In recent years, the AEO has tracked the growing number of States that have adopted requirements or goals for renewable energy. While there is no Federal renewable generation mandate, the States have been adopting such standards for some time. AEO2005 provided a summary of all existing programs in effect at that time [29], and subsequent AEOs have examined new policies or changes to existing ones [30,31]. Since the publication of AEO2007, four States have enacted new RPS legislation, and five others have strengthened their existing RPS programs. In total, 25 States and the District of Columbia now have mandatory RPS programs (Table 4). At least four other States—Missouri, North Dakota, Vermont, and Virginia— have voluntary renewable energy programs.

All mandatory State RPS programs enacted as of the end of 2007 are represented in the AEO2008 reference case. While States differ in aspects such as eligible generation technologies and compliance penalties, a regional representation was created for modeling purposes. With the exception of California and New York, where eligible future renewable generation is uncertain because of funding limitations for State-supported programs, all States were assumed to meet their program targets, consistent with regionally aggregated compliance schedules. EIA estimated compliance generation in California and New York based on regional costs and authorized funding levels. In estimating diverse State mandates on a regional level, some precision is lost; however, including the State RPS programs in the reference case results in a better projection that is more consistent with current legislation and regulation. If recent trends continue, the State RPS programs will exert growing influence over the national energy mix.

Four States enacted new mandatory RPS programs over the past year:

New Hampshire. In May 2007, the State enacted an RPS which requires that the renewable share of energy consumed for electricity generation increase through 2025, reaching nearly 24 percent by 2025 [32]. Approximately 16 percent of all electricity sales must be from renewable facilities that begin operation after 2006. New Hampshire will collaborate with the New England control area to establish a renewable energy certificate (REC) program. Eligible generation must occur within New England or be consumed by costumers in the area. In this legislation, different renewable technologies are given distinct classifications with minimum generation requirements and compliance penalties. Solar power, which has the highest compliance penalty, must make up 0.3 percent of total sales by 2015 to reach the mandate.

North Carolina. The State established an RPS in August 2007 with different targets for investor- owned utilities, municipal suppliers, and electric cooperatives [33]. Investor-owned utilities must generate 12.5 percent of their total electric sales from renewable generation sources by 2021. Until 2018, one-quarter of this requirement can be met through the implementation of energy efficiency technologies. After 2018, 40 percent of the requirement can be met through the use of energy efficiency technologies. Municipal suppliers and electric cooperatives have a renewable mandate of 10 percent of retail electricity sales by 2018. In addition to the energy efficiency provision, municipal suppliers and electric cooperatives may meet a majority of the mandate through demand- side management and the use of large hydroelectric facilities. North Carolina will use an REC market, and limited out-of-State generation qualifies in meeting the RPS.

Oregon. The State enacted an RPS in June 2007, with standards that vary according to the size of the electricity provider [34]. Larger utilities must produce 25 percent of their electricity sales from renewable resources by 2025. Medium-sized suppliers have a 10-percent requirement and small providers a 5- percent requirement. Any renewable power plant coming online after 1995 is considered eligible toward meeting the State renewable energy goal. Oregon will use an REC market exclusive to the State, and credits will be capped at a price yet to be determined.

Washington. Voters approved Initiative 937 in November 2006, enacting the Nation’s second ballot RPS [35]. The law covers 84 percent of Washington’s sales, affects the State’s 17 largest suppliers, and specifies that 15 percent of their electricity load must be generated from renewable energy by 2020. Eligible generation includes any renewable facility that comes on line after 1999. The 17 suppliers also must identity feasible areas of conservation and publish implementation plans to achieve demand reductions. Failure to comply with the RPS or the conservation measures will result in a penalty to the generator of 5 cents per kilowatthour of generation.

Five States significantly changed their existing RPS requirements:

Delaware. The State enacted Senate Bill (S.B.) 19 in July 2007, increasing the required RPS from 10 percent to 20 percent of electricity by 2019 [36]. It also created a solar photovoltaic (PV) provision under which 2 percent of electricity must originate from solar PV by 2019. Both the solar target and the renewable target consist of escalating interim milestones. The existing schedule of alternative compliance payments (ACPs) is not affected [37], but the bill does provide for separate solar ACPs with a minimum value of $250 per megawatthour—much higher than the standard ACPs. In-State solar PV generation receives triple credits toward meeting the RPS.

Colorado. House Bill 1281 strengthened the RPS that was approved by voters in 2004 by increasing the amount of renewable energy required in 2015 from 10 percent to 15 percent of sales [38]. It also added the requirement that 20 percent of total electricity sales by investor-owned utilities must come from renewable energy by 2020. Investor-owned utilities also are required to generate 2 percent of their sales with solar energy technologies. House Bill 1281 created a less stringent standard for electric cooperatives and municipal utilities, requiring that only 10 percent of sales be from qualifying sources by 2020. It also establishes that generation within Colorado receives 125 percent of the value that out-of-State energy would earn.

Connecticut. The State revised its RPS requirement in June of 2007 as part of Public Act 07-242 [39]. The revisions extended the RPS to 2020, with a 27-percent requirement in that year. Most of the standard is to be met through renewable technologies using wind, solar, sustainable biomass, and wave energy. Generation from surrounding States is eligible. There are separate rules requiring CHP systems and efficiency enhancements (4 percent). Three percent of the total may be met from waste-to-heat facilities and conventional biomass. Suppliers that do not comply face a penalty of 5.5 cents that will be used to fund renewable development.

Illinois. In August 2007, the State’s voluntary renewable goal was replaced by a mandatory RPS [40]. Suppliers with more than 100,000 customers are required to provide 25 percent of their electricity from qualifying facilities by 2025, with several interim requirements. Three-quarters of the facilities must be wind powered. Until 2011, lower cost in- State resources must be used unless they are proven exhausted, in which case out-of-State generation would qualify. After 2011, no preference is given to Illinois resources over others in the region. The costs associated with the mandates are capped and reviewable.

Minnesota. Minnesota’s new RPS regulations became effective in February 2007. They created two standards, one for Xcel Energy and another for other suppliers [41]. Previously, Minnesota had a voluntary standard. The Xcel milestones are the most significant, with 30 percent of all power required to come from renewable energy by 2020. Approximately 83 percent of the power from renewables must come from wind turbines. Other suppliers, including municipal utilities, have until 2025 to meet a smaller goal of 25 percent. The State Public Utilities Commission is still constructing an REC trading system, and the role that interstate or interregional credits will play is still unknown.

Notes and sources

Contact: Chris Namovicz
Phone: 202-586-7120
E-mail: chris.namovicz@eia.doe.gov