Posts Tagged ‘Solar incentives’

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Which is more efficient – RPS or Feed-in-Tariffs?

Friday, November 19th, 2010

Two of the most popular policy models administered to stimulate the deployment of solar energy are Renewable Portfolio Standards (RPS) and Feed-in-Tariffs (FITs).

RPS programs with a solar carve-out define a set percentage of electricity that each utility or energy supplier must procure from solar energy generators. To comply, an energy supplier can develop its own solar projects, or procure Solar Renewable Energy Credits (SRECs) from SREC aggregators or individual solar energy system owners.

In contrast, a FIT is a solar energy subscription program in which a solar energy owner can sell their electricity at a premium to the government or regulated energy suppliers. The solar electricity premiums, like the one in Ontario, Canada can be very lucrative. The stable cash flow from a state body minimizes the risk for the financier. The returns are defined for a 20-year period, the O&M costs of the facility are typically very low, and the project developer can seek financing with the FIT contract in hand.

These two policy models share similar objectives; they accelerate the deployment of solar energy technologies, build economies of scale that reduce technology costs, and carve out a space for solar within the electricity market. Both models also have unique strengths and proven track records of creating exponential growth in solar energy markets.

In some circles, FITs are held as the gold standard in stimulating solar development, while RPS programs are held in a lesser regard. Advocates of FITs can point to solar success stories like Germany and Ontario, Canada and like to discuss how a FIT could be effectively administered in America. Yet, these discussions are premised on the assumption that FITs are better for solar than an RPS. In an attempt to reframe these discussions, we would challenge this assumption and suggest that, in the mid-term and long-term, an RPS program is a more sophisticated policy instrument which is capable of creating a healthier and sustainable solar market.

The fundamental difference between the two models is that an RPS is a self-correcting model based on incentivizing individuals through secondary markets, while a FIT is a subscription program that sustains a solar market to the extent that governments continually allocate sufficient funds or political will. FITs allow solar developers to secure long term financing for solar development, but they do not create an incentive structure which encourages developers to continually reduce costs. An RPS program, as compared to a FIT, does not provide such security. In states with an RPS and an SREC market, system owners recoup their investment through the Investment Tax Credit (ITC), local rebates or incentives, and through the sale of SRECs.

While the ITC and state rebates tend to be reliable, the value of SRECs on the spot market can fluctuate dramatically over short periods of time. This spot market variability thus creates risk for the system owner and financier. And, if we were to stop the analysis here, it might seem clear that FITs are better for solar energy than an RPS. However, this conclusion would overlook the mid-term and long-term growth of solar markets in favor of robust short-term growth (and it would also ignore the fact that system owners can lock into multi-year guaranteed rate SREC contracts).

In fact, one should recognize that the price fluctuations in SREC markets are a result of supply and demand, and are part of the way that RPS markets adjust themselves. The supply is set by the amount of solar energy installed, and the demand is defined by the compliance requirements as established in the RPS. In the event a solar market witnesses exponential growth in solar development and SREC supply outpaces growth in demand, prices will be pushed down for SRECs.

And, to be clear, this is the goal of both an RPS program and a FIT: drive economies of scale and create a competitive market for solar technologies. If prices are pushed downwards in SREC markets, system developers will be incentivized to reduce the costs of the development in order to maintain margins. In the event prices are too low, the supply of SRECs will be short, energy suppliers will be required to pay higher prices for SRECs, and the market will receive the stimulus needed to push development forward again.

In a state with an RPS program and a robust SREC market, the winners will be those that can stay ahead of the curve in developing systems at lower and lower costs compared to other developers. The losers will be those that continually lag in developing systems at lower costs compared to other developers in the market. In so doing, an RPS program creates competition in the market that will ultimately drive down the costs of solar energy and make it more affordable for more people.

FITs, on the other hand, do not create the same sort of competition between developers to reduce costs. Depending on the FIT premium and the payment schedule, developers can maintain strong margins whilst making no investments in efficiency. The result is FITs can become oversubscribed, burn through allocated funds, and then come to a halt because the market never weans itself off of the crutches of government support. Because of the amount of capital required to fund these programs, FITS are also subject to political scrutiny, and if political change occurs, it can wipe a market out almost overnight (i.e. Spain).

For all these reasons, we would conclude that short-term FITs can create spectacular growth in solar markets, but are less sustainable compared to an RPS program which can adjust to the basic laws of supply and demand.

About Sol Systems:
Sol Systems is a Washington D.C. based solar finance and development firm that is committed to making solar energy more affordable. We enable homeowners, businesses, and solar developers to finance their solar energy systems by providing a conduit for solar renewable energy credit (SREC) monetization and long-term price stability. With more than 1,200 customers across 13 states, Sol Systems has become a critical player in developing SREC markets and financing solar energy systems. We are proud to be the oldest, most sophisticated, and largest SREC aggregator in the country.

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As the Federal RES Evolves, What Does it Mean for Solar?

Monday, October 4th, 2010

This last September, the U.S. Senate introduced the Renewable Electricity Promotion Act of 2010, Senate Bill 3813, a stand-alone Renewable Electricity Standard (RES) that will require sellers of electricity to retail customers to obtain certain percentages of their electric supply from renewable energy resources. If S. 3813 looks familiar, it should. The legislation is what remains of comprehensive climate change legislation that was introduced in the American Clean Energy Leadership Act of 2009 S.1462. This is therefore perhaps the last chance for any comprehensive federal approach to climate change or renewable energy prior to the next election.

So what does it mean for solar energy? In sum, it doesn’t hurt solar, but its immediate effects may not help much either. The proposed alternative compliance payment (ACP), which is the penalty energy suppliers must pay if they do not comply with their requirements is set low, especially when compared to current state RES programs such as New Jersey or D.C that have developed a foundation for a strong solar market. In addition, the portfolio of qualifying technologies may be too inclusive (by including numerous technologies the impact on any one technology is limited.

However, the legislation provides the framework, a seed of sorts, for the continued implementation and development of RES legislation nationwide. As RES markets develop nationwide, the solar industry can begin the task of adjusting to a more sustainable regulatory mechanism that is likely to help accelerate the implementation of solar technology (and others) well into the next decade. Our analysis is below.

BACKGROUND

What Does a Federal RES Do?

The federal Renewable Electricity Standard requires that a certain percentage of the electricity purchased in the country come from renewable energy resources. The purpose of an RES is to set up a competitive market in which utilities either (1) directly produce a specific amount of renewable energy based on their total load or (2) effectively purchase this renewable energy from others producing it or (3) pay a penalty. Most utilities will choose some combination of all three. In some state markets, an RES is called a renewable portfolio standard (RPS) or alternative energy portfolio standard (AEPS).

If utilities opt to go with the second strategy listed above, they usually do not purchase the energy from renewable energy resources, they simply purchase title to the “credit” associated with the renewable energy, termed a renewable energy credit (REC). Since energy can be measured in megawatt-hours (MWh), one REC represents the green attributes associated with one MWh of production from a renewable energy resource. Each time a homeowner or business produces one MWh from its solar system, it can sell the REC associated with this MWh in a competitive market. Technologies compete to produce RECs and sell them, and as these technologies scale, the supply of RECs increases, and the costs of these RECs decreases. The market is designed to drive down the costs of compliance and catalyze alternative energy technologies to scale.

CURRENT RES OVERVIEW

Volumes

The RES targets are less than the twenty to twenty-five percent recommended by most industry groups and President Obama himself this last year. The current RES requirements are below:

2012-13: 3%
2014-16: 6%
2017-18: 9%
2019-20: 12%
2021-39: 15%

The Alternative Compliance Payment

The Alternative Compliance Payment, which is the fee that electric utilities must pay in lieu of actually purchasing or producing the renewable energy credits required by the RES, is $21, adjusted for inflation. This means that for every MWH of electricity that the utility fails to supply from renewable energy, it must pay a fine of $21. The ACP effectively sets the ceiling on the value of renewable energy credits, with the caveat that there are multipliers (described below) that make some RECs more valuable than others.

Qualifying Technologies

Under the current RES, those resources include solar, wind, geothermal, biomass, landfill gas, qualified hydropower, marine and hydrokinetic renewable energy, incremental geothermal, coal-mined methane, qualified waste-to-energy, and potentially other technologies.

Multipliers

In order to incentivize certain technologies, states (and in this case the federal government) often provide multipliers for RECs from specific technologies or locations. Under the federal RES, utilities will receive double credit for RECs produced by renewable energy systems located on Indian land (to incentivize the development of renewable energy on Indian land) and triple credit for small renewable distributed generation less than 1 MW. Although not stated, it is likely that the maximum ceiling on energy efficiency credits will conversely reduce the value of RECs produced from energy efficiency upgrades.

No Preemption

The national RES will not preempt current state RES or RPS standards. Instead, the RES is meant to set a floor for states without current RES or RPS legislation to set up trading regimes and complement preexisting state legislation. The RES is a bit like the federal Clean Air Act or Clean Water Act in this respect, both of which provide states with a blueprint which they can either accept in whole, or mimic with state-specific standards that are as strict or less strict. This is incredibly important for those states that have more favorable solar requirements than the federal RES.

National Market

It is unclear at this point whether a national market will develop because of the legislation. Currently, the legislation provides for the delegation of responsibilities to either a national trading mechanism or a more regional mechanism. States will have to figure out whether they want their REC markets to be regional, like the Regional Greenhouse Gas Initiative (RGGI), or isolated, like Delaware, New Jersey, Massachusetts and others.

SREC Values

The value of solar renewable energy credits (SRECs) is typically a function of supply and demand . It is therefore unclear what the values of SRECs will be since this supply and demand will differ from state to state. Taken by itself, the legislation will not push SREC prices very high since the ACP is $21, with a potential multiplier of three ($63). However, current RPS states will likely retain their markets, and states without an RPS may develop more aggressive RPS legislation in light of the national RES.

ANALYSIS

Potential Negatives

1. The effective solar alternative compliance payment (SACP) is $63 per MWH for distributed solar energy systems (those below 1 MW in nameplate capacity). This is low enough that it is not likely to create a significant market for solar renewable energy credits (since the ACP provides a ceiling on the value of SRECs). This legislation is therefore unlikely to single-handedly develop robust markets for solar. However, as discussed below, the RES may provide the necessary legislative framework for the creation of such a market.

2. The list of qualifying “renewable energy resources” includes technologies that will be much less expensive to implement initially, and will likely flood REC markets. Solar energy, for example, is not likely to be able to compete with biomass or methane from mining.

3. Utilities can purchase energy efficiency credits. These credits are also likely to be much less valuable than SRECs, and may also flood the market – although they are limited to 26.67 percent of their overall required needs.

Potential Positives

Setting up a national RES begins to set minimum requirements, build the framework for the introduction of renewable energy legislation that many states currently do not have in an organized fashion, and develop a sustainable means by which to incentivize renewable energy. RES legislation is especially important for new technologies that may have higher up-front costs (like solar) because requirements can be structured around these costs. Although the standards may not be perfectly structured to assist solar energy at this time, most RES legislation is tweaked over time to better suite solar energy.

OUR CONCLUSION

The proposed federal RES is a good beginning, and provides a decent foundation for future legislation. Although it may not be perfect for solar initially, it forces legislators to address the important issue of alternative energy development, and provides them with a blueprint with which to do so. Our guess is that the requirements, and the ACP, will likely increase on a state-by-state basis. In the meantime, renewable energy is able to put itself on the map, and we’ve taken the first step of many in diversifying our energy infrastructure and moving towards a more sustainable future.

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The Difference Between SREC and Carbon Markets

Friday, October 1st, 2010

People outside the solar energy industry often refer to Renewable Energy Credit compliance markets as “carbon markets”, and solar renewable energy credits (SRECs) as “carbon credits”. This is a common misconception, so we wanted to flesh out the underlying similarities between SREC and carbon markets and then clarify the differences.

Carbon markets and SREC markets both utilize tradable permits, and market incentives, to achieve policy objectives. However, whereas carbon markets are established to reduce a pollutant and correct a market failure, SREC markets are established to incentivize the production of solar energy and create value for individuals investing in solar.

The underlying similarity between SREC and carbon markets is that both markets are based on the use of tradable permits. In markets with tradable permits, a new commodity is created through the passage of a law. The law requires regulated entities to obtain compliance permits, and in so doing creates a price signal which affects behavior and markets. In the case of mandatory carbon markets, like the Regional Greenhouse Gas Initiative in the Northeastern US, a regulating agency is given the authority by a law to regulate emissions of greenhouse gasses.

Hypothetically, the regulating agency tells a utility it can only emit 10 tons of pollution in 2011, and then gives the utility 10 carbon credits (each credit equal to 1 ton). The utility can either (1) emit 10 tons of pollution and surrender back the 10 credits to the regulatory agency, (2) emit less than 10 tons pollution and sell the excess credits to another utility or market actor, or (3) emit more than 10 tons of pollution and purchase credits from another utility or market actor. The decision the hypothetical utility ultimately takes is based on its own marginal costs of abatement (i.e. the cost of not emitting greenhouse gas) versus the market value of the carbon credit.

SREC markets share this market structure with carbon markets, and this is why I think people new to the SREC market often inadvertently confuse SREC markets with carbon markets.

However, SREC markets are entirely different than carbon markets in both intention and function. Whereas carbon markets utilize market forces to identify the most economical manner to reduce greenhouse gas emissions, SREC markets incentivize the creation of a new market and a new source of renewable energy. SRECs can be created by individual homeowners that have invested in solar energy, and these SRECs (paired with tax credits, rebates, and energy savings) can make the solar energy system affordable. Companies like Sol Systems can work with solar energy system owners to monetize the SRECs, and achieve the best value for the sale of their SRECs through long-term contracts. By aggregating customer’s SRECs into a large portfolio, Sol Systems can sell SRECs directly to energy suppliers and utilities through long-term agreements that bring security and value to both the utility, and the customer that has invested in solar.

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Comprehensive ACORE Report on Renewable Energy in the 50 States

Monday, September 20th, 2010

Last week the American Council on Renewable Energy released an impressive report “Renewable Energy in America: Markets, Economic Development and Policy in the Fifty States ”; and it’s free. The interactive report provides an executive summary on a state by state basis of the capacity of renewable energy installed, the type of technology, a description of large economic developments, and a review the various policy and incentive structures intended to deploy renewable energy technologies. The report provides macro-level analysis on large trends occurring within the renewable energy sector in America, but more importantly, the report provides in-depth, yet digestible, sector and policy oriented analysis of renewable energy markets. We recommend this report to experienced professionals in the renewable energy sector, and also for those people interested just starting out and looking to learn more.

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Long-term SREC Contracts to Secure Financing for Solar Power Projects

Thursday, September 9th, 2010

An article recently posted in the Novogradac and Company Journal of Tax Credits discusses the implications of securing financing for solar energy developments utilizing long-term SREC contracts (as opposed to state rebate and grant money). We recommend reading the full article, but we wanted to provide a quick analysis of its central points, and follow up on the central strength of long-term SREC financing that this article misses.

The article observes that regional and state solar grant and rebate programs are being cut back as cash strapped governments find ways to reduce costs. In replacement of the grant and rebate programs, states (like Massachusetts) are instituting performance-based incentive structures, also known as Solar Renewable Energy Credit (SREC) markets. The subsidy for solar development is tied to performance, the value of the subsidy is determined by market and regulatory forces, and the costs of funding the subsidy are distributed to regulated energy suppliers and their customers.

The article concludes that securing long-term contracts for the sale of SRECs provides a solar energy developer with better leverage to secure financing for his or her project because the SREC contract provides a stable revenue stream for the financier. We agree in full. The article also notes, “prices offered in contracts could likely be either the floor price or something perceived as substantially below market”. While this point may appeal to those bullish on the future of SREC markets; we think this article misses a fundamental purpose of SREC markets.

The intended goal of SREC markets and Renewable Portfolio Standards is it to stimulate economies of scale for solar development, driving down manufacturing and installation costs thereby pushing solar energy markets towards grid parity (i.e. making solar electricity competitive with fossil fuel generated electricity). As solar development costs continue to decrease and the number of solar energy projects increases, the supply of SRECs on the market can quickly outpace the demand created by SREC Alternative Compliance Payments which would cause the floor price of SRECs to fall. For example, in Massachusetts the floor price is currently determined by the Clearinghouse Auction price of $285.00. In the event an energy supplier could broker with project owners to secure SRECs at a value below $285.00, the Clearinghouse Auction would freeze up and the market would find a new bottom.

We think one of the reasons investors often favor long-term SREC contracts instead of spot market transactions is precisely because there is certainty about the SREC floor price. Aggregators like Sol Systems, who manage a portfolio of SRECs through long-term contracts with energy suppliers, provide both a stable cash flow for the project developer as well as security against the intended consequence of a successful SREC market and Renewable Portfolio Standard. And, herein lies the paradox: a successful and vibrant SREC market creates exponential solar development, which drives down SREC values and leads to a mature solar market that does not require an SREC market.

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An Installer’s Guide to SREC Sale Strategies

Monday, August 23rd, 2010

by George Ashton

As a residential solar installer, you have without question been challenged by prospective customers regarding the high price tag of solar; a typical residential system (3kW in size) can cost between $18,000 and $24,000. Luckily, there are a number of incentives available at the federal, state, and local levels that you can present to your customers to help them realize that solar can be more affordable than often perceived. Federal and state incentives are relatively easy and straightforward to explain. The concept of selling SRECs, however, is more allusive and harder for customers to grasp.

Because SREC income can significantly improve a project’s economics (reducing costs by 20-40% depending on location) and can increase a customer’s return on investment, ensuring that customers understand their SREC options and take advantage of the sale options available will assist your business with closing more sales. This article provides an overview of SRECs and explains the pros and cons of different SREC sale options.

What Are SRECs?
An SREC is a tradable credit that represents the clean energy benefits of electricity generated from a solar energy system. Each time a solar system generates 1000 kWh (1 MWh) of electricity, an SREC is issued which can be sold or traded separately from the power. SRECs have high value in some states where there is legislation called a Renewable Portfolio Standard (RPS). An RPS requires energy suppliers to either produce solar energy from their own projects or purchase credits from individuals or businesses that own solar energy systems.

How Are SREC Prices Determined?
RPS Compliance fee schedules dictate how much energy suppliers must pay for each SREC they fail to produce or acquire. As a result, SREC prices usually trade at or below the dollar amount of these compliance fees. In some states, the fee remains the same dollar amount year over year while in other states, like New Jersey and Ohio, the fee decreases over time which will result in a decrease of the price for SRECs over time.

SREC Supply
SREC supply will increase in the coming years. As solar panel prices fall, solar will become more affordable and more popular. As more solar systems are installed, more SRECs will be available on the market. Additionally, as credit markets continue to improve, more large projects will become financeable and built, resulting in more SRECs. Both of these trends will put downward pressure on SREC prices.

SREC Demand
SREC demand will also increase in the coming years. The demand for SRECs in a given state is set by RPS legislation that determines the overall number of SRECs energy suppliers are required to acquire each year, and this number quickly increases year over year in every state with an RPS. Because SRECs are a compliance commodity, if there are more SRECs supplied than demanded in a given state market, the pricing for excess SRECs will likely be equivalent to pricing seen on voluntary SREC markets, which today trade at $15-$30 per credit.

What are the Options for Selling SRECs and the Risks of Each Option?
Selling SRECs on the open market is analogous to day trading in the stock market. Your customers may make good money, but there is no certainty with regards to their long-term profitability. If SREC prices fall for any of the reasons mentioned above, they will receive a lot less for their SRECs. This option is best recommended for SREC sellers who do not rely on SREC proceeds to pay for the cost of a solar energy system and have a little extra time on their hands to monitor the market.

Selling SRECs into a long-term contract can be a strategy that provides adequate returns, but with less risk than selling on the open market. A typical long-term contract offers a fixed price per SREC for a 3-5 year term. By choosing this option, your customers will know exactly how much income they will receive over the contract term. However, the true value of a long-term SREC offer depends heavily on what supports that offer.

The most secure offers come directly from energy suppliers as they are the ultimate purchasers of all compliance eligible SRECs. However, very few energy suppliers offer contracts directly to non-commercial system owners. The next best offer is a contract from a select few SREC companies that back up their promises to purchase SRECs with their own long-term contracts to sell those SRECs to energy suppliers. These SREC companies have negotiated to sell your SRECs to energy suppliers at a specific price for 3-10 years at a time and can pass that guarantee on to you. Beware of SREC companies offering long-term contracts that have not negotiated fixed price long-term contracts to sell SRECs. If they have nothing to support their promises, and the market price falls, it will be difficult for them to honor your customer’s contracts.

Selling your SRECs for an upfront, lump sum payment is the SREC market’s version of a risk free investment; the return is a noticeably lower than the other options, but there is absolutely no risk. With this option, you will sell the rights to your future SRECs in exchange for a discounted one-time payment received close to the date of installation. You keep that money regardless of what happens to SREC markets. This option is recommended for solar energy system owners that are risk averse or having trouble with accessing financing through banks.

Educating your customers on all three SREC sale options and helping them evaluate their risk tolerance and financial needs will be a key strategy to selling more solar energy systems. The metrics presented in this article should help you identify the best route for your customers. Regardless of which option a customer chooses, monetizing their SRECs will play a critical role in financing their solar energy system.

George Ashton is Vice President and CFO of Sol Systems, a solar energy finance company located in Washington DC.

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Ontario Solar Explained

Thursday, August 19th, 2010

Ontario Solar Explained

According to the Canadian Solar Industries Association (CanSIA), the Canadian Province of Ontario had only 2 Megawatts (MW) of installed solar electric capacity in 2008. In 2010 alone, approximately 100 MW of solar capacity has already been installed in Ontario. Furthermore, CanSIA expects the province to install nearly another 100 MW of capacity in the remainder of this year. The Ontario solar market is booming, and it is because a relatively nuanced Feed-in-Tariff (FIT) program launched in 2009.

A FIT is a production-based incentive, in which a solar energy owner is guaranteed a fixed, above-market price for the sale of their solar electricity over an extended period of time. As an example, in a FIT program, a system owner may be guaranteed a sale price of their gross solar electrical output for $0.20 per kWH for a period of 20 years; meanwhile the weighted average price of electricity could be closer to $0.08 in the system owner’s geographic region. This program allows system owners to secure a stable and significant source of revenue and an appealing return on their solar investment.

After an extended rule making process, Ontario launched its FIT program at the end of 2009. This FIT program is delineated into six different tranches, in which different Feed in Tariff values are determined by the size and type of the solar generator. Below is a schedule of the FIT value for each tranche, and an estimated cumulative value of the incentive in the column to the right (this column estimates the total value garnered for each KW of capacity installed). As the column furthest to the right indicates, investing in solar is not a risky decision in Ontario currently, but a quite profitable one.

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A Secondary Market for SRECs In California?

Friday, August 13th, 2010

In California, the environmental attributes of solar electricity are bundled with the electricity; in fact, they are not allowed to be separated. For this reason, the environmental attributes of solar-generated electricity, or Solar Renewable Energy Credits are not tradable as compliance commodities. This means there is no secondary market for Solar Renewable Energy Credits (“SRECs”) in California. However, this may change.

The people of California have been trying to create an SREC market since 2006 when the California Assembly passed Senate Bill 107 (the “Bill”). This Bill granted authority for the California Public Utilities Commission (CPUC) to develop and administer a secondary market for Tradable Renewable Energy Credits (TRECs).

Three years later, in March 2010, the CPUC issued a decision establishing the rules and regulations that would structure California’s future secondary SREC market. The regulations proposed an alternative compliance penalty of $50.00 for 2010 and 2011; this amount would effectively serve as the ceiling value for the TRECs. (This is a relatively low value when compared to more robust SREC markets such as New Jersey and Maryland). However, the CPUC sidelined their decision in May 2010, and that is where the secondary SREC market sits today in California. The decision was sidelined in response to concerns expressed by investor owned utilities (IOUs) and energy suppliers.

However, a new bill in the State Assembly proposes a legal framework for a secondary SREC market in California. The details of this new bill are not firm enough to offer a good viewpoint on what a future SREC market may look like in California.

In the meantime, California solar energy system owners must sell their electricity and attributes bundled.  Systems sited outside of the state of California can enter into Power Purchase Agreements with California IOUs, to sell their bundled electricity and attributes.  However these systems must be located within the Western Regional Energy Generation Information System (WREGIS).  If, and when, California’s laws change, Sol Systems will be there to develop the SREC market for our customers.

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Solar Energy Gets Cheaper Than Nuclear Energy

Friday, August 6th, 2010

The steady decline in solar photovoltaic system costs is helping solar electricity become cheaper than electricity from new nuclear power plants. In a recent report titled “Solar and Nuclear Costs – The Historic Crossover (1), Dr. John O Blackburn and Sam Cunningham of Duke University makes a strong case for utilities to adopt a distributed model of electricity generation. The study indicates that the cost of solar electricity is expected to reduce from 14 cents per kilowatt-hour in 2010 to 7.5 cents per kilowatt-hour in 2020 while nuclear-generated electricity will be 12-20 cents per kilowatt-hour. Moreover, rooftop solar plants can be installed in a few days whereas construction of a new nuclear plant can take up to 6 years.

Some solar critics argue that solar electricity is only affordable because of government tax benefits. While this may be true, nuclear also benefits from government aid – in the form of government backed insurance and loan guarantees. Meanwhile, the rapid cost decline of solar technology will help solar electricity reach grid parity by 2020. In contrast, nuclear power is yet to be cost competitive despite being operational for the last 40 years.

The power industry and the energy economy are undergoing a paradigm shift from a centralized power source to a more “distributed” power model. A 2007 report by the American Council for an Energy Efficient Economy (ACEEE) (2) shows that 77% of new energy service demand is met by energy efficiency. These energy efficiency gains and most of solar supply are located in residential homes. The combination of energy efficiency, wind generation, solar water heating and solar photovoltaic technology has challenged the traditional model of centralized power generation.

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(1) http://www.ncwarn.org/wp-content/uploads/2010/07/NCW-SolarReport_final1.pdf

(2) ACEEE, “ A White Paper prepared for the Energy Efficient Finance Forum”

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Update on Proposed Changes to Solar Investment Tax Credit and Section 1603 Grant Program

Friday, August 6th, 2010

A discussion draft of the Domestic Manufacturing and Energy Jobs Act of 2010 was introduced by acting Chairman of the House Way and Means Committee last week. The Chairman’s discussion draft (the “Bill”) proposes significant changes to the current federal incentive structures for renewable energy.

One major change is that the Bill allows the Section 1603 Grant program to expire. Section 1603, which was funded through the American Recovery and Reinvestment Act (ARRA), allowed companies who installed solar energy systems to receive a cash grant in lieu of Investment Tax Credits or Production Tax Credits. In other words, a business investing $100,000 in a solar energy project could receive a one-time payment from the Treasury for $30,000. This allowed businesses who did not have a tax appetite (due to the recession of 2009-2010) to receive the same financial benefits as they would have received with a tax credit. (Click here for more information on Sec. 1603 Grants).

In place of renewing Section 1603, the Bill would allow the taxpayer to elect a refundable deemed tax payment in lieu of the Investment Tax Credit or Production Tax Credit. Using the example above, a deemed tax payment means that the $30,000 cash grant would be treated as a $30,000 tax payment. In the event that $30,000 exceeds the actual tax liabilities of the business, the taxpayer could file for a refund. Treating the ITC and PTC as refundable deemed tax payments means the system owner will likely need to wait longer to receive the value of the federal incentive, but would not need to have the full tax appetite to fully utilize the subsidy.

Sol Systems will continue to track this and other solar legislation.

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