According to the Database of State Incentives for Renewables and Efficiency,1 all 50 states have adopted some form of financial incentive program to encourage the development of renewable energy. Incentives may take the form of tax breaks, rebates, grants, low-cost loans, expedited siting and similar measures, and in many cases, all of the above. Most states have adopted a combination of such programs targeting renewable projects.
In parallel with financial incentives, 29 states have adopted renewable portfolio standards (RPS), which over time are requiring more substantial percentages of electric load to be served from renewable resources. As RPS mandates escalate, however, questions emerge regarding whether the goals of renewable incentive programs to promote local resources and in-state economic development are consistent with the idea of achieving RPS compliance in the most cost-effective manner. As the cost of RPS compliance also increases, there should be a greater focus on the relative costs and benefits of current incentive programs and the sufficiency of resources expected to be available through the renewable energy credit (REC) markets.
The state of Connecticut provides an example of an all-of-the-above approach to incentives for renewable energy. The state has aggressive RPS requirements, and has a variety of programs in place to encourage the development of local resources, including utility-backed contracts to qualifying projects, and customer grants for distributed generation projects utilizing renewable technologies, among other financial incentives. Programs are funded by a line-item charge on electric bills.
Recent proceedings before the state public utilities commission have highlighted the emerging struggle to balance program objectives of promoting in-state resources and economic development, with consideration of the substantial above-market costs and ratepayer impact of those programs, and the cost of RPS compliance generally. To date, most of the state’s RPS requirements have been met through market purchases of RECs from out-of-state resources, with costs embedded in utility standard-service contracts or retail-supply contracts. While this likely will continue to be the model for most of the state’s RPS compliance, Connecticut now has authorized electric distribution companies to seek proposals for long-term REC contracts. This effort could serve the dual purposes of providing an incentive to the regional REC market while mitigating the cost of RPS compliance, aligning these thus-far competing objectives.
Connecticut is among the 29 states and the District of Columbia that have adopted RPS. As of 2009, the state’s RPS requirement requires that 12 percent of load be served from renewable resources, increasing to 27 percent by 2020. The percentages are shared among three categories of resources, with the predominant amount designated for class-I resources, which include solar, wind, landfill gas, ocean thermal, wave or tidal power, low-emission advanced renewable energy conversion technologies, certain run-of-the-river hydro and sustainable biomass facilities. Connecticut also classifies fuel cells as a class-I resource. Suppliers meet the RPS requirements by purchasing RECs created through the New England Power Pool Generation Information System, in which each REC represents one megawatt hour (MWh) of electricity generated from a renewable energy source that either is located within, or imported into, the control area of the regional system operator. Connecticut must certify each resource for use in meeting the state’s RPS. To date, the public utilities commission has approved more than 275 renewable resources.
The Connecticut RPS has influenced the development of in-state class-I resources, particularly fuel cell projects, but arguably has had a more substantial influence on renewable projects elsewhere in the northeast. The state’s incentive programs are designed to provide financial subsidies directly to in-state projects, thus far with few sizable projects to their credit. The result is that most of the class-I RPS requirements are being met with RECs from lower-cost projects elsewhere in the region. In 2007, for example, more than 95 percent of the class-I requirements were met with resources outside of Connecticut. Biomass was the predominant fuel source, followed by landfill methane gas. For class-II resources, which are primarily trash-to-energy facilities, 40 percent of the requirement was met with RECs from out-of-state projects, and the balance was from in-state facilities that predate the RPS.
Further, the demand for class-I resources to keep pace with Connecticut’s escalating RPS requirements is expected to remain high, suggesting “a potentially protracted period of high REC prices” approaching alternative compliance payment levels.2 The market for class-I RECs is expected to tighten after 2010. Approximately 5,800 MW of renewable projects are waiting in the ISO New England queue, which if built would be sufficient for several years, but it’s highly uncertain how many of these projects ultimately might go forward. The market for class-II RECs has been comparatively soft, due to a surplus of class-II resources and a fixed RPS requirement for such resources. Connecticut also is considering changes to its program to allow banking of excess RECs for use in up to two subsequent years under certain conditions.
In 2003, Connecticut established financial incentives for renewable and distributed resources, and shortly thereafter expanded those programs to target additional in-state resources. Among the programs is a requirement for the state’s electric distribution companies to enter long-term power-purchase agreements (PPA) for 150 MW of grid-side renewable resource projects. The projects must be class-I resources located within the state to qualify.
Through three rounds of procurement, the public utilities commission has approved contracts with 13 projects to meet the 150-MW requirement, including four biomass, one landfill gas, and eight fuel cells. In the most recent round, the commission approved five projects, all fuel cells, for 27 MW at an estimated cost between $4.4 million and $5.3 million per MW. These contracts would result in above-market costs over the life of the contracts in the range of $250 million to $300 million. The commission expressed concerns in approving the projects regarding the cost and “severe projected rate impact,” but determined that it was nevertheless constrained by the legislatively mandated timeline for achieving the 150-MW threshold. None of the projects are on-line yet, and the fate of many of them is uncertain. Even with the relative security of the PPAs, and additional ratepayer-funded project grants, the financial viability of the projects might depend on their ability to qualify for additional federal incentives. Additional rounds of procurement likely will be needed to deal with project attrition.
The price of the PPAs is set by law at not more than the estimated “comparable wholesale market price for generation” plus a 5.5 cents-per-kWh adder. In the alternative, projects could be priced at up to 50 percent of the wholesale electricity cost, plus a fuel adjustment based on natural gas futures, plus the 5.5-cent adder. The law also provides a preference to projects that use fuel cells principally manufactured in Connecticut, by allocating all air emissions credits and tax credits to these projects and not less than half of any associated RECs. The structure of the pricing and incentives might give the fuel cell projects the better chance of moving forward as compared to the other approved projects. If any of the projects go forward, available RECs would be credited toward class-I RPS requirements.
Efforts to promote development of smaller-scale renewable projects in Connecticut have been more successful. The Connecticut Clean Energy Fund (CCEF) runs a ratepayer-funded program to promote the installation of customer-side distributed generation utilizing renewable technologies. The program provides grants to customers to buy down the cost of renewable generation equipment, and is intended to enable the project owner to break even over the life of the project, including a return on investment, as compared to purchasing an equivalent amount of power from the utility. The program targets primarily class-I resources, but because of the small size of the projects, its potential impact on the REC market and RPS compliance costs also is small. By mid-2007 CCEF had issued grants for projects totaling 5 MW. CCEF intends to subsidize an additional 15 MW by mid-2010.
The state’s electric distribution companies typically serve standard-service loads through short-term full-requirements contracts, in which the wholesale suppliers to the companies are responsible for meeting all RPS requirements. As a result, each supplier has been required to procure RECs to cover its full portion of the electric distribution company’s load—or incur an alternative compliance payment should it fail to do so. The cost of the RECs associated with each supply contract is embedded in the supplier’s bid price.
Connecticut recently modified its procurement rules to authorize electric distribution companies to explore additional contract options, including the option to seek proposals for long-term bilateral contracts and REC contracts to meet a portion of the RPS requirements. RECs may be procured through a separate long-term deal, or as part of a bundled contract for energy and capacity. The electric distribution companies are expected to evaluate the class-I REC market from time to time to examine whether market conditions and supplier interest may facilitate favorable terms for Connecticut ratepayers.
The REC contract initiative recognizes the projected constraint on class-I resources, and is intended in part to promote renewable development in the Northeast. In approving the initiative, the commission noted that long-term contracts could provide greater market certainty to project developers, including a revenue stream that would lower risks and facilitate project financing. Consistent with the RPS requirements, contracts aren’t limited to in-state resources.
The larger impetus for authorizing long-term REC contracts appears to have been their potential to provide cost savings to customers. As an example, the contracts aren’t limited to new resources, thus putting existing facilities on an equal footing for purposes of submitting competitive bids. There’s some concern that excluding existing resources could skew the market and increase the bid prices for new resources. The contracts also aren’t limited to in-state resources, but could be located anywhere within the region, with price being the overriding factor. Other factors include the potential for price stability, fuel diversity, a hedge against potentially higher market prices, and elimination of the mark up on REC costs embedded in full-requirements bid prices from suppliers. Long-term contracts provide the opportunity to meet a portion of the RPS requirements with RECs obtained at cost. In anticipation of possible changes in the definition of RECs over time or the imposition of carbon caps, the contracts may be drafted to encompass all environmental attributes.
The contract costs will be recovered in a bypassable generation charge. While the enabling statute allowed regulators to approve contracts of up to 15 years, the commission indicated that it would limit the term of REC contracts to a range of four to 10 years in order to mitigate the possibility of stranded costs. It’s unclear whether the shorter contract term will be sufficient to promote new development or have the desired positive impact on REC market prices.
In September 2009, the governors of the six New England states adopted the Governors’ Renewable Energy Blueprint, which was prepared by the New England States Committee on Electricity.3 The report states that New England has “untapped renewable resources” on the order of over 10,000 MW. The report suggests a coordinated approach to develop a level of resources sufficient to keep pace with the region’s renewable goals, but also potentially to exceed those goals to exploit the capability of the region to become a net exporter. The report notes that “[m]ore aggressive development of generation resources—with corresponding transmission infrastructure investment—would enable New England to export clean power.”
The Governors’ Blueprint could signal a shift toward a regional focus on renewable project development. This shift would be a further reason for states to revisit their renewable incentive programs with respect to alignment with RPS goals.
1. Established in 1995, the Database of State Incentives for Renewables & Efficiency (DSIRE) is an ongoing project of the North Carolina Solar Center and the Interstate Renewable Energy Council (IREC). It’s funded by the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy (EERE), primarily through the Office of Planning, Budget and Analysis (PBA).
2. Integrated Resource Plan for Connecticut, prepared by the Brattle Group for The Connecticut Light and Power Co. and The United Illuminating Co., dated Jan. 1, 2008.
3. The report is available at www.nescoe.com/Blueprint.html.