Background:

State Greenhouse Gas Emissions Reductions.

The state is required to achieve the following statewide Greenhouse Gas (GHG) emission reductions:

by 2020 reduce overall GHG emissions in the state to 1990 levels;
by 2035 reduce overall GHG emissions in the state to 25 percent below 1990 levels; and
by 2050 reduce overall GHG emissions in the state to 50 percent below 1990 levels, or 70 percent below the state's expected GHG emissions that year.

Greenhouse Gas Emissions Performance Standard.

Electric utilities may not enter into a long-term financial commitment for baseload electric generation on or after July 1, 2008, unless the generating plant's emissions are the lower of:

1,100 pounds of GHG per megawatt-hour; or
the average available GHG emissions output as updated by the Department of Commerce.

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 60 percent. Long-term financial commitment means: (1) either a new ownership interest in baseload electric generation or an upgrade to a baseload electric generation facility; or (2) 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.

Executive Order.

In 2009 the Governor issued an executive order directing the Department of Ecology (DOE) to work with the existing coal-fired plant within Washington that burns over one million tons of coal per year to establish an agreed order to apply the Greenhouse Gas Emissions Performance Standard (GHG EPS) to the facility by no later than December 31, 2025. The agreed order must include a schedule of major decision-making and resource investment milestones.

Energy Facility Site Evaluation Council.

The Energy Facility Site Evaluation Council (EFSEC) is the permitting and certificating authority for the siting of major energy facilities in Washington, such as thermal electric power plants 350 megawatts or greater. In addition, energy facilities of any size that exclusively use alternative energy resources (wind, solar, geothermal, landfill gas, wave or tidal action, or biomass energy) can opt-in to the EFSEC process. The EFSEC must generally process an application within 12 months of receipt; however, it can be as short as 180 days under an expedited siting process.

Sales and Use Tax Exemptions for Coal.

Purchases of coal used at a thermal electric generating facility placed in operation after 1969 and before July 1, 1997, are exempt from retail sales and use taxes. The exemptions are contingent upon owners of the plant demonstrating to the DOE that progress is being made to install the necessary air pollution control devices and that the facility has emitted no more than 10,000 tons of sulfur dioxide during the previous 12 months.

Technologies to Control Emissions of Nitrogen Oxides.

Selective Catalytic Reduction (SCR) is a technology for capturing Nitrogen Oxides (NOx) emissions from industrial boilers such as coal fired power plants. It uses a combination of ammonia injection and a catalyst to capture NOx emissions. Selective Noncatalytic Reduction (SNCR) is also a NOx control technology for industrial boilers. It is similar to SCR but only uses injected ammonia without a catalyst. According to the DOE, SCR may capture up to 90 percent of NOx emissions from a large coal-fired plant while SNCR may capture up to 25 percent. While SCR is the most effective technology for capturing NOx emissions, it is substantially more expensive than SNCR.

Utilities and Transportation Commission.

The Utilities and Transportation Commisssion (UTC) is a three-member commission that has broad authority to regulate the rates, services, and practices of investor-owned electric utilities, among other industries. Under general rate-making principles, an electric utility may recover the full cost of a power purchase agreement in rates, with no additional premium, if the contract is approved by the UTC. An electric utility may recover the full cost of an investment in a new generating facility in rates, with an additional return to reflect the risk of the investment, if the investment is approved by the UTC.

Integrated Resource Plan.

All investor-owned and consumer-owned electric utilities in the state with more than 25,000 customers must develop an Integrated Resource Plan (IRP). All other utilities in the state, including those that essentially receive all their power from the Bonneville Power Administration, must file either an IRP or a less detailed resource plan.

An IRP must describe the mix of generating resources and conservation and efficiency resources that will meet current and projected needs at the lowest reasonable cost to the utility and its ratepayers. When determining the lowest reasonable cost for resources identified in its IRP, a utility must provide a detailed and consistent analysis of a wide range of commercially available sources. At a minimum, this analysis must consider resource cost, market volatility risks, demand-side resource uncertainties, resource dispatchability, resource effect on system operation, the risks imposed on ratepayers, public policies regarding resource preference adopted by Washington state or the federal government, and the cost of risks associated with environmental effects including emissions of carbon dioxide.

Carbon Dioxide Mitigation for Fossil-Fueled Energy Facilities.

Under state law, certain fossil-fueled thermal power facilities with a generating capacity of 25 megawatts (MW) or more must mitigate their carbon dioxide (CO2) emissions. The requirement applies to new electric generating facilities seeking site certification from EFSEC or an order of approval under the Washington Clean Air Act. The requirement also applies to existing facilities between 25 and 350 MW that increase their generating capacity by at least 25 MW or their emissions production of CO2 by 15 percent or more.

Mitigation is required for 20 percent of the CO2 emissions produced by a facility over a 30-year period, and must include one or a combination of the following options: (1) payments to an independent qualified organization; (2) direct purchase of permanent carbon credits; or (3) direct investment in CO2 mitigation projects, including qualified alternative energy resources and cogeneration.

Community Economic Revitalization Board.

Comprised of 20 members appointed by the Governor, the Community Economic Revitalization Board (CERB) funds public infrastructure improvements, such as the acquisition, construction, or repair of water and sewer systems, bridges, railroad spurs, telecommunication systems, roads, structures, and port facilities.

Public Works Board.

Comprised of 13 members appointed by the Governor, the Public Works Board (PWB) administers the public works assistance account to provide loans to local governments and special purpose districts with infrastructure projects.

Summary of Amended Bill:

Greenhouse Gas Emissions Performance Standard.

A coal-fired baseload electric generation facility in Washington that has emitted more than one million tons of GHG in any calendar year prior to 2008 must meet the lower of the following emissions standards such that one generating boiler is in compliance by December 31, 2020, and any other generating boiler is in compliance by December 31, 2025:

1,100 pounds of GHG per MW-hour; or
the average available GHG emissions output as updated by the Department of Commerce.

The GHG EPS does not apply to a coal-fired baseload electric generating facility if the DOE determines as a requirement of state or federal law or regulation that selective catalytic reduction technology must be installed on any of its boilers.

Recognition of Coal Transition Power in the GHG EPS and in the UTC Rate Proceedings.

The GHG EPS is amended to allow electric utilities to enter into long-term power purchase agreements for coal transition power. "Power purchase agreement" has the same meaning as "long-term financial commitment" under the state's GHG EPS law. Coal transition power is defined as the output of a coal-fired electric generation facility that is subject to an obligation to meet the GHG EPS.

A process is created to allow an electrical company to petition the UTC for approval of a power purchase agreement for coal transition power and the recovery of related acquisition costs. When a petition is filed, the UTC must provide notice to the public and potentially affected parties and expedite the hearing of that petition. The hearing must be carried out as an adjudicative proceeding under the Administrative Procedures Act. The electrical company must file supporting testimony and exhibits together with the power purchase agreement. Information provided by the facility owner to the purchasing electrical company for evaluating the costs and benefits associated with acquisition of coal transition power must be made available to other parties to the petition under a protective order entered by the UTC.

The UTC must issue a final order that approves or disapproves the agreement within 180 days after a petition is filed. The UTC must approve the power purchase agreement if it determines the resource is needed by the electrical company to serve its ratepayers and the resource meets the need in a cost-effective manner as determined under the lowest reasonable cost resource standards. As part of these determinations, the UTC must consider the long-term economic benefit to the electrical company and its ratepayers of such a long-term purchase.

Upon UTC approval of a power purchase agreement, the electrical company is allowed to earn the equity component of its authorized rate of return in the same manner as if it had purchased or built an equivalent plant and to recover the cost of the coal transition power under the power purchase agreement. Any power purchase agreement that earns a return on equity may not be included in an imputed debt calculation for setting customer rates.

Any power purchase agreement must provide for modification of the agreement to the satisfaction of the parties if a new or revised emission or performance standard or other new or revised operational or financial requirement or limitation directly or indirectly addressing greenhouse gas emissions is imposed by state or federal law, rules, or regulatory requirements. A modification to a power purchase agreement must be reviewed and considered for approval by the UTC. In the event the parties cannot agree to modification of the agreement, either party may terminate the agreement if it is adversely affected by a new standard, requirement, or limitation.

Authorizing recovery of costs under a power purchase agreement does not prohibit the UTC from authorizing recovery of an electrical company's acquisition of capacity resources for the purpose of integrating intermittent power or following load.

The approval of a power purchase agreement for acquisition of coal transition power by the UTC does not establish any precedent for an electrical company to receive an equity return on any other power purchase agreement or other power contract.

Memorandum of Agreement Between the Governor and Owners of Coal-fired Baseload Facilities.

By January 1, 2012, the Governor, on behalf of the state, must enter into a Memorandum of Agreement (MOA) that takes effect on April 1, 2012, with the owners of a coal-fired baseload facility in Washington that emitted more than one million tons of greenhouse gases in calendar year 2005 for achieving the specified GHG emissions reductions. The MOA entered into by the Governor may only contain provisions authorized in this act.

The MOA must incorporate by reference the state's GHG EPS and provisions that allow electric utilities to enter into long-term financial agreements for the purchase of coal transition power, and binding commitments to install SNCR pollution control technology by January 1, 2013. The MOA terminates if the DOE determines state or federal law or regulation requires the installation of SCR technology. If a MOA is not signed by January 1, 2012, the Governor must implement requirements to install selective noncatalytic reduction pollution control technology in any coal-fired generating boilers by January 1, 2013, after discussing the proper use of ammonia in this technology.

The MOA must also require the facility owner to provide the following financial assistance to the affected community: (1) $30 million for economic development and energy efficiency and weatherization; and (2) $25 million for energy technologies with the potential to create considerable energy, economic development, and air quality, haze, or other environmental benefits. Financial assistance investments by the facility owner begin on January 1, 2012, and consist of equal annual payments through December 31, 2023, or until the full amount has been provided. Only funds for energy efficiency and weatherization may be spent prior to December 31, 2015.

The MOA must specify the independent accounts at an appropriate financial institution where the funds are to be deposited, the schedule for disbursing the funds, and which individuals may approve expenditures from the accounts. These individuals must include members representing the Lewis County Economic Development Council, local elected officials, employees at the facility, and the facility owner.

Financial assistance is no longer required if the sales and use tax exemptions on coal are repealed.

Prohibition from Additional State and Local GHG EPS and Other GHG Emissions Limitations.

If an MOA is reached, no state agency or political subdivision of the state may adopt or impose an additional or inconsistent GHG emission standard, requirement, or limitation on a coal-fired electric generation facility located in Washington in operation on or before the effective date of this act or upon an electric utility's long-term purchase of coal transition power.

Recognition of Carbon Reductions.

An MOA may include provisions recognizing such reductions in state policies and programs relating to GHG emissions, and advocating for such reductions in all established and emerging regional, national, or international GHG frameworks. The Governor may recommend actions to the Legislature concerning the recognition of investments in emissions reductions.

Expedited Energy Facility Site Evaluation Council Processing.

The EFSEC must use its expedited certification process for siting generating facilities meeting the GHG EPS if the facility is to be sited in the county where a coal-fired electric generating facility subject to the GHG EPS is located, and if the siting application is filed before December 31, 2025.

Decommissioning Plan Requirement.

A coal-fired baseload electric generation facility subject to GHG EPS, or to closure through a MOA between the Governor and the owner of the facility, must provide the DOE with a plan for the closure and post-closure of the facility at least 24 months prior to facility closure or 24 months prior to start of decommissioning work, whichever is earlier. Among other things, the plan must include financial assurances to fund required activities and the preparation of a decommissioning and site restoration plan that is consistent with rules established by the EFSEC. The decommissioning plan, as well as any significant changes to it, is subject to the DOE's approval.

Financial Assistance Guarantees in the Decommissioning Plan.

A coal-fired baseload electric generation facility subject to GHG EPS or to closure through a MOA between the Governor and the owner of the facility must guarantee funds are available to perform all activities in the decommissioning plan. The guarantee may be accomplished with a DOE approved letter of credit, surety bond, or other means acceptable to the DOE.

Community Economic Development.

The CERB and the PWB must each solicit projects to attract new industrial and commercial projects to areas affected by the closure or potential closure of large coal-fired electric generation facilities. Project awards must be consistent with applicable community redevelopment plans for the area, including planning for future industrial activities associated with reuse of reclaimed coal mine lands. When the boards receive timely and eligible project applications for financial assistance for such projects, the boards must give priority consideration to such projects.

Integrated Resource Plans.

When assessing commercially available, utility-scale renewable and nonrenewable generating technologies as part of an integrated resource plan, an electric utility must compare the benefits and risks of purchasing power or building new resources.

Carbon Mitigation Exemption.

An applicant for siting a natural gas-fired generation plant to be constructed in a county with a coal-fired electric generation facility subject to the GHG EPS is exempt from state carbon mitigation requirements, if the application is filed before December 31, 2025. An applicant is defined as the owner of a coal-fired electric generation facility subject to the GHG EPS. The exemption expires December 31, 2025, or when the station-generating capability of all natural gas-fired generation plants approved under this exemption equals the station-generating capability from a coal-fired electric generation facility subject to the GHG EPS.

Findings, Legislative Intent, and Severability Clause.

Various findings are adopted, including the harmful effects of emissions from the combustion of coal; the contribution of coal-powered electricity generation as a large source of the state's GHG emissions; the need for the deliberate development of replacement generation to maintain grid stability and reliability; and the necessity to ensure substantial planning and funding for the closure and post-closure activities of coal-fired electric generation facilities.

A severability clause is provided, stating that if any provision of this act or its application to any person or circumstance is held invalid, the remainder of the act or the application of the provision to other persons or circumstances is not affected.

Staff Summary of Public Testimony (Environment):

(In support) The process to address greenhouse gas (GHG) emissions from existing coal-fired generation facilities began two years ago when the Governor issued her executive order and initiated negotiations with the TransAlta Corporation to reduce GHG emissions from the Centralia coal-fired generation facility. The negotiations failed to produce an agreement due in part to potential fiscal impacts to the state and its taxpayers. This bill is the bones of a very good agreement which provides certainty to the company, workers, the community and the ratepayers of the state. The TransAlta Corporation is really a good neighbor in Lewis County and this bill provides the company and the community the stability they need to transition from coal. Lewis County has suffered high levels of unemployment and this bill will keep people working for the next decade. The emissions from the Centralia coal-fired generation facility is a significant source of pollutants and without this bill environmental groups will continue to campaign against the facility. If that is the case, the likely loser will be the community. This bill represents a convergence of a shared vision of many stakeholders. The bill allows us to meet our economic and environmental obligations as well as our obligation to the community in a responsible way. The bill provides a pathway to minimize future regulatory and financial risk for the power plant. The bill provides time for natural attrition of the power plant's workforce. This bill reflects one of the four environmental community priorities this year. This bill could be a national model for how business and the environmental community can work together to build a green economy.

(In support with concerns) Puget Sound Energy is interested in this bill because it provides certainty in planning for future energy needs of the utility. Puget Sound Energy's integrated resource plan shows that the utility needs to acquire over 900 MW of electricity in the next few years to meet growing customer demand. For this bill to succeed it must ensure that an agreement for coal transition power is the least cost alternative for our customers, the power has a safe harbor from future carbon dioxide regulations, there is a process for pre-approval of coal transition power, that the contract for coal transition power be treated as an asset, and that there is flexibility in acquiring additional resources in the future.

(With concerns) There are concerns about potential impacts to utility ratepayers. This bill arrived late on the Senate floor and it was not well worked when it arrived. While the bill has been worked on since passage by the Senate, there are still serious unresolved issues. We are concerned that ratepayers may have to pay the equity kicker for a power purchase agreement. Ratepayers are not adequately protected from future environmental risks associated with an agreement to purchase coal transition power over the long-term. This bill could potentially cost hundreds of millions of dollars to utility ratepayer.

(Opposed) None.

Staff Summary of Public Testimony (Capital Budget):

(In support) Community, company, environmental, and workforce representatives worked collaboratively on this issue. This bill will help meet the state's economic, environmental, and community obligations, and will be a national model for transitioning from the state's largest polluter into a clean energy, green economy sector that is sustainable for workers. It helps move the state away from coal to cleaner sources of electrical power, with sufficient time to ensure stability in the electrical grid and secure the economic future of the affected communities. In a county with a 14.6 percent unemployment rate, the plant: employs 300 full-time workers at $88,000 per year and 400 workers in building and construction trades during plant shut-down periods; pays $9 million in taxes; and contributes $200 million to the regional economy. Allowing the company to operate until 2025 provides the company with certainty in an uncertain economic climate and market, and the new authorization to enter into long-term contracts to sell the facility's output provides financial stability to the company. On the environmental side, there will be a reduction in emissions as soon as 2020 and air pollution control investments as soon as 2013. The company has agreed to help the community financially through the transition. We endorse the Senate's concept of contributing state infrastructure funding, if available, to help in the economic transition. Language in the bill identifies the conditions under which funds will be made available. These state funding components are complementary to the investments to be made by the company and were one of the key tools in negotiating the bill. We understand, however, the sense of the proposed amendment—to elevate projects in the community that would assist in the transition. We can support the amendment in that spirit and do not find it hostile to the bill. Perhaps language can be added to require performance measurement and reports back to the Legislature on the state funds that are provided.

(With concerns) This bill could potentially cost hundreds of millions of dollars to utility ratepayers. For manufacturers, processors, and other companies, energy reliability and cost competitiveness are key. Authorizing an investor-owned utility to earn an equity component through a power purchase agreement is unprecedented in this state. Usually, long-term power purchase agreements allow electrical utilities to only recover the cost of the power, and not the equity component, because their shareholders do not take the risk of building an equivalent generation facility. Also, 14 years for coal transition power is a risky contract. Who will pay for replacement power if the agreement is terminated part-way through? We want to ensure there is no precedent set for future long-term power purchase agreements.

(Opposed) None.