Many states have recently elected to enact standards encouraging the increased development of solar or other renewable resources in their state through the use of a market-based portfolio mechanism.

These portfolio mechanisms have a number of advantages as compared with other incentive schemes (such as tax or rebate-based schemes). In particular, they maximize competitive pressure to drive down clean energy prices and by design maximize eligible generation at lowest costs. However, a flat RPS alone will develop almost no solar, as the retail cost structure of solar energy is much different than the wholesale structure used by, for instance, large wind farms.

With regard to solar energy, the solar portfolio can be a standalone requirement or a solar band within or in addition to an existing portfolio. The devil is in the details; it's easy to create a standard that fails to create a functioning market simply through the omission of one critical element.

In an RPS, owners of renewable generation receive a certificate for each megawatt-hour of renewable energy they produce. Utilities purchase these certificates according to their price and need. At the end of each compliance year, utilities must produce a given number of these certificates to the relevant regulatory agency to verify compliance.

This allows all parties to comply with relative ease, as compared with attempting to physically track each electron through the system – a physical impossibility – or through hundreds of individual contracts – a needless expense and complication.

In an appropriately designed standard, the price of certificates will naturally rise to that incentive level needed for customers to go forward with a renewable energy project, while the mutual competition of project developers drives down prices.

Requirement on distribution utilities: Depending on the status of restructuring and utility laws in a given state, it can be difficult to require competitive energy suppliers to enter into long-term contracts. Requirements for solar deployment should accordingly bear on integrated or distribution utilities. Additionally, the distribution utilities will necessarily handle the connection and billing of customer-sited solar, so the obligation rests most efficiently with them.

"Backloaded" requirements: The first year or two of requirements should be comparatively modest, requiring perhaps 50% more solar than is currently installed in the state, so as not to overwhelm modest in-state installation capacity. Such capacity can and will develop rapidly in the face of adequate incentives, as seen in New Jersey, where several hundred new, qualified solar electric installers and thousands of installations have developed in just 5 years.

Significant market size / exponential growth: The solar electricity industry – both globally and in leading states like New Jersey and California – is growing at an annual rate of 30–50%. Any requirement must grow at a rate of at least 20% annually to attract significant interest and maximize public benefits. Such targets can be met with relative ease by solar installers, who can bring projects to fruition in much shorter design/build cycles than conventional power developers.

Long horizons: Equally important to attract and retain significant clean energy development is a demonstration that the standard (and the market it creates) be transparent and reliable for a reasonable period into the future. This means that requirements must be stated for a minimum ten-year period, and that even after year-over-year increases cease, the requirements remain in place such that long-term contracts may still be signed in out years.

Sample Requirement

See Also:

Year % of retail sales from solar 2008 .010 2009 .020 2010 .035 2011 .060 2012 .100 2013 .200 2014 .300 2015 .500 2016 .750 2017 1.250 2018 and beyond 2.000

MD 2% solar by 2022 NJ 2.12% solar by 2021 PA 0.5% solar by 2021 CO 0.4% solar by 2015 AZ 0.06% solar by 2007, 4.5% distributed renewables by 2025   Arizona's standard specified 15% renewables, of which 30% must be small resources, usually located at a customer site. It is anticipated that the majority of this will be solar. NV 1% solar by 2015 NY Approx. 0.61% solar by 2013   Currently, the NY RPS assigns funding, not a percentage of generation, to solar. This number is therefore approximate.

The enforcement mechanism for many portfolio standards is an "alternative compliance payment." Under this system, utilities can elect to make a per-kWh payment for any missing RECs. The effect is to put a price cap on the tradable certificates used for compliance (if certificates exceed the ACP amount, utilities will pay the fee instead of purchasing RECs). This also provides a certain degree of self-enforcement; rather than having to institute separate enforcement proceedings for any non-complying utility in any noncompliance period, regulatory agencies can simply collect a known fee.

ACP Levels
These ACPs are frequently set at between 2 and 5 cents per kWh ($20–50 / MWh) for large central station renewable sources. It is critical to note that this ACP is adequate only for large central station renewable sources such as wind or hydropower.

Solar generation technologies, by way of contrast, are generally located at the point of use; their cost structure is based on retail energy rates (nationwide, as much as $0.13–$0.20 / kWh, or $130–200 / MWh) instead of wholesale rates of $.01–$.04 / kWh, $10–$40 / MWh).

It is a critical threshold issue that any solar requirement have an high enough ACP to encourages construction of solar instead of merely the payment of fines. Initial solar ACP rates upwards of $400 / MWh are ideal to ensure compliance, though they can and should decline in a transparent fashion in out years (as requirements increase, cost caps decrease).

ACPs Directed to Renewable Generation
If utilities pay compliance payments for failing to support adequate renewable generation, those funds should be used in a dedicated fund for the development of solar resources.

A portfolio standard can be a complex policy; building on best practices from other states is the best way to ensure a successful standard.

Credit banking: "Banking" lets utilities keep extra credits to meet future requirements. This frees utilities from having to meet requirements precisely in any given year, down to the last decimal; instead, they can aim for conservative compliance rates and retain any credits for one or two future periods. This encourages long-term contracting and full compliance.

Double-counting provisions: For a market to have integrity, it is key that RECs used up in an RPS can't be used again for voluntary purchase or emissions programs.

Long-term contract requirement: In practice, RECs can only finance solar systems if they are sold via long-term contracts to creditworthy entities.

Many homeowners will be receiving just one or two RECs per year; the administrative complexity of negotiating individual contracts for these credits can be massively reduced by requiring long term contracts with individual customers. In order to reduce complexity for all parties involved, contracts with individual residential and small commercial customers should have a specified length of at least 15 years – and be paid up front. In practice, brokers and aggregators exempt from this requirement will make up the rest of the liquidity and spot markets necessary for market functioning.

CO	20 year contracts required for on-site solar.
PA	Long-term contracts permitted.
	Pennsylvania's implementation of the AEPS is not yet complete, but it is expected that long-term contracts for RECs will be realized through any of several mechanisms.
NY	20 Year+ REC assignment for upfront payment.
	In the NY RPS, RECs are transferred to the state agency NYSERDA upon payment of a single upfront payment at the beginning of the contract term.

Credit trading platform: Any portfolio standard must specify a trading platform for renewable energy credits. Several regional systems exist – among them the Western Renewable Energy Generation Information System (WREGIS) or the Generation Attributes Tracking System (GATS) operated by PJM. Individual states have also developed their own systems. This undertaking can be highly complex; it is generally best to use an existing system, if available. If not, involving stakeholders from the small customer-generator community is critical such that the resulting system is not unusable or overly expensive for the smallest users.

Direct Incentive Programs