Original Notice.

     Preproposal statement of inquiry was filed as WSR 07-15-084.

     Title of Rule and Other Identifying Information: This proposal will amend the following two rules to implement chapter 80.80 RCW in which the 2007 legislature directed the department of ecology to adopt rules by June 30, 2008, to implement and enforce a greenhouse gases emissions performance standard and to establish criteria for evaluating sequestration plans: Chapter 173-407 WAC, Carbon dioxide mitigation program for fossil-fueled thermal electric generating facilities and chapter 173-218 WAC, Underground injection control program.

     Hearing Location(s): Ecology Headquarters Building, Auditorium, 300 Desmond Drive S.E., Lacey, WA, on April 8, 2008, at 6:00 p.m.; and at the Spokane County Public Health Center, 1101 West College Avenue, Room 140, Spokane, WA, on April 10, 2008, at 6:00 p.m. Department of ecology hearings are being conducted jointly with the energy facility site evaluation council (EFSEC).

     Date of Intended Adoption: June 16, 2008.

     Submit Written Comments to: Nancy Pritchett, P.O. Box 47600, Olympia, WA 98504-7600, e-mail npri461@ecy.wa.gov, fax (360) 407-7534, received by 5:00 p.m., April 18, 2008.

     Assistance for Persons with Disabilities: Contact Tami Dahlgren at (360) 407-6800, by April 1, 2008. If you have a hearing loss, call 711 for Washington Relay Service. If you have a speech disability, call (877) 833-6341.

     Purpose of the Proposal and Its Anticipated Effects, Including Any Changes in Existing Rules: The purpose of this proposal is to adopt, as directed in chapter 80.80 RCW, a greenhouse gases emissions performance standard for baseload electric generation and establish criteria to implement and enforce the emissions performance standard. The proposal will:

     (1) Amend chapter 173-407 WAC to modify the title to reference the greenhouse gases emissions performance standard; add new sections to implement and enforce the greenhouse gases emissions performance standard for baseload electric generation, as directed in chapter 80.80 RCW; and make minor corrections to existing rule language implementing chapter 80.70 RCW.

     (2) Amend chapter 173-218 WAC to include permitting requirements for the permanent geologic sequestration of CO₂ as a method for meeting the greenhouse gases emissions performance standard. The purpose of the proposed amendments is to protect ground water and public health and safety from contamination due to geologic sequestration of CO₂.

     Reasons Supporting Proposal: Executive Order 07-02 established goals for the statewide reduction of greenhouse gases emissions within Washington over the next several decades as one of the methods of addressing climate change. These emissions reductions goals were also adopted within ESSB 6001 and codified in chapter 80.80 RCW. The legislature passed chapter 80.80 RCW in 2007 with the intent to establish statutory goals for statewide reductions in greenhouse gases emissions and to authorize immediate actions in the electric power generation sector for the reduction of greenhouse gases emissions. RCW 80.80.040 directed the department of ecology to adopt rules by June 30, 2008, to implement and enforce a greenhouse gases emissions performance standard and to establish criteria for evaluating sequestration plans. The proposed rules satisfy the statutory requirements under chapter 80.80 RCW. These proposed rules also support the goals of Executive Order 07-02 by beginning to address the impacts of climate change in Washington.

     Statutory Authority for Adoption: ESSB 6001, codified as chapter 80.80 RCW.

     Statute Being Implemented: Chapter 80.80 RCW.

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

     Name of Proponent: Department of ecology, air quality program and water quality program, governmental.

     Name of Agency Personnel Responsible for Drafting, Implementation and Enforcement: Nancy Pritchett, Lacey, Washington, (360) 407-6082.

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

     You can also view this report on the department of ecology's web site at http://www.ecy.wa.gov/biblio/0802006.html.

     Note: Due to size limitations relating to the filing of documents with the code reviser, the small business economic impact statement (SBEIS) does not contain the appendices, reference section, and footnotes 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.

     1. Background: The Washington state department of ecology (ecology) is proposing to amend chapter 173-407 WAC, Carbon dioxide mitigation program for fossil-fueled thermal electric generating facilities and chapter 173-218 WAC, Underground injection control program.

     In 2007, state lawmakers passed new climate change legislation that Governor Christine Gregoire signed into law on May 3, 2007. The new law (chapter 80.80 RCW) requires ecology, in coordination with the energy facility site evaluation council (EFSEC), to adopt rules setting a greenhouse gases emissions performance standard. The rules will set standards for:

•	Baseload generation and cogeneration facilities in Washington.
•	Baseload electric generation for which electric utilities enter into long-term financial commitments on or after July 1, 2008.

     Reason for this rule proposal: Carbon dioxide (CO₂) is the main source of the greenhouse gas emissions that are contributing to climate change. Electricity generation is the third leading contributor of greenhouse gases in Washington, behind transportation and the direct use of fuel. Ecology is proposing rule amendments that will:

•	Implement a CO2 emission performance standard of 1,100 pounds of greenhouse gases per mega watt hour (MWh) of power generated for baseload power plants.
•	Establish an output-based methodology for calculating greenhouse gas emissions from a cogeneration facility.
•	Establish performance standards to protect the quality of ground water associated with a carbon capture and sequestration project.
•	Establish criteria for evaluating carbon capture and sequestration plans submitted by power plants.

     All of these are necessary to implement the new law and they will help us begin to address the impacts of climate change in Washington and support the Governor's Climate Change Challenge Executive Order 07-02.

     Scope of Analysis: Although the energy sector has broad impacts, ecology has defined a narrow scope for this analysis.

•	This analysis does not deal with energy and economy interactions. It only addresses change to the electrical sector for electricity sold to the grid.
•	Generally, this kind of analysis only covers the costs of the proposed rule.
•	The price data in this document are from the market and include the impacts of all existing subsidies. Most energy sources are subsidized. Hydro, wind, solar, and fossil fuels all receive different forms of subsidies. Ecology has not attempted to net out the price effect of subsidies from the cited data because the market interactions are too complex to allow it. The USDOE estimates do not appear to include subsidies, except that the modeled price of coal and natural gas come from a market that is affected by subsidies. The price data used to determine the viability of carbon capture in this document are from the market and therefore include the impacts of all subsidies.

     Comparison of the Current and Proposed Rules: Two rules are affected by this proposal. This analysis covers both rules. The first rule is chapter 173-407 WAC implementing the requirements of chapter 80.70 RCW. The second rule is chapter 173-218 WAC implementing provisions of chapter 90.48 RCW to protect ground water quality.

     Current rule requirements: The existing rules of chapter 173-407 WAC implements the provisions of chapter 80.70 RCW that do not affect the activities or permitting requirements of EFSEC. The existing rule requires mitigation "of the emissions of CO₂ from all new and certain modified fossil-fueled thermal electric generating facilities with station-generating capability of more than 25 MWe." The law and existing rule require that the mitigation cover the expected emissions for the thirty year expected lifetime of a power plant. Carbon capture and sequestration is one option for accomplishing this.

     The existing rules of chapter 173-218 WAC do not include specific requirements for using underground injection control wells for underground geologic sequestration of carbon dioxide, but they do regulate the discharge of fluids into the wells to prevent ground water contamination. Permits for these types of projects are required under chapter 90.48 RCW, Water pollution control and chapter 173-216 WAC, the state waste discharge permit program.

     Description of proposed changes: Who is affected? The rule applies in a complex manner and would apply to power plants only in specific cases. This is laid out in Table 1. Any plant that meets the criteria in the table must comply, however, it will be easier for the new natural gas turbines and gas/oil turbines to meet the requirements. Given the 1,100 pounds of CO₂ per MWh emission performance standard, the law and the proposed rule are most likely to affect coal-based power plants. Affected coal power and old style natural gas boilers are likely to need carbon capture and sequestration to comply. Based on recent project permitting history, only natural gas combined cycle power plants are likely to be proposed and permitted for baseload operation in Washington. However, the law and the rule have flexibility which limits who is affected.

     Baseload generation: According to the definition of baseload generation in WAC 173-407-110 if a new generator finds it is viable to operate less than 60% of the time so that they are not part of baseload generation, then the proposed rules would not affect them. This means a new generator could purposely build a facility to be permitted for operating at only 60% to avoid having to meet the requirements of the proposed rules. This is true even if the facility provided power on an emergency basis for more than 60% of the year. The other side of this scenario is that the law and proposed rules are likely to limit the development of any new large coal or inefficient fossil fuel power plants. This is because these types of power plants must operate more than 60% of the time to make a profit. For plants outside Washington, selling power into Washington, the law and rule limit emissions from baseload facilities that are subject to contracts for more than five years and they cannot put power on the system as an unspecified source.

     Short-term contracts: Because the law only covers long-term contracts the proposed rule (WAC 173-407-300, 173-407-310 and 173-407-320) can only address long-term contracts. Therefore, short-term contracts for purchases of less than five years are not covered. This means entities who want to buy electricity from a new coal or another fossil fuel source (that is not required to comply with the new law or proposed rules) will be able to do so, but only based on short-term contracts. This creates some uncertainty for any new coal or other fossil fuel generators who prefer long-term contracts to guarantee payoff of construction loans. This uncertainty may limit their willingness to develop this resource in Washington.

     Distributed Generation: Distributed generation is when power is generated but no power is sold to the grid it is used to supply only the electrical needs of the facility for where it is located. This is not cogeneration. Even if these types of generators end up providing power during peak or emergency times, via short-term contracts, they would be unaffected by the proposed rules.

     Emergency Generation: Emergency generators are designed to come on if grid power is lost. These generators will be unaffected.

     Averaging of load: WAC 173-407-300 allows the load from specified and unspecified sources in a contract that provides a mix of types of power generation (such as a Bonneville Power Authority (BPA) contract) to be averaged based on a formula.

     BPA provided comments expressing concerns that they would have difficulty contracting with Washington public utility districts (PUDs) if they had to specify all sources of power. Therefore, WAC 173-407-300 is included in the proposed rule. When an entity signs a contract that includes electricity from unknown sources, they are allowed to average the CO₂ emissions from all of the sources. In practice, this means that if a contract is for a specified share of power from renewables, up to 42% of their sources can be unspecified. Given that the northwest has a very large current supply of renewable power, in practice this means they may be able to include as much existing and new fossil fuel-based power as necessary under long-term BPA contracts.

Table 1: Affected Power Plants

When would a power plant be required to meet the emission performance standard?
	Instate				Out of state
	upon start-up	new ownership interest	nonexempt upgrade	new long-term contract to supply baseload power	upon start-up	new ownership interest	nonexempt upgrade	new long-term contract to supply baseload power
Baseload generation
Stand-alone								X
New	X	X	X	X				X
existing		X	X	X
Cogeneration
new	X	X	X					X
existing		X	X					X
Distributed generation
new				X				X
existing				X				X
Nonbaseload generation
Seasonal
new				X				X
existing				X				X
Emergency
new				X				X
existing				X				X
Peaking power
new				X				X
existing				X				X
Table assumes that the facility is not powered exclusively by renewable fuels. Distributed generation is generation installed to supply the electrical needs of the facility it is located within. No power is sold to the grid. This is not cogeneration. Cogeneration, aka combined heat and power, is a facility that produces both electrical energy and useful thermal energy. One or both forms of energy may be sold. Cogenreation [Cogeneration] facilities must meet certain FERC requirements to qualify. Emergency generation are emergency generators, designed to operate on event of loss of grid power. Peaking power plants and seasonal power plants are facilities designed, intended and permitted to operate at less than full time. Peaking power plants operate solely to provide peak shaving [saving] power through the course of the day/year. They are not permitted for full-time operation. Seasonal power plants are plants that operate only during portions of the year with high power demand. They are not permitted for full-time operation. Once nonbaseload generation becomes baseload generation through a new contract to supply baseload power, such units become existing baseload units.

     What is required? Chapter 80.80 RCW created additional requirements with respect to greenhouse gases emissions. The law itself has a substantial impact without the proposed rules. However, it would be difficult for new power contracts in the state to be signed or new power plants sited and permitted for operation without adopting the proposed rules. The law and proposed rules adds a requirement for permanent sequestration of greenhouse gases above the 1,100 pounds of allowable emissions per MWh of electricity generated. The law does not define permanent sequestration or the specific plan requirements for designing, building, and monitoring a sequestration site or project. This is covered in the proposed rules.

     The law and proposed rules also require that a new long-term financial commitment to buy electricity must meet the 1,100 pounds per MWh emissions performance standard. The rule specifies how a purchaser of electricity would determine if the proposed long-term financial commitment would meet the emissions performance standard.

     Chapter 173-218 WAC is amended to include specific provisions for the design, permitting, implementation, closure and financial assurance requirements of an underground geologic sequestration project.

     Baseline for Analysis: The baseline for this analysis is the law, as it can't be implemented without the existing rules or the proposed amendments.

     Time Period for Analysis: This analysis is limited to a twelve-year span reviewing likely choices available to power plants up to 2020. Ecology typically uses a twenty-year period when evaluating rules. For major investments such as industrial plants, a longer period could be used. The law and the proposed rules allow CO₂ emissions to be reduced through perpetual storage, which would also require a longer time span for analysis. However, major potential changes make extending the time span less viable:

•	The time span of the analysis affects not just discounting, but in this case, what should be evaluated. At the 2007 Electric Power Research Institute (EPRI) summer seminar, only 5% of the participants (industry professionals) indicated they thought CO2 capture would be commercially available by 2015. Only 24% thought it would be available by 2020, and only 15% by 2025. Over half of the participants do not expect it to be available for at least twenty years. The proposed rules limit CO2 emissions for long-term baseload, but allows carbon capture and sequestration. If carbon capture and sequestration is not viable within the next twenty years, then it is the foregone energy that must be valued.
•	On the other hand, 42% of the EPRI participants believe mandatory CO2 controls will be placed on the energy sector by 2010. Another 31% believe it will happen by 2012. The market forces that will affect the United States economy under carbon constraints and/or carbon pricing make twenty years too long a period to evaluate. It will change both the rules in the markets and the prices.
•	Results from Wallula sequestration testing may change our understanding of geological sequestration.
•	At the end of the five-year period, the law directs the department of community, trade and economic development (CTED) to revise the emission performance standard to reflect the capabilities of combined cycle natural gas fired turbine equipment available at that time. Based on current combined cycle power plant equipment, the standard would be revised downward to 830 – 860 lb/MWh if this update were to occur today. However, we don't know what will be viable five years from now. When revisions occur they must be evaluated. A change of this magnitude would likely alter the market outcome and therefore ecology would count those costs for this analysis.
•	As part of the 2008 legislative session, the legislature is considering a bill adding a greenhouse gas reporting requirement to chapter 70.94 RCW. The bill would direct ecology to develop proposed legislation and other recommendations to implement a greenhouse gas cap and trade program that would become effective by 2012. If this series of proposed laws is passed by the legislature and the implementing rules are finalized per the timeframe in the current bill, the economic landscape of power plants and their greenhouse gas emissions will be very different than what exists today.

     Finally, if the rule has a short-term of action because changes in state law significantly alter the constraints on the market, then the rule would only affect a very limited number of plants. This makes the unit costs of electricity and carbon a better mechanism for comparison.

     Discount rates (interest rates) are used to compare values that accrue over time. This document relies heavily on the USDOE analysis of the cost of carbon dioxide capture. The USDOE models do not state the discount rate for modeling efforts that provide the unit cost of carbon capture and electricity. Ecology has requested this information so that the final analysis can have a coherent set of discount rates.

     2. Analysis of Compliance Costs for Washington Businesses: The primary effect of the law and proposed rules taken together is to make it difficult to produce electricity with coal or with natural gas steam plants. Some companies may choose to shift to natural gas turbines.

     Ecology could have counted small detailed costs involved with applying for sequestration, however, that cost is unlikely to accrue. The shift in fuel is more expensive than these small costs but less expensive than carbon capture. Since carbon capture is so expensive that it is likely to make the electricity unmarketable, it is not likely to be selected for long-term compliance by any company. Therefore, the shift in fuel and all the costs associated with that are both the most likely and the appropriate measure of the costs. The total cost shift for this scenario involves significant differences in capital, labor, fuel costs and other items. Ecology has relied on USDOE estimates for this data.

     3. Quantification of Costs and Ratios: If the law and the proposed rules have any affect, and if [it] affects more than one firm, then the impact will tend to be disproportionate. If construction of a plant were precluded then the revenue loss would be the highest possible cost that could be evaluated. It is not possible to estimate the size of the hypothetical plant. However, the disproportionate impact can be illustrated using a cost per MWh basis.

Table 2: Cost of electricity in Mills/KWh

Source	Mills per kWh
GE Energy	78
Conoco Phillips	75.3
Shell	80.5
Subcritical Pulverized Coal	64
Supercritical Pulverized Coal	63.3
Natural Gas Combined Cycle	68.4

     A range of expected costs per MWh is available from USDOE data. The wholesale market price of electricity would have to be greater than or equal to these values in order for a company to want to produce and sell the electricity. Thus, these costs form a low estimate of the price that would have to be available to create entry into the market.

     Taking the average of the coal-based sources, $72/MWh, we can construct an estimate of the loss per MWh per employee for either a generator or a potential buyer, such as a public utility district.

Table 3: Cost of foregone revenue per MWh per employee by NAICS

Cost per MWh per Employee
NAICS	221112	221121	221122	926130	All
Small Businesses			$3.59	******	$3.84
Large Business	$0.17	$0.96	$0.22		$0.32

*** data which would reveal the identity of companies or the number of employees is suppressed.

     4. Actions Taken to Reduce the Impact of the Proposed Rule on Small Business: Ecology has done a variety of things to reduce the cost of the rule. These are listed below under the topic headings in the law. However, the primary cost-reducing feature is averaging of load under (e) below.

     (a) Reducing, modifying, or eliminating substantive regulatory requirements;

•	Ecology considered a wide range of options for requiring a demonstration of compliance with the performance standard. Some advocated for regular and some for a one-time action when rule applicability is triggered while others advocated for a continuing compliance requirement based on annual reporting of compliance. Ecology chose to propose an annual compliance and reporting approach to be consistent with other air quality program requirements, including current emission inventory program requirements.
•	In the performance standard applicability to contracts (WAC 173-407-300), proposed to use default values for some generation sources and for unspecified sources to simplify the effort of a utility to determine compliance for contracts. This allows the use of actual emission information, in the calculation for specified sources, but does not require actual emission information to be used.
•	At one point the draft rule required monitoring of greenhouse gas emissions by all baseload power plants in Washington, as of the date the rule would go into effect, regardless of whether the facility was required to demonstrate compliance with the performance standard. Proposal has reduced the monitoring and reporting requirement to only those facilities and units that are subject to the applicability criteria - i.e. those which are new baseload plants, enter into a new long-term financial commitment, upgrade, new ownership interest, etc.
•	The law does not contain a de minimis criterion for a new ownership interest (which triggers the requirement to comply with the standard). We propose a de minimis ownership interest change to trigger applicability. This will reduce work associated with the trading of a few shares or small percentages of a facility's output.
•	The law does not include a de minimis usage of fossil fuel in a renewable resource generation facility. We have proposed a de minimis fossil fuel use to qualify as a renewable resource fueled generator. This de minimis is based on a criterion in several federal regulations. We have also defined what a renewable resource fuel is and utilized that definition in the proposed rule text. A de minimis fossil fuel usage is necessary for biomass fueled generation plants, because (1) you need to light the fire and fossil fuel (oil or natural gas) is usually used, (2) the cogeneration plants based on renewable fuels often have mandatory steam or electricity production contracts and need some sort of back-up fuel, and (3) occasionally the renewable fuel (especially wood waste) is too wet and needs supplemental fuel to properly burn. Without this de minimis, no electric generation facility that uses renewable fuels (biomass, landfill gas, etc.) could qualify for the renewable energy source exemption in the law.
•	The proposed rules will allow sequestration pilot projects to be permitted before meeting all of the data gathering requirements for a full permit.
•	The proposed rules will allow the use of all existing geologic data previously collected for other activities to be used for site characterization.
•	Geologic carbon sequestration projects will be permitted using the existing State Waste Discharge Permit Program instead of creating a unique permit program. Very few geologic sequestration permit applications are expected so if there were a unique permit program, the few projects would require permit fees that covered the total cost of the program.
•	If a geologic sequestration project is associated with a fossil fuel power plant, which is likely, the same wastewater permit fee would cover all discharges including the carbon sequestration.
•	The proposed rule will allow the use of all existing geologic data previously collected for other activities to be used for site characterization.
•	During the discussions ecology considered:

o	Requiring monitoring for each potable aquifer at a sequestration project and the unsaturated zone above the uppermost aquifer but chose to only require monitoring of the groundwater as close as practicable to the geologic sequestration formation.
o	Requiring evaluation and monitoring within six miles beyond the project boundary but chose to require this evaluation and monitoring one mile beyond the project boundary.
o	Requiring annual pressure testing of all injection wells but chose to require these tests every five years.
o	Requiring the post-closure period to extend for a set number of years after injection is complete but chose to allow the post-closure period to end once monitoring and modeling indicate that there is little continued environmental risk.
o	Requiring the project boundary to include the area of 100% of the carbon dioxide injected but chose to define the boundary as the calculated extend of 95% of the injected carbon dioxide mass one hundred years after the end of injection.
o	Requiring a minimum number of deep characterization wells prior to permitting any site but chose to allow the number of wells to be determined based on site specific considerations.

•	During the discussions ecology considered not allowing:

o	Sequestration projects within ten miles of any jurisdictional boundary, but chose to allow it as long as the project proponents addressed issues related to boundaries.
o	Sequestration projects within ten miles of marine shorelines, but chose to allow as long as the project proponents addressed issues related to the shorelines.
o	Sequestration projects with more than 25% of the project area within a one hundred year flood plain, but chose to allow as long as the project proponents addressed issues related to flood plains.
o	Sequestration projects where more than 25% of the land overlying is not physically accessible, but chose to allow as long as the project proponents addressed issues related to accessibility.
o	Sequestration projects with more than a low risk of seismic events, but chose to allow as long as the project proponents addressed issues related to seismic risks of the site.
o	Sequestration projects within five miles of any active faults, but chose to allow as long as the project proponents addressed any active (Holocene) faults within five miles.
o	The injection of carbon dioxide with any contaminants but chose to allow carbon dioxide as long as all known treatment technologies are used to remove contaminants.

     (b) Simplifying, reducing, or eliminating record-keeping and reporting requirements;

•	Ecology considered requiring continuous monitoring for N2O at large plants, instead propose that large plants (above 25MW) do periodic emissions testing for the first year to establish a plant specific emission factor, and use that factor until an upgrade or other rule applicability triggering action occurs. For smaller plants, only emission factors derived from an authoritative source used, subject to ECY approval. For methane the same approach as for N2O is used.
•	In the monitoring and record-keeping and reporting requirements ecology considered continuous stack monitoring of CO2, and exhaust flow rate for all plant sizes. Proposal only requires this for facilities subject to the EPA acid rain program requirements, and allows the use of emission factor calculations as allowed by that program for natural gas combustion units. For all units not subject to the federal acid rain program allow the use of emission factors.
•	For all plant sizes, an annual reporting requirement to ecology, done electronically for acid rain program sources, piggybacked on their fourth quarter report to EPA, for all others a separate submittal to ecology containing the required information.
•	The minimum reporting requirements for geologic sequestration projects is the same as the minimum required for all state waste discharge permits.

     (c) Reducing the frequency of inspections;

•

For compliance with the emission performance standard, no inspections are required. However, the facilities subject to the federal acid rain program requirements to monitor CO2 emissions already and will continue to have required quality assurance and substitute data provisions to be followed. This proposed rule does not add new requirements but rather references those existing requirements. The federal program already requires this, and a different state program would be more burdensome on the facilities due to having to maintain duplicate and differing data.

•

There is no set schedule for ecology inspection of geologic sequestration projects.

     (d) Delaying compliance timetables;

•	For compliance with the emission performance standard, no inspections are required. However, the facilities subject to the federal acid rain program requirements to monitor CO2 emissions already and will continue to have required quality assurance and substitute data provisions to be followed. This proposed rule does not add new requirements but rather references those existing requirements. The federal program already requires this, and a different state program would be more burdensome on the facilities due to having to maintain duplicate and differing data.
•	There is no set schedule for ecology inspection of geologic sequestration projects.
•	There is no compliance dates in this proposed rule, just applicability dates in the law. Except for the enforcement of the sequestration plan requirements. The source is required to submit the sequestration plan or the sequestration program at the time of the submittal of the notice of construction application. The approval of this plan or program will be issued at the same time as the permit. If there is an instance of noncompliance with the emissions performance standard (EPS), there is a requirement to revisit the program or plan. There is a requirement to submit the new plan or program as soon as possible, but no later than one hundred fifty days after the annual report that compares actual performance with the EPS. We could have made the deadline sooner, but we decided to make it this length of time. The source should have enough internal information on meeting the EPS some months before the end of the reporting period, and as such would prudently start work on a plan or program.

     Geologic sequestration projects may begin with a pilot project prior to complying with all of the permitting requirements for a full-scale project.

     (f) Any other mitigation techniques.

     The most significant cost reduction in the proposed rules is the section that allows averaging of the load for contracted power supply involving multiple sources of electrical power. WAC 173-407-300 allows the load from specified and unspecified sources to be averaged based on a formula.

•

Bonneville Power Administration provided comments expressing concerns that they would have difficulty contracting with Washington PUDs if they had to specify all sources of power. Therefore, WAC 173-407-300 is included in the proposed rule. When an entity signs a contract that includes purchases of electricity from unknown sources they are allowed to average the CO2 emissions from all the sources. In practice this means that if the contract includes a specified share of power from renewables, they can have up to 42% of their sources be unspecified. Given that the northwest has a very large current supply of renewable power, in practice this means they may be able to include as much existing and new fossil fuel-based power as they find to be necessary under long-term BPA contracts.

     5. The Involvement of Small Business in the Development of the Proposed Rule Amendments: The rule advisory committee contained representatives of both the consumer-owned utilities and the publicly-owned utilities. The entities represented by these representatives are the small businesses that are directly affected by the rules.

     6. The NAICS of Affected Industries:

     The rule may affect companies in four NAICS codes.

Table 4. NAICS Codes

Activity	NAICS
Fossil fuel electric power generation	221112
Electric bulk power transmission and control	221121
Electric power distribution	221122
Utility regulation and administration	926130

     7. Impacts on Jobs: Ecology used the OFM input/output table to estimate the potential labor impacts if a coal power plant were not opened. The size of the plant is unknown. In this case it is likely that electricity would be supplied by another typical source. The analysis assumes a shift of 10 MW of face place capacity from average coal production costs to average gas cogeneration production costs. Since this is a cost savings to the economy it acts as a reduction in expenditure (demand) in the model. The net change in demand based payments plugged into the model is $-335,000. This yields an annual loss of four jobs.

     A copy of the statement may be obtained by contacting Cathy Carruthers, Department of Ecology, P.O. Box 47600, Olympia, WA 98504-7600, phone (360) 407-6564, fax (360) 407-6989, e-mail caca461@ecy.wa.gov.

     A cost-benefit analysis is required under RCW 34.05.328. A preliminary cost-benefit analysis may be obtained by contacting Cathy Carruthers, Department of Ecology, P.O. Box 47600, Olympia, WA 98504-7600, phone (360) 407-6564, fax (360) 407-6989, e-mail caca461@ecy.wa.gov.

February 22, 2008

Polly Zehm

Deputy Director

OTS-1277.2

AMENDATORY SECTION(Amending Order 01-10, filed 1/3/06, effective 2/3/06)

WAC 173-218-030   Definitions.   "Abandoned well" means a well that is unused, unmaintained, or is in such disrepair as to be unusable.

     "AKART" is an acronym that means all known, available and reasonable methods of prevention, control and treatment. AKART shall represent the most current methodology that can be reasonably required for preventing, controlling, or abating the pollutants associated with a discharge. The concept of AKART applies to both point and nonpoint sources of pollution. The term "best management practices" typically applies to nonpoint source pollution controls, and is considered a subset of the AKART requirement. The storm water management manuals (see definition in this section) may be used as a guideline, to the extent appropriate, for developing best management practices to apply AKART for storm water discharges.

     "Aquifer" means a geologic formation, group of formations or part of a formation capable of yielding a significant amount of ground water to wells or springs.

     "Beneficial uses" mean uses of the waters of the state which include, but are not limited to, use for domestic, stock watering, industrial, commercial, agricultural, irrigation, mining, fish and wildlife maintenance and enhancement, recreation, generation of electric power and preservation of environmental and aesthetic values, and all other uses compatible with the enjoyment of the public waters of the state.

     "Best management practices" mean approved physical, structural, and/or managerial practices that, when used singularly or in combination, prevent or reduce pollutant discharges.

     "Caprock" means geologic confining layer(s) that has sufficiently low permeability and lateral continuity to prevent the migration of injected carbon dioxide out of the geologic containment system.

     "Cesspool" means a drywell that receives untreated sanitary waste containing human excreta, and that sometimes has an open bottom and/or perforated sides that discharge to the subsurface.

     "Commercial business" means a type of business activity that may distribute goods or provide services, but does not involve the manufacturing, processing or production of goods.

     "Contaminant" means any chemical, physical, biological, or radiological substance that does not occur naturally in ground water or that occurs at concentrations greater than those found naturally.

     "Contamination" means introduction of a contaminant.

     "Dangerous waste" means those solid wastes designated in WAC 173-303-070 through 173-303-100 as dangerous, or extremely hazardous or mixed waste. As used in chapter 173-303 WAC, Dangerous waste regulations, the words "dangerous waste" will refer to the full universe of wastes regulated by chapter 173-303 WAC.

     "Decommission" means to fill or plug a UIC well so that it will not result in an environmental or public health or safety hazard, nor serve as a channel for movement of water or pollution to an aquifer.

     "Department" means department of ecology.

     "Dispersion" means the release of surface and storm water runoff from a drainage facility system such that the flow spreads over a wide area and is located so as not to allow flow to concentrate anywhere upstream of a drainage channel with erodible underlying granular soils.

     "Drywell" means a well, other than an improved sinkhole or subsurface fluid distribution system, completed above the water table so that its bottom and sides are typically dry except when receiving fluids.

     "Existing well" means a well that is in use at the adoption date of this chapter.

     "Fluid" means any material or substance which flows or moves whether in a semisolid, liquid, sludge, gas, or any other form or state.

     "Geologic containment system" means the geologic layers that both receive the injected carbon dioxide (CO₂) and contains or sequesters it within the system's physical boundaries. The containment system is a three-dimensional area with defined boundaries, that includes one or more geologic formations.

     "Geologic sequestration of carbon dioxide" means the injection of carbon dioxide, usually from human activities like burning coal or oil, into subsurface geologic formations to prevent its release into the atmosphere for a defined length of time.

     "Geologic sequestration project" means the surface and underground facilities used to inject carbon dioxide for sequestration and includes: Geologic containment system, monitoring zone(s) and surface facilities described in the permit application.

     "Geologic sequestration project boundary" means a three-dimensional boundary defined in permit that encloses all surface and underground facilities of the geologic sequestration project and extending vertically to the overlying ground surface.

     "Ground water" means water in a saturated zone or stratum beneath the surface of land or below a surface water body.

     "Ground water protection area" means a geographic area that is by or close by a surrounding community and nontransient noncommunity water system, that uses ground water as a source of drinking water (40 CFR 144.87) and other sensitive ground water areas critical to protecting underground sources of drinking water from contamination; such as sole source aquifers, highly productive aquifers supplying private wells, critical aquifer recharge areas and/or other state and local areas determined by state and local governments.

     "Hazardous substances" mean any dangerous or extremely hazardous waste as defined in RCW 70.105.010 (5) and (6) or any dangerous or extremely dangerous waste as designated by rule under chapter 70.105 RCW; any hazardous substance as defined in RCW 70.105.010(14) or any hazardous substance as defined by rule under chapter 70.105 RCW; any substance that, on the effective date of this section, is a hazardous substance under section 101(14) of the federal cleanup law, 42 U.S.C., Sec. 9601(14); petroleum or petroleum products; and any substance or category of substances, including solid waste decomposition products, determined by the director by rule to present a threat to human health or the environment if released into the environment.

     "High threat to ground water" means, for this chapter, a UIC well is a high threat to ground water when it receives fluids that cannot meet the criteria in chapter 173-200 WAC Water quality standards for ground waters of Washington (GWQS) at the top of the aquifer, which include, but are not limited to, the following examples: A UIC well that receives drainage, that has not been pretreated and does not meet the GWQS; such as, from an area where storm water comes into contact with a vehicle fueling area, airport deicing activities, storage of treated lumber or vehicle washing; or a UIC well that receives a discharge that is determined to be an imminent public health hazard by a legal authority or is prohibited in this chapter.

     "Improved sinkhole" means a naturally occurring karst depression or other natural crevice found in volcanic terrain and other geologic settings that has been modified by man for the purpose of directing and emplacing fluids into the subsurface.

     "Infiltration pond" means an earthen impoundment used for the collection, temporary storage and infiltration of incoming storm water runoff.

     "Infiltration trench" means a trench used to infiltrate fluid into the ground, is generally at least twenty-four inches wide and backfilled with a coarse aggregate. Perforated pipe or a product with similar use may also be installed.

     "Industrial wastewater" means water or liquid-carried waste from industrial or commercial processes, as distinct from domestic wastewater. These wastes may result from any process or activity of industry, manufacture, trade or business, from the development of any natural resource, or from animal operations such as feedlots, poultry houses or dairies. The term includes contaminated storm water and leachate from solid waste facilities.

     "Monitoring zone(s)" means the geologic layers, identified in the application, where chemical, physical and other characteristics are measured to establish the location, behavior and effects of the injected carbon dioxide in the subsurface and to detect leakage from the geologic containment system. At a minimum, a monitoring zone must be established beneath the ground surface but outside of the geologic containment system to detect leakage of injected CO₂.

     "Motor vehicle waste disposal well" means a Class V injection well that is typically a shallow disposal system that receives or has received fluids from vehicular repair or maintenance activities such as auto body repair shop, automotive repair shop, new and used car dealership, specialty repair shops or any facility that does any vehicular repair work (40 CFR 144.81).

     "New injection well" means an injection well that is put in use following the adoption date of this chapter.

     "Nonendangerment standard" means to prevent the movement of fluid containing any contaminant into the ground water if the contaminant may cause a violation of the Water quality standards for ground waters of the state of Washington, chapter 173-200 WAC or may cause health concerns.

     "Nonpollution-generating surface" means a surface considered to be an insignificant source of pollutants in storm water runoff and/or a surface not defined as a pollution-generating surface.

     "Person" means any political subdivision, local, state, or federal government agency, municipality, industry, public or private corporation, partnership, association, firm, individual, or any other entity whatsoever.

     "Point of compliance" means the location where the facility must be in compliance with chapter 173-200 WAC Water quality standards for ground waters of the state of Washington; the top of the aquifer, as near to the source as technically, hydrogeologically, and geographically feasible.

     "Pollution" means contamination or other alteration of the physical, chemical, or biological properties of waters of the state, including change in temperature, taste, color, turbidity, or odor of the waters, or such discharge of any liquid, gaseous, solid, radioactive or other substance into any waters of the state as will, or is likely to, create a nuisance or render such waters harmful, detrimental, or injurious to the public health, safety or welfare, or to domestic, commercial, industrial, agricultural, recreational, or other legitimate beneficial uses, or to livestock, wild animals, birds, fish or other aquatic life.

     "Pollution-generating surfaces" mean the surfaces are considered a significant source of pollutants in storm water runoff. Pollution generating surfaces include pollution generating pervious surfaces and pollution generating impervious surfaces such as surfaces that are subject to: Regular vehicular use, industrial activities, or storage of erodible or leachable materials that receive direct rainfall, or the run-on or blow-in of rainfall, use of pesticides or fertilizers or loss of soil; or leaching such as from metal roofs not coated with an inert, nonleachable material, roofs that are subject to venting of manufacturing, commercial, or other indoor pollutants. Examples of commercial indoor pollutants are commercial facilities such as restaurants where oils and other solid particles are expected to be expelled. It does not include normal indoor air venting at commercial facilities where activities such as cooking, processing, etc., do not take place. Examples are: Roads, unvegetated road shoulders, bike lanes within the traveled lane of a roadway, driveways, parking lots, unfenced fire lanes, vehicular equipment storage yards, airport runways, lawns, and landscaped areas that apply pesticide applications; such as golf courses, parks, cemeteries, and sports fields except for landscaped areas that are approved infiltrative best management practices.

     "Proper management of storm water" means AKART has been provided or the well owner has demonstrated that the discharge will meet the nonendangerment standard.

     "Radioactive waste" means any waste which contains radioactive material in concentrations that exceed those listed in 10 Code of Federal Regulations Part 20, Appendix B, Table II, and Column 2.

     "Retrofit" means taking actions to reduce the pollutant load from a UIC well to meet the statutory requirements of 40 CFR 144.12 and RCW 90.48.010. These actions may include, but are not limited to: Changes to the source control activities and/or structures around the well; an upgrade to the well such as adding a catch basin or spill control device; and/or addition of pretreatment facilities or decommissioning. The selection of actions is based on local priorities, required by the department or the local jurisdiction to address a documented water quality problem.

     "Rule authorized" means a UIC well that is registered with the department and meets the nonendangerment standard. If a well is rule authorized, it does not require a state waste discharge permit from the department.

     "Sanitary waste" means liquid or solid wastes originating solely from humans and human activities, such as wastes collected from toilets, showers, wash basins, sinks used for cleaning domestic areas, sinks used for food preparation, clothes washing operations, and sinks or washing machines where food and beverage serving dishes, glasses, and utensils are cleaned. Sources of these wastes may include single or multiple residences, hotels and motels, restaurants, bunkhouses, schools, ranger stations, crew quarters, guard stations, campgrounds, picnic grounds, day-use recreation areas, other commercial facilities, and industrial facilities provided the waste is not mixed with industrial waste.

     "Septic system" means a well that is used to discharge sanitary waste below the surface and is typically comprised of a septic tank and subsurface fluid distribution system or disposal system. (Also called on-site sewage system.)

     "Sequestration" means to set apart or remove.

     "State waste discharge permit" means a permit issued in accordance with chapter 173-216 WAC, State waste discharge permit program.

     "Storm water" means the portion of precipitation that does not naturally percolate into the ground or evaporate, but flows via overland flow, interflow, pipes and other features of a storm water drainage system into a defined surface water body, or a constructed treatment, evaporation, or infiltration facility.

     "Storm water manuals" mean the Stormwater Management Manual for Eastern or Western Washington or other manuals approved by the department.

     "Storm water pollution prevention plan" means a documented plan to implement measures to identify, prevent, and control the contamination of storm water and its discharge to UIC wells.

     "Subsurface fluid distribution system" means an assemblage of perforated pipes, drain tiles, or other similar mechanisms intended to distribute fluids below the surface of the ground.

     "Underground source of drinking water" means ground waters that contain fewer than 10,000 mg/L of total dissolved solids and/or supplies drinking water for human consumption.

     "UIC well" or "underground injection control well" means a well that is used to discharge fluids into the subsurface. A UIC well is one of the following: (1) A bored, drilled or driven shaft, or dug hole whose depth is greater than the largest surface dimension; (2) an improved sinkhole; or (3) a subsurface fluid distribution system.

     "Waste fluid" means any fluid that cannot meet the nonendangerment standard at the point of compliance, which is the top of the aquifer.

     "Well assessment" means an evaluation of the potential risks to ground water from the use of UIC wells. A well assessment includes information such as the land use around the well which may affect the quality of the discharge and whether the UIC well is located in a ground water protection area. It may include the local geology and depth of the ground water in relation to the UIC well if the well is considered a high threat to ground water.

     "Well injection" means the subsurface emplacement of fluids through a well.

     "You" means the owner or operator of the UIC well.

[Statutory Authority: Chapters 43.21A and 90.48 RCW. 06-02-065 (Order 01-10), § 173-218-030, filed 1/3/06, effective 2/3/06. Statutory Authority: RCW 43.21A.445. 84-06-023 (Order DE 84-02), § 173-218-030, filed 2/29/84.]

     (1) "Class I injection well" means a well used to inject dangerous and/or radioactive waste, beneath the lowermost formation containing an underground source of drinking water within one-quarter mile of the well bore. All Class I wells are prohibited in Washington and must be decommissioned.

     (2) "Class II injection well" means a well used to inject fluids:

     (a) Brought to the surface in connection with natural gas storage operations, or conventional oil or natural gas production. It may be mixed with wastewaters from gas plants that are an integral part of production operations, unless those waters are classified as hazardous wastes at the time of injection;

     (b) For enhanced recovery of oil or natural gas; or

     (c) For storage of hydrocarbons that are liquid at standard temperature and pressure.

     (3) "Class III injection well" means a well used for extraction of minerals. All Class III wells are prohibited in Washington and must be decommissioned. Examples of Class III injection wells include, but are not limited to, the injection of fluids for:

     (a) In situ production of uranium or other metals that have not been conventionally mined;

     (b) Mining of sulfur by Frasch process; or

     (c) Solution mining of salts or potash.

     (4) "Class IV injection well" means a well used to inject dangerous or radioactive waste into or above an underground source of drinking water. Class IV wells are prohibited and must be decommissioned except for Class IV wells reinjecting treated ground water into the same formation from where it was drawn as part of a removal or remedial action if such injection is approved by EPA in accordance with the Comprehensive Environmental Response, Compensation, and Liability Act or the Resource Conservation and Recovery Act, 40 CFR 144.13(c). Other examples of Class IV wells include:

     (a) Dangerous or radioactive waste into or above a formation that contains an underground source of drinking water within one quarter mile of the well. This includes disposal of dangerous waste into a septic system or cesspool regardless of the size; or

     (b) Dangerous or radioactive waste that cannot be classified as a Class I well type or (a) of this subsection.

     (5) "Class V injection well" means all injection wells not included in Classes I, II, III, or IV. Class V wells are usually shallow injection wells that inject fluids above the uppermost ground water aquifer. Some examples are dry wells, French drains used to manage storm water and drain fields.

     (a) The following are examples of Class V injection wells that are allowed in Washington:

     (i) Drainage wells used to drain surface fluids, primarily storm water runoff, into or below the ground surface, such as, but not limited to, a drywell or infiltration trench containing perforated pipe;

     (ii) Heat pump or cooling water return flow wells used to inject water previously used for heating or cooling;

     (iii) Aquifer recharge wells used to replenish the water in an aquifer;

     (iv) Salt water intrusion barrier wells used to inject water into a fresh water aquifer to prevent the intrusion of salt water into the fresh water;

     (v) Septic systems serving multiple residences or nonresidential establishments that receive only sanitary waste and serve twenty or more people per day or an equivalent design capacity of 3,500 gallons or larger per day;

     (vi) Subsidence control wells (not used for the purpose of oil or natural gas production) used to inject fluids into a nonoil or gas producing zone to reduce or eliminate subsidence associated with the removal of fresh water;

     (vii) Injection wells associated with the recovery of geothermal energy for heating, aquaculture and production of electric power;

     (viii) Injection wells used in experimental technologies;

     (ix) Injection wells used for in situ recovery of lignite, coal, tar sands, and oil shale;

     (x) Injection wells used for remediation wells receiving fluids intended to clean up, treat or prevent subsurface contamination;

     (xi) Injection wells used to inject spent brine into the same formation from which it was withdrawn after extraction of halogens or their salts;

     (xii) Injection wells used to control flooding of residential basements;

     (xiii) Injection wells used for testing geologic reservoir properties for potential underground storage of natural gas or oil in geologic formations; if the injected water used is of equivalent or better quality than the ground water in the targeted geologic formation and the ground water in the targeted geologic formation is nonpotable and/or toxic because of naturally occurring ground water chemistry; ((and))

     (xiv) Injection wells used as part of a reclaimed water project as allowed under a permit; and

     (xv) Injection wells used to inject carbon dioxide for geologic sequestration.

     (b) The following are examples of Class V wells that are prohibited in Washington:

     (i) New and existing cesspools including multiple dwelling, community or regional cesspools, or other devices that receive sanitary wastes that have an open bottom and may have perforated sides that serve twenty or more people per day or an equivalent design capacity of 3,500 gallons or larger per day. The UIC requirements do not apply to single family residential cesspools or to nonresidential cesspools which receive solely sanitary waste and have the capacity to serve fewer than twenty persons a day or an equivalent design capacity of less than 3,500 gallons per day;

     (ii) Motor vehicle waste disposal wells that receive or have received fluids from vehicular repair or maintenance activities (see definition of motor vehicle waste disposal wells in WAC 173-218-030). UIC wells receiving storm water located at vehicular repair, maintenance or dismantling facilities shall not be considered waste disposal wells if the wells are protected from receiving vehicle waste;

     (iii) Wells used for solution mining of conventional mines such as stopes leaching;

     (iv) Backfill wells used to inject a mixture of water and sand, mill tailings or other solids into mined out portions of subsurface mines whether what is injected is a radioactive waste or not;

     (v) UIC wells receiving fluids containing hazardous substances (see definition for hazardous substances in WAC 173-218-030) except for wells:

     (A) Allowed under (a)(x) of this subsection; or

     (B) Receiving storm water that meets the nonendangerment standard by applying the best management practices and requirements in WAC 173-218-090 or storm water authorized under a permit; and

     (vi) UIC wells receiving industrial wastewater except for industrial wastewater authorized under a permit.

[Statutory Authority: Chapters 43.21A and 90.48 RCW. 06-02-065 (Order 01-10), § 173-218-040, filed 1/3/06, effective 2/3/06. Statutory Authority: RCW 43.21A.445. 84-06-023 (Order DE 84-02), § 173-218-040, filed 2/29/84.]

     (1) New Class V UIC wells used for storm water management must:

     (a) Meet additional ground water protection area requirements as determined by other state laws or by local ordinances;

     (b) Not directly discharge into ground water. A separation between the bottom of the well and the top of the ground water is required. The treatment capacity of the unsaturated zone or the zone where the fluid is discharged, and the pollutant loading of the discharge must be considered when determining the vertical separation; and

     (c) The owner or operator of a new Class V well used to manage storm water must meet the nonendangerment standard as defined under WAC 173-218-080. The owner or operator of a new Class V well must show compliance with the nonendangerment standard prior to placing a new well into service. Compliance with the nonendangerment standard may be met through one or a combination of the following two approaches:

     (i) Presumptive approach: The presumptive approach means compliance with the nonendangerment standard is presumed, unless discharge monitoring data or other site specific information shows that a discharge causes or contributes to a violation of chapter 173-200 WAC Water quality standards for ground waters of the state of Washington, when:

     (A) The well activity is in compliance with this chapter; and either

     (B) The well is designed and installed to the storm water manual current at the time of construction and is operated in conformance with storm water best management practices including the proper selection, implementation, and maintenance of all on-site pollution control using the current storm water manual published by the department for your region or an equivalent department approved local manual.

     (C) Owners or operators of municipal separate storm sewer systems regulated under section 1342(p) of the Federal Water Pollution Control Act which also own or operate Class V UIC wells may satisfy the presumptive approach by applying the storm water management programs developed to comply with the Federal Water Pollution Control Act to their new UIC wells. For new UIC wells, construction phase and postconstruction storm water controls must be applied in accordance with applicable storm water manuals.

     (D) The presumptive approach may not be used when best management practices do not exist to remove or reduce a contaminant, the vadose zone has no treatment capacity and/or the storm water quality is such that a best management practice does not exist to reduce or eliminate the concentration.

     (ii) Demonstrative approach: The demonstrative approach means that the technical bases for the selection of storm water best management practices are documented. The documentation must include:

     (A) The method and reasons for choosing the storm water best management practices selected;

     (B) The pollutant removal performance expected from the practices selected;

     (C) The technical basis supporting the performance claims for the practices selected, including any available existing data concerning field performance of the practices selected;

     (D) An assessment of how the selected practices will satisfy the requirements of WAC 173-218-080 and chapter 173-200 WAC; and

     (E) An assessment of how the selected practices will satisfy state requirements to use all known, available, and reasonable methods of prevention, control and treatment.

     (2) Existing Class V UIC wells used for storm water management do not have to meet the new well requirements. If the UIC wells are not already registered, the owner or operator must register the wells with the department and complete a well assessment. The following timelines must be met unless otherwise approved from the department:

     (a) If you own or operate less than or equal to fifty wells:

     (i) You have three years after the adoption date of this rule to register your UIC wells unless an extension has been approved by the department;

     (ii) You have five years after the adoption date of this rule to complete a well assessment. The approach to conducting the well assessment will be determined by the owner. The well assessment evaluates the potential risks to ground water from the use of UIC wells and includes information such as the land use around the well which may affect the quality of the discharge and whether the UIC well is located in a ground water protection area. It may include the local geology, and depth of the ground water in relation to the UIC well if the well is considered a high threat to ground water. The well assessment requirements will be met if an owner or operator applies the storm water best management practices contained in a guidance document approved by the department to their UIC wells and determines if the UIC well is located in a ground water protection area;

     (iii) Any well assessment that identifies a well as a high threat to ground water must include a retrofit schedule; and

     (iv) You must immediately take action to correct the use of a well that is determined to be an imminent public health hazard, for example when a drinking water supply is contaminated and causes a public health emergency. The department must be notified within thirty days from the determination and may determine a retrofit schedule. The department's enforcement procedure (see WAC 173-218-130) will be followed when a retrofit schedule is needed.

     (b) If you own or operate more than fifty wells:

     (i) You have five years after the adoption date of this rule to register your UIC wells unless an extension has been approved from the department;

     (ii) You have seven years after the adoption date of this rule to complete a well assessment. The approach to conducting the well assessment will be determined by the owner. The well assessment evaluates the potential risks to ground water from the use of UIC wells and includes information such as the land use around the well which may affect the quality of the discharge, and whether the UIC well is located in a ground water protection area. It may include the local geology, and depth of the ground water in relation to the UIC well if the well is considered a high threat to ground water. The well assessment requirements will be met if an owner or operator applies the storm water best management practices contained in a guidance document approved by the department to their UIC wells and determines if the UIC well is located in a ground water protection area;

     (iii) Any well assessment that identifies a well as a high threat to ground water must include a retrofit schedule; and

     (iv) You must immediately take action to correct the use of a well that is determined to be an imminent public health hazard, for example when a drinking water supply is contaminated and causes a public health emergency. The department must be notified within thirty days from the determination and may establish a retrofit schedule. The department's enforcement procedure will be followed when a retrofit schedule is needed.

     (c) If you own or operate a site that uses, stores, loads, or treats hazardous substances or is an industrial facility that has a Standard Industrial Classification as regulated by Federal Regulations, 40 CFR Subpart 122.26 (b)(14) (excluding construction sites), you may use the following to satisfy the documentation requirements for meeting the nonendangerment standard:

     (i) If the facility has or will have a waste water discharge permit issued pursuant to chapter 90.48 RCW, including a National Pollutant Discharge Elimination System (NPDES) permit, the associated storm water pollution prevention plan may be used in place of the well assessment to meet the nonendangerment standard provided the storm water pollution prevention plan specifically addresses storm water discharges to UIC wells; or

     (ii) For unpermitted facilities, the preparation and implementation of a storm water pollution prevention plan can be used in place of the well assessment to meet the nonendangerment standard if applied to the UIC wells or documentation must be provided to show that the well does not pose a threat to ground water. Examples of documentation include, but are not limited to, a site drainage map for the UIC wells or a no-exposure certification form completed for discharges to ground.

     (d) Owners or operators of municipal separate storm sewer systems regulated under section 1342(p) of the federal Water Pollution Control Act which also own or operate Class V UIC wells may satisfy the nonendangerment standard by applying the storm water management programs developed to comply with the federal Water Pollution Control Act to their UIC wells. For existing UIC wells receiving new sources of storm water, construction phase and post-construction storm water controls must be applied to all development and redevelopment projects in accordance with applicable storm water manuals.

     (3) Class V UIC wells not used for storm water management:

     (a) New UIC wells that are not used for storm water management must:

     (i) Not directly discharge into an aquifer, except for wells listed in WAC 173-218-040 (5)(a)(ii) through (iv), (vii) through (xi), (xiii) ((and)), (xiv) and (xv). A separation between the bottom of the well and the top of the aquifer is required; and

     (ii) Meet additional ground water protection requirements if the UIC well is located in a ground water protection area (see WAC 173-218-030) as determined by other state laws or by local ordinances.

     (b) Existing registered UIC wells that are not used for storm water management are already considered to be rule authorized. To verify that current site practices are protective of ground water quality, the owner or operator must complete a survey from the department except for UIC wells used at CERCLA sites. The department will provide written notification that the current site practices are adequate.

     (c) Existing UIC wells that are not registered and not used for storm water management must meet the requirements for new wells.

[Statutory Authority: Chapters 43.21A and 90.48 RCW. 06-02-065 (Order 01-10), § 173-218-090, filed 1/3/06, effective 2/3/06. Statutory Authority: RCW 43.21A.445. 84-06-023 (Order DE 84-02), § 173-218-090, filed 2/29/84.]

     (a) Class V UIC wells used for the geologic sequestration of carbon dioxide are not rule authorized and must obtain a state waste discharge permit under chapter 173-216 WAC, State waste discharge permit program or chapter 173-226 WAC, Waste discharge general permit program.

     (b) Class V injection wells used for the geologic sequestration of carbon dioxide may directly discharge into an aquifer only if:

     (i) The aquifer contains "naturally nonpotable ground water" as defined in WAC 173-200-020(18) and is beneath the lowermost formation containing potable ground water within the vicinity of the geologic sequestration project area;

     (ii) The operator has obtained a permit under the state waste discharge permit program or the waste discharge general permit program establishing enforcement limits which may exceed the ground water quality criteria, as allowed under WAC 173-200-050 (3)(b)(vi);

     (iii) The operator uses all known, available and reasonable methods of prevention, control and treatment (AKART) to remove contaminants, such as sulfur compounds and other contaminants, from the injected CO₂. Geologic sequestration of carbon dioxide shall not be used for the disposal of non-CO₂ contaminants that can be removed with known treatment technologies; and

     (iv) The operator is in compliance with all conditions of their state waste discharge permit or their waste discharge general permit.

     (2) Permit application: A licensed geologist or engineer shall conduct the geologic and hydrogeologic evaluations required under this section. Technical evaluations shall reflect the best available scientific data as well as existing geologic, geophysical, geomechanical, geochemical, hydrogeological and engineering data available on the proposed project area. Existing data may be used in evaluations provided their source and chronology is identified and the effects of any subsequent modifications due to natural (seismic or other) or human induced (hydraulic fracturing, drilling or other) events are analyzed. The waste discharge permit application, under chapter 173-216 or 173-226 WAC, for a permit authorizing the geologic sequestration of carbon dioxide shall include information supporting the demonstration required by WAC 173-200-050 (3)(b)(vi) and all of the following:

     (a) A description of how the project will address:

     (i) All jurisdictional boundaries within ten miles of the geologic sequestration project boundary such as: International borders, state borders, local jurisdictions, tribal land, national parks or state parks;

     (ii) Accessibility for operations and monitoring in areas where access is restricted by: Shorelines, flood plains, urban or other development, and any other natural or man-made limiting factors;

     (iii) Active Holocene faults within five miles and seismic risks;

     (b) A current site map showing:

     (i) The boundaries of the geologic sequestration project which shall be calculated to include the area containing ninety-five percent of the injected CO₂ mass one hundred years after the completion of all CO₂ injection or the plume boundary at the point in time when expansion is less than one percent per year, whichever is greater, or another method approved by the department;

     (ii) Location and well number of all proposed CO₂ injection wells;

     (iii) Monitoring wells;

     (iv) Location of all other wells including cathodic protection boreholes; and

     (v) Location of all pertinent surface facilities, including atmospheric monitoring within the boundary of the project;

     (c) A technical evaluation of the proposed project, including but not limited to, the following:

     (i) The names and lithologic descriptions of the geologic containment system;

     (ii) The name, description, and average depth of the reservoir or reservoirs to be used for the geologic containment system;

     (iii) A geophysical, geomechanical, geochemical and hydrogeologic evaluation of the geologic containment system, including:

     (A) An evaluation of all existing information on all geologic strata overlying the geologic containment system including the immediate caprock containment characteristics as well as those of other caprocks if included in the containment system and all designated subsurface monitoring zones;

     (B) Geophysical data and assessments of any regional tectonic activity, local seismicity and regional or local fault zones; and

     (C) A comprehensive description of local and regional structural or stratigraphic features;

     (iv) The evaluation shall focus on the proposed geologic sequestration reservoir or reservoirs and a description of mechanisms of geologic containment, including but not limited to:

     (A) Rock properties;

     (B) Regional pressure gradients;

     (C) Structural features; and

     (D) Absorption characteristics or geochemical reaction/mineralization processes, with regard to the ability to prevent migration of CO₂ beyond the proposed geologic containment system;

     (v) The evaluation shall also identify:

     (A) Any productive oil and natural gas zones occurring stratigraphically above, below, or within the geologic containment system;

     (B) All water-bearing horizons known in the immediate vicinity of the geologic sequestration project;

     (C) The evaluation shall include a method to identify unrecorded wells that may be present within the project boundary;

     (vi) The evaluation shall include exhibits, plans and maps showing the following:

     (A) All wells, including but not limited to, water, oil, and natural gas exploration and development wells, injection wells and other man-made subsurface structures and activities, including any mines, within one mile of the geologic sequestration project;

     (B) All man-made surface structures that are intended for temporary or permanent human occupancy within one mile of the geologic sequestration project;

     (C) Any regional or local faulting within the boundary of the geologic sequestration project;

     (D) An isopach map of the proposed CO₂ storage reservoir or reservoirs that make up the geologic containment system;

     (E) An isopach map of the primary and any secondary caprock or containment barrier;

     (F) A structure map of the top and base of the storage reservoir or reservoirs that make up the geologic containment system;

     (G) Identification of all structural spill points or stratigraphic discontinuities controlling the isolation of CO₂ or associated fluids;

     (H) An evaluation of the potential displacement of in situ water and the potential impact on ground water resources, if any; and

     (I) Structural and stratigraphic cross-sections that describe the geologic conditions at the geologic containment system;

     (vii) An operations and maintenance plan including, but not limited to, a diagram of the entire injection system and a description of the proposed operating and maintenance procedures;

     (viii) A review of the data of public record for all wells within the geologic sequestration project area which penetrate the geologic containment system including the primary and/or all other caprocks and those wells that penetrate these geologic layers within one mile of the boundary of the geologic sequestration project area, or any other distance deemed necessary by the department. This review shall determine if all abandoned wells have been plugged in a manner that prevents the movement of CO₂ or associated native fluids away from the geologic containment system;

     (ix) The proposed maximum bottom hole injection rate and injection pressure to be used at the geologic containment system. The maximum allowed injection pressure shall be no greater than eighty percent of the formation fracture pressure as determined by a mini-frac injection test or multiple-stage, minimum threshold fracture injection test or other method approved by the department. The geologic containment system shall not be subjected to injection pressures in excess of the calculated fracture pressure even for short periods of time. Higher operating pressures may only be allowed if approved in writing by the department;

     (x) The proposed maximum long-term geologic containment system pressure and the necessary technical data to support the proposed geologic containment system storage pressure request;

     (xi) The evaluation and data quality shall be sufficient to establish with a high degree of confidence that the geologic containment system has sufficient capacity, injectivity and other geologic characteristics to permanently sequester CO₂ for the lifetime of the project;

     (d) The predicted extent of the injected CO₂ plume throughout the life of the project, determined with established modeling tools that use all available geologic and reservoir engineering information, and the projected response and storage capacity of the geologic containment system. The assumptions used in the model and a discussion of the uncertainty associated with the estimate shall be clearly presented;

     (e) An analysis and selection of proposed treatment technology for non-CO₂ contaminant that identifies the technology which meets the requirement that all known, available and reasonable methods of prevention, control and treatment (AKART) to remove contaminants from the injected CO₂;

     (f) A detailed description of the proposed project public safety and emergency response plan. The plan shall detail the safety procedures concerning the facility and residential, commercial, and public land use within one mile, or any other distance as deemed necessary by the department, of the boundary of geologic sequestration project area. The public safety and emergency response procedures shall include contingency plans for leakage from any well, flow lines, or other permitted facility. The public safety and emergency response procedures also shall identify specific contractors and equipment vendors capable of providing necessary services and equipment to respond to incidents such as: Injection well leaks or loss of containment from injection wells or releases from the geologic containment system. These emergency response procedures shall be updated as necessary throughout the operational life of the permitted storage facilities;

     (g) A detailed worker safety plan that addresses safety training and safe working procedures at the facility;

     (h) A corrosion monitoring and prevention plan for all wells and surface facilities;

     (i) A leak detection and monitoring plan for all wells and surface facilities. The approved leak detection and monitoring plan shall define the threshold for determining that a leak has occurred and shall address:

     (i) Identification of any failure of the containment system;

     (ii) Identification of release to the atmosphere;

     (iii) Identification of degradation of any ground water or surface water resources; and

     (iv) Identification of migration of CO₂ or other contaminants into any overlying oil and natural gas reservoirs;

     (j) A geologic sequestration project leak detection and monitoring plan using subsurface measurements to monitor movement of the CO₂ plume both within and to detect migration outside of the permitted geologic containment system. This must include:

     (i) Collection of baseline information on formation pressure and background concentrations in ground water, surface soils, and chemical composition of in situ waters within the geologic containment system and monitoring zone(s);

     (ii) Monitoring of pressure responses and other appropriate information immediately above caprock of the geologic containment system;

     (k) The approved subsurface leak detection and monitoring plan shall be based on the site-specific characteristics as documented by materials submitted in the permit application and shall address:

     (i) Identification of any failure in the containment system;

     (ii) Identification of release to the atmosphere;

     (iii) Identification of degradation of any ground or surface water resources; and

     (iv) Identification of migration of CO₂ or other contaminants into any overlying oil and natural gas reservoirs;

     (l) A risk assessment that identifies and quantifies hazards, probabilities, features, events and processes that might result in undesirable impacts to public health and the environment;

     (m) A mitigation and remediation plan that identifies trigger thresholds and corrective actions to be taken prior to a containment system failure, if ground water quality in the monitoring zone or above is degraded, or if carbon dioxide is released to the atmosphere. The mitigation and remediation plan must be approved by the department before injection begins;

     (n) The proposed well casing, cementing and integrity testing program;

     (o) A closure and post-closure plan, including a closure and post-closure cost estimate;

     (p) The application shall designate a financial assurance mechanism sufficient to cover the cost to the department for the abandonment of the project or remediation of facility leaks should the operator not perform as required or cease to exist;

     (q) The application shall designate a financial assurance mechanism sufficient to provide financial assurance to the department to cover the plugging and abandonment or the remediation of a CO₂ injection and/or subsurface observation well should the operator not perform as required in accordance with the permit or cease to exist;

     (r) The payment of the application fee; and

     (s) Any other information that the department requires.

     (3) Geologic sequestration well standards. (Note: In statutory references to chapter 344-12 WAC, the word "gas" shall include all injected carbon dioxide for geologic sequestration, including supercritical CO₂.) Wells used for geologic sequestration projects must meet the following:

     (a) Casing materials and cement must be designed and tested to withstand the reactive fluids and expected conditions encountered during the lifetime of the geologic sequestration project, including the post-closure period.

     (b) Minimum standards for construction and maintenance of wells. Chapter 173-160 WAC.

     (c) Drilling fluid standards of WAC 344-12-098.

     (d) Directional or other appropriate surveys shall be completed for all wells to verify location at depth.

     (e) Wells must be logged with appropriate geophysical methods which include at a minimum: Cement bonding and evaluation logs, and casing inspection logs. In addition a standard suite of "state of the art" wireline logs shall be run on each well to document physical properties of the well, the well integrity and any potential leakage points. At a minimum the wireline logging suite must include: Gamma ray, resistivity, temperature, formation pressure, both p- and v-sonic and neutron-density.

     (f) All collected geologic data, including geophysical logs, geologists logs, mud logs, and drilling logs, core, drill cuttings, and all other logs and surveys shall be submitted to the department of natural resources, division of geology and earth resources within thirty days after well completion. Submitted information shall include one paper and one digital copy of logs. (Note: The department of natural resources maintains geologic records in the state to enhance the scientific, economic and environmental values of the people of the state.)

     (g) One paper and one digital copy of all reports and data collected from surface geological and geophysical surveys of sequestration sites shall be submitted to the department of natural resources, division of geology and earth resources within thirty days after completion.

     (h) Wells that are completed within or below the geologic containment system must in addition:

     (i) Meet the well casing and cementing standards of WAC 344-12-087;

     (ii) Verify the integrity of cement behind casings, including the location of any channels, contamination or missing cement, by a cement map that incorporates data from a cement bond log, a variable density display, and an ultrasonic image, unless an alternative evaluation has been approved in writing by the department;

     (iii) Meet the blowout prevention standards of WAC 344-12-092;

     (iv) Wells shall be periodically tested to assess their structural integrity. Annual tests shall include wireline surveys for casing integrity/corrosion assessment and other appropriate tests. An injection well casing pressure test will be conducted prior to use and retested at least once prior to each permit renewal or when casing integrity/corrosion assessments identify risks. Any finding of inadequate structural integrity shall be reported to the department within twenty-four hours.

     (i) Notify the department thirty days prior to beginning any substantial work on wells including, deepening, repair or closure. Advance notice period may be reduced by the department when the work is intended to address immediate threats to public health, safety or the environment.

     (4) Permit terms and conditions. All terms and conditions listed in WAC 173-216-110, state waste discharge permit program, apply. In addition, the following terms and conditions shall apply to injection permits for the geologic sequestration of carbon dioxide:

     (a) To be issued a permit, an applicant must demonstrate the following:

     (i) That the geology, including geochemistry, of the site will:

     (A) Provide "permanent sequestration" of carbon dioxide as defined by WAC 173-407-110; and

     (B) The caprock and other features of the geologic containment system have the appropriate characteristics to prevent migration of carbon dioxide, other contaminants and nonpotable water.

     (ii) A monitoring program has been developed to identify leakage from the geologic containment system to the atmosphere, surface water and ground water. The monitoring program must be able to identify ground water quality degradation in aquifers prior to degradation of any potable aquifer. The monitoring program shall include observations in the monitoring zone(s) that can identify migration to aquifers as close stratigraphically to the geologic containment system as practicable.

     (iii) Design and construction standards of all facility structures and wells are sufficient to prevent migration of carbon dioxide or nonpotable water that will degrade water quality or impact beneficial uses outside the geologic containment system.

     (iv) All known, available and reasonable methods of prevention, control and treatment (AKART) will be used to remove contaminants from the injected CO₂. Geologic sequestration of carbon dioxide shall not be used for the disposal of non-CO₂ contaminants that can be removed with known treatment technologies.

     (b) Pilot studies at potential geologic sequestrations projects sites shall be encouraged to collect site characterization, risk assessment and feasibility information. Permits for pilot studies may be issued without meeting all the Class V geologic sequestration project requirements only when:

     (i) The pilot study is for a limited time duration;

     (ii) Public health and the environment are protected;

     (iii) The pilot study will collect detailed site-specific information used to establish the feasibility of permanent sequestration in developing a permit application that meets the standards of this section. The pilot study permit shall be based upon an operator submitted pilot study plan that addresses:

     (A) Site-specific geologic information including reasons for selecting a site as a potential geologic sequestration project;

     (B) Site-specific hydrogeologic information that includes information on potable aquifers and how their water quality will be protected;

     (C) A detailed plan of work for the pilot study that includes monitoring and quarterly reporting;

     (D) The information to be gained by the study;

     (E) The total quantity of CO₂ to be injected and an estimated injection schedule for the study. CO₂ injections for pilot studies shall be limited to no more than 1,000 metric tons CO₂, unless the operator demonstrates in the plan that a larger quantity is necessary to determine the feasibility and risks of a project;

     (F) The procedures to be implemented to protect public health and the environment;

     (iv) Pilot study permits shall not be used for a full scale carbon sequestration project. Injection of carbon dioxide associated with a pilot study permit shall be of limited quantity and duration, not to exceed five years.

     (c) The permit shall include a maximum working pressure in the geologic containment system, calculated from information provided in the application, that assures that the pressure in the injection zone does not initiate new fractures or propagate existing fractures in the injection zone or caprock. In no case shall the injection pressure initiate fractures in the caprock or cause the movement of injected fluids or formation fluids into shallower aquifers. Controlled artificial fracturing of the injection zone of the geologic containment system may be allowed with a plan that has been approved by the department.

     (d) If the operator identifies leakage in excess of the thresholds established in the mitigation and remediation plan, water quality degradation in shallower aquifers or leaks to the surface, including those around wells or within well casing, the operator must:

     (i) Notify the department within twenty-four hours;

     (ii) Take all necessary actions to protect public health, safety and the environment;

     (iii) Stop injecting immediately, until the project obtains approval for redefining the geologic containment system and its relevant dimensions by the department;

     (iv) Implement the mitigation and remediation plan to arrest and reverse environmental impacts. Amendments to the mitigation plan shall be developed in consultation with the department;

     (e) Monitoring for geologic sequestration projects shall include:

     (i) Characterization of injected fluids;

     (ii) Continuous recording of injection pressure, flow rate and volume;

     (iii) Continuous recording of pressure on annulus between tubing and long string casing;

     (iv) Monitoring zone leak detection identified in (a)(ii) of this subsection;

     (v) Sufficient monitoring to confirm the spatial distribution of the CO₂ in the subsurface.

     (f) Quarterly reports shall be submitted to the department that include the following:

     (i) Physical, chemical and other relevant characterization of the injected fluids;

     (ii) Monthly average, maximum and minimum values for injection pressure, flow rate, volume injected and annular pressure;

     (iii) Updated data for modeling that will project and/or establish the spatial distribution of CO₂ in the subsurface;

     (iv) Results from monitoring zone leak detection;

     (v) Results from any other tests/work completed during the reporting period, such as mechanical integrity tests, geophysical surveys, acoustic monitoring, well repairs, etc.

     (g) Annual reports shall be submitted to the department that include:

     (i) A summary of the data collected throughout the year, including any trends, observations, predictions as well as calculated spatial distribution of injected CO₂;

     (ii) List of all noncompliance with the permit along with an explanation of the cause(s) and subsequent remedial measures taken;

     (iii) Updated modeling based on the monitoring observations and measurements including a summary of calculated spatial distribution of CO₂ and all other conditions in the subsurface necessary to establish the effectiveness of the geologic containment system, as well as a discussion of history matching and an assessment of the model's accuracy to date. Updated projections of project response and capacity based on operational experience, including all new geologic data and information;

     (iv) Observed anomalies from predicted behavior shall be identified and explained;

     (v) Discussion of suggested changes in project management or suggested amendment of permit conditions;

     (vi) A report on the financial assurance account which includes updated calculation of cost estimates for all closure and post closure activities and documentation that the account is adequately funded to cover the calculated cost.

     (5) Closure. If all of the project's carbon dioxide injections are interrupted for a period of one hundred eighty consecutive days, the operator shall begin implementing the approved closure plan. Injection project management may include injection and resting periods possibly exceeding one hundred eighty days for individual injection wells. The closure triggers are for the entire injection facility not individual wells. The department may extend this one hundred eighty day period, in writing, upon the request of the operator, if the operator demonstrates that carbon dioxide injection will resume within a period of not more than two years. The operator shall review and amend the closure plan as needed, at a minimum the plan shall be reviewed at each permit renewal. Proposed amendments shall be effective only after approved in writing by the department. Approval of proposed amendments shall not delay the commencement of closure activities using the most recent approved closure plan. If the operator fails to begin closure, or is not able to begin closure, the department shall use the financial assurance account to begin closure activities.

     (6) Post-closure activities. The operator is obligated to renew and be covered under permit and pay all appropriate permit fees throughout the post-closure period. The operator shall continue all required monitoring and reporting throughout the closure and post-closure period. The operator shall review and amend the post-closure plan as needed, at a minimum the plan shall be reviewed at each permit renewal. The post-closure period shall continue until the department determines that modeling and monitoring demonstrate that conditions in the geologic containment system indicate that there is little or no risk of future environmental impacts and there is high confidence in the effectiveness of the containment system and related trapping mechanisms. The post-closure period shall be complete only after the operator has received written approval from the department. If the operator fails to or is not able to continue the post-closure activities as required, the department shall use the financial assurance account to complete post-closure activities. Any funds remaining in the financial assurance account shall be released to the operator upon the department's approval of the completion of the post-closure period.

     (7) Financial assurance.

     (a) The owner or operator shall establish a closure and post-closure account to cover all closure and post-closure expenses. The performance security held in the account may be:

     (i) Bank letters of credit;

     (ii) Cash deposits;

     (iii) Negotiable securities;

     (iv) An assignment of savings account;

     (v) A savings certificate in a Washington bank; or

     (vi) A corporate surety bond executed in favor of the department by a corporation authorized to do business in the state of Washington.

     (b) The department may for any reason refuse any performance security not deemed adequate.

     (c) The cost of the closure and post-closure activities shall be calculated using current cost of hiring a third party to close all existing facilities and to provide post-closure care, including monitoring identified in the closure and post-closure plan.

     (d) The closure and post-closure cost estimate shall be revised annually to include any changes in the facility and to include cost changes due to inflation.

     (e) The obligation to maintain the account for closure and post-closure care survives the termination of any permits and the cessation of injection. The requirement to maintain the closure and post-closure account is enforceable regardless of whether the requirement is a specific condition of the permit.

     (8) Mitigation and remediation. Each project must develop a mitigation and remediation plan that identifies trigger thresholds and corrective actions to be taken if the containment system fails, if water quality outside the geologic containment system is degraded, if carbon dioxide is released to the atmosphere or if any other factor poses an unacceptable risk to public health or the environment. A mitigation and remediation plan must be approved by the department before injection begins and amended as needed. The operator shall review and amend the mitigation and remediation plan as needed, at a minimum the plan shall be thoroughly reviewed at each permit renewal. The mitigation and remediation plan shall:

     (a) Define leakage (i.e., trigger threshold), leak detection and identification;

     (b) Address caprock and spill-point leaks;

     (c) Address well bore leaks from project wells or previously unidentified wells;

     (d) Identify immediate responses to protect public health, safety and the environment;

     (e) Provide a detailed list of notifications and surveys;

     (f) Address remedial measures such as: Well repairs, reduced injection pressure, reservoir or formation pressure, creation of a pressure barrier through increased pressure above geologic containment system, interception, recovery and reinjection of CO₂ or the removal of injected materials;

     (g) Address redefining the geologic containment system or closure and abandonment of the sequestration project.

[]

OTS-1278.2

[]

CARBON DIOXIDE MITIGATION FOR FOSSIL-FUELED THERMAL ELECTRIC GENERATING FACILITIES, IMPLEMENTING CHAPTER 80.70 RCW
AMENDATORY SECTION(Amending Order 03-09, filed 12/22/04, effective 1/22/05)

WAC 173-407-010   Policy and purpose of Part I.   (1) It is the policy of the state to require mitigation of the emissions of carbon dioxide (CO₂) from all new and certain modified fossil-fueled thermal electric generating facilities with station-generating capability of more than 25 megawatts of electricity (MWe).

     (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.

[Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-010, filed 12/22/04, effective 1/22/05.]

     (((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))) "Independent qualified organization" is an organization identified by the energy facility site evaluation council as meeting the requirements of RCW 80.70.050.

     "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.

[Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-020, filed 12/22/04, effective 1/22/05.]

     (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) ((Modifiying)) Modifying existing fossil-fueled thermal electric generating 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 increase to the facility or units is the greater of the following measures:

     (i) An increase in station-generating capability of more than 25 MWe; or

     (ii) An increase in CO₂ emissions output by 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 or provide hydrogen for use in fuel cells;

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

[Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-030, filed 12/22/04, effective 1/22/05.]

[Statutory Authority: RCW 70.94.181, [70.94.]152, [70.94.]331, [70.94.]650, [70.94.]745, [70.94.]892, [70.94.]011. 07-19-005 (Order 07-10), § 173-407-040, filed 9/6/07, effective 10/7/07. Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-040, filed 12/22/04, effective 1/22/05.]

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

where:

CO2rate	=	Maximum potential emissions in metric tons per year
F1 -n	=	Maximum design fuel firing rate in MMBtu/hour calculated as manufacturer((/)) or designer's guaranteed total net station generating capability in MWe times the new equipment heat rate in Btu/MWe. Determined based on higher heating values of fuel
K1 -n	=	Conversion factor for the fuel(s) being evaluated in lb CO2/((mmBtu)) 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, at higher heating value of the fuel
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 (derived from the EPA's AP-42, Compilation of Air Pollutant ((Emmission)) Emission Factors):

Fuel	Kn lb/MMBtu
#2 oil	158.16
#4 oil	160.96
#6 oil	166.67
Lignite	((328.57)) 287.50
Sub-bituminous coal	((282.94)) 267.22
Bituminous coal, low volatility	((312.50)) 232.21
Bituminous coal, medium volatility	((274.55)) 241.60
Bituminous coal, high volatility	((306.11)) 262.38
Natural gas	117.6
Propane	136.61
Butane	139.38
Petroleum coke	242.91
Coal coke	243.1
Other ((fossil-fuels)) fossil fuels	Calculate based on carbon content of the fossil fuel and application of the gross heat content (higher heating value) of the fuel
((Nonfossil-fuels)) Nonfossil fuels	00.00

     (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	x (Ka) ÷ ((.35)) n
		2204.6

where:

((Where cogeneration credit)) CO2 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.
n	=	Efficiency of new boiler that would provide the same quantity of thermal energy. Assume n = 0.85 unless applicant provides information supporting a different value.

Calculate the metric tons of the cogeneration credit over the thirty-year period.

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

where:

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_2rate) is the difference between the premodification condition and the postmodification condition, but using the like new heat rate for the combustion equipment((.)); and

     (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.))

[Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-050, filed 12/22/04, effective 1/22/05.]

     (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)) are 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 direct investment cost of the applicant controlled mitigation project including funds used for selection, monitoring, and evaluation of mitigation projects cannot be required by ecology or the local authority to exceed the cost of making a lump sum payment to a third party per WAC 173-407-060(3).

     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)) (d) The 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)))

[Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-060, filed 12/22/04, effective 1/22/05.]

     (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.

[Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-070, filed 12/22/04, effective 1/22/05.]

[Statutory Authority: RCW 70.94.892 and chapter 80.70 RCW. 05-01-237 (Order 03-09), § 173-407-080, filed 12/22/04, effective 1/22/05.]

GREENHOUSE GASES EMISSIONS PERFORMANCE STANDARD AND SEQUESTRATION PLANS AND PROGRAMS FOR BASELOAD ELECTRIC GENERATION FACILITIES IMPLEMENTING CHAPTER 80.80 RCW
NEW SECTION
WAC 173-407-100   Policy and purpose of Part II.   It is the intent of the legislature, under chapter 80.80 RCW, to establish statutory goals for the statewide reduction in greenhouse gases emissions. The legislature further intends by chapter 80.80 RCW to authorize immediate actions in the electric power generation sector for the reduction of greenhouse gases emissions.

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     "Average available greenhouse gases emissions output" means the level of greenhouse gases emissions as surveyed and determined by the energy policy division of the department of community, trade, and economic development under RCW 80.80.050.

     "Baseload electric generation" means electric generation from a power plant that is designed and intended to provide electricity at an annualized plant capacity factor of at least sixty percent. For a cogeneration facility, the sixty percent annual capacity factor applies to only the electrical production intended to be supplied for sale.

     "Baseload electric cogeneration facility" means a cogeneration facility that provides baseload electric generation.

     "Baseload electric generation facility" means the power plant that provides baseload electric generation.

     "Benchmark" means a planned quantity of the greenhouse gases to be sequestered each calendar year at a sequestration facility as identified in the sequestration plan or sequestration program.

     "Bottoming-cycle cogeneration facility" means a cogeneration facility in which the energy input to the system is first applied to a useful thermal energy application or process, and at least some of the reject heat emerging from the application or process is then used for electrical power production.

     "Change in ownership" as related to cogeneration plants means a new ownership interest in the electric generation portion of the cogeneration facility or unit.

     "Cogeneration facility" means a 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 (16 U.S.C. Sec. 824a-3), as amended. In general, a cogeneration facility is comprised of equipment and processes which through the sequential use of energy are used to produce electric energy and useful thermal energy (such as heat or steam) that is used for industrial, commercial, heating, or cooling purposes.

     "Combined-cycle natural gas thermal electric generation facility" means a power plant that employs a combination of one or more gas turbines and steam turbines in which electricity is produced in the steam turbine from otherwise lost waste heat exiting from one or more of the gas turbines.

     "Commence commercial operation" means, in regard to a unit serving an electric generator, to have begun to produce steam or other heated medium, or a combustible gas used to generate electricity for sale or use, including test generation.

     "Commission" means the Washington utilities and transportation commission.

     "Consumer-owned utility" means a municipal utility formed under Title 35 RCW, a public utility district formed under Title 54 RCW, an irrigation district formed under chapter 87.03 RCW, a cooperative formed under chapter 23.86 RCW, a mutual corporation or association formed under chapter 24.06 RCW, or port district within which an industrial district has been established as authorized by Title 53 RCW, that is engaged in the business of distributing electricity to more than one retail electric customer in the state.

     "Department" or "ecology" means the department of ecology.

     "Electric generating unit" is the equipment required to convert the thermal energy in a fuel into electricity. In the case of a steam electric generation unit, it is comprised of all equipment from fuel delivery to the plant site through an individual boiler, any installed emission control equipment, and ending with the generation of electricity in a dedicated steam turbine/generator. Where a steam turbine generator is supplied by two or more boiler units, all boilers contributing to that steam turbine/generator comprise a single electric generating unit. All combustion units/boilers/combined cycle turbines that produce steam for use in a single steam turbine/generator unit are part of the same electric generating unit.

     Examples:

     (a) For an integrated gasification combined cycle combustion turbine plant, it is comprised of all equipment from fuel delivery to the unit through the combustion processes, any installed emission control equipment, and ending with the generation of electricity.

     (b) For a combined cycle natural gas fired combustion turbine, it is the point where natural gas is delivered to the plant site and ends with the generation of electricity from the combustion turbine and from steam produced and used on a steam turbine.

     (c) Fuel cells fueled by hydrogen produced in a reformer utilizing nonrenewable fuels or by a gasifier producing hydrogen from nonrenewable fuels.

     "Electricity from unspecified sources" means electricity to be delivered pursuant to a long-term financial commitment whose sources or origins of generation and expected average annual deliveries of electricity cannot be ascertained with reasonable certainty.

     "EFSEC" means the energy facility site evaluation council.

     "Electric utility" means an electrical company or a consumer-owned utility.

     "Electrical company" means a company owned by investors that meets the definition of RCW 80.04.010.

     "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.

     "Governing board" means the board of directors or legislative authority of a consumer-owned utility.

     "Greenhouse gases" includes carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.

     "Long-term financial commitment" means:

     (a) Either a new ownership interest in baseload electric generation or an upgrade to a baseload electric generation facility; or

     (b) A new or renewed contract for baseload electric generation with a term of five or more years for the provision of retail power or wholesale power to end-use customers in this state.

     "MWh" means megawatt-hour electricity.

     "MWh_eq" means megawatt-hour equivalent electrical energy of useful thermal energy output. 1 MWh_eq = 3.413 million Btu of thermal energy.

     "New ownership interest" means a change in the ownership structure of a baseload power plant or a cogeneration facility or the electrical generation portion of a cogeneration facility affecting at least:

     (a) Five percent of the market value of the power plant or cogeneration facility; or

     (b) Five percent of the electrical output of the power plant or cogeneration facility.

     The above thresholds apply to each unit within a multi-unit generation facility.

     "Permanent sequestration" means the retention of greenhouse gases in a containment system using a method and in accordance with standards approved by the department that creates a high degree of confidence that substantially ninety-nine percent of the greenhouse gases will remain contained for at least one thousand years.

     "Plant capacity factor" means the ratio of the electricity produced during a given time period, measured in kilowatt-hours, to the electricity the unit could have produced if it had been operated at its rated capacity during that period, expressed in kilowatt-hours.

     "Power plant" means a facility for the generation of electricity that is permitted as a single plant by the energy facility site evaluation council or a local jurisdiction. A power plant may be comprised of one or more individual electrical generating units, each unit of which can be operated or owned separately from the other units.

     "Regulated greenhouse gases emissions" is the mass of carbon dioxide emitted plus the mass of nitrous oxide emitted plus the mass of methane emitted. Regulated greenhouse gases emissions include carbon dioxide produced by a sulfur dioxide control system such as a wet limestone scrubber system.

     "Renewable fuel" means:

     (a) Landfill gas;

     (b) Biomass energy utilizing animal waste, solid organic fuels from wood, forest, or field residues or dedicated energy crops that do not include wood pieces that have been treated with chemical preservatives such as creosote, pentachlorophenol, or copper-chrome-arsenic;

     (c) By-products of pulping or wood manufacturing processes, including but not limited to bark, wood chips, sawdust, and lignin in spent pulping liquors; or

     (d) Gas from sewage treatment facilities.

     "Renewable resources" means a renewable fuel plus electricity generation facilities fueled by:

     (a) Water;

     (b) Wind;

     (c) Solar energy;

     (d) Geothermal energy; or

     (e) Ocean thermal, wave, or tidal power.

     "Sequential use of energy" means:

     (a) For a topping-cycle cogeneration facility, the use of reject heat from a power production process in sufficient amounts in a thermal application or process to conform to the requirements of the operating standard; or

     (b) For a bottoming-cycle cogeneration facility, the use of reject heat from a thermal application or process, at least some of which is then used for power production.

     "Sequestration plan" means a comprehensive plan describing how a plant owner or operator will comply with the emissions performance standard by means of sequestering greenhouse gases, where the sequestration will start after electricity is first produced, but within five years of the start of commercial operation.

     "Sequestration program" means a comprehensive plan describing how a baseload electric generation plant's owner or operator will demonstrate compliance with the emissions performance standard at start of commercial operation and continuing unchanged into the future. The program plan is a description of how the facility meets the emissions performance standard based on the characteristics of the baseload electric generation facility or unit or by sequestering greenhouse gases emissions to meet the emissions performance standard with the sequestration starting on or before the start of commercial operation.

     "Supplementary firing" means an energy input to:

     (a) A cogeneration facility used only in the thermal process of a topping-cycle cogeneration facility;

     (b) The electric generating process of a bottoming-cycle cogeneration facility; or

     (c) Any baseload electric generation unit to temporarily increase the thermal energy that can be converted to electrical energy.

     "Topping-cycle cogeneration facility" means a cogeneration facility in which the energy input to the facility is first used to produce useful electrical power output, and at least some of the reject heat from the power production process is then used to provide useful thermal energy.

     "Total energy input" means the total energy supplied by all fuels used to produce electricity in a baseload electric generation facility or unit.

     "Total energy output" of a topping cycle cogeneration facility or unit is the sum of the useful electrical power output and useful thermal energy output.

     "Upgrade" means any modification made for the primary purpose of increasing the electric generation capacity of a baseload electric generation facility or unit. Upgrade includes the installation, replacement or modification of equipment that increases the heat input or fuel usage as specified in existing generation air quality permits in effect as of July 22, 2007. Upgrade does not include:

     (a) Routine or necessary maintenance;

     (b) Installation of emission control equipment;

     (c) Installation, replacement, or modification of equipment that improves the heat rate of the facility; or

     (d) Installation, replacement, or modification of equipment for the primary purpose of maintaining reliable generation output capability that does not increase the heat input or fuel usage as specified in existing generation air quality permits as of July 22, 2007, but may result in incidental increases in generation capacity.

     "Useful energy output" of a cogeneration facility means the electric or mechanical energy made available for use, exclusive of any such energy used in the power production process.

     "Useful thermal energy output" of a cogeneration facility means the thermal energy:

     (a) That is made available to and used in an industrial or commercial process (net of any heat contained in condensate return and/or makeup water);

     (b) That is used in a heating application (e.g., space heating, domestic hot water heating); or

     (c) That is used in a space cooling application (i.e., thermal energy used by an absorption chiller).

     "Waste gas" is refinery gas and other fossil fuel derived gases with a heat content of more than 300 Btu/standard cubic foot. Waste gas does not include gaseous renewable energy sources.

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     (a) Are new and are permitted for construction and operation after June 30, 2008, that utilize fossil fuel or nonrenewable fuels for all or part of their fuel requirements.

     (b) Are existing and that commence operation on or before June 30, 2008, when the facility or unit's owner or operator engages in an action listed in subsection (3) or (4) of this section.

     (2) This rule is not applicable to any baseload electric generation facility or unit or cogeneration facility or unit that is designed and intended to utilize a renewable fuel to provide at least ninety percent of its total annual heat input.

     (3) A baseload electric generation facility or an individual electric generating unit at a baseload electric generation facility is required to meet the emissions performance standard in effect when:

     (a) The new baseload electric generation facility or new electric generating unit at an existing baseload electric generation facility is issued a notice of construction approval or a site certification agreement;

     (b) The existing facility or a unit is upgraded; or

     (c) The existing facility or a unit is subject to a new long-term financial commitment.

     (4) A baseload electric cogeneration facility or unit is required to meet the emissions performance standard in effect when:

     (a) The new baseload electric cogeneration facility or new cogeneration unit is issued a notice of construction approval or a site certification agreement;

     (b) The existing facility or unit is upgraded; or

     (c) The existing facility or unit is subject to a change in ownership.

     (5) A new baseload electric generation or cogeneration facility becomes an existing baseload electric generation or cogeneration facility the day it commences commercial operation.

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     (2) All baseload electric generation facilities and units in operation on or before June 30, 2008, are deemed to be in compliance with the emissions performance standard until the facility or unit is subject to a new long-term financial commitment.

     (3) All baseload electric cogeneration facilities and units in operation on or before June 30, 2008, and operating exclusively on natural gas, waste gas, a combination of natural and waste gases, or a renewable fuel, are deemed to be in compliance with the emissions performance standard until the facility or unit is subject to a new ownership interest or is upgraded.

     (4) Compliance with the emissions performance standard may be through:

     (a) Use of fuels and power plant designs that comply with the emissions performance standard without need for greenhouse gases emission controls; or

     (b) Use of greenhouse gases emission controls and greenhouse gases sequestration methods meeting the requirements of WAC 173-407-220 or 173-218-115 as appropriate.

     (5) The greenhouse gases emissions performance standard in subsection (1) of this section applies to all baseload electric generation for which electric utilities enter into long-term financial commitments on or after July 1, 2008.

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     (a) Fuels and fuel feed stocks.

     (i) All fuels and fuel feed stocks used to provide energy input to the baseload electric generation facility or unit.

     (ii) Fuel usage and heat content is to be monitored, and reported as directed by WAC 173-407-230.

     (b) Electrical output in MWh as measured and recorded per WAC 173-407-230.

     (c) Regulated greenhouse gases emissions from the baseload electric generation facility or unit as monitored, reported and calculated in WAC 173-407-230.

     (d) The owner or operator of a baseload electric generation facility or unit may adjust its greenhouse gases emissions to account for the usage of renewable resources. If the owner or operator of a baseload electric generation facility or unit adjusts its greenhouse gases emissions to account for the use of renewable resources, greenhouse gases emissions are reduced based on the ratio of the annual heat input from all fuels and fuel feed stocks and the annual heat input from use of nonrenewable fuels and fuel feed stocks. Such adjustment will be based on records of fuel usage and representative heat contents approved by ecology.

     (2) By January 31 of each year, the owner or operator of each baseload electric generation facility or unit subject to the monitoring and compliance demonstration requirements of this rule will:

     (a) Calculate the pounds of regulated greenhouse gases emissions emitted per MWh of electricity produced during the prior calendar year by dividing the regulated greenhouse gases emissions by the total MWh produced in that year; and

     (b) Submit that calculation and all supporting information to ecology.

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     (2) The owner or operator of a baseload electric cogeneration facility or unit that must demonstrate compliance with the emissions performance standard in WAC 173-407-130(1) shall demonstrate compliance annually, using the data identified below:

     (a) Fuels and fuel feed stocks.

     (i) All fuels and fuel feed stocks used to provide energy input to the baseload electric cogeneration facility or unit.

     (ii) Fuel and fuel feed stocks usage and heat content is to be monitored, and reported as directed by WAC 173-407-230.

     (b) Electrical output will be the electrical output measured in MWh as directed by WAC 173-407-230.

     (c) All useful thermal energy and useful energy used for nonelectrical generation uses will be converted to units of megawatts energy equivalent (MWeq) using the conversion factor of 3.413 million British thermal units per megawatt hour (MMBtu/MWh).

     (d) Regulated greenhouse gases emissions from the baseload electric cogeneration facility or unit as monitored, reported and calculated in WAC 173-407-230.

     (e) The owner or operator of a baseload electric cogeneration facility or unit may adjust its greenhouse gases emissions to account for the usage of renewable resources. If the owner or operator of a baseload electric cogeneration facility adjusts its greenhouse gases emissions to account for the use of renewable resources, the greenhouse gases emissions are reduced based on the ratio of the annual heat input from all fuels and fuel feed stocks and the annual heat input from use of nonrenewable fuels and fuel feed stocks. Such adjustment will be based on records of fuel usage and representative heat contents approved by ecology.

     (3) Bottoming-cycle cogeneration facilities. The formula to determine compliance of a bottoming-cycle cogeneration facility or unit with the emissions performance standard will be jointly developed by ecology and the facility. To the extent possible, the facility specific formula must be based on the one for topping-cycle facilities identifying the amount of energy converted to electricity, thermal losses, and energy from the original fuel(s) used to provide useful thermal energy in the industrial process. The formula should be specific to the installed equipment, other thermal energy uses in the facility, and specific operating conditions of the facility.

     (4) Topping-cycle cogeneration facilities. Compliance of a topping-cycle facility or unit with the emissions performance standard will be as follows:

     (a) Determine annual electricity produced in MWh.

     (b) Determine the annual electrical energy equivalent of the useful thermal energy output in MWh_eq.

     (c) Determine the annual regulated greenhouse gases emissions produced in pounds.

     (5) By January 31 of each year, the owner or operator of each baseload electric cogeneration facility or unit subject to the monitoring and compliance demonstration requirements of this rule will:

     (a) Calculate the pounds of regulated greenhouse gases emissions emitted per MWh of electricity produced during the prior calendar year by dividing the regulated greenhouse gases emissions by the sum of the MWh and MWh_eq produced in that year; and

     (b) Submit that calculation and all supporting information to ecology.

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     (a) A site certification application is submitted to EFSEC for a new baseload electric generation facility or baseload electric cogeneration facility or new unit at an existing baseload electric generation or cogeneration facility;

     (b) A site certification application is submitted to EFSEC for an upgrade to an existing baseload electric generation facility or unit or baseload electric cogeneration facility or unit that has a site certificate and the upgrade is not an exempt upgrade;

     (c) A notice of construction application is submitted to ecology or a local authority for a new baseload electric generation facility or baseload electric cogeneration facility or unit at a baseload electric generation or cogeneration facility;

     (d) A notice of construction application is submitted to ecology or a local authority for an upgrade to an existing baseload electric generation facility or unit or an existing baseload electric cogeneration facility or unit and the upgrade is not an exempt upgrade;

     (e) A baseload electric generation facility or unit or baseload cogeneration facility or unit enters a new long-term financial commitment with an electric utility to provide baseload power and the facility or unit does not comply with the emissions performance standard in effect at the time the new long-term financial commitment occurs; or

     (f) A qualifying ownership interest change occurs and the facility or unit does not comply with the emissions performance standard in effect at the time the change in ownership occurs.

     (2) A sequestration program is required to be submitted when:

     (a) A site certification application is submitted to EFSEC for new baseload electric generation facility or unit or baseload electric cogeneration facility or unit;

     (b) A site certification application is submitted to EFSEC for an upgrade to an existing baseload electric generation facility or unit or baseload electric cogeneration facility or unit that has a site certificate and the upgrade is not an exempt upgrade;

     (c) A notice of construction application is submitted to ecology or a local authority for a new baseload electric generation facility or unit or baseload electric cogeneration facility or unit;

     (d) A notice of construction application is submitted to ecology or a local authority for an upgrade to an existing baseload electric generation facility or unit or baseload electric cogeneration facility or unit and the upgrade is not an exempt upgrade;

     (e) A baseload electric generation facility or unit or baseload electric cogeneration facility or unit enters a new long-term financial commitment with an electric utility to provide baseload power if the facility or unit does not comply with the emissions performance standard in effect at the time the new long-term financial commitment occurs; or

     (f) A qualifying ownership interest change occurs and the facility does not comply with the emissions performance standard in effect at the time the change in ownership occurs.

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     (1) Sequestration plans must include:

     (a) Financial requirements. Each owner or operator of a baseload electric generation or cogeneration facility or unit utilizing other sequestration as a method to comply with the emissions performance standard in WAC 173-407-130 is required to provide a letter of credit as a condition of plant operation sufficient to ensure successful implementation, closure, and post-closure activities identified in the sequestration plan, including construction and operation of necessary equipment, and any other significant costs.

     (i) The owner or operator of a proposed sequestration project shall establish a letter of credit to cover all expenses for construction and operation of necessary equipment, and any other significant costs. The cost estimate for the sequestration project shall be revised annually to include any changes in the project and to include cost changes due to inflation.

     (ii) Closure and post-closure financial assurances. The owner or operator shall establish a closure and post-closure letter of credit to cover all closure and post-closure expenses. The owner or operator must designate ecology or EFSEC, as appropriate, as the beneficiary to carry out the closure and post-closure activities. The value of the closure and post-closure account shall cover all costs of closure and post-closure care identified in the closure and post-closure plan. The closure and post-closure cost estimate shall be revised annually to include any changes in the sequestration project and to include cost changes due to inflation. The obligation to maintain the account for closure and post-closure care survives the termination of any permits and the cessation of injection. The requirement to maintain the closure and post-closure account is enforceable regardless of whether the requirement is a specific condition of the permit.

     (b) The application for approval of a sequestration plan shall include (but is not limited to) the following:

     (i) A current site map showing the boundaries of the permanent sequestration project containment system(s) and all areas where greenhouse gases will be stored.

     (ii) A technical evaluation of the proposed project, including but not limited to, the following:

     (A) The name of the area in which the sequestration will take place;

     (B) A description of the facilities and place of greenhouse gases containment system;

     (C) A complete site description of the site, including but not limited to the terrain, the geology, the climate (including rain and snowfall expected), any land use restrictions that exist at the time of the application or will be placed upon the site in the future;

     (D) The proposed calculated maximum volume of greenhouse gases to be sequestered and aerial extent of the location where the greenhouse gases will be stored using a method acceptable to and filed with ecology; and

     (E) Evaluation of the quantity of sequestered greenhouse gases that may escape from the containment system at the proposed project.

     (iii) A public safety and emergency response plan for the proposed project. The plan shall detail the safety procedures concerning the sequestration project containment system and residential, commercial, and public land use within one mile, or as necessary to identify potential impacts, of the outside boundary of the project area.

     (iv) A greenhouse gases loss detection and monitoring plan for all parts of the sequestration project. The approved greenhouse gases loss detection and monitoring plan shall address identification of potential release to the atmosphere.

     (v) A detailed schedule of annual benchmarks for sequestration of greenhouse gases.

     (vi) Any other information that the department deems necessary to make its determination.

     (vii) A closure and post-closure plan.

     (c) In order to monitor the effectiveness of the implementation of the sequestration plan, the owner or operator shall submit a detailed monitoring plan that will be able to detect failure of the sequestration method to place the greenhouse gases into a sequestered state. The monitoring plan will be sufficient to detect losses of sequestered greenhouse gases at a level of no greater than twenty percent of the leakage rate allowed in the definition of permanent sequestration. The monitoring shall continue for the longer of twenty years beyond either the end of placement of the greenhouse gases into a sequestration containment system, or the date upon which it is determined that all of the greenhouse gases has achieved a state at which it is now stably sequestered in that environment.

     (d) If the sequestration plan fails to sequester greenhouse gases as provided in the plan, the owner or operator of the baseload electric generation or cogeneration facility or unit is no longer in compliance with the emissions performance standard.

     (2) Public notice and comment. Ecology must provide public notice and a public comment period before approving or denying any sequestration plan or program plan.

     (a) Public notice. Public notice shall be made only after all information required by the permitting authority has been submitted and after applicable preliminary determinations, if any, have been made. The applicant or other initiator of the action must pay the cost of providing public notice. Public notice shall include analyses of the effects on the local, state and global environment in the case of failure of the sequestration plan or program plan. The plan must be available for public inspection in at least one location near the proposed project.

     (b) Public comment.

     (i) The public comment period must be at least thirty days long or as specified in the public notice.

     (ii) The public comment period must extend through the hearing date.

     (iii) Ecology shall make no final decision on any sequestration plan or sequestration program until the public comment period has ended and any comments received during the public comment period have been considered.

     (c) Public hearings.

     (i) Ecology will hold a public hearing within the thirty-day public comment period. Ecology will determine the location, date, and time of the public hearing.

     (ii) Ecology must provide at least thirty days prior notice of a hearing on a sequestration plan or sequestration program.

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     (a) Electrical output: Electrical output as measured at the point of connection with the local electrical distribution network or transmission line, as appropriate. Measurement will be on an hourly or daily basis and recorded in a form suitable for use in calculating compliance with the greenhouse gases emissions performance standard;

     (b) Useful thermal energy output: Determine quantity of energy supplied to nonelectrical production uses through monitoring of both the energy supplied and unused energy returned by the thermal energy user or uses. This can be accomplished through:

     (i) Measurement of the supply and return streams of the mass pressure and temperature of the steam or thermal fluid.

     (ii) Use of thermodynamic calculations as approved by ecology.

     (iii) Measurements will be on an hourly or daily basis and recorded in a form suitable for use in calculating compliance with the greenhouse gases emissions performance standard;

     (c) Regulated greenhouse gases emissions.

     (i) The regulated greenhouse gases emissions are the emissions from the main plant exhaust stack and any bypass stacks or flares. For baseload electric generation and cogeneration facilities or units utilizing CO₂ controls and sequestration to comply with the greenhouse gases emissions performance standard, direct and fugitive CO₂ emissions from the CO₂ separation and compression process are included.

     (ii) Carbon dioxide (CO₂).

     (A) For baseload electric generation and cogeneration facilities or units subject to WAC 173-407-120, producing 25 MW or more of electricity, CO₂ emissions will be monitored by a continuous emission monitoring system meeting the requirements of 40 CFR Part 75.10, 75.13 and Appendix F. If allowed by the requirements of 40 CFR Part 72, a facility may estimate CO₂ emissions through fuel carbon content monitoring and methods meeting the requirements of 40 CFR Part 75.10, 75.13 and Appendix G.

     (B) For baseload electric generation and cogeneration facilities or units subject to WAC 173-407-120 producing less than 25 MW of electricity, the owner or operator may either utilize a continuous emission monitoring system meeting the requirements of 40 CFR Part 75.10, 75.13 and Appendix F, or through fuel carbon content monitoring and methods meeting the requirements of 40 CFR Part 75.10, 75.13 and Appendix G.

     (C) When the monitoring data from a continuous emission monitoring system does not meet the completeness requirements of 40 CFR 75, the baseload electric generation facility operator or operator will substitute data according to the process in 40 CFR Part 75.

     (D) Continuous emission monitors for CO₂ will be installed at a location meeting the requirements of 40 CFR Part 75, Appendix A. The CO₂ and flow monitoring equipment must meet the quality control and quality assurance requirements of 40 CFR Part 75, Appendix B.

     (iii) Nitrous oxide (N₂O).

     (A) For baseload electric generation or cogeneration facilities or units subject to WAC 173-407-120 producing 25 MW or more of electricity.

     (I) For the first year of operation, N₂O emissions are estimated by use of emission factors as published by the Environmental Protection Agency, the federal Department of Energy's Energy Information Agency, or other authoritative source as approved by ecology for use by the facility.

     (II) For succeeding years, N₂O emissions will be estimated through use of generating unit specific emission factors derived through use of emissions testing using ecology or Environmental Protection Agency approved methods. The emission factor shall be derived through testing at varying loads and through at least four separate test periods spaced evenly throughout the first year of commercial operation.

     (B) For baseload electric generation or cogeneration facilities or units subject to WAC 173-407-120 producing less than 25 MW of electricity, the annual N₂O emissions will be estimated by use of emission factors as published by the Environmental Protection Agency, the federal Department of Energy's Energy Information Agency, or other authoritative source as approved by ecology for use by the facility.

     (iv) Methane (CH₄).

     (A) For baseload electric generation or cogeneration facilities or units subject to WAC 173-407-120 producing 25 MW or more of electricity.

     (I) For the first year of operation, CH₄ emissions are estimated by use of emission factors as published by the Environmental Protection Agency, the federal Department of Energy's Energy Information Agency, or other authoritative source as approved by ecology for use by the facility.

     (II) For succeeding years, CH₄ emissions will be estimated through use of plant specific emission factors derived through use of emissions testing using ecology or Environmental Protection Agency approved methods. The emission factor shall be derived through testing at varying loads and through at least four separate test periods spaced evenly through the first year of commercial operation.

     (B) For baseload electric generation or cogeneration facilities or units subject to WAC 173-407-120 producing less than 25 MW of electricity. The annual CH₄ emissions will be estimated by use of emission factors as published by the Environmental Protection Agency, the federal Department of Energy's Energy Information Agency, or other authoritative source as approved by ecology for use by the facility;

     (d) Fuel usage and heat content information.

     (i) Fossil fuel usage will be monitored by continuous fuel volume or weight measurement as appropriate for the fuel used. Measurement will be on an hourly or daily basis and recorded in a form suitable for use in calculating greenhouse gases emissions.

     (ii) Renewable energy fuel usage will be monitored by continuous fuel volume or weight measurement as appropriate for the fuel used. Measurement will be on an hourly or daily basis and recorded in a form suitable for use in calculating greenhouse gases emissions.

     (iii) Heat content of fossil fuels shall be tested at least once per calendar year. The owner or operator of the baseload electric generation facility or unit shall submit a proposed fuel content monitoring program to ecology for its approval. Upon request and submission of appropriate documentation of fuel heat content variability, ecology may allow a source to:

     (A) Test the heat content of the fossil fuel less often than once per year; or

     (B) Utilize representative heat content for the renewable energy source instead of the periodic monitoring of heat content required above.

     (iv) Renewable energy fuel heat content will be tested monthly or on a different frequency approved by ecology. A different frequency will be based on the variability of the heat content of the renewable energy fuel.

     (A) If the baseload electric generation or cogeneration facilities or units subject to WAC 173-407-120 using a mixture of renewable and fossil fuels does not adjust its greenhouse gases emissions by the heat input from the renewable energy fuels, the monitoring of the heat content of the renewable energy fuels is not required.

     (B) Upon request and with appropriate documentation, ecology may allow a source to utilize representative heat content for the renewable energy source instead of the periodic monitoring of heat content required above.

     (2) Reporting requirements. The results of the monitoring required by this section shall be reported to ecology and the permitting authority annually.

     (a) Facilities or units subject to the reporting requirements of 40 CFR Part 75. Annual emissions of CO₂, N₂O and CH₄ will be reported to ecology and the air quality permitting authority with jurisdiction over the facility by January 31 of each calendar year for emissions that occurred in the previous calendar year. The report may be an Excel™ or CSV format copy of the report submitted to EPA with the emissions for N₂O and CH₄ appended to the report.

     (b) For facilities or units not subject to the reporting requirements of 40 CFR Part 75. Annual emissions of CO₂, N₂O and CH₄ and supporting information will be reported to ecology and the air quality permitting authority with jurisdiction over the facility by January 31 of each calendar year for emissions that occurred in the previous calendar year.

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     These penalties can include:

     (a) Financial penalties shall be assessed after any year of failure to meet a sequestration benchmark established in the sequestration plan or sequestration program. Each pound of greenhouse gases above the emissions performance standard will constitute a separate violation, as averaged on an annual basis;

     (b) Revocation of approval to construct the source or to operate the source.

     (2) If a new, modified or upgraded baseload electric generation or cogeneration facility or unit fails to meet a sequestration plan or sequestration program benchmark on schedule, a revised sequestration plan or sequestration program will be required to be submitted no later than one hundred fifty calendar days after the due date established under subsection (3)(c) of this section for reporting the failure. The revised sequestration plan or sequestration program is to be submitted to ecology or EFSEC, as appropriate, for approval.

     (3) Provisions for unavoidable circumstances.

     (a) The owner or operator of a facility operated under an approved sequestration plan or sequestration program shall have the burden of proving to ecology, EFSEC, or the decision-making authority in an enforcement action that failure to meet a sequestration benchmark was unavoidable. This demonstration shall be a condition to obtaining relief under (d), (e), and (f) of this subsection.

     (b) Failure to meet a sequestration benchmark determined to be unavoidable under the procedures and criteria in this section shall be excused and not subject to financial penalty.

     (c) Failure to meet a sequestration benchmark shall be reported by January 31 of the year following the year during which the event occurred or as part of the routine sequestration monitoring reports. Upon request by ecology, the owner(s) or operator(s) of the sequestration project source(s) shall submit a full written report including the known causes, the corrective actions taken, and the preventive measures to be taken to minimize or eliminate the chance of recurrence.

     (d) Failure to meet a sequestration benchmark due to startup or shutdown conditions shall be considered unavoidable provided the source reports as required under (c) of this subsection, and adequately demonstrates that the failure to meet a sequestration benchmark could not have been prevented through careful planning and design and if a bypass of equipment occurs, that such bypass is necessary to prevent loss of life, personal injury, or severe property damage.

     (e) Maintenance. Failure to meet a sequestration benchmark due to scheduled maintenance shall be considered unavoidable if the source reports as required under (c) of this subsection, and adequately demonstrates that the excess emissions could not have been avoided through reasonable design, better scheduling for maintenance or through better operation and maintenance practices.

     (f) Failure to meet a sequestration benchmark due to upsets shall be considered unavoidable provided the source reports as required under (c) of this subsection, and adequately demonstrates that:

     (i) The event was not caused by poor or inadequate design, operation, maintenance, or any other reasonably preventable condition;

     (ii) The event was not of a recurring pattern indicative of inadequate design, operation, or maintenance; and

     (iii) The operator took immediate and appropriate corrective action in a manner consistent with good practice for minimizing nonsequestration during the upset event.

     (4) Enforcement for permit violations.

     (a) Enforcement of an ecology or local air agency permitting authority notice of construction will take place under the authority of chapter 70.94 RCW. Enforcement of an ecology approved sequestration plan or sequestration program will be in accordance with this section.

     (b) Enforcement of any part of an EFSEC site certification agreement will proceed in accordance with RCW 80.50.150.

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LONG-TERM FINANCIAL COMMITMENTS; RELATIONSHIP OF ECOLOGY AND THE WUTC; AND RELATIONSHIP OF ECOLOGY AND THE GOVERNING BOARDS OF CONSUMER-OWNED UTILITIES UNDER CHAPTER 80.80 RCW
NEW SECTION
WAC 173-407-300   Procedures for determining the emissions performance standard of a long-term financial commitment and addressing electricity from unspecified sources and specified sources under Part II.   (1) The following procedures are adopted by the department to be utilized by the department under RCW 80.80.060 and to be available to and utilized by the governing boards of consumer-owned utilities pursuant to RCW 80.80.070 when evaluating a potential long-term financial commitment when the long-term financial commitment includes electricity from unspecified sources, electricity from one or more specified sources, and/or provisions to meet load growth with electricity from unspecified and/or specified sources.

     (2) For each year of a long-term financial commitment for electric power, the regulated greenhouse gases emissions from specified and unspecified sources of power are not to exceed the emissions performance standard in WAC 173-407-130(1), in effect on the date the long-term contract is executed. The emissions performance standard for a long-term financial commitment for electricity that includes electricity from specified and unspecified sources is calculated using a time-weighted average of all sources of generation and emissions in the years in which they are contributing electricity and emissions in the commitment. Each source's proportional contribution to emissions per each MWh delivered under the contract is added together and summed for each year and divided by the number of years in the term of the commitment.

     (3) An extension of an existing long-term financial commitment is treated as a new commitment, not an extension of an existing commitment.

     (4) Annual and lifetime calculations of greenhouse gases emissions.

     (a) The time-weighted average emissions shall be calculated, for every year of the contract, using the formula in subsection (5) of this section. The calculation of the pounds of greenhouse gases per megawatt-hour is based upon the delivered electricity, including the portion from specified and unspecified sources, of the total portfolio for the year for which the calculation is being made.

     (b) The average greenhouse gases emissions per MWh of the power supply portfolio over the life of the long-term financial commitment is compared to the emissions performance standard. The calculation of the pounds of greenhouse gases per MWh is based on the expected annual delivery contracted or expected to be supplied by each specified and unspecified source's portion of the total portfolio of electricity to be provided under the contract for the year for which the calculation is being made.

     (c) Default values adopted in this procedure shall be used for each source unless actual emissions are known or specified by the manufacturer. A default greenhouse gases emissions value of an average pulverized coal plant per WAC 173-407-300 (5)(b) shall be used for unspecified sources in the procedure.

     (5) The time-weighted average calculation shall be performed using the regulated greenhouse gases emissions factors as follows:

     (a) For a specified source, utilize the manufacturer's emissions specification or the measured emission rate for a specified generator. When there is no available information on greenhouse gases emissions from a specified source, utilize the following:

     (i) Combined cycle combustion turbines that begin operation after July 1, 2008 = 1,100 lbs/MWh or as updated by rule in 2012 and every five years thereafter.

     (ii) Steam turbines using pulverized coal = 2,600 lbs/MWh minus the amount of greenhouse gases permanently sequestered by the facility on an annual basis divided by the MWhs generated that year.

     (iii) Integrated gasification combined cycle turbines = 1,800 lbs/MWh minus the amount of greenhouse gases permanently sequestered by the facility on an annual basis divided by the MWhs generated that year.

     (iv) Simple cycle combustion turbines = 1,800 lbs/MWh minus the amount of greenhouse gases permanently sequestered by the facility on an annual basis divided by the MWhs generated that year.

     (v) Combined cycle combustion turbines that begin operation before July 1, 2008 = 1,100 lbs/MWh.

     (b) Electricity from unspecified sources = 2,600 lbs/MWh.

     (c) Renewable resources = 0 lbs/MWh.

Example Calculation

EPS

=

(F1MWx T1)

+

(F2MWx T2)

+

(F3MWx T3)

+...

(FnMWx Tn)

Total Hours

where:

EPS	=	Emissions performance standard
F	=	EPS of each type of source expressed as MW
T	=	Percentage of time used for that source
Total Hours	=	Total hours that power was available to customers in the year (8,760 or less)

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     (2) Ecology's consultation with the commission:

     (a) In assisting the commission to apply the emissions verification procedures adopted, ecology will compare the commission's procedures to the ecology procedures found in WAC 173-407-130, 173-407-140, and 173-407-230.

     (b) In consulting with the commission to determine if a long-term financial commitment for baseload electric generation meets the greenhouse gases emissions performance standard, ecology shall consider whether the commitment meets WAC 173-407-300.

     (3) When conducting the consultation and reporting processes, ecology will conclude this process of consultation and assistance within thirty days of receiving all necessary information from the commission to determine compliance.

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     (2) RCW 80.80.070(5) also requires the governing boards of consumer-owned utilities to "apply the procedures adopted by the department to verify the emissions of greenhouse gases from baseload electric generation under RCW 80.80.040, and may request assistance from the department in doing so." The procedures adopted by the department to be utilized by the governing boards are found in WAC 173-407-300. Ecology shall provide consultation or further assistance to the governing boards of a consumer-owned utility to apply such procedures if the governing board makes such a request.

     (3) When consulting or providing assistance under subsections (1) and (2) of this section, ecology will conclude this process of consultation and assistance within thirty days unless the governing board requesting the assistance grants additional time.

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