open market” meaning that it’s RPS allows Renewable Energy Credits (“RECs”) from a large region outside of Connecticut to be eligible for compliance. If new legislation retains this “openness” the SREC and REC values will likely be decreased, as was the case with SRECs in the District of Columbia. To ensure the integrity of a future market, advocates for solar in Connecticut should ensure eligibility requirements that would not lead to an oversupply of SRECs on the market.

3. The Solar Carve-Out Schedule: A solar carve-out schedule defines how much solar electricity must be produced each year, and therefore determines the demand for SRECs. To ensure the market is robust, advocates of solar should advance aggressive solar requirements, akin to states such as New Jersey and Maryland.

Sol Systems’ anticipates future SREC legislation in Connecticut, and will be working with other solar advocates towards advancing a robust solar future in the state.

About Sol Systems:

Sol Systems is a solar energy finance and development firm that was built on the principle that solar energy should be an economically viable energy solution. With thousands of customers and hundreds of partners throughout the United States, Sol Systems is the largest and oldest SREC aggregator. We provide homeowners, businesses, solar installers, and developers with sophisticated financing solutions that help make solar energy more affordable. Sol Systems also helps energy suppliers and utilities manage and meet their solar RPS requirements efficiently by providing them with access to diverse portfolios of SRECs. For more information, please visit www.solsystemscompany.com.

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Why are spot market and long-term SRECs priced differently?

Monday, December 13th, 2010

Many prospective solar energy owners are quick to notice that spot market rates for Solar Renewable Energy Credits (Solar RECs or “SRECs”) are typically higher than long-term SREC rates on the contract start date. For example, a person that owns a solar energy system in Delaware could sell a single SREC on the spot market for approximately $275 in December 2010, but if that same person wanted to lock-in at a 5 year SREC rate, she would only be able to get approximately $250 for each SREC produced between today and 2015.

This price difference sometimes leads solar owners to sell their SRECs on the spot market, particularly if they expect SREC prices to go up over time.

So, why would a solar owner choose to enter a long term SREC agreement?

The main reason a system owner would choose a long term contract is because they realize that spot market rates may not always stay high. These owners prefer to guarantee their SREC returns by locking into a fixed rate multi-year contract, which will give them long term security and a predictable source of income. If these system owners are correct, they will end up getting more income over time than they would have by selling their SRECs on the spot market.

But why are long term rates lower than current spot market prices?

There are a few reasons why multi-year contract rates are initially lower than spot market rates, and they relate to SREC buyers appetite to buy SRECs. Let’s start by considering the profile of an SREC buyer.

The ultimate SREC buyer is an energy supplier or utility that is subject to a state Renewable Portfolio Standard with a solar carve-out. These energy suppliers and utilities have the choice of:
(1) Building solar power plants and generating solar energy themselves
(2) Buying the environmental attributes of solar (SRECs) from independent solar energy system owners, or
(3) Paying an Alternative Compliance Payment (ACP) or a penalty fee for not meeting their legislative mandates

If these energy suppliers and utilities do not own operational solar power plants, they typically prefer to buy SRECs. If they want to buy SRECs they can do so by buying them on the spot market or they can enter multi-year agreements at a pre-determined price.

Most energy suppliers will hedge their bets by buying some SRECs on the spot market and some SRECs through multi-year agreements. However, in virtually all cases, these energy suppliers will contract for lower prices per SREC for multi-year agreements than they will pay on today’s spot market. There are a few reasons for this:
(1) They expect that they will not need to buy SRECs in the future. Why? They plan to build solar power plants and generate their own solar energy, so they won’t have to buy them from independent system owners.
(2) They expect that they can buy SRECs at lower costs in the future. Why? They anticipate that there will be more solar projects and that the increased SREC supply (http://www.solsystemscompany.com/faqs-recs-and-srecs) will lead to lower SREC prices.
(3) They want to wait and see what happens to requirements and prices in future years. Why? They expect that legislative changes may reduce or eliminate the requirement for them to buy SRECs.

In other words, energy suppliers themselves believe SREC prices will go down. Because of these expectations, energy suppliers are usually only willing to engage in multi-year agreements at reduced SREC prices. And these uncertainties are the very same risk factors that create SREC spot market volatility.

In summary, when choosing between the SREC spot market and a long term contract, a solar energy system owner should examine their appetite for risk and reward.
System owners who choose to sell their SRECs on the spot market get the reward of higher spot market prices today, but they are likely to face reduced or eliminated SREC values in future years. System owners who choose to sell their SRECs through long term contracts typically receive lower SREC rates today, but they get more certainty on their solar investment returns.

About Sol Systems:
As the largest and oldest SREC aggregator in the U.S., Sol Systems aggregates SRECs from independent solar energy system owners and sells them directly to energy suppliers and utilities through spot-market arrangements and multi-year contracts. Sol Systems operates in 13 states. For more information, please visit www.solsystemscompany.com.

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What will SRECs be worth in 3, 5, and 10 years?

Thursday, December 9th, 2010

When potential customers ask me about their options for selling SRECs, I explain that they have different options depending on their appetite for risk and their investment time horizon. Some of these potential customers then ask me “what will SRECs be worth in 3, 5, and 10 years?”

This is a very important question in determining the return on a solar investment, so I am always very careful to point out that there are many factors that determine the value of an SREC and these factors change over time, therefore the future value of SRECs is uncertain.

When I note the uncertainty about the future value of SRECs, many customers remark that they believe that the SREC values will go up. As a solar industry advocate, I certainly hope they are right, but I feel that it is my duty to explain the risk factors that affect SREC values.

I usually start by discussing Renewable Portfolio Standards (RPS), and I mention that SREC demand will go up in line with yearly RPS increases, but not necessarily the value of the SRECs.

Sometimes these customers, particularly those bullish on SREC futures, express interest in entering into a shorter-term SREC agreement, such as Sol Brokerage or our 3-year Sol Annuity contract because they fear that they will lose if SREC prices go up in the future. At this point in the conversation, I usually mention that SREC values will not rise (or remain stable) in perpetuity; instead prices will likely decline.

For example, in Pennsylvania and DC, we have witnessed a decline in SREC values on the spot market by 15% and 23%, respectively, over the last three months. In these cases, system owners that decided to “gamble” by selling their SRECs on the spot market (versus entering into a long-term agreement) have lost value in their SREC transactions – and have no guarantees on the future value of SRECs.

However, in explaining that SREC values can fall, I have noticed that some potential customers suspect we are misleading them, attempting to create doubt about SREC values in order to capitalize on our position in the market.

I now realize this is likely the first time they have heard the idea that SREC values will decrease. After all, many installers claim that SREC demand is going to rise exponentially (or stay constant) over time, and SREC values will be strong for 10, even 20 years (long after the system has been paid for) – which is a line of reasoning that helps installers close more sales.

In an attempt to be objective, I often provide details on particular provisions within a state’s Renewable Portfolio Standard (RPS). For Ohio, I may cite that the Alternative Compliance Penalty (ACP) is set to decline by $50 per SREC in 2012, and will decline another $50 bi-annually thereafter. Similarly, Maryland, DC, and New Jersey all have declining ACP schedules.

Sometimes this information strikes a chord with a customer, but in more cases, it becomes clear that the customer favors a short-term contract, such as our Sol Brokerage service. This is perfectly fine so long as they understand the risk factors, but I cannot help but conclude that it is easier to sell somebody what they want to believe, instead of trying to educate them on the inherent uncertainty of complex SREC markets.

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Mid Size Commercial Solar Projects Require Guaranteed Long Term SREC Contracts

Monday, November 15th, 2010

The mid-Atlantic region has witnessed a rapid growth in solar installations over the past few years. While the large multi-megawatt commercial projects make front-page news, it is interesting to note that there is also vibrant growth in mid-size commercial projects, ranging from 50kW-500 kW. Today, the total capacity of solar installed in the PJM region (solar projects in the mid-Atlantic region) is 262 MW, of which 83 MW comes from systems in the 50 kW-500 kW range. Moreover, the mid-size commercial project segment has shown steady growth, adding approximately 26 MW each year since 2009.

Large solar projects face significant financing hurdles because millions of dollars of capital are required, but these projects also fetch the attention of large banks, energy suppliers and tax equity investors. Mid-size commercial projects face the daunting challenge of financing their projects with less visibility, but they can be successful if they make use of all the available incentives and financing tools.

Many mid-size commercial developers and installers can help the customer through the process for applying to federal and state grants; however, monetizing the Solar Renewable Energy Credits (SRECs) is often more difficult. SREC markets are complex for two main reasons. First, SREC markets differ across various states depending on the State’s Renewable Energy Portfolio Standard (RPS) and Solar Alternative Compliance Payment (SACP), the fee paid by energy suppliers for non-compliance of RPS requirements. Second, SREC markets have been known to be fairly volatile due to legislation changes and variations in supply and demand. These challenges can be mitigated by finding a stable partner with long-term SREC contracts who can help system owners navigate the legislation, and provide security of cash flow payments which allow system owners to accurately determine their payback period.

Investing in a mid-size commercial solar project is a sizeable investment for a small business owner or homeowner, thereby making it imperative to ask some difficult questions to the SREC aggregator or financier. The most important question to ask the SREC aggregator is: “Are your customer contracts backed up with energy supplier contracts?” If an SREC aggregator has long term contracts with energy suppliers, then the SREC firm has foresight into future SREC prices and can offer a fair, guaranteed rate. On the contrary, if an SREC aggregator is speculating on price and hoping to sell the SRECs in the spot market at a future date without any security of a long term agreement, their customer is exposed to a lot more SREC market risk. System owners should also be aware of the other factors that shape the SREC markets, like regulatory changes, rapid adoption of solar, and market shifts due to large-scale solar projects.

Being the oldest and largest SREC aggregator in the country, Sol Systems has matched a majority of its long-term SREC contracts with its energy supplier contracts, thereby providing the market stability and flexibility that mid-size commercial customers seek. Today, Sol Systems works with over 200 developers and installers in financing mid-size commercial solar projects. More information can be found at www.solsystemscompany.com.

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SREC Monitoring, Reporting, and Verification, Explained

Monday, October 18th, 2010

When speaking with homeowners who have recently invested in solar energy, and who are considering how to manage the sale of their Solar Renewable Energy Credits (SRECs), a common question is, “how will my solar electricity be monitored and how do I earn SRECs?”

This simple question cuts right to some of the most complex and nuanced underpinnings of how SREC markets work and begs answers to questions like:

• How is solar electricity production monitored?
• How is this production reported to a solar Attributes Tracking Program?
• How is the reported generation verified as accurate?

These questions illustrate the complexity of SREC markets — particularly because the answers to these questions vary by state. It’s understandable that homeowners can be intimidated by the solar industry and SREC markets; however, navigating these complexities is possible.

Each state determines its own regulations for monitoring solar electricity generation for SREC production. These regulations may require an inverter, a solar meter, or a remote monitoring system. Depending on the system state, and the size of the system, vastly different reporting technologies are required.

Reporting provisions refer to how the solar monitoring data is transmitted to an Attributes Tracking System (such as PJM’s Generation Attributes Tracking System “GATS”) for verification and ultimately SREC production. Solar reporting provisions are also determined on a state by state basis. For example, in Massachusetts all monitoring data must be reported to the Massachusetts Production Tracking Systems (administered by the MA Clean Energy Center). For systems above 10 KW , the monitoring data must also be reported electronically though a remote monitoring system, such as Locus Energy. However, each state differs on these provisions as well.

Verification of reported monitoring data is the final step of the compliance cycle for SREC production, and is conducted by the Attributes Tracking System. The only exception to this rule is Massachusetts, in which the Production Tracking System verifies the reporting data and then transmits it to NEPOOL GIS on the system owner’s behalf. For all solar energy systems registered with PJM GATS, GATS verifies reporting data by comparing the data with its own internal models. If and when GATS determines the reported generation falls within boundaries of the projected modeled generation, GATS then awards the system owner’s account SREC value. In the event that the reported data is not within the bounds of the projected modeled generation, GATS follows up to verify the accuracy of the reported data. In the future, some states will be implementing independent verification steps to ensure that the reported data is accurate, and markets are operating efficiently.

Certainly, it can be challenging to understand and abide by the requirements of SREC monitoring, reporting, and verification; however, the benefit of working with an aggregator like Sol Systems is that we navigate these complexities on behalf of our customers. We understand these provisions, abide by them, and work with regulators on a daily basis. This means our customers can rest assured that they receive all the credit, and solar credits, for their solar electricity production.

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