IGCC State Incentives Report

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1 IGCC State Incentives Report Created by the Energy Center of Wisconsin CO Name: Colorado Carbon Adder Description: The Colorado PUC approved a carbon cost adder for the current Xcel (Public Service) RFP as part of a settlement with environment groups allowing the proposed Comanche 3 coal-fired power plant to move through the PUC approval process unopposed. The carbon adder is set at $9 per ton of CO2 emissions beginning in 2010 and escalates at 2.5% annually. The adder only applies to the 2003 RFP, and explicitly does not apply either to other regulated utilities or to future resource acquisition. Preliminary modeling by Xcel determined that the carbon adder would not impact the resource selection. Joshua Bushinsky, State Solutions Fellow, Pew Center on Global Climate Change, 2101 Wilson Blvd. Suite 550, Arlington, VA 22209Phone , Fax , OH Name: Ohio Development Office Description: The Ohio Coal Development Office (OCDO) is an office of the Ohio Air Quality Development Authority undertaking a series of research programs and pilot projects investigating the feasibility of reducing GHG emissions from coal power plants. The OCDO co-funds the development and implementation of technologies that can use Ohio's vast reserves of high sulfur coal in an economical, environmentally sound manner. Several of OCDO s projects are researching and testing climate-friendly technologies and practices, such as IGCC and carbon sequestration. The OCDO supports projects on a cost-sharing basis with partners from private industry and research institutions, and gives preference to projects that support the commercial development of a particular technology. Projects include: Development of technologies to provide hydrogen and liquid fuels from coal. In cooperation with Battelle, American Electric Power and the U.S. Department of Energy, an investigation into the use of deep underground saline formations for carbon sequestration. In cooperation with American Electric Power, Alstom Power, and the U.S. Department of Energy, the development of a technology to separate CO2 from power plant emissions. In cooperation with the U.S. Department of Energy, the OCDO is funding the Midwest Regional Carbon Sequestration Partnership, which is assessing the technical and economic potential of carbon sequestration. The members of the partnership include Ohio, West Virginia, Kentucky, Indiana, and Pennsylvania. Joshua Bushinsky, State Solutions Fellow, Pew Center on Global Climate Change, 2101 Wilson Blvd. Suite 550, Arlington, VA 22209Phone , Fax , Energy Center of Wisconsin State Incentives Report Page 1 of 7

2 OR Name: Oregon Carbon Adder Description: In a 1993 update to its least-cost planning requirements, the Oregon Public Utilities Commission mandated that regulated electric utility IRPs include analysis of a range of carbon costs. This order (93-695) specified that Oregon s regulated electric utilities analyze the impact of adders from $10 to $40 (in 1990 dollars) per ton of carbon dioxide. The Idaho Power Company uses a carbon adder specified in the Oregon PUC order. The order applied to the Idaho Power Company because a small percentage of the utility s generation is in Oregon, and it must therefore get PUC approval for its resource plan in both Oregon and Idaho. The Idaho Power Company s 2004 IRP was completed with input from a public advisory committee as requested by the Idaho PUC, which had found public input lacking in the company s 2002 IRP. Staff from Pacificorp, the Oregon PUC, and environmental groups participated in this advisory committee and provided input form their experience developing resource plans using a carbon adder. Government, industry, and consumer groups were also represented on the advisory committee. The Idaho Power Company was affected by the California energy crisis, which emphasized the importance of mitigating exposure to all forms of financial risk, including those presented by future carbon constraints. PacifiCorp s 2004 IRP includes scenario analysis for a range of future market conditions including a carbon constraint. The PacifiCorp base case assumes a cap-and-trade system beginning in 2010 with the cap set at 2000 emissions, and a 50% chance of an $8/ton allowance price (in 2008 dollars). In compliance with the Oregon order , the IRP also modeled a range of carbon costs from $0 to $40 per ton of carbon dioxide in 1990 dollars. PacifiCorp s treatment of carbon costs in planning is consistent with its RFPs. Joshua Bushinsky, State Solutions Fellow, Pew Center on Global Climate Change, 2101 Wilson Blvd. Suite 550, Arlington, VA 22209Phone , Fax , MA Name: Multiple Pollutant Cap 2000 Description: The Massachusetts rule requires each of the six plants to achieve specified reduction levels for several pollutants, including a ten percent reduction from CO2 levels. The state does not impose a method to achieve these reductions but would clearly prefer that they be converted to natural gas. The rule offers an incentive for a fuel shift by delaying the compliance deadline to October 2008 for any facility undergoing such a conversion. Plants using other techniques, such as pollution control equipment, would have to comply by It also allows the plants some opportunity to secure credits through verifiable off-site reduction measures such as carbon sequestration or renewable energy generation. Plants that fail to achieve the reductions themselves may also purchase emissions credits. Bill Lamkin, Bureau of Waste Prevention, MA Department of Environmental protection, One Winter StreetBoston, MA 02108, Phone (978) ,` PA Name: Alternative Energy Portfolio Standards Act Incentive Type: Supply-side Energy Center of Wisconsin State Incentives Report Page 2 of 7

3 Description: Electricity sold by an electric distribution company or electric generation supplier to retail electric customers must be comprised of electricity generated from alternative energy sources. There are two tiers of energy sources, IGCC is included as a energy source in Tier II. The commission will establish alternative energy credits in order to implement this act. By the end of the 15 year period at least 5 percent of electric generation must be from Tier II ME Name: 2003 Description: Maine enacted a climate change statute An Act to Provide Leadership in Addressing the Threat of Climate Change (Public Law 2003, Chapter 237, H.P. 622, L.D. 845) in June 2003 [23]. The statute requires the establishment of a greenhouse gas emissions inventory for State-owned facilities and State-funded programs and calls for a plan to reduce emissions to 1990 levels by It specifies that carbon emission reduction agreements must be signed with at least 50 businesses and nonprofit organizations by January 2006, and that Maine must participate in a regional greenhouse gas registry. The goals of the statute are a reduction of greenhouse gases to 1990 levels by January 2010, a reduction to 10 percent below 1990 levels by 2020, and a reduction to 75 and 80 percent below 2003 levels in the long term. It authorizes the Department of Environmental Protection to submit to the Legislature a State climate action plan to meet the goals of the statute. CT Name: Abatement of Air Pollution 2000 Description: The Connecticut Abatement of Air Pollution regulation was enacted in December 2000, and revisions are being made on an ongoing basis. It limits SO2 and NOx emissions from all NOx budget program (NBP) sources that are more than 15 megawatts or require fuel input greater than 250 million Btu per hour [20]. The regulation applies to the electricity generation sector, the cogeneration sector, and industrial units. The NOx limit is 0.15 pound per million Btu of heat input. The SO2 limit applies to NBP sources that are also Acid Rain Program sources, and the limit is 0.3 percent sulfur in fuel and 0.33 pound per million Btu. Modifications are being made to the current NBP rules to provide incentives in the form of allowances for renewable energy and energy efficiency programs. In May 2003, the Connecticut General Assembly passed legislation (Connecticut Public Act 02-64) requiring coal-fired power plants to remove 90 percent of the mercury from smokestack emissions (or a maximum of 0.6 pound of mercury emitted per trillion Btu input, which is equivalent to to pound per gigawatthour) by July The legislature has recommended that the State Department of Environmental Protection consider stricter limits by July In addition, Connecticut enacted a law in June 2004 called An Act Concerning Climate Change, Public Act No The goal of the legislation is to reduce emissions of greenhouse gases from sources in Connecticut to 1990 levels by 2010 and to 10 percent below 1990 levels by 2020, and it establishes a process to determine reduction goals beyond The Act covers electricity Energy Center of Wisconsin State Incentives Report Page 3 of 7

4 generators, fleet vehicles, industrial facilities, and commercial establishments; however, there are no enforcement procedures in the law. There is a requirement for the Governor s Steering Committee on Climate Change to develop a Climate Action Plan by January 2005, and for the Commissioner of Environmental Protection to establish a regional greenhouse gas registry that will collect emissions data. MA Name: Emissions Standards for Power Plants 2001 Description: The Massachusetts Department of Environmental Protection air pollution control regulations (310 CMR 7.29, Emissions Standards for Power Plants ), approved in May 2001, apply to six existing older power plants in Massachusetts. There are two options for utilities to comply with the regulations: either repower (defined as replacing existing boilers with new ones that meet the environmental standards, switching fuel to low-sulfur coal, or switching from coal to natural gas); or choose a standard path that includes installing low-nox burners, installing SO2 scrubbers, and installing SCR or SNCR equipment. The rule offers an incentive for a fuel shift by delaying the compliance deadline to October 2008 for any facility choosing to repower. Plants using other techniques, such as pollution control equipment, must comply by October The regulation calls for a reduction in SO2, NOx, CO2, Mercury. MO Name: Emission Limitation and Emissions Trading of Oxides of Nitrogen Description: The Missouri NOx rule, Emission Limitation and Emissions Trading of Oxides of Nitrogen (Rule 10 CSR ) applies to fossil-fueled capacity larger than 25 megawatts. The emissions cap is based on a unit s heat input. Power plants had to be in compliance by May Allowances can be banked, with some restrictions, and some exchange of allowances is allowed [29]. The seasonal NOx limits (from May to September of each year) vary by county and generally range from 0.18 to 0.35 pound per million Btu. NY Name: Acid Deposition Reduction Budget Trading Programs 2003 Description: New York s Acid Deposition Reduction Budget Trading Programs Title 6 NYCRR Parts 237 and 238 were approved by the State Environmental Board in March 2003 and became effective in May 2003, but implementation of the rule has been delayed by a court order. The NOx regulations apply to electricity generators of 25 megawatts or greater, and the SO2 Energy Center of Wisconsin State Incentives Report Page 4 of 7

5 regulations apply to all CAAA90 Title IV sources, including electric utilities and other sources of SO2 and NOx, such as cogenerators and industrial facilities. NOx emissions were limited to 39,908 short tons beginning in October This is a non-ozone season cap (October 1 to April 31), based on the same rate (0.15 pound per million Btu) as the NOx cap in the current State emissions regulation. SO2 emissions are limited in two phases: Phase I, beginning in January 2005, limits SO2 to 25 percent below Title IV allocations (197,046 short tons); Phase II, beginning in January 2008, increases the limit to 50 percent below Title IV allocations (131,364 short tons). A governor s task force was established in June 2001 to recommend greenhouse gas limits. NC Name: Air Quality/Electric Utilities Act 2002 Description: The General Assembly of North Carolina has passed the Clean Smokestacks Act officially called the Air Quality/Electric Utilities Act (S.B. 1078) which requires emissions reductions from 14 existing coal-fired power plants in the State. It was signed into law in June Under the Act, North Carolina power companies must reduce NOx emissions from 178,000 short tons in 1999 to 56,000 short tons by 2009 and SO2 emissions from 429,000 short tons in 1999 to 250,000 short tons by 2009 and 130,000 short tons by Progress Energy Carolinas, Inc., and Duke Power have submitted compliance plans to the North Carolina Department of Environment and Natural Resources and the North Carolina Utilities Commission. The utilities will comply with the Act by installing scrubbers and SNCR technology at their plants. Duke Power and Progress Energy have reported compliance costs for SO2 and NOx control, with SNCR costs ranging from $4.93 to $63.70 per kilowatt and scrubber costs ranging from $113 to $414 per kilowatt. The Act requires the Department of Environment and Natural Resources to evaluate issues related to the control of mercury and CO2 emissions and recommends the development of standards and plans to control them. In 2003, the Department of Air Quality prepared reports on mercury and CO2 emissions reductions for the State, in the first of three sets of reports to be submitted to the Environmental Management Commission and the Environmental Review Commission.. WA Name: 2004 Description: Washington s House Bill 3141, signed into law in May 2004, requires 20 percent of their CO2 emissions from new power plants to be offset. Plant owners can either directly or indirectly invest in CO2 mitigation projects, such as forest preservation or the conversion of buses from diesel to natural gas. Power plant CO2 emissions must be reduced by 20 percent over a 30-year period. CO2 emissions can be offset by payments to an independent qualified organization, by direct purchase of permanent carbon credits, or by direct investment in CO2 mitigation projects. The rate of payment to third parties is fixed at $1.60 per metric ton CO2 [43]. The Washington State Energy Facility Site Evaluation Council may adjust the rate every 2 years, but any decrease or increase may not exceed 50 percent of the current rate. Energy Center of Wisconsin State Incentives Report Page 5 of 7

6 PA Name: Alternative Energy Deployment Grants Incentive Type: Loans 11/29/2004 Description: The Pennsylvania Energy Development Authority (PEDA) issues funding solicitations to support advanced energy research and deployment projects, and to assist businesses interested in locating or expanding advanced energy operations in Pennsylvania. PEDA's April 2005 solicitation offered $10 million in grants, loans and loan guarantees to support in-state projects, manufacturing or research involving solar energy; wind; low-impact hydropower; geothermal; biologically-derived methane gas, including landfill gas; biomass; fuel cells; coalmine methane; waste coal; integrated gasification combined cycle, and; demand management measures, including recycled energy and energy recovery, energy efficiency and load management. PEDA intends to issue a new funding solicitation in 2006 to support grants, loans and loan guarantees. Under the 2005 solicitation, two types of grants were available through PEDA: Alternative Energy Deployment Grants and Applied Research Grants. Alternative Energy Deployment Grants support the construction of innovative, advancedenergy projects in Pennsylvania. Applied Research Grants support research directly related to alternative-energy resources. PEDA jointly administers the loan program with the Pennsylvania Department of Community and Economic Development (DCED). Loans awarded under the 2005 solicitation had a maximum term of 10 years, or the life of the asset, whichever is less. The interest rate on PEDA loans is 50% of the prime interest rate (as specified by Bloomberg), but no less than 3.25%. Loan guarantees of up to $500,000 for corporations, partnerships and other legal business entities were also supported by the 2005 solicitation. Loan terms are determined by a lending institution rather than by PEDA. Ana Gomez, Pennsylvania Department of Environmental Protection, Pennsylvania Energy Development Authority, Rachel Carson State Office Building, 400 Market Street, 15th Floor, Harrisburg, PA , Phone: (717) , or NH Name: Clean Power Act Description: On May 9, 2002, New Hampshire Governor Jeanne Shaheen signed HB 284, known as the Clean Power Act. The Act, which took effect July 1, 2002, sets annual upper limits or caps on emissions of CO2, SO2, and NOx, and requires that a cap be set for mercury, from the state s three fossil fuel burning power plants, all owned by Public Service of New Hampshire (PSNH). In the case of CO2, the law requires emissions to be reduced to 1990 levels by the end of The law required PSNH to file a plan for compliance with the state s Department of Environmental Services (DES), and PSNH is required to comply with the caps beginning January 1, In the case of failure to comply, a monetary penalty would be imposed. The cap of 5,425,866 tons of CO2 annually will apply through December 31, A cap for years following 2010 has not been determined, but on March 31, 2004, DES recommended a cap of 4,069,400 tons (25 percent below 1990 levels) to the legislature, contingent on the existence of an acceptable regional trading program. The legislature is committed to considering the proposed lower cap by July 1, The legislation sets up a cap-and-trade system, which allows the affected sources to buy emission credits through a national, regional, or other trading program acceptable to the DES. Reductions in CO2 emissions that are achieved before the cap takes effect may be banked for future use in regional or national Energy Center of Wisconsin State Incentives Report Page 6 of 7

7 trading programs or to meet the emission caps established under the law. The law directed the DES Commissioner to adopt rules regarding the establishment of trading and banking programs. Joanne Morin, Administrator, Technical Services Bureau, New Hampshire Department of Environmental Services, Air Resources Division29 Hazen Drive, PO Box 95, Concord, NH , Phone , Fax , MO Name: Emission Limitation and Emissions Trading of Oxides of Nitrogen Description: The Missouri NOx rule, Emission Limitation and Emissions Trading of Oxides of Nitrogen (Rule 10 CSR ) applies to fossil-fueled capacity larger than 25 megawatts. The emissions cap is based on a unit s heat input. Power plants had to be in compliance by May Allowances can be banked, with some restrictions, and some exchange of allowances is allowed [29]. The seasonal NOx limits (from May to September of each year) vary by county and generally range from 0.18 to 0.35 pound per million Btu. Energy Center of Wisconsin State Incentives Report Page 7 of 7

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