i CHP SERA COMBINED HEAT AND POWER PARTNERSHIP Draft- Portfolio Standards and the Promotion of Combined Heat and Power Energy Portfolio Standards Energy portfolio standards (EPS) are becoming a widely applied method of encouraging the development of renewable and efficient energy resources. The most commonly implemented portfolio standards are renewable portfolio standards (RPS), although there is increasing discussion about Energy Efficiency Resource Standards (EERS). An RPS requires electric utilities and other retail electric providers to supply a specified minimum amount of customer load with electricity from eligible renewable energy sources. This amount usually begins as a small percentage of the total electricity load that increases gradually over time (e.g., 5 percent by 2010, increasing 1 percent per year to 15 percent by 2020). Through January 2008, EPS requirements or goals have been established in 29 states plus the District of Columbia (see Figure I).1 Most EPSs have been established within the last five years, with 10 states enacting RPS policies in 2004 and 2005 alone.2 combined heat and power (CHP), and are including these technologies in expanded or alternative EPS policies. For example, some states, like Connecticut, are promoting a variety of energy efficient technologies in their EPS policies through a system of different technology classes or tiers; each tier requires a specific percentage or amount (in megawatts) of energy production to come from specified renewable or efficient technologies. Connecticut and Pennsylvania have both included energy efficiency and CHP in a separate tier in their EPSs. Eight statesColorado, Connecticut, Hawaii, Nevada, North Carolina, North Dakota, Pennsylvania, and Washingtoninclude CHP and/or waste heat recovery as an eligible resource and Arizona explicitly includes renewably fueled CHP systems. CHP, also known as cogeneration, is the simultaneous production of electricity and heat from a The type of resources that are eligible under an RPS or EPS varies by state. Most states include renewable resources such as solar, wind, small hydropower and ocean/tidal/thermal systems, biomass, and landfill gas. Some states also include advanced technologies, such as fuel cells, that possess beneficial energy and environmental attributes. In addition, states are increasingly recognizing the energy, environmental, and economic benefits of energy efficiency and Figure 1 - States With RPS Requirements States with RPS goals Source: Database of State Incentives for Renewable Energy (DSIRE) last accessed January 2008, www.dsireusa.org. ------- single fuel source such as natural gas or biomass/biogas. CHP systems offer considerable environmental benefits when compared to traditionally purchased electricity and onsite-generated thermal energy. Combined Heat and Power (CHP) By capturing and utilizing heat that is normally wasted, CHP systems typically achieve total system efficiencies of 60 to 80 percentcompared to less than 50 percent for equivalent separate heat and power systems. With this increased efficiency, a CHP system uses 35 percent less fuel to achieve the same energy output as separate heat and power systems. Because CHP is a form of distributed generation (DG) in which less fuel is combusted, it offers a number of environmental and economic benefits: Reduced emissions of all air pollutants - Fewer greenhouse gas emissions, such as carbon dioxide (C02) - Fewer criteria air pollutants, including nitrogen oxides (NOX) and sulfur dioxide (S02) Reduced grid congestion and avoided distribution losses Increased reliability and power quality Lower operating costs For more specific information about how CHP works and what its benefits are, see the addendum at the end of this paper or visit EPA's CHP Partnership Web site at www.epa.gov/chp. RPS Design and Implementation States have recognized the increasing need to encourage efficient and nonpolluting sources of energy. RPSs are the favored approach for most states because they can stimulate market and technology development using a cost-effective, market-based approach that is also administratively efficient. Most RPS requirements work through the application of a trading program either in the state or on a regional basis. Qualifying renewable resources receive a certain number of certificates per year, usually based upon their generation (e.g., 1 megawatt-hour [MWh] = 1 certificate). These certificates are most often referred to as renewable energy certificates (RECs). Renewable energy generators can then sell RECs to electricity suppliers, such as large utilities, that must also fulfill the RPS. RECs not only generate revenue for renewable generators, but they are also the measure of compliance for the RPS policy. REC trading programs provide flexibility and reduce administrative program costs in several ways: Not every electricity supplier needs to develop and operate renewable generation assets to comply. Independent renewable developers have access to the market. Renewable energy can be supplied from the most advantageous sites to electricity suppliers throughout a state or a region. RPSs often contain an alternative compliance mechanism under which an electric supplier or distributor can pay a fee to the state if they are unable to procure a sufficient supply of RECs. The Alternative Compliance Payment (ACP) is often set at a high level to encourage the development of renewable projects. Payments to an ACP fund are usually used by the state to promote the development of renewable projects. For example, in Massachusetts, the ACP goes to the Massachusetts Technology Collaborative. This organization then uses the money to fund clean energy and green buildings and infrastructure programs. The clean energy program's goal is to support community and utility projects that use wind, solar, and bioenergy and to educate citizens about green electricity markets. The green buildings and infrastructure program provides funding to renewable energy technologies in all types of buildings. In Connecticut, the ACP goes to the Connecticut Clean Energy Fund to promote Class I and Class II resources (new renewable generation) and to the conservation and load management program to support Class III resources (energy efficiency and CHP). Elements of a Successful RPS Policy There are several key components to the design and implementation of an RPS, discussed below. Eligibility The definition of which technologies are eligible for inclusion is quite varied. Table 1 summarizes the technology eligibility for state RPS programs as of January 2008. While states identify renewable technologies differently, most tend to include, at a minimum, solar, wind, biomass, and landfill gas/biogas. Some programs only allow combustion technologies that use biomass or other renewable fuels; others allow the use of any fuel as long as it is in an approved technology. In the case of CHP, inclusion may require meeting a minimum efficiency percentage (e.g., 50 percent total efficiency in Connecticut) or designation as a "qualifying facility" under the Public Utilities Regulatory Policy Act. These efficiency minimums also usually require some threshold of ------- Table 1 - Summary of State Energy Portfolio Standards Energy Source AZ CA CO CT DE DC HI IA IL MA MD ME MN MO* MT NC ND* NH NT NM NV NY OR PA RI TX VT* WA WI Biofuels Biomass 0 0 CHP/Waste Heat 0* 0 Energy Efficiency Fuel Cells* 0 0** 1 CU 1 o O iH X Landfill Gas Municipal Waste Ocean Thermal Photovoltaics Solar Themal Electric 3 Waste Tire 1 a e s recovered electric and/or thermal energy, such as Connecticut's 20 percent minimum thermal threshold. The RPS eligibility requirements might also set emission limits for emitting technologies. For example, through 2005, California sources were required to produce zero emissions or meet the 2007 state emission limits for DG to qualify as eligible. In Connecticut, specific emission limits apply to biomass facilities. CHP systems that are fueled with a qualifying renewable resource, such as biomass, are eligible under RPSs. In this context, typically only the electric output of the CHP system is eligible. States can also include the thermal output for these systems in their RPS to fully value the benefits of CHP. There are numerous states that credit thermal output in their environmental regulations. For example, California, Maine, Rhode Island, and Texas include thermal output in their Small DG Rule.3 So do EPA's Combustion Turbine New Source Performance Standards.4 To account for the thermal output of CHP units, these states convert the measured steam output (British thermal unit, or Btu) to an equivalent electrical output (MWh). This is done through a unit conversion factor (1 MWh = 3.413 MMBtu). By adding the thermal and electric output together, states are recognizing the full environmental and emissions benefits of CHP. RPS language can be modified to state that CHP output will be calculated as the electric output plus the thermal output in MW, based on the conversion of 1 MWh = 3.413 MMBtu of heat output. RPSs often include several tiers or classes of generators in order to differentiate between different technologies and allow different targets to be set for different classes. Often, Tier I includes primarily zero-emitting renewables, while other tiers include biomass or other emitting renewable technologies or advanced low-emitting non- renewables. Some states, such as Connecticut and Pennsylvania, can utilize a separate tier for energy efficiency and CHP, ensuring these resources do not compete with renewable energy technologies. Different generation targets are then set for each tier according to state goals, resources, and interests. RECs for different tiers typically garner different prices, with the zero- emitting renewables typically having the highest prices (see Table 2). For example in New Jersey, the price for a solar REC for the 2006-2007 calendar years was $240. Consistency among state portfolio standards in a region provides large benefits to the electric market. Considering state and regional resource availability is central to the success of a portfolio standard. States with RPS goals not mandatory requirements. 'Renewable CHP systems are eligible; fossil-fueled CHP systems are not eligible. **After January 1, 2010, hydrogen must be generated by renewable energy sources. ^Includes only those states that allow fuel cells using nonrenewable energy sources of hydrogen. Some states allow only renewable fuel cells (Arizona, California, Colorado, Delaware, Massachusetts, Maryland, Missouri, New Mexico, New York, Rhode Island, Wisconsin) as eligible technologies. Source: Database of State Incentives for Renewable Energy (DSIRE) last accessed January 2008, www.dsireusa.org. ------- Size of Requirement The basis of the renewable requirement can vary but is typically a percentage of annual generation or sales of electricity. The size of the requirement is also quite varied. Requirements normally start from a small percentage and then grow by some increment each year to achieve a plateau level by a specific target year, subject to review. Table 3 shows the range of target values in states with an RPS. The size of both the initial and target values also depends on which technologies and vintages are allowed in the program. For example, Maine's first RPS required 30 percent clean energy, but it included many existing biomass facilities, which already comprised more than 30 percent of the state's generation. It is also important for states to conduct renewable energy, energy efficiency, and CHP potential studies as a portfolio standard is created. These studies ensure that the standard can be met without placing too much strain on the affected utilities. Alternative Compliance Payment Many RPS programs include an Alternative Compliance Payment (ACP) provision. The ACP sets a limit on the price of RECs in case renewable generation does not keep up with the requirements. If the regulated entities cannot purchase RECs at a price below the ACP, they are allowed to pay the state the ACP price as an alternative. The state then uses the ACP funds to promote renewable projects. The ACP price usually escalates over time. This structure prevents the REC price from being too high while at the same time provides funding for renewable development when supply is scarce. Vintage Because the goal of an RPS is to encourage new sources of renewable or efficient generation, many RPS requirements state that eligible resources are those constructed after a certain date, such as after or shortly before the rule is promulgated. Some states credit incremental generation added after the required vintage date; CHP systems in Connecticut and biomass facilities in Massachusetts are allowed such flexibility. In a few cases, existing facilities are allowed full credit under the RPS (e.g., renewable facilities under Maine's first RPS). As previously noted, the decision on vintage also affects the appropriate size of the target. Point of Origin RPS programs are typically state programs that allow only the use of RECs generated in that state. However, some programs do allow trading of RECs from other states with harmonious RPS programs that are in the same or an adjacent power pool. The Northeast includes multiple states in this category. However, some mechanism must still ensure that RECs from other states meet appropriate Table 2 - REC Prices in July 2007 (1 REC = 1 MW) Connecticut Class I 2007 $52.00 Class II 2007 $0.55 Maine 2007 $0.20 Massachusetts 2007 $54.50 Texas 2006 2007 2008 $2.75 $3.30 $3.40 Delaware 2007 $1.75 Rhode Island 2007 $48.00 New Jersey Solar 2006/2007 $240.00 Class I 2006/2007 $40.00 Class II 2006/2007 2007/2008 $1.25 $1.35 Maryland Tier I 2006 2007 $0.55 $0.95 Tier II 2006 2007 $0.60 $0.55 DC Tier I 2007 $1.75 Tier II 2007 $0.75 Pennsylvania Tier I 2007 $5.50 Source: Evolution Markets. July 2007 Monthly Market Update (2007) www.evomarkets.com. ------- eligibility criteria. If both states are in the same power pool with a consistent attribute tracking system, ensuring eligibility across state lines is easier. For example, states in the New England Power Pool (NEPOOL) can rely on the power pool's Generation Information System (CIS) to track and compare RECs. Table 3 - State Portfolio Targets State AZ CA CO CT DC DE HI IA IL MA MD ME MN MO* MT ND* NH NC NJ NM NV NY OR PA RI TX VA* VT* WA WI Target (% of electric sales) 15% by 2025 20% by 2010 Investor-owned utilities (lOUs) 20% by 2020; electric cooperatives and municipal utilities 10% by 2020 27% by 2020 11% by 2022 20% by 2019 20% by 2020 105 MW 25% by 2025 4% by 2009 ( +l%/year after) 9.5% by 2022 10% by 2017 Xcel Energy (utility) 30% by 2020; other utilities 25% by 2025 11% by 2020 15% by 2015 10% by 2015 23.8% by 2025 (16.3% new) lOUs 12.5% by 2021; electric cooperatives 10% by 2018 22.5% by 2021 lOUs 20% by 2020; rural electric cooperatives 10% by 2020 20% by 2015 24% by 2013 Large utilities (>3% state's total electricity sales) 25% by 2025 18% by May 31, 2021 (8% renewable energy) 16% by 2020 5,880 MW by 2015 12% of 20007 sales by 2022 Total incremental energy growth between 2005 and 2012 to be met with new renewables (10% cap) 15% by 2020 10% by December 31, 2015 Specific Provisions (% of electric sales) 4.5% by 2012 from distributed energy resources lOUs: 4.0% solar by 2020 4% energy efficiency and CHP by 2010 0.386% solar by 2022 2.005% solar by 2019 18.75% wind by 2013 2% solar by 2022 Xcel Energy: 25% wind 0.3% solar by 2025 Energy efficiency measures up to 3.13%; 5% after 2021 2.12% solar by 2021 Wind, solar: 0.02% each; biomass, geothermal; 0.01% each by 2011 (lOUs only) 1% solar by 2013 0.154% customer-sited by 2013 Smaller utilities 5-10% by 2025 (depending on size) 0.5% solar by May 31, 2021 States with RPS goals not mandatory requirements. Source: Database of State Incentives for Renewable Energy (DSIRE) last accessed January 2008, www.dsireusa.org. Monitoring In most cases, the formation of a REC is based on the amount of electricity generated. Therefore, a program must have a system of tracking the generation to ensure that it comes from a qualifying resource. Many states already have such tracking systems to meet emissions disclosure requirements. NEPOOL's CIS tracks generation and even classifies RECs according to their eligibility to meet different state RPS requirements. The PJM Generation Attributes Tracking System (GATS) can be used to track generation attributes in the Mid-Atlantic region and can form the basis for awarding RECs, as it is in Pennsylvania. In California and other western states, the Western Renewable Energy Generation Information System (WREGIS) was created to issue, register, and track RECs; the system helps monitor and track renewable energy generation for both regulatory compliance and voluntary market programs. The WREGIS covers the Western Electricity Coordinating Council (WECC) service area, which extends from Canada to New Mexico and includes 14 western states and part of Baja California. The Midwest Renewable Energy Tracking System (M-RETS) tracks renewable energy generation in the form of RECs for participating states (currently Illinois, Iowa, Minnesota, Montana, North Dakota, South Dakota, and Wisconsin) and assists in verifying compliance with individual state RPS requirements or goals. M-RETS production data is provided by the Midwest Independent Transmission System Operator (MISO). In Texas, the Electric Reliability Council of Texas (ERCOT) allocates RECs to renewable generators each year for every MWh metered on the grid. ERCOT then uses a pro- rata basis to determine renewable requirements for each retail electricity provider (REP). The requirements are based on total electricity sales for a given year, not on generation. REPs are required to retire RECs; they do not have to buy the associated generation. Trading In most RPS states, affected entities must meet the RPS through the surrender and retirement of RECs. The affected entity can generate, purchase, or trade the RECs. States typically utilize a regional tracking system that allows renewable generators located anywhere within the region to participate in the market. RECs are the currency used to represent renewable generation that is creditable against the RPS requirements for a seller or generator of electricity. The affected entity can create the RECs itself or purchase them from another eligible generator. Trading RECs increases flexibility and reduces the cost of compliance. This method provides a market that encourages the development of eligible resources by many independent developers by providing an important income stream for ------- project developers. This income can be an important component of the pro-forma financial package needed to attract capital to finance a new project. Trading allows the flexibility to develop renewable resources wherever the available resource is most favorable, either within the state or between states, allowing the development of the most cost-effective resources. However, accepting out-of-state RECs might reduce the amount of in- state environmental improvement and economic development resulting from the RPS. This tradeoff must be evaluated against cost and resource availability to determine the appropriate structure for any given state. One state that deviates from the common RPS compliance options is New York. New York's RPS works though a method called a central procurement model. Under this model, electric utilities collect a surcharge on electricity sold to consumers. These funds are turned over to the New York State Energy Research and Development Authority (NYSERDA), which purchases RECs on behalf of all the regulated entities. State Examples of EPS That Include CHP The inherent flexibility in RPS design allows states to identify and promote specific resources or technologies that support their environmental, energy, and economic development goals. CHP is one of the technologies that supports each of these goals. Table 1 summarizes the characteristics of current state portfolio standards, including the nine states that include CHP.5 Of these states, six include clean fossil- fueled CHP, three include waste heat CHP, and one includes renewably fueled CHP.6 State EPS programs that include CHP are summarized below. Connecticut The Connecticut RPS was originally promulgated in 1998 and was revised in 2005 and 2007. In 2005, Connecticut added a third tier to the RPS resource requirements, establishing a new RPS Class III that must be fulfilled with CHP, demand response, and electricity savings from conservation and load management (C&LM) programs.7 In 2007, the Class III standard was expanded to include systems that recover waste heat.8 The RPS standard requires electric suppliers and distribution companies to obtain 1 percent of their generation from Class III resources beginning in 2007, increasing by 1 percent per year until leveling out at 4 percent in 2010 and thereafter. The total RPS requirement is 10 percent in 2008 and will rise to 27 percent in 2020 (including Class I, Class II, and Class III resources). The Connecticut Department of Public Utility Control (DPUC) released its final decision regarding the implementation of a Class III standard on June 28, 2006, in Docket No. 05-07-19.9 The final decision outlines requirements for accreditation of savings from C&LM projects; CHP efficiency and metering standards; environmental attribute management; qualifying demand response activities; and certificate creation, allocation, and incorporation with the NEPOOL CIS. The DPUC reopened the docket on August 1, 2007, to clarify the eligibility of waste heat recovery systems added to the Class III standard by the legislature in 2007, and to consider the allocation of Class III credits to eligible technologies. A decision is expected in the first quarter of 2008.10 Eligible CHP systems must be developed on or after January 1, 2006. Eligible systems that recover waste heat or pressure from commercial and industrial processes must be installed on or after April 1, 2007. Existing units that have been modified on or after January 1, 2006, may earn certificates only for the incremental output gains. A CHP system must meet a total efficiency level of at least 50 percent. The sum of all useful electrical energy output must comprise at least 20 percent of the technology's total usable energy output. The sum of all thermal energy products must also constitute at least 20 percent of the technology's usable energy output. Annual fuel-conversion efficiency and percentages of production will be assessed quarterly for the first year after initial certification. After this first year, the CHP system must demonstrate compliance with the efficiency requirements each quarter to qualify for RECs. Pursuant to the 2007 legislation, customers that install Class III resources on or after January 1, 2008, are entitled to Class III credits equal to at least one cent per kilowatt-hour (kWh). The revenue from these credits must be divided between the customer and the state C&LM Fund in different ways depending on when the Class III resources are installed, whether the owner is residential or nonresidential, and whether the resources received state support.11 Energy savings from demand response activities are eligible for Class III certificates; however, the demand response projects must be registered and participate in the region's wholesale electricity market administered by ISO New England, Inc. (ISO-NE). Hawaii Hawaii has had a mandatory RPS since 2004,12 which was amended in 2006.13 The RPS requires 10 percent renewable energy and renewable electrical energy to be generated in 2010, 15 percent in 2015, and 20 percent in 2020. Existing renewables may be counted in the total. Renewable electrical energy includes electrical energy savings "brought about by the use of energy efficiency technologies," including the "use of rejected heat from co- generation and combined heat and power systems excluding fossil-fueled qualifying facilities that sell electricity to electric utility companies and central power projects."14 ------- The Hawaii Public Utility Commission (PUC) has the authority to review the RPS every five years and potentially extend requirements past 2020. The PUC may also establish standards for each utility that prescribe what portion of the RPS shall be met by specific types of renewable energy sources, provided that at least 50 percent of the RPS is met by renewable energy sources. In Hawaii, an electric utility company must fulfill the RPS requirement. However, electric utilities and electric affiliates are allowed to combine their renewable portfolios to meet the requirements. Thus, Hawaii's program does not include a REC trading program as such. The utilities must document their generation directly to show compliance. North Carolina In August 2007, North Carolina enacted a Renewable Energy and Energy Efficiency Portfolio Standard (REPS) requiring all investor-owned utilities to supply 12.5 percent of 2020 retail electricity sales from eligible energy resources by 2021. Municipal utilities and electric cooperatives must meet a target of 10 percent eligible energy resources by 2018. Up to 25 percent of the requirements may be met through energy efficiency measures, including CHP. After 2018, up to 40 percent of the standard may be met through energy efficiency and CHP.15 Under the REPS, there is no minimum efficiency requirement for CHP. Energy from CHP is included to the extent that the system "uses waste heat to produce electricity or useful, measurable thermal or mechanical energy for the retail customer's use and results in less energy used to perform the same function or provide the same level of service at the retail customer's facility."16 Thermal energy that is not used to generate electric power and is measured accurately in British thermal units (Btu) shall earn equivalent RECs based on the end-use energy value of electricity of 3,412 Btu per kWh. Renewable energy and CHP must have been installed after January 1, 2007, to be considered eligible. Utilities may meet their obligations through actual generation of electricity with eligible fuels and technologies, through the purchase of bundled renewable energy, by procuring unbundled RECs (each equivalent to 1 MWh) from in-state or out-of-state renewable energy facilities, or through the implementation of energy efficiency measures.17 The North Carolina Utilities Commission (NCUC) is responsible for administering the RPS and may adjust or modify the RPS schedule if it deems such modifications to be in the public interest. The NCUC opened docket E-100 Sub 113 on August 23, 2007, to initiate rulemaking to implement the RPS.18 A final order had not been issued as of February 1, 2008. Pennsylvania Pennsylvania's Alternative Energy Portfolio Standard (AEPS) was enacted in 2004 and amended in 2007.19 Pennsylvania has a tiered structure to its RPS, similar to Connecticut. Both new and existing renewables are eligible as Tier I resources. Tier II resources include demand-side management and distributed generation systems, including CHP. In 2007/2008, 1.5 percent of electricity sold must come from Tier I sources with 4.2 percent from Tier II. The Tier I standard increases to 2 percent in 2008/2009 and 0.5 percent each year thereafter, to reach 8 percent of electricity from Tier I sources by 2020/2021. The Tier II standard increases 2 percent every five years to reach 6.2 percent in 2010/2011 and 8.2 percent in 2015/2016. An additional jump to 10 percent in Tier II resources by 2020/2021 is included as part of the standard. Utilities comply with the RPS by obtaining the required number of RECs (each equivalent to one MWh of generation), which are tracked using the PJM power pool's GATS. AEPS amendments in 2007 clarified that RECs are the property of the renewable energy generator. The AEPS contains a force majeure clause under which the Pennsylvania Public Utilities Commission (PUC) can make a determination as to whether there are sufficient alternative energy resources in the market for utilities to meet their targets. If the PUC determines that utilities are unable to comply with the standard despite good faith efforts, the PUC may alter the obligation for a given year. It may then require higher obligations in subsequent years to compensate for shortfalls.20 Washington In 2006, Washington State passed a Renewable Energy Standard (RES) by ballot initiative I-937.21 The initiative requires electric utilities that serve more than 25,000 customers in the state to generate 15 percent of their electric load from new renewables by the year 2020. Additionally, electric utilities must identify and undertake all cost-effective energy conservation. As of 2007, 17 of Washington's 62 utilities will be regulated under the RES, covering more than 80 percent of the population.22 The RES starts at 3 percent of a utility's load for 2012 to 2015, rising to 9 percent for 2016 to 2019, and 20 percent from 2020 forward. Renewably fueled DG with a capacity of not more than 5 MW is eligible under the renewable portion of the RES. DG may also be counted as double the facility's electrical output if the utility owns the facility, has contracted for the DG and associated RECs, or has contracted to purchase only the related RECs. CHP systems owned and used by a retail electric customer to meet its own needs may be counted toward the conservation provision in the initiative. By January 1, 2010, ------- and every two years thereafter, each affected utility is required to identify its "achievable cost-effective conservation potential through 2019." Each utility must then issue an acquisition target to be met during the next two years. Utilities may count high-efficiency CHP units with a useful thermal output of at least 33 percent of the total energy output towards meeting their conservation targets. The amount of energy conservation eligible towards meeting the target will be determined based on an analysis of the reduction in electricity consumption from the CHP system compared to a best-commercially available technology combined-cycle natural gas-fired combustion turbine. Additionally, only the output used by the customer to meet its own needs will count towards the target.23 The Washington Department of Community, Trade and Economic Development (CTED) Energy Policy Division released draft rules for implementing the initiative in late 2007 and early 2008. CTED expects to issue final rules by March 4, 2008.24 Waste Heat CHPColorado, Nevada, North Dakota Colorado, Nevada, and North Dakota all include recycled energy or energy recovery processes as eligible technologies within their RPS. CHP is included under each of these definitions, but the most common type of CHP, which recovers otherwise lost energy from a process whose primary purpose is electricity generation, is excluded in each case. In Colorado, the RPS was originally passed by ballot initiative (Amendment 37) in November 2004, and was then increased and extended by the state legislature in March 2007 as HB 1281.25 The expanded RPS requires utilities to meet a target of 20 percent of electric sales from renewable and recycled energy resources by 2020 and each year thereafter. Eligible CHP units must be smaller than 15 MW and convert otherwise wasted heat from exhaust stacks or pipes to electricity. In Nevada, the RPS was initiated in 1997 and was expanded to include energy savings from efficiency measures in 2005. The RPS requirement is 9 percent for 2007 and 2008, increasing 3 percent every two years to reach 20 percent in 2015 and thereafter. CHP systems are eligible under the RPS as a qualified energy recovery process. Eligible CHP units must be 15 MW or less, and only "the heat from exhaust stacks or pipes used for engines or manufacturing or industrial processes" used to generate electricity is considered to be an eligible CHP process.26 North Dakota's legislature passed a voluntary RPS, HB 1506, in March 2007 that establishes an objective that 10 percent of all retail electricity sold in the state be obtained from renewable and recycled energy by 2015. CHP systems are eligible under the recycled energy definition by "producing electricity from currently unused waste heat resulting from combustion, or other processes, into electricity."27 Each retail provider or generation supplier must conduct an economic evaluation of new renewable and recycled energy and consider the RPS objective and economic evaluation to determine the electricity alternatives that best meet its resource or customer needs. Additional A number of additional resources are available for developing RPS policies. EPA's Clean Energy-Environment Guide to Action outlines 16 policies and programs states are successfully implementing to increase clean energy. Chapter 5 discusses RPS. www.epa .gov/clea nenergy/docu ments/gta/g u ide_action_ chap5_sl.pdf EPA's Fact Sheet, Renewable Portfolio Standards: An Effective Policy to Support Clean Energy Supply describes the benefits of RPS for states and how RPS encourage CHP projects. www.epa.gov/chp/documents/rps_fs.pdf The Database of State Incentives for Renewable Energy (DSIRE) is a comprehensive and continually updated source of information on state, local, utility, and selected federal incentives that promote renewable energy. www.dsireusa.org Evaluating Experiences With Renewable Portfolio Standards in the United States (2004) provides a comprehensive analysis of U.S. experience with RPS, including lessons learned. http://eetd.lbl.gov/EA/EMP/reports/54439.pdf Projecting the Impact of RPS on Renewable Energy and Solar Installations (2005) is a PowerPoint presentation that estimates and summarizes the potential impacts of existing state RPS on renewable energy capacity and supply. www.newrules.org/de/solarestimates0105.ppt Endnotes 1 Vermont's RPS is voluntary, but if the utilities have not met their goal by 2012, then the RPS will become mandatory in 2013. EERE State Activities and Partnerships, www.eere.energy.gov/states/maps/renewable_portfolio_states.cfm. 2 Rabe, B. Race to the Top: The Expanding Role of U.S. State Renewable Portfolio Standards (2006), Pew Center on Global Climate Change, www.pewclimate.org/global-warming-in depth/all_reports/race_to_the_top/ index, cfm. 3 www.arb.ca.gov/energy/dg/dg.htm. www.eea-inc.com/rrdb/DGRegProject/Documents/MEDGRuleChapterl48.pdf. www.tceq.state.tx.us/assets/public/permitting/air/Guidance/NewSourceReview/ segu_final.pdf. www.dem.ri.gov/pubs/regs/regs/air/air43_07.pdf 4 www.epa.gov/ttn/atw/combust/turbine/turbnsps.html. 5 As of 2007, Maine is not included among the states with current RPS that include CHP. In Maine's original RPS, requiring 30 percent eligible technologies by 2000, CHP was considered an eligible resource. In 2007, Maine enacted a new RPS of 10 percent renewable by 2017 and declared eligible technologies to include only new renewable energy systems placed into service after ------- September 1, 2005. CHP is not eligible under the current standard. www.dsireusa.org/ library/includes/incentive2.cfm?Incentive_Code=ME01R&state=ME&CurrentPageI D=1&RE=1&EE=1. 6 In Arizona, only renewably fueled CHP systems are eligible within the state's RPS; fossil-fueled CHP systems are not eligible. 7 Connecticut Public Act No. 05-1, "An Act Concerning Energy Independence," www.cga.ct.gov/2005/ACT/PA/2005PA-00001-ROOHB-07501SSl-PA.htm. 8 Connecticut Public Act No. 07-242 §40-44, "An Act Concerning Electricity and Energy Efficiency," www.cga.ct.gov/2007/ACT/PA/2007PA-00242-ROOHB- 07432-PA.htm. 9 Docket No. 05-07-19: DPUC Proceeding to Develop a New Distributed Resources Portfolio Standard (Class III) - Decision, June 28, 2006, www.dpuc.state.ct.us/ FINALDEC.NSF/2b40c6ef76b67c438525644800692943/cad07929137a202785257 19c006ec899/$FILE/050719-062806.doc. 10 Docket No. 05-07-19: DPUC Proceeding to Develop a New Distributed Resources Portfolio Standard (Class III) - Reopening, August 1, 2007, www.dpuc.state.ct.us/ FINALDEC.NSF/2b40c6ef76b67c438525644800692943/6a82a9c57e998dd285257 32f004aee23/$FILE/050719-080107.doc. 11 DSIRE, Connecticut Renewables Portfolio Standard, www.dsireusa.org/libra ry/includes/incentive2.cfm?Incentive_Code=CT04R&state =CT&CurrentPageID=l&RE=l&EE=l. 12 A Bill for an Act Relating to Renewable Energy, SB 2474, June 2, 2004, www.capitol.hawaii.gov/session2004/bills/SB2474_HDl_.htm. 13 A Bill for an Act Relating to Energy, SB 3185, June 2, 2006, www. capital.hawaii.gov/session2006/bills/SB3185_cd l_.htm. 14 A Bill for an Act Relating to Energy, SB 3185, June 2, 2006, www.capitol.hawaii.gov/session2006/bills/SB3185_cdl_.htm. 15 Session Law 2007-397/SB 3, August 20, 2007, www.ncleg.net/Sessions/2007/Bills/Senate/PDF/S3v6.pdf. 16 Session Law 2007-397/SB 3, August 20, 2007, www.ncleg.net/Sessions/2007/Bills/Senate/PDF/S3v6.pdf. 17 North Carolina Utilities Commission, Renewable Energy and Energy Efficiency Portfolio Standard (REPS), www.ncuc.commerce.state.nc.us/reps/reps.htm. 18 North Carolina Utilities Commission, Orders and Filings in Docket No. E-100, Sub 113, http://ncuc.commerce.state.nc.us/cgi-bin/fldrdocs.ndm/INPUT?compdesc= Generic%20Proceeding&numret=001&comptype=E&docknumb=100&suffixl=&s ubNumb=113&suffix2=&parml=000127195. 19 Pennsylvania Public Utility Commission, Alternative Energy Portfolio Standards, www.puc.state.pa.us/electric/electric_alt_energy.aspx. 20 HB 1203, July 17, 2007, www.legis.state.pa.us/CFDOCS/Legis/PN/Public/btCheck.cfm?txtType=HTM&sess Yr=2007&sessInd=0&billBody=H&billTyp=B&billNbr=1203&pn=2343 21 Chapter 19.285 RCW: Energy independence act, November 7, 2006, http://apps.leg.wa.gov/RCW/default.aspx?cite=19.285. 22 DSIRE, Washington Renewable Energy Standard, www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=WA15R&state =WA&CurrentPageID=l&RE=l&EE=l. 23 Department of Community, Trade and Economic Development, WSR 07-20-126 Proposed Rules, December 27, 2007, www.cted.wa.gov/DesktopModules/CTEDPublications/CTEDPublicationsView.aspx ?tabID=08JtemID=5375&MId=863&wversion=Staging. 24 Department of Community, Trade and Economic Development, 1-937 Rulemaking, www.cted.wa.gov/site/1001/default.aspx. 25 HB 07-1281 Concerning Increased Renewable Energy Standards, March 27, 2007, www.leg.state.co.us/clics/clics2007a/csl.nsf/fsbillcont3/C9BOB62160D 242CA87257251007C4F7A?open&file=1281_enr.pdf. 26 Nevada Revised Statues Annotated, www.dsireusa.org/documents/Incentives/NV01R.htm. 27 HB 1506, An Act to establish a state renewable and recycled energy objective, March 23, 2007, www.legis.nd.gov/assembly/60-2007/bill-text/HBI00500.pdf. Fuel AddendumInformation about Combined Heat and Power (CHP) CHP is the sequential generation of power (electricity or shaft power) and thermal energy from a common fuel combustion source. CHP captures waste heat that is ordinarily discarded from conventional power generation; typically, two-thirds of the input energy is discarded to the environment as waste heat (up exhaust stacks and through cooling towers). This captured energy is used to provide process heat, space cooling or heating for commercial buildings or industrial facilities, and cooling or heating for district energy systems. CHP facilities typically have efficiencies of 60 to 80 percent and use numerous types of technologies, including turbines, reciprocating engines, and fuel cells, as well as various fuels, including natural gas, biomass, coal, and biogas. More information about these technologies and their applications can be found in the EPA CHP Partnership's Catalog of CHP Technologies (www.epa.gov/chp/basic/catalog.html). Figure 2 shows two common configurations for CHP systems. CHP's applicability to many technologies and fuels means that it can be applied in many different end uses and can use many fuels. It is a well-known and well-demonstrated technology. The United States has approximately 85 gigawatts (GW) of CHP Figure 2 - Two Typical CHP Configurations Steam Boiler/ Steam Turbine: Water Gas Turbine Or Engine/Heat Recovery Unit: Water High-Pressure Steam I Fuel ' Steam To Process Source: U.S. EPA Output-Based Regulations: A Handbook for Air Regulators (2004), www.epa.gov/chp/documents/obr_final_9105.pdf. capacity in place as of 2007, yet the potential for substantial expansion is great.28 In 2000, the U.S. Department of Energy (DOE) and U.S. Environmental Protection Agency (EPA) set a goal to double the capacity of U.S. CHP installations by 2010. By providing electrical and thermal energy from a common fuel input, CHP significantly reduces the associated fuel use and emissions. Figure 3 illustrates the higher efficiency of a CHP facility compared to a conventional system providing the same service. In this case, both systems provide 30 units of electric energy and 45 units of thermal energy to the facility. ------- In the conventional system, the electricity required by the facility is purchased from the central grid. Power plants on average are about 31-percent efficient, considering both generating plant losses and the transmission and distribution losses. Thermal energy required by the facility is provided by an onsite boiler, averaging 80 percent efficiency. Combined, the two systems use 154 units of fuel to meet the combined electricity and steam demand. The combined efficiency to provide the thermal and electric service is 49 percent. In the CHP system, an onsite system provides the same combined thermal and electric service. Electricity is generated in a combustion turbine, and the waste heat is captured for process use. The CHP system satisfies the same energy demand using only 100 units of fuel. This system is 75 percent efficient. Due to its higher efficiency compared to conventional central-station generating systems, CHP produces lower emissions of traditional air pollutants and carbon dioxide, the leading greenhouse gas associated with global climate change, than conventional generating systems. Figure 4 shows the NOX emissions benefits of the CHP system. The CHP system has much lower emissions because it uses 35 percent less fuel, even if the combustion process has the same input-based emission rates as the conventional equipment. In this example, as is often the case, the new CHP system displaces higher-emitting generators on the electric grid, and the emissions rate for the new system is lower than the conventional alternative, further reducing emissions. In the case shown, the CHP system emits less than half as much NOX as the conventional system due to a combination of greater efficiency and lower emissions rate. Figure 3 - Efficiency Benefits of CHP Conventional Generation: Combined Heat & Power: 5 MW Natural Gas Combustion Turbine Losses Power Station Fuel Source: U.S. EPA Output-Based Regulations: A Handbook for Air Regulators (2004), www.epa.gov/chp/documents/obr_final_9105.pdf. Figure 4 - Nitrogen Oxide Emissions Benefits of CHP Conventional Generation: Power Station Fuel Combined Heat & Power: 5 MW Natural Gas Combustion Turbine CHp EFFICIENCY: 80% _^. I ) Heat Emissions Source: U.S. EPA Output-Based Regulations: A Handbook for Air Regulators (2004), www.epa.gov/chp/documents/obr_final_9105.pdf. 28 U.S. DOE CHP database, maintained by Energy and Environmental Analysis, www.eea-inc.com/chpdata/index.html. For more information, contact: g CHP &EPA COMBINED HEAT AND POWER PARTNERSHIP Katrina Pielli U.S. Environmental Protection Agency Phone: (202) 343-9610 e-mail: pielli.katrina@epa.gov 10 ------- |