Original Notice.

     Preproposal statement of inquiry was filed as WSR 03-21-119.

     Title of Rule and Other Identifying Information: Chapter 173-407 WAC, Carbon dioxide mitigation program for fossil fueled thermal electric generating facilities.

     Hearing Location(s): Department of Ecology, 300 Desmond Drive S.E., Lacey, WA 98503, on November 30, 2004, at 2:00 p.m.

     Date of Intended Adoption: December 21, 2004.

     Submit Written Comments to: Melissa McEachron, Department of Ecology, Air Quality Program, P.O. Box 47600, Olympia, WA 98504-7600, e-mail MMCE461@ecy.wa.gov, fax (360) 407-7534, by December 8, 2004.

     Assistance for Persons with Disabilities: Contact Tami Dahlgren by November 22, 2004, TTY (711) 1-800-833-6388 or (360) 407-6800.

     Purpose of the Proposal and Its Anticipated Effects, Including Any Changes in Existing Rules: During the 2004 legislative session, SHB 3141 became law. The new law (codified as chapter 80.70 RCW and RCW 70.94.892) establishes a carbon dioxide mitigation program and requires carbon dioxide offsets from new and certain modified fossil-fueled electric generating facilities. The purpose of the rule is to recover permitting authority costs related to implementing the mitigation program, to clarify CO₂ emissions calculations, and to integrate mitigation program plans into the air quality permits using the order of approval process.

     There is no existing rule related to carbon dioxide mitigation program for fossil-fueled thermal electric generating facilities. The anticipated effect of the proposal is a complete and ready to implement program.

     Statutory Authority for Adoption: Chapters 70.94 and 80.70 RCW.

     Statute Being Implemented: Chapter 80.70 RCW and RCW 70.94.892.

     Rule is not necessitated by federal law, federal or state court decision.

     Name of Proponent: Department of Ecology, governmental.

     Name of Agency Personnel Responsible for Drafting: Melissa McEachron, Olympia, Washington, (360) 407-6860; Implementation and Enforcement: Stu Clark, Olympia, Washington, (360) 407-6800.

     A small business economic impact statement has been prepared under chapter 19.85 RCW.

     BACKGROUND: The Department of Ecology (ecology) is proposing adoption of a new rule implementing chapter 70.94 RCW and Title 80 RCW. The proposed rule provides additional direction regarding carbon dioxide mitigation for public and private entities that are constructing certain types of energy facilities in Washington state. Ecology's goal is that the rule will provide clarification as to what is required for energy facility developers in Washington. As required under RCW 19.85.030, ecology is developing and issuing this small business economic impact statement (SBEIS) as part of its rule adoption process. Ecology will use the information developed in the SBEIS as required by law to ensure that the proposed rules are consistent with legislative policy.

     RULE DEVELOPMENT: Washington has been actively involved in evaluating the implications of climate change having completed several studies in the last fifteen years. Development of a rule to mitigate GHG emissions was initiated by Governor Gary Locke in 2001. The governor authorized the Energy Facility Site Evaluation Council (EFSEC) to commence rule making in an effort to mitigate the amount of greenhouse gas emissions from new electricity generation facilities. The result was the proposed EFSEC carbon dioxide mitigation rule. The rule required new fossil fuel fired electricity generation facilities to mitigate 20% of their lifetime CO₂ emissions. However, the rule was never adopted because the 2004 legislature created law that closely reflected the proposed EFSEC rule. This statutory language modified portions of chapter 70.94 RCW and Title 80 RCW to reflect the legislature's intent to require greenhouse gas mitigation. Ecology is proposing to implement these revisions to statute via proposed chapter 173-407 WAC, Carbon dioxide mitigation program for fossil fueled thermal electric generating facilities, that is the subject of this analysis.

     DESCRIPTION AND PURPOSE OF THE SBEIS: The objective of this SBEIS is to identify and evaluate the various requirements and costs that the proposed rule might impose on businesses. In particular, the SBEIS examines whether the costs to businesses that might be imposed by the proposed rule impose a disproportionate impact on the state's small businesses. The specific purpose and required contents of the SBEIS is contained in RCW 19.85.040 and are noted below (the bracketed numbers are for the reader's convenience, and reflect the organization of this SBEIS):

     "A small business economic impact statement must include [1] a brief description of the reporting, record keeping and other compliance requirements of the proposed rule, and [2] the kinds of professional services that a small business is likely to need in order to comply with such requirements. [3] It shall analyze the costs of compliance for business required to comply with the proposed rule adopted pursuant to RCW 34.05.320, including costs of equipment, supplies, labor and increased administrative costs. [4] It shall consider, based on input received, whether compliance with the rule will cause businesses to lose sales or revenue. [5] To determine whether the proposed rule will have a disproportionate impact on small businesses, the impact statement must compare the costs of compliance for small businesses with the cost of compliance for the ten percent of businesses that are the largest businesses required to comply with the proposed rules using one or more of the following as a basis for comparing costs:

     a. Cost per employee

     b. Cost per hour of labor

     c. Cost per hundred dollars of sales

     (2) A small business economic impact statement must also include:

     a. [6] A statement taken by the agency to reduce the costs of the rule on small businesses as required by RCW 19.85.030(3), or reasonable justification for not doing so, addressing the options listed in RCW 19.85.030(3).

     b. [7] A description of how the agency will involve small business in the development of the rule; and

     c. [8] A list of industries that will be required to comply with the rule.["]

     For purposes of an SBEIS, "Small business," is defined by RCW 19.85.020: "Small business" means any business entity, including a sole proprietorship, corporation, partnership, or other legal entity, that is owned and operated independently from all other businesses, that has the purpose of making a profit, and that has fifty or fewer employees.

     CONTENTS OF THE DOCUMENT: The proposed carbon dioxide mitigation rule developed through this rule-making process will be further evaluated in the following sections as required in chapter 19.85 RCW.

     Section 2 - This section discusses the new rule and provides [1] a brief description of the reporting, record keeping, and other compliance requirements, [2] the kinds of professional services that a small business is likely to need in order to comply, [3] the costs of compliance for businesses required to comply with the proposed rule including costs of equipment, supplies, labor, and increased administrative costs.

     Section 3 - This section considers [4] whether compliance with the rule will cause businesses to lose sales or revenue and evaluates [5] whether the proposed rule will have a disproportionate impact on small business.

     Section 4 - This section considers [6] actions taken to reduce the impact of the rule on small business, [7] how small business was involved in the development of this rule and provides [8] a list of industries required to comply with the rule. The appendix contains additional information used in this analysis.¹

     2. DISCUSSION OF COMPLIANCE COSTS FOR BUSINESSES.

     INTRODUCTION: The proposed rule restates much of what is explicitly presented in chapter 70.94 RCW and Title 80 RCW and clarifies several aspects likely to be relevant to energy facility construction. The most significant clarification is explicitly stating the formula for calculating carbon dioxide emissions and outlining how to incorporate multiple fuels and supplemental firing. The proposed rule also provides a fee schedule. Ecology has carefully evaluated each of the proposed new rule sections and determined which are likely to have significant impacts on future applicants. These are discussed below along with a discussion of the baseline. A discussion of costs likely to be experienced by firms is also provided.

     RULE DESCRIPTION AND BASELINE DEVELOPMENT: In order to discuss the cost impacts of the proposed rule it is necessary to consider the proposed rule language and the baseline from which the change in requirements is measured. The baseline is the best estimate of how chapter 70.94 RCW and Title 80 RCW would be implemented if the rule was not promulgated.

     The proposed rule provides definitions of the regulated community, outlines statutory authority, and provides formulas for emissions calculations and requirements for addressing multiple fuels.² The rule requires all new or expanding fossil fuel powered electricity generation facilities to mitigate a portion of their carbon dioxide emissions. Twenty percent of all emissions forecast over a thirty-year period are required to be mitigated either via a third-party or through self-initiated mitigation.³

     In the case of proposed chapter 173-407 WAC, much of the rule language is simply restated from the statute. If ecology did not adopt a rule, carbon dioxide mitigation would still be required from new fossil-fueled power plants since it is explicitly described in statute.⁴ The components of the rule where there is additional direction provided than included in statute are those associated with supplemental firing and multiple fuel sources. The statute defines total carbon dioxide emissions as those emitted from fossil fuel powered facilities over thirty years and mandates "taking into account any enforceable limitations on operational hours or fuel types and use." This statutory language is unclear as to whether it is to require mitigation of all fuel sources or the base fuel or some estimated fuel use up to the fuel's operational hour limitation. Ecology's proposed rule requires that all allowable supplemental firing hours be used in the emissions calculations and that the fuel with the highest CO₂ emissions factor be incorporated first until the total annual operational hours have been allocated. Without the rule, calculation of the CO₂ quantity subject to mitigation would be negotiated with individual permit writers resulting in differing mitigation requirements between otherwise identical proposals.

     Ecology has chosen to base this analysis on two assumptions. First, because the statute is quite clear about considering limitations on operational hours and since supplemental firing is usually an allowed use based on a maximum number of hours, it is assumed that mitigation would be required for allowed supplemental firing hours even without the rule.

     Second, because the statute is unclear about regulation of multiple fuels, ecology will assume that mitigation for reserve fuels with higher emission factors than the base fuel is an impact of this rule making. Though this could have been the intention of the statute, it could also be interpreted to require basing it on actual use, estimated use, etc. Without the rule, ecology permit writers and applicants would have to negotiate which fuels are included and how much of the allowable use of the higher emitting fuel would be considered. Therefore, the baseline in the case of multiple fuel sources will be mitigation based on the primary fuel type.

     COST IMPACTS TO BUSINESSES: For those energy facilities that want the flexibility to use multiple fuel sources, the requirements described above will be a cost impact of the rule making. Firms may have to pay a greater amount of mitigation than would have been required if they had simply negotiated with individual permit writers. It is possible this may even cause some firms to choose to reduce their permitted use of back-up fuels from what would have been the case without the rule.

     The economic impact of the proposed rule will most likely be experienced by those developing/modifying electricity generation facilities⁵ as an increase in facility development costs. The following cost categories are required by chapter 19.85 RCW.

     Reporting and Record keeping: Additional carbon mitigation rule requirements will not likely require additional on-going monitoring or record keeping.

     Additional Professional Services: Additional carbon mitigation rule requirements may require additional project management services to execute additional carbon offsets if the self-mitigation option is selected. This cost is included in the mitigation amount.

     Costs of Equipment, Supplies, Labor, and Increased Administrative Costs: No additional equipment, supplies, labor or administrative costs are anticipated.

     Other Compliance Requirements: As mentioned above, the main impact of the rule will be the additional carbon mitigation that may be required of some facilities. This amount will vary with the facility, fuel-type and owner with a typical range of between $0 and $1,100,000.⁶

     3. REVENUE IMPACTS AND DISTRIBUTION OF COSTS.

     INTRODUCTION: RCW 19.85.040 requires that the analysis consider [4] whether compliance with this rule will cause businesses to lose sales or revenue and [5] whether the proposed rule will have a disproportionate impact on small businesses. The increased costs come from increased carbon dioxide mitigation requirements for new energy facilities locating in the state.

     Increased mitigation costs associated with higher carbon emitting supplemental fuels could be reduced by decreasing the hourly limit on supplemental fuel use. This would reduce the amount of mitigation required of firms, but comes at the expense of decreased operational flexibility. All costs in this analysis assume no change in the use of supplemental fuels by electricity project proponents and therefore are conservative (biased against the rule).

     The increased costs will affect both existing and proposed energy facilities and could have indirect effects on other business entities operating in Washington state. The increase will affect siting costs and is related to capacity of the facility but not the output.⁷ In general, an increase in fixed costs will impact firms with less output (i.e. "small" firms) more significantly than firms with more output (i.e. "large" firms). This occurs because firms with less output that try to recoup fixed costs by raising the price of their final product must raise the price proportionately more than large firms.

     Increased siting costs for new energy facilities could benefit existing firms if existing plants are used more intensively or retirements of existing plants are delayed. In some cases, the impacts may be passed along to others as secondary effects. Which business entities are affected and how these new requirements will affect them depend on the specific markets and market participants. Firms that provide third-party mitigation services may benefit from increased demand for their services.

     ANALYSIS OF FUTURE PLANTS: The proposed rule will apply to any facility that sells power to the grid and uses a fossil fuel energy source. To analyze this, ecology considered existing and expected future market conditions and reviewed several facilities that have been constructed in the state and that obtained air operating permits. The analysis revealed that potentially impacted facilities likely to be constructed in the future include natural gas and coal-fired electricity generation plants. These facilities are typically constructed by consumer-owned utilities, investor-owned utilities, and independent power producers and range in size from 25 MW to 349 MW. Many of the larger facilities have supplemental firing capability, reserve fuels and can be cogeneration facilities.

     Ecology elected to evaluate the impacts on three hypothetical electricity generation facilities that represent the anticipated range of facilities likely to be constructed in the future. All facilities are natural gas fired facilities⁸ but operational capacities are different consisting of 30 MW, 172 MW and 274 MW facilities. Capabilities for supplemental firing, reserve fuels and cogeneration vary with each facility. The specific parameters are provided in Table 3.1.

Table 3.1. Parameters of Hypothetical Electrical Generation Facilities

Characteristic	Facility No. 1	Facility No. 2	Facility No. 3
Turbine Type	GE LM 2500+	Siemens/Westinghouse W501D5	Siemens/Westinghouse 501F
Nominal Capacity (MW)	30	172	274
Supplemental (Duct) Firing	No	No	Yes
Type & Primary Fuel	Natural Gas-Simple Cycle	Natural Gas-Comb. Cycle	Natural Gas-Comb. Cycle
Secondary Fuel	N/A	Distillate Fuel; 876 hour limit	Distillate Fuel; 1,752 hour limit
Cogeneration Facility	No	No	Yes

     SALES IMPACTS: Potential sales impacts for new generating resources in Washington could occur if the increased cost of siting facilities delays construction or are passed along in wholesale electricity prices. Table 3-2 provides an analysis of cost and investment return impacts for the three proposed facilities.

Table 3-2. Facility Siting and Wholesale Electricity Cost and Investment Return Impacts Due to the Proposed Rule

	Facility No. 1 (NGSC-30 MW)	Facility No. 2 (NGCC-172 MW)	Facility No. 3 (NGCC-274 MW)
Increased Mitigation Cost from Rule (Thousand $)	0	108.6	312.9
Capital Cost (Million $)9	17.7	101.1	159.6
Percentage Increase in Capital Cost	0.0%	0.11%	0.20%
Percentage Change in NPV10	0.0%	-0.4%	-0.4%
Change in Cost of Electricity ($/MWh)	0.00	+0.01	+0.02

     The estimated increased siting cost ranges from $0 to approximately $313,000 for the natural gas fired plants listed above. This represents an increase of between 0.0% and 0.20% of a typical plant's capital costs. If increased costs are passed along in wholesale electricity prices, the price of wholesale electricity is expected to increase between $0.0/MWh and $0.02/MWh which represents between 0% and 0.05% of the price of wholesale power.¹¹ This may result in a small decrease in sales depending on how sensitive the market is to a price increase. However, fuel price volatility, variable power demand and changing hydroelectric conditions are likely to be far more significant cost factors.

     As mentioned previously, a reduction in NPV for new facilities or an increase in wholesale power costs may be a beneficial effect for existing facilities. Existing electricity generation facilities may experience an increase in sales if siting of new facilities is delayed due to the reduced investment return or if time of use (dispatch) is reduced. This would increase the dispatch of existing plants and potentially delay retirement of some plants. The impact of these investment value and price changes for both existing and new plants is likely to be relatively minor as other factors are likely to drive siting decisions like fuel costs, public responsiveness, plant efficiency, and availability of transmission facilities.

     DISTRIBUTION OF COMPLIANCE COSTS: RCW 19.85.040 requires an evaluation of how compliance costs may vary between small firms and the largest 10% of firms required to comply. This is complicated in this case by the fact that the rule will only apply to facilities developed in the future. To inform the rule making, ecology evaluated several energy facilities that recently obtained AOP permits with capacities that would be subject to carbon mitigation requirements if constructed today. Sixteen permits for fossil-fuel fired facilities that sold electricity to the grid were considered. In all cases, the firms were large firms.

     Changes in the wholesale power industry make plants developed in the past less relevant. Developers can be classified as consumer owned utilities (COUs), investor owned utilities (IOUs) and independent power producers (IPPs). In the past, IOUs and COUs were often vertically integrated providing generation, transmission and distribution. Restructuring in the electricity markets has allowed IPPs to develop a much larger share of electricity generation. Moreover, they will likely be much more prevalent in future development. As such, ecology analyzed all existing COUs and IOUs and considered a collection of IPPs with existing assets or an interest in electricity development in Washington to assess proportionality.¹² The results are listed in Table 3-3.

Table 3-3. Proportionality of Compliance Costs (Dollars per Hundred Dollars in Sales)

Firm Size	No. Firms	Facility No. 1 (NGSC- 30 MW)	Facility No. 2 (NGCC-174 MW)	Facility No. 3 (NGCC-272 MW)
Small	40	0.0	0.007	0.012
Large	42	0.0	0.007	0.012

     As can be seen from Table 3-3, the cost impacts as measured per hundred dollars in sales will not be greater for small firms but will vary with the capacity of the plant. These results are not surprising because the mitigation costs are spread over the same revenue stream for a given size plant and technology regardless of the number of employees. If plant capacity or technology selection varies with the size of developer, we would expect effects to be disproportionate. Therefore, a more relevant question is "does new plant capacity or technology choice vary with the size of the proponent firm in the class of plants 25 megawatts to 350 megawatts?" Ecology's experience with previously constructed facilities indicates little relationship between plant capacity and proponent size.¹³

     It appears that mostly large firms develop plants between 25 MW and 350 MW capacity. Even in cases where small firms develop plants, there is little evidence that plant capacity is related to the number of employees of the proponent. For both of these reasons, the proposed rule should not disproportionately affect smaller proponents more than large proponents.

     SECONDARY IMPACTS: It is possible that some or all of the increased costs associated with the proposed rule revisions will be passed on to consumers in the form of higher electricity rates. For COUs and IOUs this would occur by including the increased cost in the utility rates approved by individual utility boards. For IPPs, higher prices would be determined within the market for wholesale power. Analysis by ecology found that it is unlikely that there will be disproportionate secondary impacts. The complete analysis can be found in the appendix.

     Natural gas has been the most efficient fuel used for new electricity facilities in recent years. Raising the cost to develop these plants might lead to a reduction in the use of natural gas. However, any impact would depend on the cost of the other generation technologies like wind, and on the cost for other inputs like coal. To the extent that coal will also be subject to increased requirements for carbon mitigation and that wind is a site specific resource with a low capacity factor, it is unlikely that the increased costs from the proposed rule will change the generation technology choice at the margin.

     CONCLUSION: Businesses engaged in the production of electricity will incur increased compliance costs as a result of the rule revisions. These costs will vary significantly with the plant characteristics. The most important characteristics affecting siting costs will be the generation technology, plant size and use of supplemental fuels. Ecology has analyzed several representative facilities and finds that the impacts on sales should be minimal and that the rule will not likely have disproportionate impacts.

     4. BUSINESS INVOLVEMENT AND INDUSTRY.

     ACTIONS TAKEN TO REDUCE THE IMPACT ON SMALL BUSINESS: As noted previously, the rule making is unlikely to have disproportionate impacts on smaller firms. Ecology's overall intent for this rule making is to implement state law mitigating greenhouse gases. It is intended that the new rule will reduce the uncertainty associated with siting 25MW-350MW capacity electricity generation facilities in Washington and reduce the associated financial penalties. To the extent that this is a fixed cost, it will benefit firms with less output more than firms with greater output. Because the impacts are unlikely to be disproportionate, ecology did not further pursue the options for reducing costs to small businesses listed in RCW 19.85.030(3).

     HOW WAS SMALL BUSINESS INVOLVED IN THE DEVELOPMENT OF THIS RULE? As mentioned previously, the stimulus for rule making came from legislation passed in 2004. Ecology began rule making in 2004 by drafting preliminary rule language and posting it for external stakeholder review. Written comments were taken through August, 2004. The proposed rule was also posted on ecology's website. Throughout the process, ecology has encouraged the participation of all entities in considering the impacts and outcomes of the proposed rules. This public process was open to both small and large businesses. Further input will be encouraged during the future draft rule public comment period.

     LIST OF INDUSTRIES REQUIRED TO COMPLY: The most likely industries to which this rule will apply will be those involved in the production of electricity. Other firms that elect to develop co-generation facilities might also be included. Table 4.1 contains [9] a list of industries required to comply with the rule. The table was constructed based on air permitting data and market analysis. In general, the majority of plants are classified SIC Code 4911.

Table 4.1. Industries Likely to be Required to Comply with the Rule Revisions

SIC Code	Description
4911	Electric Services
4931	Electric and other services combined

¹ Due to size limitations relating to the filing of documents with the code reviser, the SBEIS does not contain the appendices that further explain ecology's analysis. Additionally, it does not contain the raw data used in this analysis, or all of ecology's analysis of this data. However, this information is being placed in the rule-making file, and is available upon request.

² See www.ecy.wa.gov/programs/air/psd/draft_rule_page.html for complete text.

³ Typical mitigation projects include those that will offset emissions elsewhere such as energy efficiency programs and green power purchases.

⁴ Chapter 19.85 RCW does not require analysis where the statute explicitly defines the requirements.

⁵ Replacement of turbines "in-kind" for remanufacturing/repair is unlikely to result in increased mitigation cost as the replacement turbine is usually of similar size.

⁶ A cost of $0 would occur in the case of a simple cycle natural gas CT with no reserve fuels. An additional cost of $1,086,000 would occur for a 172 megawatt (MW) plant with unlimited use of back-up diesel. The likely upper limit in additional cost would be a 349 MW plant with unlimited back-up fuel in which mitigation would be increased by approximately $2,000,000.

⁷ These are known as "fixed" costs. Costs that depend on output levels are known as "variable" costs.

⁸ Coal-fired plants were not considered since rule requirements for reserve fuel mitigation will not likely affect the required mitigation since coal is a highly emitting fuel source.

⁹ Cost assumptions taken from "Wholesale Power Price Forecast for the Fifth Power Plan," NPPC, 2003.

¹⁰ NPV is "net present value." Calculations assume a wholesale electricity price of $40/MWh.

¹¹ Assuming a wholesale price of $40/MWh.

¹² Data used is from NPPC "Power Plants of the Northwest," the Northwest Independent Power Producers Coalition, Washington Employment Security, corporate websites and personal contacts.

¹³ All proponents with existing plants considered by ecology were large firms. Among these firms the correlation coefficient of capacity vs. number of employees was 0.09.

     A copy of the statement may be obtained by contacting David Reich, Department of Ecology, P.O. Box 47600, Olympia, WA 98504-7600, phone (360) 407-6865, fax (360) 407-6989, e-mail DAVR461@ecy.wa.gov.

     A cost-benefit analysis is required under RCW 34.05.328. A preliminary cost-benefit analysis may be obtained by contacting David Reich, Department of Ecology, P.O. Box 47600, Olympia, WA 98504-7600, phone (360) 407-6865, fax (360) 407-6989, e-mail DAVR461@ecy.wa.gov.

October 18, 2004

Polly Zehm

Deputy Director

OTS-7503.2

     (2) A fossil-fueled thermal electric generating facility is not subject to the requirements of chapter 173-401 WAC solely due to its emissions of CO₂.

     (a) Emissions of other regulated air pollutants must be a large enough quantity to trigger those requirements.

     (b) For fossil-fueled thermal electric generating facilities that are subject to chapter 173-401 WAC, the CO₂ mitigation requirements are an applicable requirement under that regulation.

     (3) A fossil-fueled thermal electric generating facility not subject to the requirements of chapter 173-401 WAC is subject to the requirements of the registration program in chapter 173-400 WAC.

[]

     (1) "Applicant" has the meaning provided in RCW 80.50.020 and includes an applicant for a permit for a fossil-fueled thermal electric generation facility subject to RCW 70.94.152 and 80.70.020 (1)(b) or (d).

     (2) "Authority" means any air pollution control agency whose jurisdictional boundaries are coextensive with the boundaries of one or more counties.

     (3) "Carbon credit" means a verified reduction in carbon dioxide or carbon dioxide equivalents that is registered with a state, national, or international trading authority or exchange that has been recognized by the council.

     (4) "Carbon dioxide equivalents" means a metric measure used to compare the emissions from various greenhouse gases based upon their global warming potential.

     (5) "Cogeneration credit" means the carbon dioxide emissions that the council, department, or authority, as appropriate, estimates would be produced on an annual basis by a stand-alone industrial and commercial facility equivalent in operating characteristics and output to the industrial or commercial heating or cooling process component of the cogeneration plant.

     (6) "Cogeneration plant" means a fossil-fueled thermal power plant in which the heat or steam is also used for industrial or commercial heating or cooling purposes and that meets federal energy regulatory commission standards for qualifying facilities under the Public Utility Regulatory Policies Act of 1978.

     (7) "Commercial operation" means the date that the first electricity produced by a facility is delivered for commercial sale to the power grid.

     (8) "Council" means the energy facility site evaluation council created by RCW 80.50.030.

     (9) "Department" means the department of ecology.

     (10) "Fossil fuel" means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material to produce heat for the generation of electricity.

     (11) "Mitigation plan" means a proposal that includes the process or means to achieve carbon dioxide mitigation through use of mitigation projects or carbon credits.

     (12) "Mitigation project" means one or more of the following:

     (a) Projects or actions that are implemented by the certificateholder or order of approval holder, directly or through its agent, or by an independent qualified organization to mitigate the emission of carbon dioxide produced by the fossil-fueled thermal electric generation facility. This term includes, but is not limited to, the use of energy efficiency measures, clean and efficient transportation measures, qualified alternative energy resources, demand side management of electricity consumption, and carbon sequestration programs;

     (b) Direct application of combined heat and power (cogeneration);

     (c) Verified carbon credits traded on a recognized trading authority or exchange; or

     (d) Enforceable and permanent reductions in carbon dioxide or carbon dioxide equivalents through process change, equipment shutdown, or other activities under the control of the applicant and approved as part of a carbon dioxide mitigation plan.

     (13) "Order of approval" means an order issued under RCW 70.94.152 with respect to a fossil-fueled thermal electric generation facility subject to RCW 80.70.020 (1)(b) or (d).

     (14) "Permanent" means that emission reductions used to offset emission increases are assured for the life of the corresponding increase, whether unlimited or limited in duration.

     (15) "Qualified alternative energy resource" has the same meaning as in RCW 19.29A.090.

     (16) "Station generating capability" means the maximum load a generator can sustain over a given period of time without exceeding design limits, and measured using maximum continuous electric generation capacity, less net auxiliary load, at average ambient temperature and barometric pressure.

     (17) "Total carbon dioxide emissions" means:

     (a) For a fossil-fueled thermal electric generation facility described under RCW 80.70.020 (1)(a) and (b), the amount of carbon dioxide emitted over a thirty-year period based on the manufacturer's or designer's guaranteed total net station generating capability, new equipment heat rate, an assumed sixty percent capacity factor for facilities under the council's jurisdiction or sixty percent of the operational limitations on facilities subject to an order of approval, and taking into account any enforceable limitations on operational hours or fuel types and use; and

     (b) For a fossil-fueled thermal electric generation facility described under RCW 80.70.020 (1)(c) and (d), the amount of carbon dioxide emitted over a thirty-year period based on the proposed increase in the amount of electrical output of the facility that exceeds the station generation capability of the facility prior to the applicant applying for certification or an order of approval pursuant to RCW 80.70.020 (1)(c) and (d), new equipment heat rate, an assumed sixty percent capacity factor for facilities under the council's jurisdiction or sixty percent of the operational limitations on facilities subject to an order of approval, and taking into account any enforceable limitations on operational hours or fuel types and use.

[]

     (2) Statutory carbon dioxide mitigation program applicability requirements. RCW 80.70.020 describes the applicability requirements and is reprinted below:

     (1) The provisions of this chapter apply to:

     (a) New fossil-fueled thermal electric generation facilities with station-generating capability of three hundred fifty thousand kilowatts or more and fossil-fueled floating thermal electric generation facilities of one hundred thousand kilowatts or more under RCW 80.50.020 (14)(a), for which an application for site certification is made to the council after July 1, 2004;

     (b) New fossil-fueled thermal electric generation facilities with station-generating capability of more than twenty-five thousand kilowatts, but less than three hundred fifty thousand kilowatts, except for fossil-fueled floating thermal electric generation facilities under the council's jurisdiction, for which an application for an order of approval has been submitted after July 1, 2004;

     (c) Fossil-fueled thermal electric generation facilities with station-generating capability of three hundred fifty thousand kilowatts or more that have an existing site certification agreement and, after July 1, 2004, apply to the council to increase the output of carbon dioxide emissions by fifteen percent or more through permanent changes in facility operations or modification or equipment; and

     (d) Fossil-fueled thermal electric generation facilities with station-generating capability of more than twenty-five thousand kilowatts, but less than three hundred fifty thousand kilowatts, except for fossil-fueled floating thermal electric generation facilities under the council's jurisdiction, that have an existing order of approval and, after July 1, 2004, apply to the department or authority, as appropriate, to permanently modify the facility so as to increase its station-generating capability by at least twenty-five thousand kilowatts or to increase the output of carbon dioxide emissions by fifteen percent or more, whichever measure is greater.

     (3) New facilities. Any fossil-fueled thermal electric generating facility is required to mitigate CO₂ emissions as described in chapter 80.70 RCW, if the facility meets the following criteria:

     (a) An application was received after July 1, 2004;

     (b) The station-generating capability is below 350 MWe and above 25 MWe;

     (c) The facility is not a fossil-fueled floating thermal electric generation facility subject to regulation by the energy facility site evaluation council.

     (4) Modifications to existing facilities. A fossil-fueled thermal electric generating facility seeking to modify the facility or any electrical generating units is required to mitigate the increase of the emission of CO₂, as described in RCW 80.70.020, when the following occur:

     (a) The application was received after July 1, 2004;

     (b) The unmodified station generating capability is more than 25 MWe and less than 350 MWe;

     (c) The modification to the fossil-fueled thermal electric generating facility or units will increase electrical output by the greater of:

     (i) At least 25 MWe; or

     (ii) An increase in the annual emissions of CO₂ of 15% or more;

     (d) The facility or the modification is not under the jurisdiction of the energy facility site evaluation council;

     (5) Examples of fossil-fueled thermal electric generation units. The following are some examples of fossil-fueled thermal electric generating units:

     (a) Coal, oil, natural gas, or coke fueled steam generating units (boilers) supplying steam to a steam turbine - electric generator;

     (b) Simple cycle combustion turbine attached to an electric generator;

     (c) Combined cycle combustion turbines (with and without duct burners) attached to an electric generator and supplying steam to a steam turbine - electric generator;

     (d) Coal gasification units, or similar devices, where the synthesis gas produced is used to fuel a combustion turbine, boiler or similar device used to power an electric generator;

     (e) Hydrocarbon reformer emissions where the hydrogen produced is used in a fuel cell.

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     (2) Fees. The fees for the carbon dioxide mitigation program are described in this section and listed in the table below. The fees listed are added to the fees established in chapters 173-400 and 173-401 WAC, when the carbon dioxide mitigation plan requirements are triggered.

Activity		Fee
a. Application Review		$65.00/hr1 not to exceed $500.00
b. Mitigation Plan approval
	i. Payment to third party	$1002
	ii. Purchase of CO2 credits	$65.00/hr3
	iii. Direct investment	$65.00/hr4
c. Routine Compliance Monitoring
	i. Payment to third party	$1005 annually until full amount paid
	ii. Purchase of CO2 credits	$65.00/hr6
	iii. Applicant Controlled Project	$65.00/hr7

	1Estimated using an EE3 per hour rate with a cap.
	2Small fee primarily to check math and that the source is using an EFSEC approved qualified organization.
	3Estimated EE3 per hour rate to check that the credits purchased will be verifiable and from a reputable trading or marketing organization.
	4Estimated using an EE3 per hour rate.
	5Same as rationale for 2 above.
	6Verify and confirm credits with the trading or marketing organization.

     (3) The department or authority may use RCW 70.94.085 to structure a cost-reimbursement agreement with the applicant.

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CO2rate	=	Fs x Ks	x Ts +	F1 x K1	x T1 +	F2 x K2	x T2 +	F3 x K3	x T3. . . +	Fn x Kn	x Tn
		2204.6		2204.6		2204.6		2204.6		2204.6

CO2 rate	=	Maximum potential emissions in metric tons per year
F1 - n	=	Maximum design fuel firing rate in mmBtu/hour calculated as manufacturer/designer's guaranteed total net station generating capability in MWe times the new equipment heat rate in Btu/MWe
K1 - n	=	Conversion factor for the fuel(s) being evaluated in lb CO2/mmBtu for fuel Fn
T1 - n	=	Hours per year fuel Fn is allowed to be used. The default is 8760 hours unless there is a limitation on hours in an order of approval
Fs	=	Maximum design supplemental fuel firing rate in mmBtu/hour
Ks	=	Conversion factor for the supplemental fuel being evaluated in lb CO2/mmBtu for fuel Fn given fuel
Ts	=	Hours per year supplemental fuel Fn is allowed. The default is 8760 hours unless there is a limitation on hours in an order of approval

     (a) When there are multiple new fossil-fueled electric generating units, the above calculation will be performed for each unit and the total CO₂ emissions of all units will be summed.

     (b) When a unit or facility is allowed to use multiple fuels, the maximum allowed hours on the highest CO₂ producing fuels will be utilized for each fuel until the total of all hours per fuel add up to the allowable annual hours.

     (c) When a new unit or facility is allowed to use multiple fuels without restriction in its approval order(s), this calculation will be performed assuming that the fuel with the highest CO₂ emission rate is used 100% of the time.

     (d) When the annual operating hours are restricted for any reason, the total of all T_{1 - n} hours equals the annual allowable hours of operation in the Order of Approval.

     (e) Fuel to CO₂ conversion factors:

Fuel	Kn lb/mmBtu
#2 oil	158.16
#4 oil	160.96
#6 oil	166.67
Lignite	328.57
Sub-bituminous coal	282.94
Bituminous coal, low volatility	312.50
Bituminous coal, medium volatility	274.55
Bituminous coal, high volatility	306.11
Natural gas	117.6
Propane	136.61
Butane	139.38
Petroleum coke	242.91
Coal coke	243.1
Other fuels	Calculate based on carbon content of the fossil fuel and application of the gross heat content (higher heating value) of the fuel

     (2) Step 2 - Insert the annual CO₂ rate to determine the total carbon dioxide emissions to be mitigated. The formula below includes specifications that are part of the total carbon dioxide definition:

Total CO2 Emissions = CO2rate x 30 x 0.6

     (3) Step 3 - Determine and apply the cogeneration credit (if any). Where the cogeneration unit or facility qualifies for cogeneration credit, the cogeneration credit is the annual CO₂ emission rate (in metric tons per year) and is calculated as shown below or similar method:

CO2credit	=	Hs	(Ka) ÷ .35
		2204.6

Where cogeneration credit	=	The annual CO2 credit for cogeneration in metric tons/year.
Hs	=	Annual heat energy supplied by the cogeneration plant to the "steam host" per the contract or other binding obligation/agreement between the parties in mmBtu/yr as substantiated by an engineering analysis.
Ka	=	The time weighted average CO2 emission rate constant for the cogeneration plant in lb CO2/mmBtu supplied. The time weighted average is calculated similarly to the above method described in subsection (1) of this section.

Cogeneration Credit = CO2credit x 30

     (4) Step 4 - Apply the mitigation factor.

     (a) RCW 80.70.020(4) states that "Fossil-fueled thermal electric generation facilities that receive site certification approval or an order of approval shall provide mitigation for twenty percent of the total carbon dioxide emissions produced by the facility."

     (b) The CO₂ emissions mitigation quantity is determined by the following formula:

Mitigation Quantity = Total CO2 Emissions x 0.2 - Cogeneration Credit

Mitigation quantity	=	The total CO2 emissions to be mitigated in metric tons
CO2rate	=	The annual maximum CO2 emissions from the generating facility in tons/year
0.2	=	The mitigation factor in RCW 80.70.020(4)

     (5) Additional restrictions for modifications to an existing facility not involving installation of new generating units. The quantity of CO₂ to be mitigated is calculated by the same methods used for the new generating units with the following restrictions:

     (a) The quantity of CO₂ subject to mitigation is only that resulting from the modification and does not include the CO₂ emissions occurring prior to the modification.

     (b) An increase in operating hours or other operational limitations established in an order of approval is not an exempt modification under this regulation. However, only emissions related to the increase in operating hours are subject to the CO₂ mitigation program requirements.

     (c) The annual emissions (CO_{2 rate}) is the difference between the premodification condition and the postmodification condition, but using the like new heat rate for the combustion equipment.

     (d) The cogeneration credit may be used, but only if it is a new cogeneration credit, not a cogeneration agreement or arrangement established prior to July 1, 2004, or used in a prior CO₂ mitigation evaluation.

7Review reports and document project progress.

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     (2) What are the mitigation plan options? The options are identified in RCW 80.70.020(3), which states that "An applicant for a fossil-fueled thermal electric generation facility shall include one or a combination of the following carbon dioxide mitigation options as part of its mitigation plan:

     (a) Payment to a third party to provide mitigation;

     (b) Direct purchase of permanent carbon credits; or

     (c) Investment in applicant-controlled carbon dioxide mitigation projects, including combined heat and power (cogeneration)."

     (3) What are the requirements of the payment to a third party option? The payment to a third party option requirements are found in RCW 80.70.020 (5) and (6). Subsection (5) identifies the mitigation rate for this option and describes the process for changing the mitigation rate. Subsection (6) describes the payment options.

     The initial mitigation rate is $1.60 per metric ton of carbon dioxide to be mitigated. If there is a cogeneration plant, the monetary amount is based on the difference between twenty percent of the total carbon dioxide emissions and the cogeneration credit. This rate will change when the energy facility site evaluation council adjusts it through the process described in RCW 80.70.020 (5)(a) and (b). The total payment amount = mitigation rate x mitigation quantity.

     An applicant may choose between a lump sum payment or partial payment over a period of five years. The lump sum payment is described in RCW 80.70.020 (6)(a) and (b). The payment amount is the mitigation quantity multiplied by the per ton mitigation rate. The entire payment amount is due to the independent qualified organization no later than one hundred twenty days after the start of commercial operation.

     The alternative to a one-time payment is a partial payment described in RCW 80.70.020 (6)(c). Under this alternative, twenty percent of the total payment is due to the independent qualified organization no later than one hundred twenty days after the start of commercial operation. A payment of the same amount (or an adjusted amount if the rate is changed under RCW 80.70.020 (5)(a)) is due on the anniversary date of the initial payment for the next four consecutive years. In addition, the applicant is required to provide a letter of credit or comparable security for the remaining 80% at the time of the first payment. The letter of credit (or comparable security) must also include possible rate changes.

     (4) What are the requirements of the permanent carbon credits option? RCW 80.70.030 identifies the criteria and specifies that these credits cannot be resold without approval from the local air authority having jurisdiction or ecology where there is no local air authority. The permanent carbon credit criteria of RCW 80.70.030(1) is as follows:

     (a) Credits must derive from real, verified, permanent, and enforceable carbon dioxide or carbon dioxide equivalents emission mitigation not otherwise required by statute, regulation, or other legal requirements;

     (b) The credits must be acquired after July 1, 2004; and

     (c) The credits may not have been used for other carbon dioxide mitigation projects.

     (5) What are the requirements for the applicant controlled mitigation projects option? RCW 80.70.040 identifies the requirements for applicant controlled mitigation projects. Subsections (1) through (5) specify the criteria. Subsection (6) specifies that if federal requirements are adopted for carbon dioxide mitigation for fossil-fueled thermal electric generation facilities, ecology or the local air authority may deem the federal requirements equivalent and replace RCW 80.70.040 with the federal requirements.

     The applicant controlled mitigation project must be:

     (a) Implemented through mitigation projects conducted directly by, or under the control of, order of approval holder. (Section 1);

     (b) Approved by the authority having jurisdiction or the department where there is no local air authority and incorporated as a condition of the proposed order of approval. (Section 2);

     (c) Fully in place within a reasonable time after the start of commercial operation. Failure to implement an approved mitigation plan is subject to enforcement under chapter 70.94 RCW. (Section 3)

     In addition, an order of approval holder may not use more than twenty percent of the total funds for the selection, monitoring, and evaluation of mitigation projects and the management and enforcement of contracts. (Section 4)

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     (2) Applicants choosing to use the payment to a third party or the permanent carbon credit option must provide the department or the authority, as appropriate, with the documentation to show how the requirements will be satisfied before an order or approval will be issued.

     (3) Applicants seeking to use the applicant controlled mitigation projects option must submit the entire mitigation plan to the department or the authority. The department or authority having jurisdiction will review the plan. Under RCW 70.94.892 (2)(b), the review criteria is based on whether the mitigation plan is consistent with the requirements of chapter 80.70 RCW.

     (4) Upon completing the review phase, the department or the authority having jurisdiction must approve or deny the mitigation plan.

     (5) Approved mitigation plans become part of the order of approval.

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