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Where is the NC SREC Market?

Posted August 31st, 2010 by SRECTrade.

The SREC market in North Carolina has gotten off to a sluggish start and it appears that a thriving state SREC market may be a long way out.  Several aspects of the program have hindered the development of a market in the state, as a result, many SREC aggregation firms and market-makers have gotten out of the state. The two key problems include a non-existent mechanism for compliance and a buyer market dominated by a few large energy producers that are not participating in the market. Local installers and developers that were hoping SRECs would be a key driving force in promoting a North Carolina solar industry are now finding themselves shut out of the market.

Enforcing Compliance
The North Carolina law did not require that the North Carolina Utilities Commission (NCUC) set a Solar Alternative Compliance Payment (SACP) which is the fine that any energy supplier who falls short of the solar requirement would have to pay.  This is a standard aspect of any SREC market where SACPs vary from as low as $250 in Delaware to as high as $675 in New Jersey.  The SACP does not set the price, but acts as a cap in the market.  More importantly, it creates an indication for what the SRECs are worth in years where there is an undersupply.  In North Carolina, there is little incentive to offer higher SREC prices to promote growth in the industry and buyers are best served by holding prices down.

Utilities Locking Up Their Own Supply
Many investor-owned utilities claim to have locked in their own supply through the next few years and are therefore not participating in the market.  Part of the reason this is happening is that North Carolina places no restrictions on the amount of solar that utilities can produce themselves.  In addition, the other incentives and tax breaks combine to make solar an attractive investment for utilities.  Even Green Co Solutions, the company handling NC-REPS requirements for many of North Carolina’s electricity cooperatives is already well-positioned with respect to their SREC needs. This is a stark contrast to New Jersey and other states, where the incentives are prohibitive for investor-owned utilities and, in some states, completely excluded from the SREC market. New Jersey for example will only approve solar projects from investor-owned utilities if it is determined by the Board of Public Utilities that these projects will not impact pricing in the SREC market.

What are SRECs trading for?
Utility-run programs such as Progress Energy’s Sun Sense program and Duke Energy’s Distributed Generation program provide a structured means for generating solar electricity and selling it back to the grid along with the SRECs that are produced. These programs offer prices of $120 to $180 for bundled electricity and SRECs, resulting in SREC valuations in the $60-$120 range.  These programs limit projects to 25kW to 210 kW, a range that is too large for residential solar companies and too small for most commercial developers.  Although there have been SREC contracts struck with these large utilities, any agreements have all been done behind-closed doors with little or no transparency as to what pricing is being offered.

Who is faring well in North Carolina?
Despite the relatively non-existent NC SREC market, smaller solar systems in North Carolina have found successful ways to take advantage of SREC programs. Most notably, these systems have the opportunity to sell their SREC production into a small but more favorable Washington DC SREC market.  In addition, systems under 10kw in North Carolina are also automatically eligible for NC GreenPower, a voluntary retirement program which offers $150 per SREC bundled with electricity.  The most sensible path today for residential solar owners is to register in DC while the market continues to deliver SREC prices of $290. Meanwhile, since the market in DC is small and will likely be oversubscribed, the NC GreenPower program represents an excellent fall-back option.  Customers do not need to register for NC GreenPower right away and may choose to register later on, perhaps some time in the future after a price drop in the DC market.

What can be done to get the NC SREC market going?

  1. Set an SACP. For starters, the North Carolina Utilities Commission has the power to establish a compliance mechanism in the state.  Doing so would create some indication of what the willingness is to pay on the part of the buyers.  Sellers would then be able to properly compare the fixed-price programs being offered by Duke and Progress Energy to the alternative of selling in a market.
  2. Limit Investor-Owned Utility Solar Development. This is a much broader debate behind the purpose of subsidizing solar. New Jersey has, in no uncertain terms, made it very clear that the intention of the SREC program is not simply to ensure that the state is running on renewable energy. The intention behind the New Jersey SREC program is to a) diversify energy resources by promoting distributed, customer-sited generation (i.e. residences and businesses producing their own electricity) and b) create jobs by developing the most robust state solar industry in the nation.  Meanwhile, in North Carolina, the ultimate goal of acquiring solar energy at the lowest cost possible will likely be achieved. However, if the solar is owned and developed by a few large utility companies that in many cases outsource the development to firms in other states, then a vibrant industry will most likely not develop in North Carolina the way it has in other states.  Meanwhile, electricity generation in North Carolina will continue to remain the responsibility of and under the control of a few large firms, rather than distributed across the communities, the way solar resources are meant to be utilized.
  3. Create Transparency. The unbundled SREC contracts that are currently available are handled behind closed doors with no transparency. There is no publicly available information on the prices offered and the period of time in which these prices are being offered. The more the state can do to create transparency around pricing, the easier it will be for local developers to build projects based on SREC sales.  In addition to pricing transparency, if Investor-Owned Utilities continue to develop their own solar, information around their plans should be readily available so that the rest of the SREC market understands what the TRUE market demand will be.  Without this, it is nearly impossible to predict the forward price curve for SRECs and build projects based on those projections.
  4. Create Access to the Market. Limiting Investor-Owned Utilities from developing their own solar would turn them into active buyers within the market.  Combined with an SACP and few restrictions around procurement, more buyers, motivated by compliance obligations, will result in easier access to the market for solar projects of all sizes.

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Posted in North Carolina |

California TRECs – Will They Ever Materialize?

Posted August 25th, 2010 by SRECTrade.

Every now and then we come across an explanation of an aspect of the SREC market that could not be described in any better way.  The most enlightening piece on the California TREC market to date was authored by San Francisco Attorney David Niebauer. It was originally posted on the CleanTech blog and with the author’s permission, we have copied the post below for our readers.

Our brief summary is that California has passed legislation allowing for the creation of a Tradable REC or TREC market. This market is not specific to solar and will likely be dominated by wind and hydro RECs. However, we are optimistic that this is a precursor to an SREC market in California, especially considering FERC’s recent ruling against Feed-In Tariffs. It seems that the legislation passed earlier this spring has been held up over one issue: the importing of RECs from out-of-state.  Utilities want to be able to purchase RECs from out of state as it increases the available supply and will lower the cost of the RECs. The California Energy Commission, in the interest of promoting an in-state renewable energy industry, wants to limit REC purchases to in-state facilities. There are benefits to both sides of this issue and it really comes down to balancing the goal of cheap renewables with the goal of supporting a California renewable energy industry. Either way we hope the parties come to an agreement soon so that the TREC market can commence and we can begin to focus on how to bring an SREC market to California!

California Tradable RECs – Will they ever materialize?
by David Niebauer

California has led the nation in solar development on many fronts for a number of years, but there is one area where California has lagged significantly – the implementation of tradable renewable energy certificates (or TRECs).

As of this writing, there are five regional renewable energy tracking systems operating in North America, one national registry and three state systems. As early as June 2007, the California Energy Commission launched the Western Renewable Energy Generation Information System (WREGIS), which was designed to track renewable energy generation and create and track renewable energy certificates (RECs) for that generation. TRECs are an important tool for utilities in other states striving to meet their renewable portfolio standard (RPS) goals and help developers finance renewable energy projects in other parts of the country where TRECs are available. So why not in California?

The Basics

In California RECs are not yet tradable – all electric utility renewable energy purchases are “bundled” transactions. That is, the environmental attributes (e.g., RECs) are tied to, or bundled with, the energy itself. Therefore, the only way for utilities to comply with RPS requirements is to purchase renewable energy in bundled transactions from a qualifying renewable energy facility.

In States with unbundled or tradable RECs, electric utilities have two ways to meet with RPS goals: purchase renewable energy in bundled transactions (like in California) or purchase RECs on the open market. In States with TRECs the REC has been “stripped” from the energy and is traded separately. The energy is sold separately and is still supplied to the grid. The utility purchasing the REC may be and likely is completely different than the purchaser of the energy. Only the REC purchaser can count that energy toward its RPS goals.

Proponents of tradable RECs point out that the scheme will assist the State in achieving its RPS goal by balancing out geographical and transmission constraint differences from utility to utility. In California, for example, the State as a whole has considerable renewable resources, from geothermal to wind to solar – but these resources are not evenly distributed geographically throughout the State. Further, some areas with strong renewable resources have significant transmission constraints, making grid connection prohibitively expensive. A tradable REC regime would allow resources to be developed where cost and fit are most appropriate, and allow the environmental attributes (the RECs) to be traded among the utilities (and through intermediaries) to balance out these geographical and transmission constraint issues. As stated in the April 2006 California Public Utilities Commission (CPUC) Staff White Paper: “Importantly, under an unbundled and/or tradable REC framework, [a utility] can purchase RECs from renewable facilities largely irrespective of where those facilities are located or where the energy is ultimately delivered.”

From the energy developer’s perspective, RECs can provide an advantage for developing renewable energy sources. The ability to sell RECs in an unbundled transaction would mean that a developer would be able to negotiate with any utility or other buyer of RECs, rather than negotiating with only one utility in a bundled transaction. In states with TREC developers contract with one utility to provide energy at a relatively low cost and then sell the RECs to another utility or other buyer to enable his project to be economically viable. Where the developers must sell the energy and the REC to the same utility, the price of the energy might be too low to justify development. For this reason, tradable RECs can be a way to speed the development of renewable generation.

The California Log Jam
California has been taking slow, halting strides in the direction of permitting tradable RECs. In 2006 the California legislature passed Senate Bill (SB) 107, which gave the CPUC express authority to allow the use of tradable RECs for RPS compliance.
Three and half years later on March 11 2010 the CPUC issued a decision authorizing TRECs for RPS compliance in California (Decision10-030-021). The proposed scheme had a number of limitations but appeared to be a workable model. Most notable of the limitations was a maximum cap for IOUs of 25% of RPS compliance targets that could be met with TRECs. This limitation was to last only until the end of 2011 and was intended as a way to monitor the program before allowing unfettered use of TRECs. The other significant limitation was a price cap of $50 per REC. Again, this limitation was scheduled to expire at the end of 2011 unless the CPUC determined to extend the cap at that time based on further market studies.

The CPUC decision was made after conducting numerous workshops and receiving comments from interested parties. However, the entities that would have been most impacted by the Decision were not at all happy with the final outcome. Notably, the State’s IOUs and the Independent Energy Producers Association (IEP), whose members make up most of the merchant power producers in the State, filed objections and forceful motions to stay the decision. Prior to its implementation on May 6, only a few weeks after issuing the Decision, the CPUC granted an indefinite stay of Decision 10-03-021. This stay in still in effect.

The reasons for the stay, and the larger implications, are not at all clear. On its face, the stay was implemented in order to resolve objections raised by the IOUs and the IEP. Neither party liked the 25% limitation on use of TRECs to meet RPS requirements. Further, the IOUs, in particular, argued that the CPUC’s definition of a REC-only transaction would limit access to most out-of-state renewable resources, making implementation the TREC scheme unworkable.

Commissioner Grueneich’s Dissent

Commissioner Dian M. Grueneich filed a dissent to the stay that may shed some light on what is really going on. Commissioner Grueneich focused on the motion by the IOUs and claimed that the modifications urged by the IOUs would cause the “outsourcing of California’s renewable economy.” She points out that nothing had changed in the 60 days or so between the Decision and the Stay other than “the relentless lobbying by the utilities at this Commission and in Sacramento to overturn a decision they dislike.”

She continues:

“Since the RPS mandate was first signed into law, one message that has been repeated again and again from developers, from investors and from members of this Commission itself, is that market players need certainty and consistency in decision making in … order to make long term investments in California. This decision will disrupt renewable energy markets, threaten financing for existing and future projects, and compromise the careful work of the Governor’s office to ensure that renewable energy projects obtain their CEC permits and break ground expediently.”

Conclusion

Perhaps this is the (cynical) goal of the IOUs: to entangle the entire RPS movement in delay and uncertainty so that their own foot-dragging can be explained away and excused. Without clear guidance on a TREC program, the argument might go, how can they be expected to meet the State’s aggressive RPS goals? The IOUs have a long way to go to even comply with the 2010 RPS requirement of 20% renewable generation. In 2009, the IOUs collectively served 15.4% of their load with renewable energy. The CPUC estimates that the IOUs are expected to be at about 18% in 2010 and 21% in 2011 – assuming that existing contracts can be converted into operating facilities within that timeframe.

Or it may just be a bureaucratic quagmire that still requires time to work out. After all, the IOU’s fundamental argument in support of the stay, that out of state bundled transactions should not be defined as REC-only transactions and counted toward the 25% cap, makes sense.

California needs to get this right. Whatever system gets developed in California will be followed by other states, especially those in the WREGIS System, so a region-wide system must be supported by the final CPUC decision. We need a workable final decision soon so that we can move forward on the larger goal of lowering greenhouse gas emissions and building a truly sustainable energy infrastructure.

David Niebauer is a corporate and transaction attorney, located in San Francisco, whose practice is focused on clean energy and environmental technologies. www.niebauer.net.

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Posted in California |

FERC Rules Against Feed In Tariffs

Posted August 19th, 2010 by SRECTrade.

Several states have been exploring an alternative to solar renewable energy credits with laws establishing feed-in tariffs (FIT).  A FIT law works by requiring utilities to purchase electricity from certain sources, like solar, at a fixed rate.  This rate is higher than the utilities normal wholesale electricity purchase price in order to subsidize their higher cost.  Unlike SREC laws, the FIT is a relatively blunt policy instrument.  By setting a fixed tariff, the state legislature must exactly calculate the cost needed to incentivize new solar installations.  If the rate is set too high, ratepayers unnecessarily oversubsidize solar (remember cash for clunkers?) and if it is set too low the solar build-up is too slow.  An SREC program, by contrast, allows the market to determine the exact price necessary to incentivize solar, leading to the desired amount of solar at the minimum cost to ratepayers.

State FIT laws were recently dealt a setback by the Federal Energy Regulatory Commission (FERC) who determined that a California  Feed-in Tariff for combined heat and power (CHP) was preempted by Federal Law.  The ruling specifically determined that  FERC has exclusive jurisdiction to set rates, terms, and conditions for the sale or resale of electricity, and that feed-in tariffs are a means of setting rates for the sale or resale of electricity.  The ruling goes on to state that feed-in tariffs would be allowed for certain facilities in certain circumstances, but not at rates above the utilities avoided cost.  Since avoided cost is far below FIT levels, this ruling effectively ends solar FITs in the U.S.

Existing programs in California, Oregon, Connecticut, and Vermont will probably be impacted immediately, while pending legislation in several states will have to be re-examined.  The  good news is that most of these states have existing renewable portfolio standard laws, they only lack a solar carve-out.  By adding a solar component to these existing laws, they can join states like NJ, MD, DE, DC, PA, OH, and MA using a market based approach to drive solar growth.

Some other coverage:
Full ruling can be found at FERC’s website under dockets EL10-64 and EL10-66

FERC deals blow to above-market rates (Feed-In Tariffs)

SEIA makes plans to appeal to congress to give states authority to implement FITs

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Posted in California, Connecticut, Federal SRECs, International Markets, SREC Markets, State RPS |

U.S. Senators Push Renewable Electricity Standard (RES)

Posted August 13th, 2010 by SRECTrade.

There have been several groups lobbying for the inclusion of a Renewable Electricity Standard (RES) in the Senate’s energy legislation.  In addition to several senators, a coalition led by several trade groups and forward thinking utilities have written a letter to Senator Reid.

According to E&E News, more than half of the U.S. Senate’s Democrats have signed a letter urging Senate Majority Leader Harry Reid to include a national RES in any energy legislation that comes to the floor this summer. The senators indicated that they are willing to work together to facilitate the passage of a strong RES.

In addition to the Democrats, some Republicans have demonstrated that they want to support the passage of a national RES. Initial indications have shown that the legislation could require utilities to produce up to 15% of their power from renewable sources. Some Democrats have stated they would like this number to be at least 20% and would prefer to see something in the range of 25%.

The House-passed climate and energy bill sets a combined 20 percent renewable electricity and efficiency standard by 2020.

You can find the full letter here.
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Posted in Federal SRECs, SREC Markets |

NY Candidate for Governor Suggests SREC Program in Energy Plan

Posted August 12th, 2010 by SRECTrade.

Andrew Cuomo, the New York attorney general and Democratic candidate for governor, published an energy plan that suggests increased production of solar and wind energy.  The document, titled “Power NY,” suggests New York adopt an SREC program similar to those that have been so successful in other states such as New Jersey. It declares, “A programmatic commitment to solar power would go a long way toward stimulating the growing solar industry in New York.” Cuomo sites that significant economic growth experienced by California and Arizona upon making commitments to promote expansion of solar power within the states. Both states saw global solar manufacturers locate headquarters within their boarders (China’s Suntech Corp. in Arizona, and SunPower Corp. in California).

The candidate’s plan would create a system of solar renewable energy credits called NY-Sun. The Renewable Portfolio Standard of the state would include a solar carve-out, making utilities purchase SRECs to meet their solar requirement or suffer a compliance fine. He argues that the state should establish specific targets for the adoption of solar energy generation that utilities and electric service companies would have to meet, with the requirements to be suspended if solar costs do not drop to the extent expected.

Mr. Cuomo is the first candidate in the race for Governor to release an energy plan. The length and centrality of the document to the campaign indicates the importance of the worldwide energy transformation in the future of New York.

See the article on the Gubernatorial Candidate’s solar and SREC plan for more information.

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Posted in New York |

First Massachusetts SREC Auction closes, Q1 SRECs sell for $500

Posted August 6th, 2010 by SRECTrade.

Massachusetts now has its first SREC sale on the books.  On July 15th, the first SRECs from the first quarter (Q1: Jan-Mar) of 2010 were created by NEPOOL GIS for the new Massachusetts Solar Carve-Out program. The first transaction has now occurred on SRECTrade.com.  The SRECs cleared at a price of $500 per SREC.

There are still Q1 SRECs that did not sell in this auction.  They will continue to be available in the September and, if necessary, October SREC auctions on SRECTrade.com.  Meanwhile, the second quarter (Q2: Apr-Jun) generation will be added to the supply in the November auction.

This great news for the Massachusetts solar industry and an excellent start to what should be one of the healthiest and most robust SREC markets in the nation.

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Posted in Massachusetts |

Delaware Governer Signs Law Strengthening SREC Market

Posted August 6th, 2010 by SRECTrade.

SB119, a bill amending the Delaware RPS, was signed into law by the Governor last week.  This bill increases and extends the required minimum percentage of electricity coming from renewable sources, and will contribute to the growth and longevity of the SREC market in Delaware.  The new mandate is that 25% of electricity come from renewables by 2026, up from 20% by 2021 and will begin to have an impact on the market in June of 2011.  The requirement for solar has also been increased, which will trigger an increased demand for SRECs.   For example, the estimated SRECs needed by electicity suppliers to meet their 2011-2012 mandate has increased from 6,137 to 25,571.  These changes represent great news for solar owners and installers, as are the other provisions of the bill.

Key Changes:
1. The number of SRECs required will dramatically increase
2. The SACP which sets a ceiling price for SRECs will be raised to levels competitive with other states
3. The municipal utilities that have been exempt thus far will now be required to comply

For more information, please see our previous post on the Delaware SREC Bill or our newly updated Delaware SREC page.

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Posted in Delaware |

Solar Capacity in the SREC States in 2010

Posted July 28th, 2010 by SRECTrade.

SRECTrade’s State of the SREC Markets in 2010
The New Jersey, Pennsylvania and Delaware Energy Years came to a close on May 31, 2010.  The following is a report of the solar capacity in megawatts (MW) certified and registered to create SRECs in all states at that time.

Solar generators by state located: This table is based solely on the location of the facility and does not include multiple state listings. All facilities must have been registered by May 31st, 2010.

As you can see New Jersey has by far the largest amount of solar installed and eligible for SRECs with 146 MW. Pennsylvania is a distant second at 17 MW.  Meanwhile, Ohio and Illinois are third and fourth respectively, however of the 16 MW in Ohio, 12 come from one facility and of the 10.1 MW in Illinois, 10 come from one facility. Delaware and Maryland both have sizable markets at around 6 MW each. Volumes in other state are much smaller since there is no local SREC market.

Solar generators by size: Projects certified for SREC markets range in size from as small as 0.5 kW to as large as 12 MW, however, only 20 out of the 7,700 projects are over 1 MW.  Of those 20 projects all are well below 5 MW, with the exception of a 10 MW facility in Illinois and 12 MW facility in Ohio. The lack of multi-MW facilities in the SREC markets is a function of both the complexity involved and constraints on demand. The only state SREC market today with any legitimate appetite for multi-MW facilities is New Jersey.

Solar generators by state eligibility: Because some states accept out-of-state SRECs, the in-state supply listed above differs from the total supply available to buyers in that state.  For instance, Ohio’s market also includes facilities located in PA, WV, KY, IN, and MI.  The table below lists the total solar capacity in megawatts eligible for each SREC market, along with the percent of the market that is sourced in-state.  Note: many facilities will be counted multiple times in this table since they are eligible in several states. For example, the 10 MW facility in Illinois is eligible in both DC and PA.

In Ohio 89.6% of the market is in-state SRECs. Some of our customers have asked why in-state Ohio SRECs do not sell at a premium because of the 50% in-state requirement. The reason is that, as you can see, buyers are not having difficulty meeting the 50% requirement with the large supply of in-state SRECs. In the future as the requirements increase, in-state SRECs could be harder to come by and may indeed sell for more than out-of-state SRECs.

Interpreting the data: One important thing to notice is that the 2010 Capacity Requirement column details the capacity required to be sustained throughout the entire energy year. The Volume column shows the capacity registered through May 2010. For example, New Jersey needed approximately 160 MW of capacity running on average from June 2009 through May 2010 in order to meet the 2010 SREC requirement. The state is actually farther away from the 160 MW capacity mark than the 145.69 MW volume would suggest.  Capacity in New Jersey grew approximately 65 MW over the course of the year and so there were probably only enough SRECs created to meet approximately 110-115 MW of the 160 MW requirement. That requirement increases in the 2011 Energy Year to approximately 260 MW. For more information on the growth of the New Jersey market and any other state market, please visit our page devoted to State SREC Markets.

Assumptions used in calculations: Solar capacity required is based on 2007 Department of Energy electricity sales figures, assuming a 1.5% growth rate. The resulting solar megawatt-hours required (i.e. SRECs) are converted to megawatt capacity requirement at a rate of 1200 MWhs per MW.

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Posted in Delaware, Maryland, New Jersey, Ohio, Pennsylvania, SREC Markets, Washington, DC |

Massachusetts Solar Credit Clearinghouse Auction Explained

Posted July 26th, 2010 by SRECTrade.

MA Energy Year: January 1st – December 31st.

SREC Life: Two years for compliance buyers who may bank up to 10% of their requirement but sellers must sell SRECs in the year they are generated or deposit them in the DOER Auction. So an SREC produced in 2010 can be counted towards the 2010 or 2011 Solar Carve-Out.

When is the last SRECTrade Auction of each Energy Year?

The final SRECTrade auctions will occur in May and June of the following year, immediately before the DOER Solar Credit Clearinghouse last chance auction which closes on June 15th of each year. SRECs are generated quarterly in Massachusetts on a 4-month delay.  SRECs for Q1 (January-March) are available on July 15th and can be sold in auction at the beginning of August. Q2 SRECs are available on October 15th and can be sold in the November auction, Q3 SRECs are available on January 15th and sold in the February auction and Q4 SRECs are available on April 15th and can be sold in the May auction. Any SRECs remaining after the final SRECTrade auction can be entered into the DOER auction.

What happens if at the end of the year I still haven’t sold my SREC(s)?

If you are an SRECTrade client and you have any SRECs that were not sold then SRECTrade will automatically transfer your SRECs to the  DOER Solar Credit Clearinghouse auction.  You do not need to tell SRECTrade to transfer your SRECs if SRECTrade manages your SREC account. SRECs entered into the auction are “Re-Minted” meaning the eligibility of the SREC is adjusted. For example, a 2010 SREC is originally eligible for compliance in 2010 and 2011. If it enters into the DOER auction, the SREC is Re-Minted to be eligible for compliance in 2011 and 2012. It is no longer eligible for compliance in 2010. Buyers may then bid to purchase the SREC to get a start on meeting their requirements for 2011. The DOER auction will be open May 16th to June 15th each year.  SRECs will be sold at a gross fixed price of $300 less a 5% fee resulting in a net price of $285 to any sellers.

Am I guaranteed to sell my SRECs in the DOER Solar Credit Clearinghouse auction?

No, you are not guaranteed to sell your SRECs in the DOER auction. However, it is unlikely that the SRECs don’t sell. If there is an oversupply of SRECs in the DOER auction, the SRECs will all be granted a third year of eligibility and a second auction will be held. So, in our example, the 2010 SREC will now be eligible in 2011, 2012 and 2013. If there still aren’t enough bids to clear all of the SRECs, DOER will increase the requirements to the buyers by the number of SRECs that are available. The buyers bidding in the auction will now be required to purchase more SRECs in 2011. If after this third attempt, there still aren’t enough bids, the SRECs are returned to the owner as Re-Minted SRECs. These SRECs will be more valuable in the open market than any new SRECs that are created. Going back to our example, the original SREC was a 2010 SREC, eligible in 2010 and 2011 before the auction. Once it was entered in the DOER auction, it became eligible in 2011 and 2012. After an unsuccessful DOER auction it was released back to the owner as an SREC eligible in 2011, 2012 and 2013. This SREC now has a 3-year useful life, making it more valuable to a buyer than the new SRECs created in 2011 which only have a 2-year useful life.

If I’m unsuccessful in the DOER auction, how can I be assured that my SREC will still sell above $300?

Following the DOER last chance auction, SRECTrade will resume its monthly competitive auctions. If there was a surplus of SRECs in the DOER auction, they can be immediately listed in the SRECTrade auction the following month and made available to buyers who are now looking to meet their requirements – which have now been increased by the DOER. At this point, buyers will likely resume buying SRECs in the competitive market in order to ensure that they are able to meet their new requirement and avoid the $600 SACP. SREC prices should stay above $300 in the SRECTrade auctions since the DOER auction at the end of the year will guarantee that price.

Why would a buyer of SRECs ever pay more than $300 when they could just wait to buy their SRECs in the Solar Credit Clearinghouse?

Buyers cannot wait for the DOER auction to buy their SRECs for 2010. When an SREC enters the DOER auction, it is stripped of its 2010 eligibility and cannot be used to meet the requirement for the year in which it was generated. The 2010 SRECs placed in the DOER auction can therefore only be used to meet the 2011 or 2012 requirements. Meanwhile, buyers will want to purchase their 2010 SRECs in the competitive market prior to the DOER auction – otherwise they face the $600 fine.

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Posted in Massachusetts |

Australia Creates Separate Target for Small-scale Renewables

Posted July 26th, 2010 by SRECTrade.

On June 28th, the Australian government decided to split the REC trading environment within the country into two parts: one REC market for large-scale technologies like wind (LRECs) and one market for small-scale technologies like solar (SRECs). The law will go into effect on January 1, 2011. Of the original Australian target—45,000 GWh by 2020—LRECs are to account for 41,000 GWh and SRECs 4,000 GWh. This separation is theoretically akin to the “carve out” for solar energy development seen in several US states, but has been created with the opposite intention: to aid large-scale renewable energy development that would otherwise be dampened by a tendency toward small-scale systems.

The original Australian Renewable Energy Target law was passed last year with a target of 20% renewable electricity generation by 2020, along with a system for requiring utilities to buy all Renewable Energy Certificates (RECs – equivalent to 1 megawatt-hour, like in the US) created within the country.

The government also created a “Solar Credits Multiplier” which effectively multiplied by 5 the number of RECs produced by solar installations less than 1.5kW. This program, however, quickly flooded the market with RECs from small household solar thermal heaters and pumps. These government-discounted systems ultimately lead to a steep decline in REC prices. At values as low as $29 per REC (~$25 USD) large-scale renewable technology developers could no longer take on the financial risk of new projects. The Australian government, aware that larger wind and solar projects have greater potential to provide baseload power, decided to reinvigorate incentives for investment in large-scale renewable energy technologies.

Under the amended law, small-scale SRECs can be sold at a fixed price of $40 per MWh in a clearinghouse set up by the government. These SRECs will be sold quarterly in the order that they are produced. If supply of SRECs is greater than demand, then the government can lower this fixed price or reduce the Multiplier. Yet, if demand outpaces supply, then the government can sell “advance” SRECs to keep the price stable at $40.

The government does allow for SRECs to be traded outside of this clearinghouse, but this will most likely only attract sellers who do not want to wait if their SRECs are too far down the “first-come, first-served” list. Their SRECs will not be purchased for more than the fixed price clearinghouse, as utilities will be able to buy “advanced” SRECs at $40 if necessary. Without a true market for these SRECs, an efficient market price in Australia will be impossible to establish.

In the other market, LRECs will be sold and purchased annually, but it is important to note that those RECs that are produced from small-scale systems before January 1, 2011 will still be eligible. Critics have pointed out that the oversupply of RECs from 2010 will keep prices in both markets low until around 2014 when utilities will need to replenish their supply.

This decision was an important step for the Australian government in creating a more balanced mix of renewable energy technologies within the country. Nonetheless, one of the most pervasive elements of the initial law was the Solar Credits Multiplier. This policy instrument, coinciding with high rebates for solar thermal systems that were also eligible to create RECs, created too much overcapacity in the market. This multiplier provided the overwhelming incentive to install small solar installations. With a REC market flooded by credits that did not accurately represent the electricity produced from small systems, REC prices faced continued downward pressure. With both large- and small- scale renewable developers looking to this same pool of RECs as a means of financing their projects, most large projects (solar and wind alike) were pushed aside.

Multipliers have also been utilized within the United States as well, yet nearly always create an imbalanced mix of renewable technologies within the state’s portfolio. For Australia, it was small-scale solar that overtook the market. The government was forced to amend the law to create a “carve out” for larger-scale projects such as wind. This “carve out” mechanism has worked in the United States to provide the necessary developmental period for high-value, nascent technologies to become competitive in an otherwise hostile market. Yet, Australia may soon find that it’s support will simply create a new dominant technology. The Australian government has opted to favor large-scale projects in proposing that they should inhabit 90% of the total renewable target. These projects, given the current economic superiority of large-wind in a separated LREC market, will most likely be filled entirely with wind power.

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