Posts Tagged ‘FiT’

The Argument for SRECs

Posted October 16th, 2012 by SRECTrade.

Occasionally SRECTrade is asked to defend the efficacy of the SREC system. The harsh drop in SREC prices over the last several months in New Jersey and the long-term outlook for Pennsylvania are sobering examples of SREC market volatility. A recent guest post on Greentechmedia itemized the viewpoint that the structure of SREC markets (in their current form) are detrimental to the distributed solar industry. While we agree that the SREC subsidy mechanism is complicated and can be improved upon we also think SRECs are the best option proposed to date. Like the Winston Churchill quote on democracy we say “SRECs are the worst form of incentive except all of the others that have been tried.”

So far we’ve been presented with two production-based options for subsidizing the solar industry: 1) feed-in-tariffs (FITs) and 2) solar renewable energy credits (SRECs). It is our opinion that non-production based incentives (read grants and tax credits) are a poor method for incentivizing solar as they focus on capacity without regard for long-term optimization and maintenance of the systems to maximize lifetime electricity production.

At their most basic level, FITs are fixed electricity rate guarantees to project owners above the cost of non-solar electricity. FITs typically operate independent of a market. SRECs are a market-based incentive that fluctuate in value depending on supply and demand factors and are traded separately from the actual electricity produced. The idea is that SREC pricing should reflect a market’s need for the subsidy. Below we use some of the concerns we’ve heard voiced about SRECs to underline why they are the best option we have for now.

SRECs Enhance Risk – By definition SREC markets are risky because un-contracted SRECs do not have a fixed price. These risks should be factored into any solar investment in the SREC market states. The problem is that the solar industry ignores huge risks posed by other subsidy schemes and focuses on SREC risk instead. For example, FITs were seen by project finance players as a risk-free long-term contract subsidy until places like Spain, in an effort to control unforeseen costs, retroactively applied production caps for payments far below actual power production and wiped out the economics from under the feet of existing solar systems.

With SRECs you have an independently tradable asset that allows you to sign contracts with counterparties that can be evaluated using standard commercial risk techniques.  With a FIT you’re subject to the whim of a government that may be elected several years from today concerned with cutting “excess” costs. Additionally, solar subsidies tied to payment for actual electricity production (SRECs are traded independent of the sale of solar electricity) are subject to the risk that utilities will impose creative methods to recapture their costs. For example utilities have tried to impose punitive standby charges (recently been attempted in NJ, AZ, CA, and VA), and the tiered residential tariff structure that has driven the CA market is always subject to change. Even the 1603 cash grant in lieu of the investment tax credit (ITC) is subject to claw back, so not even the grant incentive is risk-free. The bottom line is that SREC risk is known at the outset and therefore can be managed, and in fact may be the least “risky” part of the investment.

SREC markets don’t balance themselves- Again, SREC markets aren’t perfect. The long latency between market signals and impacts on build rates are a weakness that market systems like the Massachusetts SREC market are attempting to improve. SREC markets could also be improved in this regard policy adjustments like requiring traditional electricity suppliers (the “natural” buyers of SRECs) to meet compliance requirements throughout the year, among other things. A FIT, on the other hand, is a government determined rate that is almost by definition going to be either set too high, which will give windfall profits to developers, or too low which won’t provide enough incentive to produce the desired result. A grant is an even blunter policy instrument. The compounding impact of the 1603 cash grant and state and local grant programs are large contributors to “failed” SREC markets like PA.

SRECs are too complicated- We spend a good amount of time trying to simplify and explain SREC markets, so we understand this criticism but also understand that there is almost an inverse correlation between complexity and maximum effectiveness with minimal cost. We can make it dead simple but ineffective and costly, or a little more complicated and more cost effective. An SREC program allows those who want simplicity to trade off a slightly lower return in exchange for SRECTrade or other SREC service providers to manage all the complexity of SRECs for them. Those who want to maximize returns can manage that complexity themselves. FITS and grants don’t offer this degree of flexibility and cost effectiveness.

Some Parties Bear Disproportionate Amounts of Risk- In a fully functioning market, aggregated groups of smaller players can sign up for the same contracts as larger projects, and this has been the case for some time in most of the SREC markets. This means market price is almost solely determined by aggregate supply and demand, making it hard for a single competitive supplier to have outsize influence against the aggregated supply of a company like SRECTrade.

We acknowledge that there are market inefficiencies at play that allow larger solar developers advantages, but these advantages can be mitigated through tiered mechanisms like those seen in the Delaware SREC Procurement Program where residential and solar commercial facility owners do not compete against large, sophisticated facility owners and developers.

SRECs Guarantee a Certain Amount of Added Cost- Any incentive program has administrative costs. If you use a FIT or rebate program then it will likely be administered by a regulated utility or government agency, neither of which have any competition to compel them to drive down costs. While SREC markets require aggregators and brokers, these are themselves competitive markets where service providers are incentivized to minimize their cost in order to be able to compete for customers on price.

SREC programs aren’t perfect by any means, but in our opinion they’re the best we’ve got and the proof is in the results. California is often cited as a counter-model the SREC system, but New Jersey (the largest SREC market) overtook California as the state with the most MW of solar installed the first quarter of this year, all the more amazing when you consider that CA has four times the population and a green reputation.

Rhode Island National Grid Seeks Standard Contracts

Posted December 7th, 2011 by SRECTrade.

National Grid Rhode Island is currently procuring applications for standard contracts from eligible Distributed Generation projects. The enrollment started on December 1, 2011 at 9am EPT, and will close on December 14, 2011 at 5pm EPT. The contracts will last for 15 years, and will cover a total of 5MW of capacity, with 1.5 MW allocated to wind and 3.5 to solar in the following distribution and ceiling price.

2011 Class Nameplate 2011 Target(kW) Nameplate 2011 Ceiling Price (cents/kWh)
Solar-PV: 10-150 kW 0.5 MW 33.35
Solar-PV: 151-500 kW 1.0 MW 31.60
Solar-PV: 501-5,000 kW 2.0 MW 28.95
Wind 1.5 MW 13.35

In order to be eligible for this procurement, systems must

  • Be an electric generation unit that uses exclusively an eligible renewable energy resource (as defined under R.I.G.L S39-26-5  and section 5 of the rules and regulations governing the implementation of a renewable energy standard)
  • Neither have begun operations, nor completed financing for construction
  • Be located in the Narragansett Electric Company ISO-NE load zone
  • Not have a nameplate capacity greater than 5MW
  • Be connected to the electric distribution company’s power system.

In addition, project owners must have submitted an Interconnection application and have a completed Feasibility or Impact study as defined in the Rhode Island Distributed Generation Interconnection Act and The Narragansett Electric Company Standards for Connecting Distributed Generation.

A performance guarantee deposit will have to be paid at the time of execution of the contract. It will be assessed based on $15.00 per REC for small distributed generation projects (<500kW), and $25 per REC for large distributed generation projects (>500kW) estimated to be generated per year. The total sum will be no lower than $500 and not more than $75,000. Should the distributed generation facility not produce the output proposed in its enrollment application within (18) months of contract execution, the contract will be voided automatically, and the performance guarantee deposit forfeited.

For facilities that are also being employed for net metering, a proposal may be submitted to sell the excess output from the project. In this case, the class in which the project belongs is determined by total project size, not the excess output offered.

The project must obtain qualification as a renewable resource as per Rhode Island’s Renewable Energy Standard, and must register with NEPOOL-GIS. Once qualified, National Grid must be designated to receive all the RECs produced by the project through NEPOOL-GIS.

More information and the application forms can be found on the National Grid Procurement Website.

Rhode Island Passes Renewable Energy Law

Posted November 14th, 2011 by SRECTrade.

The Ocean State took a step forward in promoting solar energy recently as Rhode Island Governor Lincoln D. Chafee signed §723 Sub A into law on June 29, 2011 to encourage the generation and use of renewable energy in the state.

The legislation requires at least 40 MWs worth of distributed generation projects in the small New England state by the end of 2014. The contracting shall be spread over 4 years based on annual targets set by the Board. Though the specific rules are still being sorted out, the program should proceed quickly as the first 5 MW are due to be contracted by the end of this year.

(1) By Dec 30, 2011, minimum 5 MW;
(2) By Dec 30, 2012, minimum aggregate of 20 MW;
(3) By Dec 30, 2013, minimum aggregate of 30 MW;
(4) By Dec 30, 2014, minimum aggregate of 40 MW.

The Board will recommend to the Commission the standard contract ceiling price by October 15 each year and it will be announced by December 15. The ceiling price for each technology should allow a private owner to receive a reasonable rate of return, based on recent reported and forecast information on the cost of capital and the cost of generation equipment. The reasonable rate of return shall include applicable state or federal incentives including but not limited to tax incentives.

This program represents the first statewide Feed-In Tariff law passed in the U.S. The implementation will be a key factor in how this program will ultimately impact the state. A target of 40 MW over 4 years is not very large, especially considering that a single wind turbine can be larger than 5 MW. All it would take is eight 5MW wind turbines (not wind farms; individual turbines!). Therefore, if Rhode Island has any ambition of developing a lasting industry, it is important that the program is designed in a way that provides access to a diverse group of participants rather than a few “winners” selected by the state and the utility companies.

To that effect, the legislation mandates that by Dec 31, 2012, there shall be at least 4 technology classes and of which, 2 shall be for solar generation technologies. A standard contract term is for 15 years. Besides distributed generation facilities having to be located within the Utility Company’s load zone, small projects shall have a nameplate capacity no larger than 500 kw for solar, 1.5 MW for wind and no more than 1 MW for other renewable energy. Large distributed generation projects may not exceed 5 MW and a project developer will not be allowed to segment a project into smaller sized projects in order to fall under the “small” definition. As long as electric distribution companies fulfill the required technology classes, they are free to mix and match small and large projects to achieve their goals.

Each electric distribution company shall conduct at least 3 standard contract enrollments during each program year except for 2011 where only 1 is required. During the two week enrollment period, the electric distribution company is required to receive standard short-form applications requesting standard contracts for distributed generation energy projects. Contracts for small distributed generation projects are awarded on a first-come first-serve basis. Contracts for large distributed generation projects will be awarded based on the lowest proposed prices received. Eligible systems that are net-metered may apply to sell excess output.